Inspection of subsea production systems · of subsea prbduction systems for . exploitation of these...
Transcript of Inspection of subsea production systems · of subsea prbduction systems for . exploitation of these...
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INSPECTION OF SUBSEA PRODUCTION SYSTEMS
by
William Walters and Stacy Gehman 1
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ACKNOWLEDGEMENTS
This report describes work done under technology transfer authorization for the Conservation Division of the US Geological Survey
The authors also thank Shell Oil Co and Exxon Company USA for their cooperation in providing detailed information
on their approach~s to subsea production without which this program would not middothave been possible
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1 Introduction
The tremendous demand for oil and gas in the United States has
dep 1 eted our oil and gas reserves to an extent which has caused concern
for many years Efforts to maintain American independence from foreign
oil suppliers albng with the rising costs of imported oil have
made possible the consideration for development of marginal or
previously unprofitable oil and gas fields in the deeper waters
of the outer cont1i nenta 1 she 1 f (OCS)
The current ~evelopment of subsea prbduction systems for
exploitation of these deep water petroleum re~erves poses new
inspection problems for the US Geological Survey (USGS)
This report presents the results of a study f~nded by USGS to
explore techniques for inspection of sea floor completion and
production equip~ent A technique requirjng reither divers nor
submersibles has been identified and its deta~lcd application for
the Exxon subsea production system (SPS) is p~esented in Appendix A
to this report The technique uses production tubing within the I
sys tern and could bullsubstantially reduce i nspect i on expense and 1
danger to i nspectors which would otherwise be encountered during
first-hand inspecticns This technique is explained in detail
in Sections 4 and 5 Section 6 contains a review of OCS orders
applicable to subs~a systems with suggest~d g~nera1 inspection
procedures Appendix B inc 1 udes the test procedure suggested to I
USGS by ShellLockheed for their subsea well control system
along with recormiendations by MDL
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2 Types of Subsea Svstems
Various approaches are being taken to produce oi 1 from deeper
water using subsea sxstems There are three basically different
approaches to deep water production
1 The complet~ly submerged remote controlled system
Production equipment specifically designed for operation in the deep
water environment ismanifolded on a submerged template mounted on
the ocean floor Maintenance is by pump dmm tools and manned or
remote manipulatorsbull The Exxon Subsea Production System SPS)
discussed in Appendix A is of this type
2 The atmosphtiric wellhead Subsea production equipment is
located in a chamber bullmaintained at at111osphe1 ic pressure The
chamber is accessibl~ to workers from transfer capsules or
submersibles This approach alloKs the use of conventional I
completion equipmentand maintenance of thi1t equipment by personnel
in a dry one-atmosphere environment The ShellALockheed system
discussed in the App~ndix B of this type I
3 The surface-platformdeep water wellheaJ system Innovative
designs for surface iroducti on p 1 a tforms whi th aie being developed for I
use in deep water present unique structural evaluation problems
These systems are ou~side the scope of this repo~t
All these systems are being designed for de~th capability of
1000 ft and beyond but most are presently condned to 300 ft or I
less for ease of experimental testing Altlough 1all these systems I
present cha 11 eng i ng problems for inspection the Exxon SPS was chosen
for detailed investigation because 1t provided a range of inspection
problems representat1ve of subsea p1middotoduction middotsystems Sufficient I
design data 1vere available on this system to permit a thorough
evaluation of these problems
3 Inspection Techn igues and lI9~~-di t_E_~
As part of ongotng OCS lease m~nagement proQram USGS personnel
are responsible for ensuring that all offshore e~ploratory and production
operations are performed in a safe and poll11tionpreventing manner
according to pub 1 is hed OCS orders This re~pons tbil i ty is carried out
by both sch0dulrd c11q 1msched11lelt1 inspccticlaquos of all offshore oprrating
facilities In some cdses these i11specticir1s can be nade by visual
observation or by re~ding instruments while prescribed test procedures
are carried out In other cases the inspcctor must question the
lessee concerning installation of critical equipment or testing without actually observing the item in question For obvious reasons it is
preferable to make first-hand ~bservations whenever possible In I
subsea operations~ this brings up the question of the techniques and
procedures required to perform these inspections One very direct ~ - j
technique would be to employ submersible vchiCles having windows for
viewing of underwater equipment by trained inspectors Howevcr this -
method will evide~tly be very costly requiri19 not only the submersible
but also a specia1ly ~quipped ~urfoce suppo~tlaunching vessel Esti shy
mates for employi~g submersible vehicles are as high as $18 millionlf
for development of a complete system including ship submersible and I
special tools The submersible cost alone 1ould be in the area of
$1 to $2 mill ion each Thus complete independence from reliance on I I middot-middot bull - - -- 1 __ middot~
the p~oducers comes deuroarly nor() v11lid d9ampmtnf- Several of the more sophisticated subsea production systems feature
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personnel transfer capsules At the risk of increasing dependence --~-middot---
on producers these company-operated submersible enclosures could be
used IStill another alternative is the possibility of leasjo_g StJ~- J 7 mersi~li_~ and supp_g_rlships from comrnerc~a_l or~an_izatio~_s as heli- _ 1 _
copter transport is currently obtained by USGS to discharge its present Jltj
inspection responsibilities This wo~ld tend to defray the high purshy
chase cost and al so minimize rel i ancc on producers middot- l -middot
However the safety of the inspectors performing the underw(lter
_inspecion is of pri~ary concern-W~l-1 knmm po~~ntial dan-ers g~n~r-1111e(~JJry ally related to life support structura1 integrity and surface comshy
munications exist when r~anned submersibles arp used in such operations
Accidents and human error occurring while submerged can be vastly more
serious than if they occurred in the notTial e~vironment The use of
manned submersibles would also require a regular inspection of the
submersible ard its ancillary equipment to assure safety The added
burden of such a program if undertaken is self-evident
lfunpublished correspondence Dr J D Stochiw NUC to J Meek HDL 23 Jan 1976
-Another alternative is the use of an unmanned submersible The J ~ 1
i 1t~ use of unmanned reniote controlled underwater vehicles 1~ith television -middot
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and manipulators would eliminate personnel danger Hov1ever extra costs and possible technical limitations make a third alternative deshy
sirable if feasi 1
ble This alternative is tomiddot provide remote read-out 71 1shy1 bullbull -- ____ - ___~ lt l
1so that inspectors may perform the inspections from aboard the pro- -~r l middot
duction-supp_ort vess9ls or deep-water platforms already in use by the middot i
lessees The alter~ative would require that t_echniques be used to -~
sense the item i1
n question at the subsea v1el1head or production equ1 shyI J I
ment and transmi~t this critical information to the surface This I
sensing may req~ire fnstallation of pgsition pressure and thermal I ) t
transducers in ~lv_gs pipes pumps etc located in the subsea enshy1 I -~middot-middotmiddotmiddotmiddot--- ---shy
vi ronment Tele111etering the information to the surface could involve
ultrasonic hydrltaulic electric-wire or other transmission techniquesI
The information 1di sp 1ays could in lcude vi sual gages or meters and comshy
Iputer controlled cathode-ray tubes (CRTs)
The consid~rations discussed above place inspection techniques
and procedures 1ln three categories ie those performed by manned
submersibles by unmanned submersible and by remote controldisplay lrf Ultimately it liould appear that emphasis should be placed on sensors
1 _on the subsea s11ste111 with data display or readout at the surface-- ---
vessel or platfdrm Increased use of sensors however will require 10
the development of methods for their calibration A method for cali shy
brating pressure transducers and determining existence and magnitude of
leakage through closed valves is presented in the next secion of this
report This approach v1ould eliminate the need for very costly submersible
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vehicles and th~ support ships required for I
them as well as avoid a -fJ possible so4rce
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of risk to USGS inspectors --- I I
4 Calibration and Jn~fiectiq~hni_~
Production or service tubing that is accessible at the surface
can be used formiddot calibration of pressure sensors and determining valve
leakage if a tu~ing path to the component tq be monitored can be isoshy
lated by remotely actuated va1ves If a closed volume of fluid can
be obtained in this way net leakage into or out of the volume can
be determined by a pressure rise or drop respectively which is meashy
sured at the surface If leakage occurs the magnitude of the leak
can be determined by measuring the flow rate required to hold the I
surface pressure constant while bleeding fluid from or pumping fluid
into the tubing(assuming the fluid in the tubing is in thermal equilishy brium with the surroundings) If there is no leakage or if the leakage
is very small the process may be used to calibrate subsurface presshy
sure transducers Surface readings of pressure in the closed volume
can be used to calibrate the remote read out of subsurface transducers I
monitoring the pressure in the volume if th~ surface readings are comshy
pensated for the hydraulic gradient in the enclosed fluid This com-middot
pensation and a~sociated errors are discuss~d in the following section
This technique for calibration and inspection of subsea transducers I
and valving requires only that the inspector have access to the pipe- middot
lines that connect the subsea system to its middotsurface production and I
distribution systems Closed volumes are oqtained in these pipelines
by appropriately setting (turning on or off) various valves in the
pipeline and subsea systems Appendix A of this report applies this
technique to the Exxon SPS and shows that the necessary closed volumes
can be obtained for this system to permit inspection of all necessary
points
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- - ~e~ Df1 J 11 ~ 5 Pressure Transducer Ca1i brati on l)t a() fh IS
If a pressure transducer at the bottom o~ a long column of fluid
(liquid or gas) is to be calibrated by applying pressure at the topI
then the pressure 1read at the top must be cor~ected for the fluid
pressure gradient in the column to obtain a correct value for presshy sure at the transducer If themiddot transducer depth bene~th the surface
is le_ss than about I
1000 ft and the calibrating fluid is a liquid
then a constant liquid density may be assumed with Jess than one pershy cent errQJ The Bressmicrore correction is then given by Pgh where P is lt--middot -- the fluid densityi g t~e acce)eration of gravity and h is the height
of the fluid colu~n ~n terms of specific gravity (relative to water) I
SpGr the pressure c~rrection (in psi) is 0~434 ~ SpGr x h
For greater accurhcy or for greater transducer depths the cornshy
pressibility of the fluid must be considered I
Figure 1 is taken from
API STD 1101 (Man4al of Petroleum Measurement bullStandards Chapter 5
Section 2) and presents the compressibility o~ hydrocarbons as percent
change in volume 9r density per 1000 psi pressure change for a range
of API gravities and temperatures Dividing ~he compressibility pershy
centage obtained from figure 1 by 100000 results in a factor F such
that
d P = FdP p
where dp is the c~ange in density associated vlith a change in pressure
dP In psi
middot l middot11 _I ] ii J l ff - middot1middot -middot
lmiddotshyltl
ltfl lbullJ JJ n 0 w 0
Dr~1 r-----~d ir f ~cmiddotmiddotmiddot t- E 1 1 0~-~0n f r AC-lgt Ilei nd C L C_fJJ middotcmiddotr -cmiddotibili~v of Liquid Ii-C-xmiddotirlmiddot~-1~ lbullo= AJ 5 I1middotJ ~7middot~i 1~iJ
~t-tbulln Con1r1middot~)11a11~ of Jiqr1d fl1r bullr11lon_~0middot1H1almmmiddotb~~____
r_c 1
~ -t c~ Ibull_~- 4-r r sngt llI
Integrating both sides results in
= F(P-Ps1
p = eF(P-P~)or PS ( 1 )
where the subscript s indicates surface cdnditions Equation (1)
relates the density 2t any depth in the fluid column to the pressure at that point
For a small change in fluid depth dP =pgdh (2)
where dh is the change in depth Substituting eq~ation (1) into (2)
dP =p geF(P-Ps)dh s
-F(P-P ) or p gdh= e s dP s
Integrating from the surface to a total depth D
-F(P-P ) -F(P -P )1 s e D s + 1= - e = shyf fI
-Rearranging we have
or I
It is interesting to note that gp 5D is the pressure head expected for an incompressible fluid If FgrsDlaquo l (that is the fluid is nearly incompressible) then equation 3 simplifies to
Po-Ps = gPsD
(note lnl+x) ~ x for x laquo 1)
For an example of the type of error that might occur if compressibility
is not considered assume gp 5D = 4000 psi (as it would for an ~gproxi mately 10000 ft deep subsea completion) and that F = 2 x 10 psi Thus
4Po-Ps = -5 x 10 ln(l-008) = 4170 psi
If compressibility had been ignored the pre~sure error would have been 170 psi This analysis has assumed that temperature is constant with depth and that the compressibility of hydrocarbon liquids does not depend on pressure The APl STD 1101 values for compressibility were based on data from zero to 1000 psig
so more data may be reshyquired to assure pressure independence
For cases in which the subsea conditions have been specified (for example setting a downhole pressure for cal~bration of a transducer) the surface presure P required to establish the condition is unknown s Thus the surface density re qui red to solve equation 3 is also unknown A derivation similar to the above shows that the hydrostatic pressure
--difference in terms of subsea conditions is
P0-Ps = ~ ln 0 + fp 0gD) (4)
The density of the oil is most usually known at atmospheric pressure
so the density at pressure P0is found from the atm~spheric density p 0
from equation 1
P0 0 FP = r e D (5)
The use of the above equation assumes a constant temperature so that density varfotions in the tubing are caused only by pressure The
density at atmosp~eric pressure and the desired temperature are found by using table 23 API STD 2540 (ASTM-IP Petroleum Measurement
Tables) to correct the standard density measured at 60degF relative to I
water at 60degF (Sp Gr 6060degF) Specific gravity may be found from
API gravity by usi 1
ng Tible 3 from API STD 2540 or from the equationI I
Sp Gr 6060~F = 1415(APl Gravity at 60degF + 1315)
In the follo~ing paragraphs several examples will be worked to I
demonstrate the uSJe of the equations and to show t~e effect of a
temperature gradi~nt in the oil from the ocean floor to the surface I
The example will i 1nclude two different oils 20deg and 60deg API 6060degF)
at two temperatur~s (70degF and 120degF) and two completion depths
(l000 ft and 101 000 ft) The equations wil1 be solved for surface
pressure assuming a sea bottom transducer is being calibrated at l000 psi
for the 1000 ft 1deep completion and at 5000
psi for the 10000 ft
deep completion The 1000 ft- depth was chosen because H represents I
present capa bi 1 i ties for subsea completion l Q 000 ft las chosen as a maximum depth fqr completions in the foreseeable future (in
areas such as the ~leutian Basin)
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-Example 1
1000 ft completion -- = 1000 psiP0 20deg API 6060~F -- Sp Gr = 09340
Temp From Fig 1 From Table 23 (API STD 2540) I
70degF F = 039 x 10-5 ps1middot-T Sp Gr = 09305 -5 -1 J
120degF F = 050 x 10 psi Sp Gr bull 09130 At 1000 psi gpl~OO = gp x lOOO = 0434 x (=~middot Gr )0 x lOOO
0
At 70F gplOOO =0434 (09305) e039 x cO x 1000 1 bull
=0405 p~~
-5 0 ( ) eo 50 x 10 x 1000
At 120 F gplOOO ~ 0434 09130
o0398 poundft 1Po - PS =-F- ln (1 + F~D gD)
At 70degFmiddot P P - l ln (1 + 039 x 10-5 x 0405 x 1000) D - S - 039 x 10-S
= 405 psi Ps = lopo - 405 = 595 psi
At 120degF Po - p = l ln (l + ~50 x 10-5 x 0398 x 1000) s 050 x 10-5
= 398 psi P~ = 1000 - 398 = 60 psi
Thus if the $urface pressure P5 were setat 599 psi the pressure
at the sea bottom transducer 1~ould be 1000 4 psi even if the temperature
of the 20deg API gravity oil varied between 70 and 120degF
bull
Example 2 I
1000 ft completion -- P~ = 1000 psi I
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60deg API 6060deg F -- Sp Gri = 0 7389 From Pi_g__j_ From Table 23 (API STD 25401
70degF F = 0~80 x 10-5 psi-1 Sp Gr bull 07344 -5 -1
120degF F = l10 x 10 psi Sp Gr bull 07117 At 1000 psi pg middot = gp eF x 1000 = 0434middotx (Sp Gr) eF x 1000
1000 o middot o i 080 ~ 10~5 x 1000
At 70degF 9P]OOO bull 0434 (07344) e bull 0321 psift I
1 i o x i o~s x 1 oooAt 120degF gP1000 bull 0434 (07117)e
I = 03]2 psift
PD - Ps = F1 1 n (1 + F PD9 D)
1At 70degF PD
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- Ps = _ ln (1 +1080 x io-5 x 0321 x 1000)5
080 x 10 = 321 psi
PS bull 679 psi
At 120degF P~ --1----~5 ln (1 + 1 1lO x 10-5 x 0312 x 1000) 110 x 10
= 311 psi Ps = 689 psi
Thus if the surtace pressure P5 were set atmiddot684psi the pressure at the sea bottom transducer would be 1000 plusmn_ 5 psi ~ven if the temperature of the 60deg API gravity oil varied between 70deg and 120degF
bull
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From the foregoing examples it is apparrnt that for subsea compleshytions up to 1000 ft there is little effect on the calculated
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pressure at a suhsea transducer due to compressibility and temperature bull
The pressure ca~ be accurately calculated from ~ I bullr
PD - PS = 0434 x Sp Gr x D where the specific gravity of the oil at sta~dard conditions has been corrected to the observed temperature (using an average between the subsea and surface oil temperatures) and 1 i ne pressure Example 3
10000 ft c~mpletion -- P0 = 5000 psi 20deg API 6060degF Sp Gr = 09340
From Fi9 l From Teble 23 (API STD 2540)
70deg F = 039 x l0-5psi-l Sp Gr = 09305 120deg F = 050 x l0-5psi-l Sp Gr = 09130
F x 5000 F x 5000At 5000 psi gp5poo = gp e = 0434 x
I
(=~middotGr ) e0 0
At 70F 9P5poo = 0434 (09305)e039 x 10 x 5000
= 0412 psift I
50 x 5000At 120F 9P~ooo = 0434 (09130)e0middot x 10 -5
= 0406 psift 1
PD - PS= -F- ln (l + Fp gD)0 __L__-=s 1nAt 70degF P ~ (l + 0~39 x 10-5 x 0412 x 10000
D I
P5 039 x 10 = 4087 psi ~ 5000 - 4087 = 913 psir5
At l20F P - P =--1-- ln (l + 050 x 10-5 x 0406 x 10000) D S 050 x l0- 5
- -p~ = 4019 psi P = 981 psi ~
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Thus if the 1surface pressure r5 were set at 947 the pressure at the
sea bottom trans~ucer would be 5000 +- 34 psi even if the temperature of
the 20degAPI gravity oil varied between 70deg and l20degF
Example 4
I 110000 ft ~omp etion P f 5000 psi0
60deg API 6060degF Sp Gr = 07389 Temp
70degF
l 20degF
From Fig l I ~ -5 -1
F = Oi80 x 10 psi I middot -5 -1F = 110 x 10 psmiddotiI
From Table 23 (API----middotmiddot Sp Gr = 07344
Sp Gr= 07117
STD 2540)
middot F x 5000 F x 5000At 5000 ps1 1 gp 5000 = gp = 0~34 x (Sp Gr)e e0 0
80At 70degF gp middot = 0434 (o 7344)e0middot x 10-5 x 5000
~ooo = o332 psift
_ llxl0_ 5 x5oooAt 120degF gp5000 - 0434 (07117)e
= 0326 psift P ~ P ~ t ln (1 + fp gD)D S D
At 70degF Po_ p = ~__]-____ ln (l + Q80 x lo- 5 x 0332 x 10000) s 080 x 10-~
= 3277 psi I P5 ~ 5000 - 3277 = 1723 psi
At l20degF PD - PS = l 5 ln (l + l l x 10-5 x 0326 x 10000) llOxlOshy
= 3203 psi
PS = 5000 - 3202 = 1797 psi
shybull
Thus if the surface pressure P5 were set at 1760 psi the presshy
sure at the sea ~ottom transducer would be 5000 + 37 psi even if the I shy
temperature cf the 60deg API gravity oil varied between 70deg and 120degF
From these pxample calculations for a 10000 ft completion it is
apparent that temperature variations cause r~latively small errors in I
sea floor ca 1 i bration pressures even for sue~ a great depth If the
pressures are needed more acet1rately than this then the temperature
profile in the tubing would be needed
It has thus been shown that relatively simple calculations of
liquid hydrostatic head result in accurate pressure values for calishy
bration of subsea transducers I
The calibration of gas pressure transdutersmiddot is somewhat different
For low pressures and shallow depth little correction need be made to
the pressure measured at the surface For a gas specific gravity SG
(relative to ai~ at 20degC and 147 psia) pressure P(psia) and depth I
D(ft) the pressure correction AP is given by
-5AP = 356 x 10 x SG x P x D
This equation assumes that the ideal gas law holds and that tPP
is small The equation nay be modified to include the super-compresshy
sibility factor z as follows 0
AP= 356 x 10-Sx SG x D x Pz
For a 1000 ft deep subsea completion line pressure of 1000 psia
(assuming SG ~ 1 and z = 1) AF= 36 psi It is thus apparent that even with large errors in specific gravity and z the pressure correction
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for hydrostatic head of the gqs is small for depths up to 1000 ft
-bull
Again for a line pressure of 1000 psi but a 10000 ft deep comshy
pletion llP = 3~0 psi so the assumption of PP being small no longer
holds An integration would thus be needed to determine the transducer
pressure and t~e vaHable z factor should be included in thi~ integral Thus a closed form solution similar to tha~ found for liquids cannot
be obtained an~ numerical integration is necessary However for a wide range of conditions the equations pre~ented for both liquids and
I II gases a11 ow acc4ra te cal i bratfon of sea bottom pressure transducers
through the production tubing~ I
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6 J_nspection_B$9YJrcment_~and Te~t Proc~dures j
The OCS Ord~rs ~ere reviewed for those item~ pertinent to a subsea system The OCS inspection requirements and the suggested general
inspection procedures for these items are discussed in the following
paragraphs Tubing PLtg_
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Inspection Requirements (OCS Order No 5)I
1 T~e s~~tained liquid leakage flow should not exceed I
400 ccmin 2 The ga~ leakage flo~1 should nGt e)ceed 15 cu ftmin
General Pro~middotedure
The first step i~ this procedure is to isolate a column of fluid
between the tubing plug and the inspector with the valves opened as
for production except that the tubing plug is in pl ace Any fl ow reaching the inspector at the surface is a direct indication of leakage past the tubing plug Thermal equilibrium may b~ required if the
maximum allowabl~ leakage is too small Theflow volume can be measured at the surface in the same manner as for conventionlt1 platform systems
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middotShut-in Tubi9_ls_e_sur~
Inspection Requirements (OCS Order No I
5)
1 Wells with a shut-in tubing ptessure of 4000 psig or
greater sha11 be equj pped with a subsurface-~ontro11 ed subsurface safety device
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2 When the shut-in tubing pressure declines below 4000 I
psig a remotely sontrolled subsurface safety device shall be installed
when the tubing is first removed and reinstalled
General Procedure
To determine if the shut-i~ tubing pressure i~ greater than 4000 psig I
a pressure sensor should be located ~1here the shut-in pressure can be sensed
A convenient arrangement is to locate a pressure s~nsor between the master
valve and wing valve on each tubing With the downhole safety valve and
master valve opened and the wing valve close~ the shmicrot-in tubing pressure
as indicated by the sensor is noted
Calibration of the pressure sensor can be accomplished by applying
a known pressure ~t the surface to a closed cdlumn of fluid connecting I
the surface with the sensor with corrections calculated as explained
in Section 5
Subsurface Safety Device
Inspection Requirements (OCS Order No 5) 1 A surface-controlled subsurface safety device shall be
test operated every six months
2 A subsurface-controlled subsurface safety device shall
be removed inspected and repaired every 12 mdnths 1
General Procedure To test a surface-controlled subsurface safety device the well
should be opened for production and the command then given to close
the subsurface Sifety device The leakage flqw volume if any is
measured at the surface in the same manner as for conventional plat shy
form sys terns bull
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Pressure Relief Valves Inspection Requtrements (0CS Order No 8)
All pressure reli-f valve~ shall be either bench tested for opershy
ation or tested with an external pressure source (if the valve is somiddot
equipped)annually Jtbt Wf SJJS~+ General Procedure
To test a pressure relief valve for operation the vessel or line
should be pressunizeq to the pressure necessary to open the valve by
using the method suggested in Section 5 Uriless remote position inshy
dicators are provided a means to determine ~hether or not the valve
has actually ope1ed would have to be devised bullfor each subsea system
by observing the effect on the pressure sensors Pressure Sensors
Inspection Requirements (OCS Order No 8)
All pressure sensors shall be tested at least once each month
General Procedure
To remotely test and cal i~rate a subsea bullpressure sensor it is
necessary to
(1) isolate a closed column of fluid irom the surface to
the subsea sensor by properly arranging the ~ys terns va1ves
(2) determine the specific gravity compressibility and the
column height of the fluid
(3) select the pressure required at the subsea sensor
(4) apply the appropriate pressure at the surface end of
the column and
(5) compare the telemetered press4re signal or indication
with the pressur~ applied to the sensor
Automatic Hellhead Safety Devices -~~__--r---
Inspection 8equiremcnts (OCS Order No 8) All automatic wellhead safety devices shall be tested for operation
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and holding pres~ureonce each1month
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bull )
General Prooedure
To test the operation of the automatic well head safety devices
the out-of-the-tolerance condition (usually ~igh or low pressure) which actuates the devices should be simulated Urless position 1ndicators
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are provided a means to deterrl1ine whether 011 not the valves have
actually closed ~ust be devised for each indi1vidu~l system because of
the peculiarities
in each syste m J I
L~ 6 - Jlaquo4 sfSf~ rCheck Valves ~J0141d 11tJt NC Uf~ l(I -v-
Inspection Requirements (OCS Order No ~)
A11 check valves on a11 fl ow 1i nes sha11 be tested for opera ti on
and holding pressure once each month
General Procedures
To test the check valve ft will have to be back pressured The
check valve fails to operate properly if any back flo~1 through the I
valve occurs
~iguid Level Shut-in Controls I
Inspection Requirements (9cs Order No 8)
All liquid-l 1
evel shut-in controls shall be tested once each month
by raising or lowering liquid level across the leyel-control detector
General Pro~edure I
The preferable way to test the liquid-level sh~t-in controls is to
simulate the out-of-tolerance conditions (1 iquid Jevel either low or I
high) at the sensor This sim~lation should cau~e either the inlet
shutoff va1ve to close or the discharge shutoff valve to close In
this manner both the control YStem and the automatif valves are tested I
A means will have to be devised for each subsea system to determine I
if the out-of-tolerance condition actually occurred at the sensor if
it was properly Jetected and i~ it caused thd proper actuation I
Vessel Automatic~Inlet-Shutoff Valves I
Inspection ~equirement (OCS Order No 8)I
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bull ) ~ J) All automatic~~~~~-shutoff valves actuated by vessel~~
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~fsensorj shalil be tested for operation onle each month General Procedure
Described above under gene~al procedure for Liquid-Level Shut-
In Controls Vessel AutomaJi c-Di sc_b~_g_e-Sh_ll__Dff__Y_ii_l ves
Inspection RequireiT1ent (OCS Order No 8) All automatic-discharge-shutoff valves actuated by vessel lowshy
level sensors shall be tested for operation qnce each month
General Proc~dure
Described above under Liquid-Level Shut-tn Controls
High-tempera_ure Coniprc2_()r-Sh_t1tdow_ri_Co~_o1s Inspection Requirement (OCS Order No 8)i
High temperature controls which protect the compressor against
abnormal pressure~ soltiY by such temperature
safety devices shall be tested annually
General Procedure Because of the danger involved in elevating the temperature suffi shy
ciently to cause + temperature device to actuate it is recommended that each temperature device be pre-tested and replaced each year rather than be tested remotely
Oil Spil 1 Detection E_g_t_pmen~
Inspection Requirements (OCS Order 7) All platforms and structures are require~ to have curbs gutters
and spill pans connected to a tank or sump fhis equipment is required to collect all hydrocarbon spillage on the platform It is recommended that this requirement be extencjed to require all unenclosed subsea
equipment to be covered by inverted spill pans with hydrocarbon sensors
and sumps to rem~ve spillage
General Procedure To test the hydrocarbon spi 11 age detection and removal system
a controlled spill should be made in each ar~a or section of spill
- bull
pans while th~ SUljlPI
pumps are monitored for proper operation This I I
metbod will require a signal to the surface to indicate directly when the pumps are running or indirectly by indicating a pressure rise in
I i
the affected pipeline due to the pun1ping action The indirect method is preferablebec~use the pressure rise not only indicates the pumps are running b~t indicates they also are pumpi~g fluid One additional safeguard should ~e employed A TV camera should be used to observe
I
the spill pans in the vicinity of the spill to assure that they are not leaking due to damage or inadequacy of de~ign Hydrocarbon S~nsors
IInspection Requirements
Hydrocarbon sensors are not covered in tbe OCS Qrders presently
in effect General Procedure The general test procedure for the oil-spill-detection equipment
above will test the hydrocarbon sensors for operation In addition
I bull some means of knowing when each separate hydrocarbon sensor in the
spill pan assemblies hus sensed hydrocarbon will provide additional I
protection by warning of system degradation b~fore the system is comshypletely inoperable
7 Summary and RecQ)enda tions This report deal~ with the inspection problems that have arisen
as a result of the present trend of the offshore oil industry towards
subsea completion and production of deep water petroleum reservoirs I
Inspection techniques for completion and prod~ction equipment are inshyvestigated but inspection of fiser systems submersibles and strucshy
tures are not inc~uded in the scope of this wprk
A technique ~as been detailed for calibr1ttion of subsea sensors I
and for verifying the proper OReration of va1ves The technique reshy
quires only that the inspector 1 have access to production tubing at
- bull
I I
the surface By actuating subsurface control valves from the surface
the inspector can isolate a closed fluid path1 to the point of interest I
Pressures read at the surface (when corrected for hydraulic gradients)
may then be used to ca 1 i brate subsurface tran1sducers Flow rates
measured at the surface can be used to I
indicate leakage rates bull
from
subsurface valves I
but fluid in the tubing must be allow
ed to reach
sufficient therma1l equilibriumwith its surroundings so that a false leakage rate is riot indicated due to thermal expansion of the fluid
I bull
This technique has been used to work ou~ an inspection procedure
for the Exxon Sulisea Production System The 1procedure demonstrates I I
that the necessany closed fluid paths can be obtained to permit inshyspection of all necessary points Thus from 1a theoretical point of et
j9aYYew 1 t has ~en established that accurate euroVa 1ua tion of subsea con- J
ditions can be made from the surface (io implement the procedures I
it would first be necessary to conduct an experimental program with field
tests to determi~e operational problems) tAtti e
bull
- Inspection of subsea production systems
-
bull
-
ACKNOWLEDGEMENTS
This report describes work done under technology transfer authorization for the Conservation Division of the US Geological Survey
The authors also thank Shell Oil Co and Exxon Company USA for their cooperation in providing detailed information
on their approach~s to subsea production without which this program would not middothave been possible
-
1 Introduction
The tremendous demand for oil and gas in the United States has
dep 1 eted our oil and gas reserves to an extent which has caused concern
for many years Efforts to maintain American independence from foreign
oil suppliers albng with the rising costs of imported oil have
made possible the consideration for development of marginal or
previously unprofitable oil and gas fields in the deeper waters
of the outer cont1i nenta 1 she 1 f (OCS)
The current ~evelopment of subsea prbduction systems for
exploitation of these deep water petroleum re~erves poses new
inspection problems for the US Geological Survey (USGS)
This report presents the results of a study f~nded by USGS to
explore techniques for inspection of sea floor completion and
production equip~ent A technique requirjng reither divers nor
submersibles has been identified and its deta~lcd application for
the Exxon subsea production system (SPS) is p~esented in Appendix A
to this report The technique uses production tubing within the I
sys tern and could bullsubstantially reduce i nspect i on expense and 1
danger to i nspectors which would otherwise be encountered during
first-hand inspecticns This technique is explained in detail
in Sections 4 and 5 Section 6 contains a review of OCS orders
applicable to subs~a systems with suggest~d g~nera1 inspection
procedures Appendix B inc 1 udes the test procedure suggested to I
USGS by ShellLockheed for their subsea well control system
along with recormiendations by MDL
-
2 Types of Subsea Svstems
Various approaches are being taken to produce oi 1 from deeper
water using subsea sxstems There are three basically different
approaches to deep water production
1 The complet~ly submerged remote controlled system
Production equipment specifically designed for operation in the deep
water environment ismanifolded on a submerged template mounted on
the ocean floor Maintenance is by pump dmm tools and manned or
remote manipulatorsbull The Exxon Subsea Production System SPS)
discussed in Appendix A is of this type
2 The atmosphtiric wellhead Subsea production equipment is
located in a chamber bullmaintained at at111osphe1 ic pressure The
chamber is accessibl~ to workers from transfer capsules or
submersibles This approach alloKs the use of conventional I
completion equipmentand maintenance of thi1t equipment by personnel
in a dry one-atmosphere environment The ShellALockheed system
discussed in the App~ndix B of this type I
3 The surface-platformdeep water wellheaJ system Innovative
designs for surface iroducti on p 1 a tforms whi th aie being developed for I
use in deep water present unique structural evaluation problems
These systems are ou~side the scope of this repo~t
All these systems are being designed for de~th capability of
1000 ft and beyond but most are presently condned to 300 ft or I
less for ease of experimental testing Altlough 1all these systems I
present cha 11 eng i ng problems for inspection the Exxon SPS was chosen
for detailed investigation because 1t provided a range of inspection
problems representat1ve of subsea p1middotoduction middotsystems Sufficient I
design data 1vere available on this system to permit a thorough
evaluation of these problems
3 Inspection Techn igues and lI9~~-di t_E_~
As part of ongotng OCS lease m~nagement proQram USGS personnel
are responsible for ensuring that all offshore e~ploratory and production
operations are performed in a safe and poll11tionpreventing manner
according to pub 1 is hed OCS orders This re~pons tbil i ty is carried out
by both sch0dulrd c11q 1msched11lelt1 inspccticlaquos of all offshore oprrating
facilities In some cdses these i11specticir1s can be nade by visual
observation or by re~ding instruments while prescribed test procedures
are carried out In other cases the inspcctor must question the
lessee concerning installation of critical equipment or testing without actually observing the item in question For obvious reasons it is
preferable to make first-hand ~bservations whenever possible In I
subsea operations~ this brings up the question of the techniques and
procedures required to perform these inspections One very direct ~ - j
technique would be to employ submersible vchiCles having windows for
viewing of underwater equipment by trained inspectors Howevcr this -
method will evide~tly be very costly requiri19 not only the submersible
but also a specia1ly ~quipped ~urfoce suppo~tlaunching vessel Esti shy
mates for employi~g submersible vehicles are as high as $18 millionlf
for development of a complete system including ship submersible and I
special tools The submersible cost alone 1ould be in the area of
$1 to $2 mill ion each Thus complete independence from reliance on I I middot-middot bull - - -- 1 __ middot~
the p~oducers comes deuroarly nor() v11lid d9ampmtnf- Several of the more sophisticated subsea production systems feature
I
personnel transfer capsules At the risk of increasing dependence --~-middot---
on producers these company-operated submersible enclosures could be
used IStill another alternative is the possibility of leasjo_g StJ~- J 7 mersi~li_~ and supp_g_rlships from comrnerc~a_l or~an_izatio~_s as heli- _ 1 _
copter transport is currently obtained by USGS to discharge its present Jltj
inspection responsibilities This wo~ld tend to defray the high purshy
chase cost and al so minimize rel i ancc on producers middot- l -middot
However the safety of the inspectors performing the underw(lter
_inspecion is of pri~ary concern-W~l-1 knmm po~~ntial dan-ers g~n~r-1111e(~JJry ally related to life support structura1 integrity and surface comshy
munications exist when r~anned submersibles arp used in such operations
Accidents and human error occurring while submerged can be vastly more
serious than if they occurred in the notTial e~vironment The use of
manned submersibles would also require a regular inspection of the
submersible ard its ancillary equipment to assure safety The added
burden of such a program if undertaken is self-evident
lfunpublished correspondence Dr J D Stochiw NUC to J Meek HDL 23 Jan 1976
-Another alternative is the use of an unmanned submersible The J ~ 1
i 1t~ use of unmanned reniote controlled underwater vehicles 1~ith television -middot
I -- - IL
and manipulators would eliminate personnel danger Hov1ever extra costs and possible technical limitations make a third alternative deshy
sirable if feasi 1
ble This alternative is tomiddot provide remote read-out 71 1shy1 bullbull -- ____ - ___~ lt l
1so that inspectors may perform the inspections from aboard the pro- -~r l middot
duction-supp_ort vess9ls or deep-water platforms already in use by the middot i
lessees The alter~ative would require that t_echniques be used to -~
sense the item i1
n question at the subsea v1el1head or production equ1 shyI J I
ment and transmi~t this critical information to the surface This I
sensing may req~ire fnstallation of pgsition pressure and thermal I ) t
transducers in ~lv_gs pipes pumps etc located in the subsea enshy1 I -~middot-middotmiddotmiddotmiddot--- ---shy
vi ronment Tele111etering the information to the surface could involve
ultrasonic hydrltaulic electric-wire or other transmission techniquesI
The information 1di sp 1ays could in lcude vi sual gages or meters and comshy
Iputer controlled cathode-ray tubes (CRTs)
The consid~rations discussed above place inspection techniques
and procedures 1ln three categories ie those performed by manned
submersibles by unmanned submersible and by remote controldisplay lrf Ultimately it liould appear that emphasis should be placed on sensors
1 _on the subsea s11ste111 with data display or readout at the surface-- ---
vessel or platfdrm Increased use of sensors however will require 10
the development of methods for their calibration A method for cali shy
brating pressure transducers and determining existence and magnitude of
leakage through closed valves is presented in the next secion of this
report This approach v1ould eliminate the need for very costly submersible
bull
vehicles and th~ support ships required for I
them as well as avoid a -fJ possible so4rce
1
of risk to USGS inspectors --- I I
4 Calibration and Jn~fiectiq~hni_~
Production or service tubing that is accessible at the surface
can be used formiddot calibration of pressure sensors and determining valve
leakage if a tu~ing path to the component tq be monitored can be isoshy
lated by remotely actuated va1ves If a closed volume of fluid can
be obtained in this way net leakage into or out of the volume can
be determined by a pressure rise or drop respectively which is meashy
sured at the surface If leakage occurs the magnitude of the leak
can be determined by measuring the flow rate required to hold the I
surface pressure constant while bleeding fluid from or pumping fluid
into the tubing(assuming the fluid in the tubing is in thermal equilishy brium with the surroundings) If there is no leakage or if the leakage
is very small the process may be used to calibrate subsurface presshy
sure transducers Surface readings of pressure in the closed volume
can be used to calibrate the remote read out of subsurface transducers I
monitoring the pressure in the volume if th~ surface readings are comshy
pensated for the hydraulic gradient in the enclosed fluid This com-middot
pensation and a~sociated errors are discuss~d in the following section
This technique for calibration and inspection of subsea transducers I
and valving requires only that the inspector have access to the pipe- middot
lines that connect the subsea system to its middotsurface production and I
distribution systems Closed volumes are oqtained in these pipelines
by appropriately setting (turning on or off) various valves in the
pipeline and subsea systems Appendix A of this report applies this
technique to the Exxon SPS and shows that the necessary closed volumes
can be obtained for this system to permit inspection of all necessary
points
I
- - ~e~ Df1 J 11 ~ 5 Pressure Transducer Ca1i brati on l)t a() fh IS
If a pressure transducer at the bottom o~ a long column of fluid
(liquid or gas) is to be calibrated by applying pressure at the topI
then the pressure 1read at the top must be cor~ected for the fluid
pressure gradient in the column to obtain a correct value for presshy sure at the transducer If themiddot transducer depth bene~th the surface
is le_ss than about I
1000 ft and the calibrating fluid is a liquid
then a constant liquid density may be assumed with Jess than one pershy cent errQJ The Bressmicrore correction is then given by Pgh where P is lt--middot -- the fluid densityi g t~e acce)eration of gravity and h is the height
of the fluid colu~n ~n terms of specific gravity (relative to water) I
SpGr the pressure c~rrection (in psi) is 0~434 ~ SpGr x h
For greater accurhcy or for greater transducer depths the cornshy
pressibility of the fluid must be considered I
Figure 1 is taken from
API STD 1101 (Man4al of Petroleum Measurement bullStandards Chapter 5
Section 2) and presents the compressibility o~ hydrocarbons as percent
change in volume 9r density per 1000 psi pressure change for a range
of API gravities and temperatures Dividing ~he compressibility pershy
centage obtained from figure 1 by 100000 results in a factor F such
that
d P = FdP p
where dp is the c~ange in density associated vlith a change in pressure
dP In psi
middot l middot11 _I ] ii J l ff - middot1middot -middot
lmiddotshyltl
ltfl lbullJ JJ n 0 w 0
Dr~1 r-----~d ir f ~cmiddotmiddotmiddot t- E 1 1 0~-~0n f r AC-lgt Ilei nd C L C_fJJ middotcmiddotr -cmiddotibili~v of Liquid Ii-C-xmiddotirlmiddot~-1~ lbullo= AJ 5 I1middotJ ~7middot~i 1~iJ
~t-tbulln Con1r1middot~)11a11~ of Jiqr1d fl1r bullr11lon_~0middot1H1almmmiddotb~~____
r_c 1
~ -t c~ Ibull_~- 4-r r sngt llI
Integrating both sides results in
= F(P-Ps1
p = eF(P-P~)or PS ( 1 )
where the subscript s indicates surface cdnditions Equation (1)
relates the density 2t any depth in the fluid column to the pressure at that point
For a small change in fluid depth dP =pgdh (2)
where dh is the change in depth Substituting eq~ation (1) into (2)
dP =p geF(P-Ps)dh s
-F(P-P ) or p gdh= e s dP s
Integrating from the surface to a total depth D
-F(P-P ) -F(P -P )1 s e D s + 1= - e = shyf fI
-Rearranging we have
or I
It is interesting to note that gp 5D is the pressure head expected for an incompressible fluid If FgrsDlaquo l (that is the fluid is nearly incompressible) then equation 3 simplifies to
Po-Ps = gPsD
(note lnl+x) ~ x for x laquo 1)
For an example of the type of error that might occur if compressibility
is not considered assume gp 5D = 4000 psi (as it would for an ~gproxi mately 10000 ft deep subsea completion) and that F = 2 x 10 psi Thus
4Po-Ps = -5 x 10 ln(l-008) = 4170 psi
If compressibility had been ignored the pre~sure error would have been 170 psi This analysis has assumed that temperature is constant with depth and that the compressibility of hydrocarbon liquids does not depend on pressure The APl STD 1101 values for compressibility were based on data from zero to 1000 psig
so more data may be reshyquired to assure pressure independence
For cases in which the subsea conditions have been specified (for example setting a downhole pressure for cal~bration of a transducer) the surface presure P required to establish the condition is unknown s Thus the surface density re qui red to solve equation 3 is also unknown A derivation similar to the above shows that the hydrostatic pressure
--difference in terms of subsea conditions is
P0-Ps = ~ ln 0 + fp 0gD) (4)
The density of the oil is most usually known at atmospheric pressure
so the density at pressure P0is found from the atm~spheric density p 0
from equation 1
P0 0 FP = r e D (5)
The use of the above equation assumes a constant temperature so that density varfotions in the tubing are caused only by pressure The
density at atmosp~eric pressure and the desired temperature are found by using table 23 API STD 2540 (ASTM-IP Petroleum Measurement
Tables) to correct the standard density measured at 60degF relative to I
water at 60degF (Sp Gr 6060degF) Specific gravity may be found from
API gravity by usi 1
ng Tible 3 from API STD 2540 or from the equationI I
Sp Gr 6060~F = 1415(APl Gravity at 60degF + 1315)
In the follo~ing paragraphs several examples will be worked to I
demonstrate the uSJe of the equations and to show t~e effect of a
temperature gradi~nt in the oil from the ocean floor to the surface I
The example will i 1nclude two different oils 20deg and 60deg API 6060degF)
at two temperatur~s (70degF and 120degF) and two completion depths
(l000 ft and 101 000 ft) The equations wil1 be solved for surface
pressure assuming a sea bottom transducer is being calibrated at l000 psi
for the 1000 ft 1deep completion and at 5000
psi for the 10000 ft
deep completion The 1000 ft- depth was chosen because H represents I
present capa bi 1 i ties for subsea completion l Q 000 ft las chosen as a maximum depth fqr completions in the foreseeable future (in
areas such as the ~leutian Basin)
i I __ _l__
-Example 1
1000 ft completion -- = 1000 psiP0 20deg API 6060~F -- Sp Gr = 09340
Temp From Fig 1 From Table 23 (API STD 2540) I
70degF F = 039 x 10-5 ps1middot-T Sp Gr = 09305 -5 -1 J
120degF F = 050 x 10 psi Sp Gr bull 09130 At 1000 psi gpl~OO = gp x lOOO = 0434 x (=~middot Gr )0 x lOOO
0
At 70F gplOOO =0434 (09305) e039 x cO x 1000 1 bull
=0405 p~~
-5 0 ( ) eo 50 x 10 x 1000
At 120 F gplOOO ~ 0434 09130
o0398 poundft 1Po - PS =-F- ln (1 + F~D gD)
At 70degFmiddot P P - l ln (1 + 039 x 10-5 x 0405 x 1000) D - S - 039 x 10-S
= 405 psi Ps = lopo - 405 = 595 psi
At 120degF Po - p = l ln (l + ~50 x 10-5 x 0398 x 1000) s 050 x 10-5
= 398 psi P~ = 1000 - 398 = 60 psi
Thus if the $urface pressure P5 were setat 599 psi the pressure
at the sea bottom transducer 1~ould be 1000 4 psi even if the temperature
of the 20deg API gravity oil varied between 70 and 120degF
bull
Example 2 I
1000 ft completion -- P~ = 1000 psi I
I
60deg API 6060deg F -- Sp Gri = 0 7389 From Pi_g__j_ From Table 23 (API STD 25401
70degF F = 0~80 x 10-5 psi-1 Sp Gr bull 07344 -5 -1
120degF F = l10 x 10 psi Sp Gr bull 07117 At 1000 psi pg middot = gp eF x 1000 = 0434middotx (Sp Gr) eF x 1000
1000 o middot o i 080 ~ 10~5 x 1000
At 70degF 9P]OOO bull 0434 (07344) e bull 0321 psift I
1 i o x i o~s x 1 oooAt 120degF gP1000 bull 0434 (07117)e
I = 03]2 psift
PD - Ps = F1 1 n (1 + F PD9 D)
1At 70degF PD
I
- Ps = _ ln (1 +1080 x io-5 x 0321 x 1000)5
080 x 10 = 321 psi
PS bull 679 psi
At 120degF P~ --1----~5 ln (1 + 1 1lO x 10-5 x 0312 x 1000) 110 x 10
= 311 psi Ps = 689 psi
Thus if the surtace pressure P5 were set atmiddot684psi the pressure at the sea bottom transducer would be 1000 plusmn_ 5 psi ~ven if the temperature of the 60deg API gravity oil varied between 70deg and 120degF
bull
I
From the foregoing examples it is apparrnt that for subsea compleshytions up to 1000 ft there is little effect on the calculated
I
pressure at a suhsea transducer due to compressibility and temperature bull
The pressure ca~ be accurately calculated from ~ I bullr
PD - PS = 0434 x Sp Gr x D where the specific gravity of the oil at sta~dard conditions has been corrected to the observed temperature (using an average between the subsea and surface oil temperatures) and 1 i ne pressure Example 3
10000 ft c~mpletion -- P0 = 5000 psi 20deg API 6060degF Sp Gr = 09340
From Fi9 l From Teble 23 (API STD 2540)
70deg F = 039 x l0-5psi-l Sp Gr = 09305 120deg F = 050 x l0-5psi-l Sp Gr = 09130
F x 5000 F x 5000At 5000 psi gp5poo = gp e = 0434 x
I
(=~middotGr ) e0 0
At 70F 9P5poo = 0434 (09305)e039 x 10 x 5000
= 0412 psift I
50 x 5000At 120F 9P~ooo = 0434 (09130)e0middot x 10 -5
= 0406 psift 1
PD - PS= -F- ln (l + Fp gD)0 __L__-=s 1nAt 70degF P ~ (l + 0~39 x 10-5 x 0412 x 10000
D I
P5 039 x 10 = 4087 psi ~ 5000 - 4087 = 913 psir5
At l20F P - P =--1-- ln (l + 050 x 10-5 x 0406 x 10000) D S 050 x l0- 5
- -p~ = 4019 psi P = 981 psi ~
I
Thus if the 1surface pressure r5 were set at 947 the pressure at the
sea bottom trans~ucer would be 5000 +- 34 psi even if the temperature of
the 20degAPI gravity oil varied between 70deg and l20degF
Example 4
I 110000 ft ~omp etion P f 5000 psi0
60deg API 6060degF Sp Gr = 07389 Temp
70degF
l 20degF
From Fig l I ~ -5 -1
F = Oi80 x 10 psi I middot -5 -1F = 110 x 10 psmiddotiI
From Table 23 (API----middotmiddot Sp Gr = 07344
Sp Gr= 07117
STD 2540)
middot F x 5000 F x 5000At 5000 ps1 1 gp 5000 = gp = 0~34 x (Sp Gr)e e0 0
80At 70degF gp middot = 0434 (o 7344)e0middot x 10-5 x 5000
~ooo = o332 psift
_ llxl0_ 5 x5oooAt 120degF gp5000 - 0434 (07117)e
= 0326 psift P ~ P ~ t ln (1 + fp gD)D S D
At 70degF Po_ p = ~__]-____ ln (l + Q80 x lo- 5 x 0332 x 10000) s 080 x 10-~
= 3277 psi I P5 ~ 5000 - 3277 = 1723 psi
At l20degF PD - PS = l 5 ln (l + l l x 10-5 x 0326 x 10000) llOxlOshy
= 3203 psi
PS = 5000 - 3202 = 1797 psi
shybull
Thus if the surface pressure P5 were set at 1760 psi the presshy
sure at the sea ~ottom transducer would be 5000 + 37 psi even if the I shy
temperature cf the 60deg API gravity oil varied between 70deg and 120degF
From these pxample calculations for a 10000 ft completion it is
apparent that temperature variations cause r~latively small errors in I
sea floor ca 1 i bration pressures even for sue~ a great depth If the
pressures are needed more acet1rately than this then the temperature
profile in the tubing would be needed
It has thus been shown that relatively simple calculations of
liquid hydrostatic head result in accurate pressure values for calishy
bration of subsea transducers I
The calibration of gas pressure transdutersmiddot is somewhat different
For low pressures and shallow depth little correction need be made to
the pressure measured at the surface For a gas specific gravity SG
(relative to ai~ at 20degC and 147 psia) pressure P(psia) and depth I
D(ft) the pressure correction AP is given by
-5AP = 356 x 10 x SG x P x D
This equation assumes that the ideal gas law holds and that tPP
is small The equation nay be modified to include the super-compresshy
sibility factor z as follows 0
AP= 356 x 10-Sx SG x D x Pz
For a 1000 ft deep subsea completion line pressure of 1000 psia
(assuming SG ~ 1 and z = 1) AF= 36 psi It is thus apparent that even with large errors in specific gravity and z the pressure correction
1
for hydrostatic head of the gqs is small for depths up to 1000 ft
-bull
Again for a line pressure of 1000 psi but a 10000 ft deep comshy
pletion llP = 3~0 psi so the assumption of PP being small no longer
holds An integration would thus be needed to determine the transducer
pressure and t~e vaHable z factor should be included in thi~ integral Thus a closed form solution similar to tha~ found for liquids cannot
be obtained an~ numerical integration is necessary However for a wide range of conditions the equations pre~ented for both liquids and
I II gases a11 ow acc4ra te cal i bratfon of sea bottom pressure transducers
through the production tubing~ I
I
- -
6 J_nspection_B$9YJrcment_~and Te~t Proc~dures j
The OCS Ord~rs ~ere reviewed for those item~ pertinent to a subsea system The OCS inspection requirements and the suggested general
inspection procedures for these items are discussed in the following
paragraphs Tubing PLtg_
I
Inspection Requirements (OCS Order No 5)I
1 T~e s~~tained liquid leakage flow should not exceed I
400 ccmin 2 The ga~ leakage flo~1 should nGt e)ceed 15 cu ftmin
General Pro~middotedure
The first step i~ this procedure is to isolate a column of fluid
between the tubing plug and the inspector with the valves opened as
for production except that the tubing plug is in pl ace Any fl ow reaching the inspector at the surface is a direct indication of leakage past the tubing plug Thermal equilibrium may b~ required if the
maximum allowabl~ leakage is too small Theflow volume can be measured at the surface in the same manner as for conventionlt1 platform systems
I
middotShut-in Tubi9_ls_e_sur~
Inspection Requirements (OCS Order No I
5)
1 Wells with a shut-in tubing ptessure of 4000 psig or
greater sha11 be equj pped with a subsurface-~ontro11 ed subsurface safety device
-J
2 When the shut-in tubing pressure declines below 4000 I
psig a remotely sontrolled subsurface safety device shall be installed
when the tubing is first removed and reinstalled
General Procedure
To determine if the shut-i~ tubing pressure i~ greater than 4000 psig I
a pressure sensor should be located ~1here the shut-in pressure can be sensed
A convenient arrangement is to locate a pressure s~nsor between the master
valve and wing valve on each tubing With the downhole safety valve and
master valve opened and the wing valve close~ the shmicrot-in tubing pressure
as indicated by the sensor is noted
Calibration of the pressure sensor can be accomplished by applying
a known pressure ~t the surface to a closed cdlumn of fluid connecting I
the surface with the sensor with corrections calculated as explained
in Section 5
Subsurface Safety Device
Inspection Requirements (OCS Order No 5) 1 A surface-controlled subsurface safety device shall be
test operated every six months
2 A subsurface-controlled subsurface safety device shall
be removed inspected and repaired every 12 mdnths 1
General Procedure To test a surface-controlled subsurface safety device the well
should be opened for production and the command then given to close
the subsurface Sifety device The leakage flqw volume if any is
measured at the surface in the same manner as for conventional plat shy
form sys terns bull
1
-)
Pressure Relief Valves Inspection Requtrements (0CS Order No 8)
All pressure reli-f valve~ shall be either bench tested for opershy
ation or tested with an external pressure source (if the valve is somiddot
equipped)annually Jtbt Wf SJJS~+ General Procedure
To test a pressure relief valve for operation the vessel or line
should be pressunizeq to the pressure necessary to open the valve by
using the method suggested in Section 5 Uriless remote position inshy
dicators are provided a means to determine ~hether or not the valve
has actually ope1ed would have to be devised bullfor each subsea system
by observing the effect on the pressure sensors Pressure Sensors
Inspection Requirements (OCS Order No 8)
All pressure sensors shall be tested at least once each month
General Procedure
To remotely test and cal i~rate a subsea bullpressure sensor it is
necessary to
(1) isolate a closed column of fluid irom the surface to
the subsea sensor by properly arranging the ~ys terns va1ves
(2) determine the specific gravity compressibility and the
column height of the fluid
(3) select the pressure required at the subsea sensor
(4) apply the appropriate pressure at the surface end of
the column and
(5) compare the telemetered press4re signal or indication
with the pressur~ applied to the sensor
Automatic Hellhead Safety Devices -~~__--r---
Inspection 8equiremcnts (OCS Order No 8) All automatic wellhead safety devices shall be tested for operation
I
and holding pres~ureonce each1month
I
- -
bull )
General Prooedure
To test the operation of the automatic well head safety devices
the out-of-the-tolerance condition (usually ~igh or low pressure) which actuates the devices should be simulated Urless position 1ndicators
I
are provided a means to deterrl1ine whether 011 not the valves have
actually closed ~ust be devised for each indi1vidu~l system because of
the peculiarities
in each syste m J I
L~ 6 - Jlaquo4 sfSf~ rCheck Valves ~J0141d 11tJt NC Uf~ l(I -v-
Inspection Requirements (OCS Order No ~)
A11 check valves on a11 fl ow 1i nes sha11 be tested for opera ti on
and holding pressure once each month
General Procedures
To test the check valve ft will have to be back pressured The
check valve fails to operate properly if any back flo~1 through the I
valve occurs
~iguid Level Shut-in Controls I
Inspection Requirements (9cs Order No 8)
All liquid-l 1
evel shut-in controls shall be tested once each month
by raising or lowering liquid level across the leyel-control detector
General Pro~edure I
The preferable way to test the liquid-level sh~t-in controls is to
simulate the out-of-tolerance conditions (1 iquid Jevel either low or I
high) at the sensor This sim~lation should cau~e either the inlet
shutoff va1ve to close or the discharge shutoff valve to close In
this manner both the control YStem and the automatif valves are tested I
A means will have to be devised for each subsea system to determine I
if the out-of-tolerance condition actually occurred at the sensor if
it was properly Jetected and i~ it caused thd proper actuation I
Vessel Automatic~Inlet-Shutoff Valves I
Inspection ~equirement (OCS Order No 8)I
-I I
bull ) ~ J) All automatic~~~~~-shutoff valves actuated by vessel~~
I
~fsensorj shalil be tested for operation onle each month General Procedure
Described above under gene~al procedure for Liquid-Level Shut-
In Controls Vessel AutomaJi c-Di sc_b~_g_e-Sh_ll__Dff__Y_ii_l ves
Inspection RequireiT1ent (OCS Order No 8) All automatic-discharge-shutoff valves actuated by vessel lowshy
level sensors shall be tested for operation qnce each month
General Proc~dure
Described above under Liquid-Level Shut-tn Controls
High-tempera_ure Coniprc2_()r-Sh_t1tdow_ri_Co~_o1s Inspection Requirement (OCS Order No 8)i
High temperature controls which protect the compressor against
abnormal pressure~ soltiY by such temperature
safety devices shall be tested annually
General Procedure Because of the danger involved in elevating the temperature suffi shy
ciently to cause + temperature device to actuate it is recommended that each temperature device be pre-tested and replaced each year rather than be tested remotely
Oil Spil 1 Detection E_g_t_pmen~
Inspection Requirements (OCS Order 7) All platforms and structures are require~ to have curbs gutters
and spill pans connected to a tank or sump fhis equipment is required to collect all hydrocarbon spillage on the platform It is recommended that this requirement be extencjed to require all unenclosed subsea
equipment to be covered by inverted spill pans with hydrocarbon sensors
and sumps to rem~ve spillage
General Procedure To test the hydrocarbon spi 11 age detection and removal system
a controlled spill should be made in each ar~a or section of spill
- bull
pans while th~ SUljlPI
pumps are monitored for proper operation This I I
metbod will require a signal to the surface to indicate directly when the pumps are running or indirectly by indicating a pressure rise in
I i
the affected pipeline due to the pun1ping action The indirect method is preferablebec~use the pressure rise not only indicates the pumps are running b~t indicates they also are pumpi~g fluid One additional safeguard should ~e employed A TV camera should be used to observe
I
the spill pans in the vicinity of the spill to assure that they are not leaking due to damage or inadequacy of de~ign Hydrocarbon S~nsors
IInspection Requirements
Hydrocarbon sensors are not covered in tbe OCS Qrders presently
in effect General Procedure The general test procedure for the oil-spill-detection equipment
above will test the hydrocarbon sensors for operation In addition
I bull some means of knowing when each separate hydrocarbon sensor in the
spill pan assemblies hus sensed hydrocarbon will provide additional I
protection by warning of system degradation b~fore the system is comshypletely inoperable
7 Summary and RecQ)enda tions This report deal~ with the inspection problems that have arisen
as a result of the present trend of the offshore oil industry towards
subsea completion and production of deep water petroleum reservoirs I
Inspection techniques for completion and prod~ction equipment are inshyvestigated but inspection of fiser systems submersibles and strucshy
tures are not inc~uded in the scope of this wprk
A technique ~as been detailed for calibr1ttion of subsea sensors I
and for verifying the proper OReration of va1ves The technique reshy
quires only that the inspector 1 have access to production tubing at
- bull
I I
the surface By actuating subsurface control valves from the surface
the inspector can isolate a closed fluid path1 to the point of interest I
Pressures read at the surface (when corrected for hydraulic gradients)
may then be used to ca 1 i brate subsurface tran1sducers Flow rates
measured at the surface can be used to I
indicate leakage rates bull
from
subsurface valves I
but fluid in the tubing must be allow
ed to reach
sufficient therma1l equilibriumwith its surroundings so that a false leakage rate is riot indicated due to thermal expansion of the fluid
I bull
This technique has been used to work ou~ an inspection procedure
for the Exxon Sulisea Production System The 1procedure demonstrates I I
that the necessany closed fluid paths can be obtained to permit inshyspection of all necessary points Thus from 1a theoretical point of et
j9aYYew 1 t has ~en established that accurate euroVa 1ua tion of subsea con- J
ditions can be made from the surface (io implement the procedures I
it would first be necessary to conduct an experimental program with field
tests to determi~e operational problems) tAtti e
bull
- Inspection of subsea production systems
-
-
1 Introduction
The tremendous demand for oil and gas in the United States has
dep 1 eted our oil and gas reserves to an extent which has caused concern
for many years Efforts to maintain American independence from foreign
oil suppliers albng with the rising costs of imported oil have
made possible the consideration for development of marginal or
previously unprofitable oil and gas fields in the deeper waters
of the outer cont1i nenta 1 she 1 f (OCS)
The current ~evelopment of subsea prbduction systems for
exploitation of these deep water petroleum re~erves poses new
inspection problems for the US Geological Survey (USGS)
This report presents the results of a study f~nded by USGS to
explore techniques for inspection of sea floor completion and
production equip~ent A technique requirjng reither divers nor
submersibles has been identified and its deta~lcd application for
the Exxon subsea production system (SPS) is p~esented in Appendix A
to this report The technique uses production tubing within the I
sys tern and could bullsubstantially reduce i nspect i on expense and 1
danger to i nspectors which would otherwise be encountered during
first-hand inspecticns This technique is explained in detail
in Sections 4 and 5 Section 6 contains a review of OCS orders
applicable to subs~a systems with suggest~d g~nera1 inspection
procedures Appendix B inc 1 udes the test procedure suggested to I
USGS by ShellLockheed for their subsea well control system
along with recormiendations by MDL
-
2 Types of Subsea Svstems
Various approaches are being taken to produce oi 1 from deeper
water using subsea sxstems There are three basically different
approaches to deep water production
1 The complet~ly submerged remote controlled system
Production equipment specifically designed for operation in the deep
water environment ismanifolded on a submerged template mounted on
the ocean floor Maintenance is by pump dmm tools and manned or
remote manipulatorsbull The Exxon Subsea Production System SPS)
discussed in Appendix A is of this type
2 The atmosphtiric wellhead Subsea production equipment is
located in a chamber bullmaintained at at111osphe1 ic pressure The
chamber is accessibl~ to workers from transfer capsules or
submersibles This approach alloKs the use of conventional I
completion equipmentand maintenance of thi1t equipment by personnel
in a dry one-atmosphere environment The ShellALockheed system
discussed in the App~ndix B of this type I
3 The surface-platformdeep water wellheaJ system Innovative
designs for surface iroducti on p 1 a tforms whi th aie being developed for I
use in deep water present unique structural evaluation problems
These systems are ou~side the scope of this repo~t
All these systems are being designed for de~th capability of
1000 ft and beyond but most are presently condned to 300 ft or I
less for ease of experimental testing Altlough 1all these systems I
present cha 11 eng i ng problems for inspection the Exxon SPS was chosen
for detailed investigation because 1t provided a range of inspection
problems representat1ve of subsea p1middotoduction middotsystems Sufficient I
design data 1vere available on this system to permit a thorough
evaluation of these problems
3 Inspection Techn igues and lI9~~-di t_E_~
As part of ongotng OCS lease m~nagement proQram USGS personnel
are responsible for ensuring that all offshore e~ploratory and production
operations are performed in a safe and poll11tionpreventing manner
according to pub 1 is hed OCS orders This re~pons tbil i ty is carried out
by both sch0dulrd c11q 1msched11lelt1 inspccticlaquos of all offshore oprrating
facilities In some cdses these i11specticir1s can be nade by visual
observation or by re~ding instruments while prescribed test procedures
are carried out In other cases the inspcctor must question the
lessee concerning installation of critical equipment or testing without actually observing the item in question For obvious reasons it is
preferable to make first-hand ~bservations whenever possible In I
subsea operations~ this brings up the question of the techniques and
procedures required to perform these inspections One very direct ~ - j
technique would be to employ submersible vchiCles having windows for
viewing of underwater equipment by trained inspectors Howevcr this -
method will evide~tly be very costly requiri19 not only the submersible
but also a specia1ly ~quipped ~urfoce suppo~tlaunching vessel Esti shy
mates for employi~g submersible vehicles are as high as $18 millionlf
for development of a complete system including ship submersible and I
special tools The submersible cost alone 1ould be in the area of
$1 to $2 mill ion each Thus complete independence from reliance on I I middot-middot bull - - -- 1 __ middot~
the p~oducers comes deuroarly nor() v11lid d9ampmtnf- Several of the more sophisticated subsea production systems feature
I
personnel transfer capsules At the risk of increasing dependence --~-middot---
on producers these company-operated submersible enclosures could be
used IStill another alternative is the possibility of leasjo_g StJ~- J 7 mersi~li_~ and supp_g_rlships from comrnerc~a_l or~an_izatio~_s as heli- _ 1 _
copter transport is currently obtained by USGS to discharge its present Jltj
inspection responsibilities This wo~ld tend to defray the high purshy
chase cost and al so minimize rel i ancc on producers middot- l -middot
However the safety of the inspectors performing the underw(lter
_inspecion is of pri~ary concern-W~l-1 knmm po~~ntial dan-ers g~n~r-1111e(~JJry ally related to life support structura1 integrity and surface comshy
munications exist when r~anned submersibles arp used in such operations
Accidents and human error occurring while submerged can be vastly more
serious than if they occurred in the notTial e~vironment The use of
manned submersibles would also require a regular inspection of the
submersible ard its ancillary equipment to assure safety The added
burden of such a program if undertaken is self-evident
lfunpublished correspondence Dr J D Stochiw NUC to J Meek HDL 23 Jan 1976
-Another alternative is the use of an unmanned submersible The J ~ 1
i 1t~ use of unmanned reniote controlled underwater vehicles 1~ith television -middot
I -- - IL
and manipulators would eliminate personnel danger Hov1ever extra costs and possible technical limitations make a third alternative deshy
sirable if feasi 1
ble This alternative is tomiddot provide remote read-out 71 1shy1 bullbull -- ____ - ___~ lt l
1so that inspectors may perform the inspections from aboard the pro- -~r l middot
duction-supp_ort vess9ls or deep-water platforms already in use by the middot i
lessees The alter~ative would require that t_echniques be used to -~
sense the item i1
n question at the subsea v1el1head or production equ1 shyI J I
ment and transmi~t this critical information to the surface This I
sensing may req~ire fnstallation of pgsition pressure and thermal I ) t
transducers in ~lv_gs pipes pumps etc located in the subsea enshy1 I -~middot-middotmiddotmiddotmiddot--- ---shy
vi ronment Tele111etering the information to the surface could involve
ultrasonic hydrltaulic electric-wire or other transmission techniquesI
The information 1di sp 1ays could in lcude vi sual gages or meters and comshy
Iputer controlled cathode-ray tubes (CRTs)
The consid~rations discussed above place inspection techniques
and procedures 1ln three categories ie those performed by manned
submersibles by unmanned submersible and by remote controldisplay lrf Ultimately it liould appear that emphasis should be placed on sensors
1 _on the subsea s11ste111 with data display or readout at the surface-- ---
vessel or platfdrm Increased use of sensors however will require 10
the development of methods for their calibration A method for cali shy
brating pressure transducers and determining existence and magnitude of
leakage through closed valves is presented in the next secion of this
report This approach v1ould eliminate the need for very costly submersible
bull
vehicles and th~ support ships required for I
them as well as avoid a -fJ possible so4rce
1
of risk to USGS inspectors --- I I
4 Calibration and Jn~fiectiq~hni_~
Production or service tubing that is accessible at the surface
can be used formiddot calibration of pressure sensors and determining valve
leakage if a tu~ing path to the component tq be monitored can be isoshy
lated by remotely actuated va1ves If a closed volume of fluid can
be obtained in this way net leakage into or out of the volume can
be determined by a pressure rise or drop respectively which is meashy
sured at the surface If leakage occurs the magnitude of the leak
can be determined by measuring the flow rate required to hold the I
surface pressure constant while bleeding fluid from or pumping fluid
into the tubing(assuming the fluid in the tubing is in thermal equilishy brium with the surroundings) If there is no leakage or if the leakage
is very small the process may be used to calibrate subsurface presshy
sure transducers Surface readings of pressure in the closed volume
can be used to calibrate the remote read out of subsurface transducers I
monitoring the pressure in the volume if th~ surface readings are comshy
pensated for the hydraulic gradient in the enclosed fluid This com-middot
pensation and a~sociated errors are discuss~d in the following section
This technique for calibration and inspection of subsea transducers I
and valving requires only that the inspector have access to the pipe- middot
lines that connect the subsea system to its middotsurface production and I
distribution systems Closed volumes are oqtained in these pipelines
by appropriately setting (turning on or off) various valves in the
pipeline and subsea systems Appendix A of this report applies this
technique to the Exxon SPS and shows that the necessary closed volumes
can be obtained for this system to permit inspection of all necessary
points
I
- - ~e~ Df1 J 11 ~ 5 Pressure Transducer Ca1i brati on l)t a() fh IS
If a pressure transducer at the bottom o~ a long column of fluid
(liquid or gas) is to be calibrated by applying pressure at the topI
then the pressure 1read at the top must be cor~ected for the fluid
pressure gradient in the column to obtain a correct value for presshy sure at the transducer If themiddot transducer depth bene~th the surface
is le_ss than about I
1000 ft and the calibrating fluid is a liquid
then a constant liquid density may be assumed with Jess than one pershy cent errQJ The Bressmicrore correction is then given by Pgh where P is lt--middot -- the fluid densityi g t~e acce)eration of gravity and h is the height
of the fluid colu~n ~n terms of specific gravity (relative to water) I
SpGr the pressure c~rrection (in psi) is 0~434 ~ SpGr x h
For greater accurhcy or for greater transducer depths the cornshy
pressibility of the fluid must be considered I
Figure 1 is taken from
API STD 1101 (Man4al of Petroleum Measurement bullStandards Chapter 5
Section 2) and presents the compressibility o~ hydrocarbons as percent
change in volume 9r density per 1000 psi pressure change for a range
of API gravities and temperatures Dividing ~he compressibility pershy
centage obtained from figure 1 by 100000 results in a factor F such
that
d P = FdP p
where dp is the c~ange in density associated vlith a change in pressure
dP In psi
middot l middot11 _I ] ii J l ff - middot1middot -middot
lmiddotshyltl
ltfl lbullJ JJ n 0 w 0
Dr~1 r-----~d ir f ~cmiddotmiddotmiddot t- E 1 1 0~-~0n f r AC-lgt Ilei nd C L C_fJJ middotcmiddotr -cmiddotibili~v of Liquid Ii-C-xmiddotirlmiddot~-1~ lbullo= AJ 5 I1middotJ ~7middot~i 1~iJ
~t-tbulln Con1r1middot~)11a11~ of Jiqr1d fl1r bullr11lon_~0middot1H1almmmiddotb~~____
r_c 1
~ -t c~ Ibull_~- 4-r r sngt llI
Integrating both sides results in
= F(P-Ps1
p = eF(P-P~)or PS ( 1 )
where the subscript s indicates surface cdnditions Equation (1)
relates the density 2t any depth in the fluid column to the pressure at that point
For a small change in fluid depth dP =pgdh (2)
where dh is the change in depth Substituting eq~ation (1) into (2)
dP =p geF(P-Ps)dh s
-F(P-P ) or p gdh= e s dP s
Integrating from the surface to a total depth D
-F(P-P ) -F(P -P )1 s e D s + 1= - e = shyf fI
-Rearranging we have
or I
It is interesting to note that gp 5D is the pressure head expected for an incompressible fluid If FgrsDlaquo l (that is the fluid is nearly incompressible) then equation 3 simplifies to
Po-Ps = gPsD
(note lnl+x) ~ x for x laquo 1)
For an example of the type of error that might occur if compressibility
is not considered assume gp 5D = 4000 psi (as it would for an ~gproxi mately 10000 ft deep subsea completion) and that F = 2 x 10 psi Thus
4Po-Ps = -5 x 10 ln(l-008) = 4170 psi
If compressibility had been ignored the pre~sure error would have been 170 psi This analysis has assumed that temperature is constant with depth and that the compressibility of hydrocarbon liquids does not depend on pressure The APl STD 1101 values for compressibility were based on data from zero to 1000 psig
so more data may be reshyquired to assure pressure independence
For cases in which the subsea conditions have been specified (for example setting a downhole pressure for cal~bration of a transducer) the surface presure P required to establish the condition is unknown s Thus the surface density re qui red to solve equation 3 is also unknown A derivation similar to the above shows that the hydrostatic pressure
--difference in terms of subsea conditions is
P0-Ps = ~ ln 0 + fp 0gD) (4)
The density of the oil is most usually known at atmospheric pressure
so the density at pressure P0is found from the atm~spheric density p 0
from equation 1
P0 0 FP = r e D (5)
The use of the above equation assumes a constant temperature so that density varfotions in the tubing are caused only by pressure The
density at atmosp~eric pressure and the desired temperature are found by using table 23 API STD 2540 (ASTM-IP Petroleum Measurement
Tables) to correct the standard density measured at 60degF relative to I
water at 60degF (Sp Gr 6060degF) Specific gravity may be found from
API gravity by usi 1
ng Tible 3 from API STD 2540 or from the equationI I
Sp Gr 6060~F = 1415(APl Gravity at 60degF + 1315)
In the follo~ing paragraphs several examples will be worked to I
demonstrate the uSJe of the equations and to show t~e effect of a
temperature gradi~nt in the oil from the ocean floor to the surface I
The example will i 1nclude two different oils 20deg and 60deg API 6060degF)
at two temperatur~s (70degF and 120degF) and two completion depths
(l000 ft and 101 000 ft) The equations wil1 be solved for surface
pressure assuming a sea bottom transducer is being calibrated at l000 psi
for the 1000 ft 1deep completion and at 5000
psi for the 10000 ft
deep completion The 1000 ft- depth was chosen because H represents I
present capa bi 1 i ties for subsea completion l Q 000 ft las chosen as a maximum depth fqr completions in the foreseeable future (in
areas such as the ~leutian Basin)
i I __ _l__
-Example 1
1000 ft completion -- = 1000 psiP0 20deg API 6060~F -- Sp Gr = 09340
Temp From Fig 1 From Table 23 (API STD 2540) I
70degF F = 039 x 10-5 ps1middot-T Sp Gr = 09305 -5 -1 J
120degF F = 050 x 10 psi Sp Gr bull 09130 At 1000 psi gpl~OO = gp x lOOO = 0434 x (=~middot Gr )0 x lOOO
0
At 70F gplOOO =0434 (09305) e039 x cO x 1000 1 bull
=0405 p~~
-5 0 ( ) eo 50 x 10 x 1000
At 120 F gplOOO ~ 0434 09130
o0398 poundft 1Po - PS =-F- ln (1 + F~D gD)
At 70degFmiddot P P - l ln (1 + 039 x 10-5 x 0405 x 1000) D - S - 039 x 10-S
= 405 psi Ps = lopo - 405 = 595 psi
At 120degF Po - p = l ln (l + ~50 x 10-5 x 0398 x 1000) s 050 x 10-5
= 398 psi P~ = 1000 - 398 = 60 psi
Thus if the $urface pressure P5 were setat 599 psi the pressure
at the sea bottom transducer 1~ould be 1000 4 psi even if the temperature
of the 20deg API gravity oil varied between 70 and 120degF
bull
Example 2 I
1000 ft completion -- P~ = 1000 psi I
I
60deg API 6060deg F -- Sp Gri = 0 7389 From Pi_g__j_ From Table 23 (API STD 25401
70degF F = 0~80 x 10-5 psi-1 Sp Gr bull 07344 -5 -1
120degF F = l10 x 10 psi Sp Gr bull 07117 At 1000 psi pg middot = gp eF x 1000 = 0434middotx (Sp Gr) eF x 1000
1000 o middot o i 080 ~ 10~5 x 1000
At 70degF 9P]OOO bull 0434 (07344) e bull 0321 psift I
1 i o x i o~s x 1 oooAt 120degF gP1000 bull 0434 (07117)e
I = 03]2 psift
PD - Ps = F1 1 n (1 + F PD9 D)
1At 70degF PD
I
- Ps = _ ln (1 +1080 x io-5 x 0321 x 1000)5
080 x 10 = 321 psi
PS bull 679 psi
At 120degF P~ --1----~5 ln (1 + 1 1lO x 10-5 x 0312 x 1000) 110 x 10
= 311 psi Ps = 689 psi
Thus if the surtace pressure P5 were set atmiddot684psi the pressure at the sea bottom transducer would be 1000 plusmn_ 5 psi ~ven if the temperature of the 60deg API gravity oil varied between 70deg and 120degF
bull
I
From the foregoing examples it is apparrnt that for subsea compleshytions up to 1000 ft there is little effect on the calculated
I
pressure at a suhsea transducer due to compressibility and temperature bull
The pressure ca~ be accurately calculated from ~ I bullr
PD - PS = 0434 x Sp Gr x D where the specific gravity of the oil at sta~dard conditions has been corrected to the observed temperature (using an average between the subsea and surface oil temperatures) and 1 i ne pressure Example 3
10000 ft c~mpletion -- P0 = 5000 psi 20deg API 6060degF Sp Gr = 09340
From Fi9 l From Teble 23 (API STD 2540)
70deg F = 039 x l0-5psi-l Sp Gr = 09305 120deg F = 050 x l0-5psi-l Sp Gr = 09130
F x 5000 F x 5000At 5000 psi gp5poo = gp e = 0434 x
I
(=~middotGr ) e0 0
At 70F 9P5poo = 0434 (09305)e039 x 10 x 5000
= 0412 psift I
50 x 5000At 120F 9P~ooo = 0434 (09130)e0middot x 10 -5
= 0406 psift 1
PD - PS= -F- ln (l + Fp gD)0 __L__-=s 1nAt 70degF P ~ (l + 0~39 x 10-5 x 0412 x 10000
D I
P5 039 x 10 = 4087 psi ~ 5000 - 4087 = 913 psir5
At l20F P - P =--1-- ln (l + 050 x 10-5 x 0406 x 10000) D S 050 x l0- 5
- -p~ = 4019 psi P = 981 psi ~
I
Thus if the 1surface pressure r5 were set at 947 the pressure at the
sea bottom trans~ucer would be 5000 +- 34 psi even if the temperature of
the 20degAPI gravity oil varied between 70deg and l20degF
Example 4
I 110000 ft ~omp etion P f 5000 psi0
60deg API 6060degF Sp Gr = 07389 Temp
70degF
l 20degF
From Fig l I ~ -5 -1
F = Oi80 x 10 psi I middot -5 -1F = 110 x 10 psmiddotiI
From Table 23 (API----middotmiddot Sp Gr = 07344
Sp Gr= 07117
STD 2540)
middot F x 5000 F x 5000At 5000 ps1 1 gp 5000 = gp = 0~34 x (Sp Gr)e e0 0
80At 70degF gp middot = 0434 (o 7344)e0middot x 10-5 x 5000
~ooo = o332 psift
_ llxl0_ 5 x5oooAt 120degF gp5000 - 0434 (07117)e
= 0326 psift P ~ P ~ t ln (1 + fp gD)D S D
At 70degF Po_ p = ~__]-____ ln (l + Q80 x lo- 5 x 0332 x 10000) s 080 x 10-~
= 3277 psi I P5 ~ 5000 - 3277 = 1723 psi
At l20degF PD - PS = l 5 ln (l + l l x 10-5 x 0326 x 10000) llOxlOshy
= 3203 psi
PS = 5000 - 3202 = 1797 psi
shybull
Thus if the surface pressure P5 were set at 1760 psi the presshy
sure at the sea ~ottom transducer would be 5000 + 37 psi even if the I shy
temperature cf the 60deg API gravity oil varied between 70deg and 120degF
From these pxample calculations for a 10000 ft completion it is
apparent that temperature variations cause r~latively small errors in I
sea floor ca 1 i bration pressures even for sue~ a great depth If the
pressures are needed more acet1rately than this then the temperature
profile in the tubing would be needed
It has thus been shown that relatively simple calculations of
liquid hydrostatic head result in accurate pressure values for calishy
bration of subsea transducers I
The calibration of gas pressure transdutersmiddot is somewhat different
For low pressures and shallow depth little correction need be made to
the pressure measured at the surface For a gas specific gravity SG
(relative to ai~ at 20degC and 147 psia) pressure P(psia) and depth I
D(ft) the pressure correction AP is given by
-5AP = 356 x 10 x SG x P x D
This equation assumes that the ideal gas law holds and that tPP
is small The equation nay be modified to include the super-compresshy
sibility factor z as follows 0
AP= 356 x 10-Sx SG x D x Pz
For a 1000 ft deep subsea completion line pressure of 1000 psia
(assuming SG ~ 1 and z = 1) AF= 36 psi It is thus apparent that even with large errors in specific gravity and z the pressure correction
1
for hydrostatic head of the gqs is small for depths up to 1000 ft
-bull
Again for a line pressure of 1000 psi but a 10000 ft deep comshy
pletion llP = 3~0 psi so the assumption of PP being small no longer
holds An integration would thus be needed to determine the transducer
pressure and t~e vaHable z factor should be included in thi~ integral Thus a closed form solution similar to tha~ found for liquids cannot
be obtained an~ numerical integration is necessary However for a wide range of conditions the equations pre~ented for both liquids and
I II gases a11 ow acc4ra te cal i bratfon of sea bottom pressure transducers
through the production tubing~ I
I
- -
6 J_nspection_B$9YJrcment_~and Te~t Proc~dures j
The OCS Ord~rs ~ere reviewed for those item~ pertinent to a subsea system The OCS inspection requirements and the suggested general
inspection procedures for these items are discussed in the following
paragraphs Tubing PLtg_
I
Inspection Requirements (OCS Order No 5)I
1 T~e s~~tained liquid leakage flow should not exceed I
400 ccmin 2 The ga~ leakage flo~1 should nGt e)ceed 15 cu ftmin
General Pro~middotedure
The first step i~ this procedure is to isolate a column of fluid
between the tubing plug and the inspector with the valves opened as
for production except that the tubing plug is in pl ace Any fl ow reaching the inspector at the surface is a direct indication of leakage past the tubing plug Thermal equilibrium may b~ required if the
maximum allowabl~ leakage is too small Theflow volume can be measured at the surface in the same manner as for conventionlt1 platform systems
I
middotShut-in Tubi9_ls_e_sur~
Inspection Requirements (OCS Order No I
5)
1 Wells with a shut-in tubing ptessure of 4000 psig or
greater sha11 be equj pped with a subsurface-~ontro11 ed subsurface safety device
-J
2 When the shut-in tubing pressure declines below 4000 I
psig a remotely sontrolled subsurface safety device shall be installed
when the tubing is first removed and reinstalled
General Procedure
To determine if the shut-i~ tubing pressure i~ greater than 4000 psig I
a pressure sensor should be located ~1here the shut-in pressure can be sensed
A convenient arrangement is to locate a pressure s~nsor between the master
valve and wing valve on each tubing With the downhole safety valve and
master valve opened and the wing valve close~ the shmicrot-in tubing pressure
as indicated by the sensor is noted
Calibration of the pressure sensor can be accomplished by applying
a known pressure ~t the surface to a closed cdlumn of fluid connecting I
the surface with the sensor with corrections calculated as explained
in Section 5
Subsurface Safety Device
Inspection Requirements (OCS Order No 5) 1 A surface-controlled subsurface safety device shall be
test operated every six months
2 A subsurface-controlled subsurface safety device shall
be removed inspected and repaired every 12 mdnths 1
General Procedure To test a surface-controlled subsurface safety device the well
should be opened for production and the command then given to close
the subsurface Sifety device The leakage flqw volume if any is
measured at the surface in the same manner as for conventional plat shy
form sys terns bull
1
-)
Pressure Relief Valves Inspection Requtrements (0CS Order No 8)
All pressure reli-f valve~ shall be either bench tested for opershy
ation or tested with an external pressure source (if the valve is somiddot
equipped)annually Jtbt Wf SJJS~+ General Procedure
To test a pressure relief valve for operation the vessel or line
should be pressunizeq to the pressure necessary to open the valve by
using the method suggested in Section 5 Uriless remote position inshy
dicators are provided a means to determine ~hether or not the valve
has actually ope1ed would have to be devised bullfor each subsea system
by observing the effect on the pressure sensors Pressure Sensors
Inspection Requirements (OCS Order No 8)
All pressure sensors shall be tested at least once each month
General Procedure
To remotely test and cal i~rate a subsea bullpressure sensor it is
necessary to
(1) isolate a closed column of fluid irom the surface to
the subsea sensor by properly arranging the ~ys terns va1ves
(2) determine the specific gravity compressibility and the
column height of the fluid
(3) select the pressure required at the subsea sensor
(4) apply the appropriate pressure at the surface end of
the column and
(5) compare the telemetered press4re signal or indication
with the pressur~ applied to the sensor
Automatic Hellhead Safety Devices -~~__--r---
Inspection 8equiremcnts (OCS Order No 8) All automatic wellhead safety devices shall be tested for operation
I
and holding pres~ureonce each1month
I
- -
bull )
General Prooedure
To test the operation of the automatic well head safety devices
the out-of-the-tolerance condition (usually ~igh or low pressure) which actuates the devices should be simulated Urless position 1ndicators
I
are provided a means to deterrl1ine whether 011 not the valves have
actually closed ~ust be devised for each indi1vidu~l system because of
the peculiarities
in each syste m J I
L~ 6 - Jlaquo4 sfSf~ rCheck Valves ~J0141d 11tJt NC Uf~ l(I -v-
Inspection Requirements (OCS Order No ~)
A11 check valves on a11 fl ow 1i nes sha11 be tested for opera ti on
and holding pressure once each month
General Procedures
To test the check valve ft will have to be back pressured The
check valve fails to operate properly if any back flo~1 through the I
valve occurs
~iguid Level Shut-in Controls I
Inspection Requirements (9cs Order No 8)
All liquid-l 1
evel shut-in controls shall be tested once each month
by raising or lowering liquid level across the leyel-control detector
General Pro~edure I
The preferable way to test the liquid-level sh~t-in controls is to
simulate the out-of-tolerance conditions (1 iquid Jevel either low or I
high) at the sensor This sim~lation should cau~e either the inlet
shutoff va1ve to close or the discharge shutoff valve to close In
this manner both the control YStem and the automatif valves are tested I
A means will have to be devised for each subsea system to determine I
if the out-of-tolerance condition actually occurred at the sensor if
it was properly Jetected and i~ it caused thd proper actuation I
Vessel Automatic~Inlet-Shutoff Valves I
Inspection ~equirement (OCS Order No 8)I
-I I
bull ) ~ J) All automatic~~~~~-shutoff valves actuated by vessel~~
I
~fsensorj shalil be tested for operation onle each month General Procedure
Described above under gene~al procedure for Liquid-Level Shut-
In Controls Vessel AutomaJi c-Di sc_b~_g_e-Sh_ll__Dff__Y_ii_l ves
Inspection RequireiT1ent (OCS Order No 8) All automatic-discharge-shutoff valves actuated by vessel lowshy
level sensors shall be tested for operation qnce each month
General Proc~dure
Described above under Liquid-Level Shut-tn Controls
High-tempera_ure Coniprc2_()r-Sh_t1tdow_ri_Co~_o1s Inspection Requirement (OCS Order No 8)i
High temperature controls which protect the compressor against
abnormal pressure~ soltiY by such temperature
safety devices shall be tested annually
General Procedure Because of the danger involved in elevating the temperature suffi shy
ciently to cause + temperature device to actuate it is recommended that each temperature device be pre-tested and replaced each year rather than be tested remotely
Oil Spil 1 Detection E_g_t_pmen~
Inspection Requirements (OCS Order 7) All platforms and structures are require~ to have curbs gutters
and spill pans connected to a tank or sump fhis equipment is required to collect all hydrocarbon spillage on the platform It is recommended that this requirement be extencjed to require all unenclosed subsea
equipment to be covered by inverted spill pans with hydrocarbon sensors
and sumps to rem~ve spillage
General Procedure To test the hydrocarbon spi 11 age detection and removal system
a controlled spill should be made in each ar~a or section of spill
- bull
pans while th~ SUljlPI
pumps are monitored for proper operation This I I
metbod will require a signal to the surface to indicate directly when the pumps are running or indirectly by indicating a pressure rise in
I i
the affected pipeline due to the pun1ping action The indirect method is preferablebec~use the pressure rise not only indicates the pumps are running b~t indicates they also are pumpi~g fluid One additional safeguard should ~e employed A TV camera should be used to observe
I
the spill pans in the vicinity of the spill to assure that they are not leaking due to damage or inadequacy of de~ign Hydrocarbon S~nsors
IInspection Requirements
Hydrocarbon sensors are not covered in tbe OCS Qrders presently
in effect General Procedure The general test procedure for the oil-spill-detection equipment
above will test the hydrocarbon sensors for operation In addition
I bull some means of knowing when each separate hydrocarbon sensor in the
spill pan assemblies hus sensed hydrocarbon will provide additional I
protection by warning of system degradation b~fore the system is comshypletely inoperable
7 Summary and RecQ)enda tions This report deal~ with the inspection problems that have arisen
as a result of the present trend of the offshore oil industry towards
subsea completion and production of deep water petroleum reservoirs I
Inspection techniques for completion and prod~ction equipment are inshyvestigated but inspection of fiser systems submersibles and strucshy
tures are not inc~uded in the scope of this wprk
A technique ~as been detailed for calibr1ttion of subsea sensors I
and for verifying the proper OReration of va1ves The technique reshy
quires only that the inspector 1 have access to production tubing at
- bull
I I
the surface By actuating subsurface control valves from the surface
the inspector can isolate a closed fluid path1 to the point of interest I
Pressures read at the surface (when corrected for hydraulic gradients)
may then be used to ca 1 i brate subsurface tran1sducers Flow rates
measured at the surface can be used to I
indicate leakage rates bull
from
subsurface valves I
but fluid in the tubing must be allow
ed to reach
sufficient therma1l equilibriumwith its surroundings so that a false leakage rate is riot indicated due to thermal expansion of the fluid
I bull
This technique has been used to work ou~ an inspection procedure
for the Exxon Sulisea Production System The 1procedure demonstrates I I
that the necessany closed fluid paths can be obtained to permit inshyspection of all necessary points Thus from 1a theoretical point of et
j9aYYew 1 t has ~en established that accurate euroVa 1ua tion of subsea con- J
ditions can be made from the surface (io implement the procedures I
it would first be necessary to conduct an experimental program with field
tests to determi~e operational problems) tAtti e
bull
- Inspection of subsea production systems
-
-
2 Types of Subsea Svstems
Various approaches are being taken to produce oi 1 from deeper
water using subsea sxstems There are three basically different
approaches to deep water production
1 The complet~ly submerged remote controlled system
Production equipment specifically designed for operation in the deep
water environment ismanifolded on a submerged template mounted on
the ocean floor Maintenance is by pump dmm tools and manned or
remote manipulatorsbull The Exxon Subsea Production System SPS)
discussed in Appendix A is of this type
2 The atmosphtiric wellhead Subsea production equipment is
located in a chamber bullmaintained at at111osphe1 ic pressure The
chamber is accessibl~ to workers from transfer capsules or
submersibles This approach alloKs the use of conventional I
completion equipmentand maintenance of thi1t equipment by personnel
in a dry one-atmosphere environment The ShellALockheed system
discussed in the App~ndix B of this type I
3 The surface-platformdeep water wellheaJ system Innovative
designs for surface iroducti on p 1 a tforms whi th aie being developed for I
use in deep water present unique structural evaluation problems
These systems are ou~side the scope of this repo~t
All these systems are being designed for de~th capability of
1000 ft and beyond but most are presently condned to 300 ft or I
less for ease of experimental testing Altlough 1all these systems I
present cha 11 eng i ng problems for inspection the Exxon SPS was chosen
for detailed investigation because 1t provided a range of inspection
problems representat1ve of subsea p1middotoduction middotsystems Sufficient I
design data 1vere available on this system to permit a thorough
evaluation of these problems
3 Inspection Techn igues and lI9~~-di t_E_~
As part of ongotng OCS lease m~nagement proQram USGS personnel
are responsible for ensuring that all offshore e~ploratory and production
operations are performed in a safe and poll11tionpreventing manner
according to pub 1 is hed OCS orders This re~pons tbil i ty is carried out
by both sch0dulrd c11q 1msched11lelt1 inspccticlaquos of all offshore oprrating
facilities In some cdses these i11specticir1s can be nade by visual
observation or by re~ding instruments while prescribed test procedures
are carried out In other cases the inspcctor must question the
lessee concerning installation of critical equipment or testing without actually observing the item in question For obvious reasons it is
preferable to make first-hand ~bservations whenever possible In I
subsea operations~ this brings up the question of the techniques and
procedures required to perform these inspections One very direct ~ - j
technique would be to employ submersible vchiCles having windows for
viewing of underwater equipment by trained inspectors Howevcr this -
method will evide~tly be very costly requiri19 not only the submersible
but also a specia1ly ~quipped ~urfoce suppo~tlaunching vessel Esti shy
mates for employi~g submersible vehicles are as high as $18 millionlf
for development of a complete system including ship submersible and I
special tools The submersible cost alone 1ould be in the area of
$1 to $2 mill ion each Thus complete independence from reliance on I I middot-middot bull - - -- 1 __ middot~
the p~oducers comes deuroarly nor() v11lid d9ampmtnf- Several of the more sophisticated subsea production systems feature
I
personnel transfer capsules At the risk of increasing dependence --~-middot---
on producers these company-operated submersible enclosures could be
used IStill another alternative is the possibility of leasjo_g StJ~- J 7 mersi~li_~ and supp_g_rlships from comrnerc~a_l or~an_izatio~_s as heli- _ 1 _
copter transport is currently obtained by USGS to discharge its present Jltj
inspection responsibilities This wo~ld tend to defray the high purshy
chase cost and al so minimize rel i ancc on producers middot- l -middot
However the safety of the inspectors performing the underw(lter
_inspecion is of pri~ary concern-W~l-1 knmm po~~ntial dan-ers g~n~r-1111e(~JJry ally related to life support structura1 integrity and surface comshy
munications exist when r~anned submersibles arp used in such operations
Accidents and human error occurring while submerged can be vastly more
serious than if they occurred in the notTial e~vironment The use of
manned submersibles would also require a regular inspection of the
submersible ard its ancillary equipment to assure safety The added
burden of such a program if undertaken is self-evident
lfunpublished correspondence Dr J D Stochiw NUC to J Meek HDL 23 Jan 1976
-Another alternative is the use of an unmanned submersible The J ~ 1
i 1t~ use of unmanned reniote controlled underwater vehicles 1~ith television -middot
I -- - IL
and manipulators would eliminate personnel danger Hov1ever extra costs and possible technical limitations make a third alternative deshy
sirable if feasi 1
ble This alternative is tomiddot provide remote read-out 71 1shy1 bullbull -- ____ - ___~ lt l
1so that inspectors may perform the inspections from aboard the pro- -~r l middot
duction-supp_ort vess9ls or deep-water platforms already in use by the middot i
lessees The alter~ative would require that t_echniques be used to -~
sense the item i1
n question at the subsea v1el1head or production equ1 shyI J I
ment and transmi~t this critical information to the surface This I
sensing may req~ire fnstallation of pgsition pressure and thermal I ) t
transducers in ~lv_gs pipes pumps etc located in the subsea enshy1 I -~middot-middotmiddotmiddotmiddot--- ---shy
vi ronment Tele111etering the information to the surface could involve
ultrasonic hydrltaulic electric-wire or other transmission techniquesI
The information 1di sp 1ays could in lcude vi sual gages or meters and comshy
Iputer controlled cathode-ray tubes (CRTs)
The consid~rations discussed above place inspection techniques
and procedures 1ln three categories ie those performed by manned
submersibles by unmanned submersible and by remote controldisplay lrf Ultimately it liould appear that emphasis should be placed on sensors
1 _on the subsea s11ste111 with data display or readout at the surface-- ---
vessel or platfdrm Increased use of sensors however will require 10
the development of methods for their calibration A method for cali shy
brating pressure transducers and determining existence and magnitude of
leakage through closed valves is presented in the next secion of this
report This approach v1ould eliminate the need for very costly submersible
bull
vehicles and th~ support ships required for I
them as well as avoid a -fJ possible so4rce
1
of risk to USGS inspectors --- I I
4 Calibration and Jn~fiectiq~hni_~
Production or service tubing that is accessible at the surface
can be used formiddot calibration of pressure sensors and determining valve
leakage if a tu~ing path to the component tq be monitored can be isoshy
lated by remotely actuated va1ves If a closed volume of fluid can
be obtained in this way net leakage into or out of the volume can
be determined by a pressure rise or drop respectively which is meashy
sured at the surface If leakage occurs the magnitude of the leak
can be determined by measuring the flow rate required to hold the I
surface pressure constant while bleeding fluid from or pumping fluid
into the tubing(assuming the fluid in the tubing is in thermal equilishy brium with the surroundings) If there is no leakage or if the leakage
is very small the process may be used to calibrate subsurface presshy
sure transducers Surface readings of pressure in the closed volume
can be used to calibrate the remote read out of subsurface transducers I
monitoring the pressure in the volume if th~ surface readings are comshy
pensated for the hydraulic gradient in the enclosed fluid This com-middot
pensation and a~sociated errors are discuss~d in the following section
This technique for calibration and inspection of subsea transducers I
and valving requires only that the inspector have access to the pipe- middot
lines that connect the subsea system to its middotsurface production and I
distribution systems Closed volumes are oqtained in these pipelines
by appropriately setting (turning on or off) various valves in the
pipeline and subsea systems Appendix A of this report applies this
technique to the Exxon SPS and shows that the necessary closed volumes
can be obtained for this system to permit inspection of all necessary
points
I
- - ~e~ Df1 J 11 ~ 5 Pressure Transducer Ca1i brati on l)t a() fh IS
If a pressure transducer at the bottom o~ a long column of fluid
(liquid or gas) is to be calibrated by applying pressure at the topI
then the pressure 1read at the top must be cor~ected for the fluid
pressure gradient in the column to obtain a correct value for presshy sure at the transducer If themiddot transducer depth bene~th the surface
is le_ss than about I
1000 ft and the calibrating fluid is a liquid
then a constant liquid density may be assumed with Jess than one pershy cent errQJ The Bressmicrore correction is then given by Pgh where P is lt--middot -- the fluid densityi g t~e acce)eration of gravity and h is the height
of the fluid colu~n ~n terms of specific gravity (relative to water) I
SpGr the pressure c~rrection (in psi) is 0~434 ~ SpGr x h
For greater accurhcy or for greater transducer depths the cornshy
pressibility of the fluid must be considered I
Figure 1 is taken from
API STD 1101 (Man4al of Petroleum Measurement bullStandards Chapter 5
Section 2) and presents the compressibility o~ hydrocarbons as percent
change in volume 9r density per 1000 psi pressure change for a range
of API gravities and temperatures Dividing ~he compressibility pershy
centage obtained from figure 1 by 100000 results in a factor F such
that
d P = FdP p
where dp is the c~ange in density associated vlith a change in pressure
dP In psi
middot l middot11 _I ] ii J l ff - middot1middot -middot
lmiddotshyltl
ltfl lbullJ JJ n 0 w 0
Dr~1 r-----~d ir f ~cmiddotmiddotmiddot t- E 1 1 0~-~0n f r AC-lgt Ilei nd C L C_fJJ middotcmiddotr -cmiddotibili~v of Liquid Ii-C-xmiddotirlmiddot~-1~ lbullo= AJ 5 I1middotJ ~7middot~i 1~iJ
~t-tbulln Con1r1middot~)11a11~ of Jiqr1d fl1r bullr11lon_~0middot1H1almmmiddotb~~____
r_c 1
~ -t c~ Ibull_~- 4-r r sngt llI
Integrating both sides results in
= F(P-Ps1
p = eF(P-P~)or PS ( 1 )
where the subscript s indicates surface cdnditions Equation (1)
relates the density 2t any depth in the fluid column to the pressure at that point
For a small change in fluid depth dP =pgdh (2)
where dh is the change in depth Substituting eq~ation (1) into (2)
dP =p geF(P-Ps)dh s
-F(P-P ) or p gdh= e s dP s
Integrating from the surface to a total depth D
-F(P-P ) -F(P -P )1 s e D s + 1= - e = shyf fI
-Rearranging we have
or I
It is interesting to note that gp 5D is the pressure head expected for an incompressible fluid If FgrsDlaquo l (that is the fluid is nearly incompressible) then equation 3 simplifies to
Po-Ps = gPsD
(note lnl+x) ~ x for x laquo 1)
For an example of the type of error that might occur if compressibility
is not considered assume gp 5D = 4000 psi (as it would for an ~gproxi mately 10000 ft deep subsea completion) and that F = 2 x 10 psi Thus
4Po-Ps = -5 x 10 ln(l-008) = 4170 psi
If compressibility had been ignored the pre~sure error would have been 170 psi This analysis has assumed that temperature is constant with depth and that the compressibility of hydrocarbon liquids does not depend on pressure The APl STD 1101 values for compressibility were based on data from zero to 1000 psig
so more data may be reshyquired to assure pressure independence
For cases in which the subsea conditions have been specified (for example setting a downhole pressure for cal~bration of a transducer) the surface presure P required to establish the condition is unknown s Thus the surface density re qui red to solve equation 3 is also unknown A derivation similar to the above shows that the hydrostatic pressure
--difference in terms of subsea conditions is
P0-Ps = ~ ln 0 + fp 0gD) (4)
The density of the oil is most usually known at atmospheric pressure
so the density at pressure P0is found from the atm~spheric density p 0
from equation 1
P0 0 FP = r e D (5)
The use of the above equation assumes a constant temperature so that density varfotions in the tubing are caused only by pressure The
density at atmosp~eric pressure and the desired temperature are found by using table 23 API STD 2540 (ASTM-IP Petroleum Measurement
Tables) to correct the standard density measured at 60degF relative to I
water at 60degF (Sp Gr 6060degF) Specific gravity may be found from
API gravity by usi 1
ng Tible 3 from API STD 2540 or from the equationI I
Sp Gr 6060~F = 1415(APl Gravity at 60degF + 1315)
In the follo~ing paragraphs several examples will be worked to I
demonstrate the uSJe of the equations and to show t~e effect of a
temperature gradi~nt in the oil from the ocean floor to the surface I
The example will i 1nclude two different oils 20deg and 60deg API 6060degF)
at two temperatur~s (70degF and 120degF) and two completion depths
(l000 ft and 101 000 ft) The equations wil1 be solved for surface
pressure assuming a sea bottom transducer is being calibrated at l000 psi
for the 1000 ft 1deep completion and at 5000
psi for the 10000 ft
deep completion The 1000 ft- depth was chosen because H represents I
present capa bi 1 i ties for subsea completion l Q 000 ft las chosen as a maximum depth fqr completions in the foreseeable future (in
areas such as the ~leutian Basin)
i I __ _l__
-Example 1
1000 ft completion -- = 1000 psiP0 20deg API 6060~F -- Sp Gr = 09340
Temp From Fig 1 From Table 23 (API STD 2540) I
70degF F = 039 x 10-5 ps1middot-T Sp Gr = 09305 -5 -1 J
120degF F = 050 x 10 psi Sp Gr bull 09130 At 1000 psi gpl~OO = gp x lOOO = 0434 x (=~middot Gr )0 x lOOO
0
At 70F gplOOO =0434 (09305) e039 x cO x 1000 1 bull
=0405 p~~
-5 0 ( ) eo 50 x 10 x 1000
At 120 F gplOOO ~ 0434 09130
o0398 poundft 1Po - PS =-F- ln (1 + F~D gD)
At 70degFmiddot P P - l ln (1 + 039 x 10-5 x 0405 x 1000) D - S - 039 x 10-S
= 405 psi Ps = lopo - 405 = 595 psi
At 120degF Po - p = l ln (l + ~50 x 10-5 x 0398 x 1000) s 050 x 10-5
= 398 psi P~ = 1000 - 398 = 60 psi
Thus if the $urface pressure P5 were setat 599 psi the pressure
at the sea bottom transducer 1~ould be 1000 4 psi even if the temperature
of the 20deg API gravity oil varied between 70 and 120degF
bull
Example 2 I
1000 ft completion -- P~ = 1000 psi I
I
60deg API 6060deg F -- Sp Gri = 0 7389 From Pi_g__j_ From Table 23 (API STD 25401
70degF F = 0~80 x 10-5 psi-1 Sp Gr bull 07344 -5 -1
120degF F = l10 x 10 psi Sp Gr bull 07117 At 1000 psi pg middot = gp eF x 1000 = 0434middotx (Sp Gr) eF x 1000
1000 o middot o i 080 ~ 10~5 x 1000
At 70degF 9P]OOO bull 0434 (07344) e bull 0321 psift I
1 i o x i o~s x 1 oooAt 120degF gP1000 bull 0434 (07117)e
I = 03]2 psift
PD - Ps = F1 1 n (1 + F PD9 D)
1At 70degF PD
I
- Ps = _ ln (1 +1080 x io-5 x 0321 x 1000)5
080 x 10 = 321 psi
PS bull 679 psi
At 120degF P~ --1----~5 ln (1 + 1 1lO x 10-5 x 0312 x 1000) 110 x 10
= 311 psi Ps = 689 psi
Thus if the surtace pressure P5 were set atmiddot684psi the pressure at the sea bottom transducer would be 1000 plusmn_ 5 psi ~ven if the temperature of the 60deg API gravity oil varied between 70deg and 120degF
bull
I
From the foregoing examples it is apparrnt that for subsea compleshytions up to 1000 ft there is little effect on the calculated
I
pressure at a suhsea transducer due to compressibility and temperature bull
The pressure ca~ be accurately calculated from ~ I bullr
PD - PS = 0434 x Sp Gr x D where the specific gravity of the oil at sta~dard conditions has been corrected to the observed temperature (using an average between the subsea and surface oil temperatures) and 1 i ne pressure Example 3
10000 ft c~mpletion -- P0 = 5000 psi 20deg API 6060degF Sp Gr = 09340
From Fi9 l From Teble 23 (API STD 2540)
70deg F = 039 x l0-5psi-l Sp Gr = 09305 120deg F = 050 x l0-5psi-l Sp Gr = 09130
F x 5000 F x 5000At 5000 psi gp5poo = gp e = 0434 x
I
(=~middotGr ) e0 0
At 70F 9P5poo = 0434 (09305)e039 x 10 x 5000
= 0412 psift I
50 x 5000At 120F 9P~ooo = 0434 (09130)e0middot x 10 -5
= 0406 psift 1
PD - PS= -F- ln (l + Fp gD)0 __L__-=s 1nAt 70degF P ~ (l + 0~39 x 10-5 x 0412 x 10000
D I
P5 039 x 10 = 4087 psi ~ 5000 - 4087 = 913 psir5
At l20F P - P =--1-- ln (l + 050 x 10-5 x 0406 x 10000) D S 050 x l0- 5
- -p~ = 4019 psi P = 981 psi ~
I
Thus if the 1surface pressure r5 were set at 947 the pressure at the
sea bottom trans~ucer would be 5000 +- 34 psi even if the temperature of
the 20degAPI gravity oil varied between 70deg and l20degF
Example 4
I 110000 ft ~omp etion P f 5000 psi0
60deg API 6060degF Sp Gr = 07389 Temp
70degF
l 20degF
From Fig l I ~ -5 -1
F = Oi80 x 10 psi I middot -5 -1F = 110 x 10 psmiddotiI
From Table 23 (API----middotmiddot Sp Gr = 07344
Sp Gr= 07117
STD 2540)
middot F x 5000 F x 5000At 5000 ps1 1 gp 5000 = gp = 0~34 x (Sp Gr)e e0 0
80At 70degF gp middot = 0434 (o 7344)e0middot x 10-5 x 5000
~ooo = o332 psift
_ llxl0_ 5 x5oooAt 120degF gp5000 - 0434 (07117)e
= 0326 psift P ~ P ~ t ln (1 + fp gD)D S D
At 70degF Po_ p = ~__]-____ ln (l + Q80 x lo- 5 x 0332 x 10000) s 080 x 10-~
= 3277 psi I P5 ~ 5000 - 3277 = 1723 psi
At l20degF PD - PS = l 5 ln (l + l l x 10-5 x 0326 x 10000) llOxlOshy
= 3203 psi
PS = 5000 - 3202 = 1797 psi
shybull
Thus if the surface pressure P5 were set at 1760 psi the presshy
sure at the sea ~ottom transducer would be 5000 + 37 psi even if the I shy
temperature cf the 60deg API gravity oil varied between 70deg and 120degF
From these pxample calculations for a 10000 ft completion it is
apparent that temperature variations cause r~latively small errors in I
sea floor ca 1 i bration pressures even for sue~ a great depth If the
pressures are needed more acet1rately than this then the temperature
profile in the tubing would be needed
It has thus been shown that relatively simple calculations of
liquid hydrostatic head result in accurate pressure values for calishy
bration of subsea transducers I
The calibration of gas pressure transdutersmiddot is somewhat different
For low pressures and shallow depth little correction need be made to
the pressure measured at the surface For a gas specific gravity SG
(relative to ai~ at 20degC and 147 psia) pressure P(psia) and depth I
D(ft) the pressure correction AP is given by
-5AP = 356 x 10 x SG x P x D
This equation assumes that the ideal gas law holds and that tPP
is small The equation nay be modified to include the super-compresshy
sibility factor z as follows 0
AP= 356 x 10-Sx SG x D x Pz
For a 1000 ft deep subsea completion line pressure of 1000 psia
(assuming SG ~ 1 and z = 1) AF= 36 psi It is thus apparent that even with large errors in specific gravity and z the pressure correction
1
for hydrostatic head of the gqs is small for depths up to 1000 ft
-bull
Again for a line pressure of 1000 psi but a 10000 ft deep comshy
pletion llP = 3~0 psi so the assumption of PP being small no longer
holds An integration would thus be needed to determine the transducer
pressure and t~e vaHable z factor should be included in thi~ integral Thus a closed form solution similar to tha~ found for liquids cannot
be obtained an~ numerical integration is necessary However for a wide range of conditions the equations pre~ented for both liquids and
I II gases a11 ow acc4ra te cal i bratfon of sea bottom pressure transducers
through the production tubing~ I
I
- -
6 J_nspection_B$9YJrcment_~and Te~t Proc~dures j
The OCS Ord~rs ~ere reviewed for those item~ pertinent to a subsea system The OCS inspection requirements and the suggested general
inspection procedures for these items are discussed in the following
paragraphs Tubing PLtg_
I
Inspection Requirements (OCS Order No 5)I
1 T~e s~~tained liquid leakage flow should not exceed I
400 ccmin 2 The ga~ leakage flo~1 should nGt e)ceed 15 cu ftmin
General Pro~middotedure
The first step i~ this procedure is to isolate a column of fluid
between the tubing plug and the inspector with the valves opened as
for production except that the tubing plug is in pl ace Any fl ow reaching the inspector at the surface is a direct indication of leakage past the tubing plug Thermal equilibrium may b~ required if the
maximum allowabl~ leakage is too small Theflow volume can be measured at the surface in the same manner as for conventionlt1 platform systems
I
middotShut-in Tubi9_ls_e_sur~
Inspection Requirements (OCS Order No I
5)
1 Wells with a shut-in tubing ptessure of 4000 psig or
greater sha11 be equj pped with a subsurface-~ontro11 ed subsurface safety device
-J
2 When the shut-in tubing pressure declines below 4000 I
psig a remotely sontrolled subsurface safety device shall be installed
when the tubing is first removed and reinstalled
General Procedure
To determine if the shut-i~ tubing pressure i~ greater than 4000 psig I
a pressure sensor should be located ~1here the shut-in pressure can be sensed
A convenient arrangement is to locate a pressure s~nsor between the master
valve and wing valve on each tubing With the downhole safety valve and
master valve opened and the wing valve close~ the shmicrot-in tubing pressure
as indicated by the sensor is noted
Calibration of the pressure sensor can be accomplished by applying
a known pressure ~t the surface to a closed cdlumn of fluid connecting I
the surface with the sensor with corrections calculated as explained
in Section 5
Subsurface Safety Device
Inspection Requirements (OCS Order No 5) 1 A surface-controlled subsurface safety device shall be
test operated every six months
2 A subsurface-controlled subsurface safety device shall
be removed inspected and repaired every 12 mdnths 1
General Procedure To test a surface-controlled subsurface safety device the well
should be opened for production and the command then given to close
the subsurface Sifety device The leakage flqw volume if any is
measured at the surface in the same manner as for conventional plat shy
form sys terns bull
1
-)
Pressure Relief Valves Inspection Requtrements (0CS Order No 8)
All pressure reli-f valve~ shall be either bench tested for opershy
ation or tested with an external pressure source (if the valve is somiddot
equipped)annually Jtbt Wf SJJS~+ General Procedure
To test a pressure relief valve for operation the vessel or line
should be pressunizeq to the pressure necessary to open the valve by
using the method suggested in Section 5 Uriless remote position inshy
dicators are provided a means to determine ~hether or not the valve
has actually ope1ed would have to be devised bullfor each subsea system
by observing the effect on the pressure sensors Pressure Sensors
Inspection Requirements (OCS Order No 8)
All pressure sensors shall be tested at least once each month
General Procedure
To remotely test and cal i~rate a subsea bullpressure sensor it is
necessary to
(1) isolate a closed column of fluid irom the surface to
the subsea sensor by properly arranging the ~ys terns va1ves
(2) determine the specific gravity compressibility and the
column height of the fluid
(3) select the pressure required at the subsea sensor
(4) apply the appropriate pressure at the surface end of
the column and
(5) compare the telemetered press4re signal or indication
with the pressur~ applied to the sensor
Automatic Hellhead Safety Devices -~~__--r---
Inspection 8equiremcnts (OCS Order No 8) All automatic wellhead safety devices shall be tested for operation
I
and holding pres~ureonce each1month
I
- -
bull )
General Prooedure
To test the operation of the automatic well head safety devices
the out-of-the-tolerance condition (usually ~igh or low pressure) which actuates the devices should be simulated Urless position 1ndicators
I
are provided a means to deterrl1ine whether 011 not the valves have
actually closed ~ust be devised for each indi1vidu~l system because of
the peculiarities
in each syste m J I
L~ 6 - Jlaquo4 sfSf~ rCheck Valves ~J0141d 11tJt NC Uf~ l(I -v-
Inspection Requirements (OCS Order No ~)
A11 check valves on a11 fl ow 1i nes sha11 be tested for opera ti on
and holding pressure once each month
General Procedures
To test the check valve ft will have to be back pressured The
check valve fails to operate properly if any back flo~1 through the I
valve occurs
~iguid Level Shut-in Controls I
Inspection Requirements (9cs Order No 8)
All liquid-l 1
evel shut-in controls shall be tested once each month
by raising or lowering liquid level across the leyel-control detector
General Pro~edure I
The preferable way to test the liquid-level sh~t-in controls is to
simulate the out-of-tolerance conditions (1 iquid Jevel either low or I
high) at the sensor This sim~lation should cau~e either the inlet
shutoff va1ve to close or the discharge shutoff valve to close In
this manner both the control YStem and the automatif valves are tested I
A means will have to be devised for each subsea system to determine I
if the out-of-tolerance condition actually occurred at the sensor if
it was properly Jetected and i~ it caused thd proper actuation I
Vessel Automatic~Inlet-Shutoff Valves I
Inspection ~equirement (OCS Order No 8)I
-I I
bull ) ~ J) All automatic~~~~~-shutoff valves actuated by vessel~~
I
~fsensorj shalil be tested for operation onle each month General Procedure
Described above under gene~al procedure for Liquid-Level Shut-
In Controls Vessel AutomaJi c-Di sc_b~_g_e-Sh_ll__Dff__Y_ii_l ves
Inspection RequireiT1ent (OCS Order No 8) All automatic-discharge-shutoff valves actuated by vessel lowshy
level sensors shall be tested for operation qnce each month
General Proc~dure
Described above under Liquid-Level Shut-tn Controls
High-tempera_ure Coniprc2_()r-Sh_t1tdow_ri_Co~_o1s Inspection Requirement (OCS Order No 8)i
High temperature controls which protect the compressor against
abnormal pressure~ soltiY by such temperature
safety devices shall be tested annually
General Procedure Because of the danger involved in elevating the temperature suffi shy
ciently to cause + temperature device to actuate it is recommended that each temperature device be pre-tested and replaced each year rather than be tested remotely
Oil Spil 1 Detection E_g_t_pmen~
Inspection Requirements (OCS Order 7) All platforms and structures are require~ to have curbs gutters
and spill pans connected to a tank or sump fhis equipment is required to collect all hydrocarbon spillage on the platform It is recommended that this requirement be extencjed to require all unenclosed subsea
equipment to be covered by inverted spill pans with hydrocarbon sensors
and sumps to rem~ve spillage
General Procedure To test the hydrocarbon spi 11 age detection and removal system
a controlled spill should be made in each ar~a or section of spill
- bull
pans while th~ SUljlPI
pumps are monitored for proper operation This I I
metbod will require a signal to the surface to indicate directly when the pumps are running or indirectly by indicating a pressure rise in
I i
the affected pipeline due to the pun1ping action The indirect method is preferablebec~use the pressure rise not only indicates the pumps are running b~t indicates they also are pumpi~g fluid One additional safeguard should ~e employed A TV camera should be used to observe
I
the spill pans in the vicinity of the spill to assure that they are not leaking due to damage or inadequacy of de~ign Hydrocarbon S~nsors
IInspection Requirements
Hydrocarbon sensors are not covered in tbe OCS Qrders presently
in effect General Procedure The general test procedure for the oil-spill-detection equipment
above will test the hydrocarbon sensors for operation In addition
I bull some means of knowing when each separate hydrocarbon sensor in the
spill pan assemblies hus sensed hydrocarbon will provide additional I
protection by warning of system degradation b~fore the system is comshypletely inoperable
7 Summary and RecQ)enda tions This report deal~ with the inspection problems that have arisen
as a result of the present trend of the offshore oil industry towards
subsea completion and production of deep water petroleum reservoirs I
Inspection techniques for completion and prod~ction equipment are inshyvestigated but inspection of fiser systems submersibles and strucshy
tures are not inc~uded in the scope of this wprk
A technique ~as been detailed for calibr1ttion of subsea sensors I
and for verifying the proper OReration of va1ves The technique reshy
quires only that the inspector 1 have access to production tubing at
- bull
I I
the surface By actuating subsurface control valves from the surface
the inspector can isolate a closed fluid path1 to the point of interest I
Pressures read at the surface (when corrected for hydraulic gradients)
may then be used to ca 1 i brate subsurface tran1sducers Flow rates
measured at the surface can be used to I
indicate leakage rates bull
from
subsurface valves I
but fluid in the tubing must be allow
ed to reach
sufficient therma1l equilibriumwith its surroundings so that a false leakage rate is riot indicated due to thermal expansion of the fluid
I bull
This technique has been used to work ou~ an inspection procedure
for the Exxon Sulisea Production System The 1procedure demonstrates I I
that the necessany closed fluid paths can be obtained to permit inshyspection of all necessary points Thus from 1a theoretical point of et
j9aYYew 1 t has ~en established that accurate euroVa 1ua tion of subsea con- J
ditions can be made from the surface (io implement the procedures I
it would first be necessary to conduct an experimental program with field
tests to determi~e operational problems) tAtti e
bull
- Inspection of subsea production systems
-
lessee concerning installation of critical equipment or testing without actually observing the item in question For obvious reasons it is
preferable to make first-hand ~bservations whenever possible In I
subsea operations~ this brings up the question of the techniques and
procedures required to perform these inspections One very direct ~ - j
technique would be to employ submersible vchiCles having windows for
viewing of underwater equipment by trained inspectors Howevcr this -
method will evide~tly be very costly requiri19 not only the submersible
but also a specia1ly ~quipped ~urfoce suppo~tlaunching vessel Esti shy
mates for employi~g submersible vehicles are as high as $18 millionlf
for development of a complete system including ship submersible and I
special tools The submersible cost alone 1ould be in the area of
$1 to $2 mill ion each Thus complete independence from reliance on I I middot-middot bull - - -- 1 __ middot~
the p~oducers comes deuroarly nor() v11lid d9ampmtnf- Several of the more sophisticated subsea production systems feature
I
personnel transfer capsules At the risk of increasing dependence --~-middot---
on producers these company-operated submersible enclosures could be
used IStill another alternative is the possibility of leasjo_g StJ~- J 7 mersi~li_~ and supp_g_rlships from comrnerc~a_l or~an_izatio~_s as heli- _ 1 _
copter transport is currently obtained by USGS to discharge its present Jltj
inspection responsibilities This wo~ld tend to defray the high purshy
chase cost and al so minimize rel i ancc on producers middot- l -middot
However the safety of the inspectors performing the underw(lter
_inspecion is of pri~ary concern-W~l-1 knmm po~~ntial dan-ers g~n~r-1111e(~JJry ally related to life support structura1 integrity and surface comshy
munications exist when r~anned submersibles arp used in such operations
Accidents and human error occurring while submerged can be vastly more
serious than if they occurred in the notTial e~vironment The use of
manned submersibles would also require a regular inspection of the
submersible ard its ancillary equipment to assure safety The added
burden of such a program if undertaken is self-evident
lfunpublished correspondence Dr J D Stochiw NUC to J Meek HDL 23 Jan 1976
-Another alternative is the use of an unmanned submersible The J ~ 1
i 1t~ use of unmanned reniote controlled underwater vehicles 1~ith television -middot
I -- - IL
and manipulators would eliminate personnel danger Hov1ever extra costs and possible technical limitations make a third alternative deshy
sirable if feasi 1
ble This alternative is tomiddot provide remote read-out 71 1shy1 bullbull -- ____ - ___~ lt l
1so that inspectors may perform the inspections from aboard the pro- -~r l middot
duction-supp_ort vess9ls or deep-water platforms already in use by the middot i
lessees The alter~ative would require that t_echniques be used to -~
sense the item i1
n question at the subsea v1el1head or production equ1 shyI J I
ment and transmi~t this critical information to the surface This I
sensing may req~ire fnstallation of pgsition pressure and thermal I ) t
transducers in ~lv_gs pipes pumps etc located in the subsea enshy1 I -~middot-middotmiddotmiddotmiddot--- ---shy
vi ronment Tele111etering the information to the surface could involve
ultrasonic hydrltaulic electric-wire or other transmission techniquesI
The information 1di sp 1ays could in lcude vi sual gages or meters and comshy
Iputer controlled cathode-ray tubes (CRTs)
The consid~rations discussed above place inspection techniques
and procedures 1ln three categories ie those performed by manned
submersibles by unmanned submersible and by remote controldisplay lrf Ultimately it liould appear that emphasis should be placed on sensors
1 _on the subsea s11ste111 with data display or readout at the surface-- ---
vessel or platfdrm Increased use of sensors however will require 10
the development of methods for their calibration A method for cali shy
brating pressure transducers and determining existence and magnitude of
leakage through closed valves is presented in the next secion of this
report This approach v1ould eliminate the need for very costly submersible
bull
vehicles and th~ support ships required for I
them as well as avoid a -fJ possible so4rce
1
of risk to USGS inspectors --- I I
4 Calibration and Jn~fiectiq~hni_~
Production or service tubing that is accessible at the surface
can be used formiddot calibration of pressure sensors and determining valve
leakage if a tu~ing path to the component tq be monitored can be isoshy
lated by remotely actuated va1ves If a closed volume of fluid can
be obtained in this way net leakage into or out of the volume can
be determined by a pressure rise or drop respectively which is meashy
sured at the surface If leakage occurs the magnitude of the leak
can be determined by measuring the flow rate required to hold the I
surface pressure constant while bleeding fluid from or pumping fluid
into the tubing(assuming the fluid in the tubing is in thermal equilishy brium with the surroundings) If there is no leakage or if the leakage
is very small the process may be used to calibrate subsurface presshy
sure transducers Surface readings of pressure in the closed volume
can be used to calibrate the remote read out of subsurface transducers I
monitoring the pressure in the volume if th~ surface readings are comshy
pensated for the hydraulic gradient in the enclosed fluid This com-middot
pensation and a~sociated errors are discuss~d in the following section
This technique for calibration and inspection of subsea transducers I
and valving requires only that the inspector have access to the pipe- middot
lines that connect the subsea system to its middotsurface production and I
distribution systems Closed volumes are oqtained in these pipelines
by appropriately setting (turning on or off) various valves in the
pipeline and subsea systems Appendix A of this report applies this
technique to the Exxon SPS and shows that the necessary closed volumes
can be obtained for this system to permit inspection of all necessary
points
I
- - ~e~ Df1 J 11 ~ 5 Pressure Transducer Ca1i brati on l)t a() fh IS
If a pressure transducer at the bottom o~ a long column of fluid
(liquid or gas) is to be calibrated by applying pressure at the topI
then the pressure 1read at the top must be cor~ected for the fluid
pressure gradient in the column to obtain a correct value for presshy sure at the transducer If themiddot transducer depth bene~th the surface
is le_ss than about I
1000 ft and the calibrating fluid is a liquid
then a constant liquid density may be assumed with Jess than one pershy cent errQJ The Bressmicrore correction is then given by Pgh where P is lt--middot -- the fluid densityi g t~e acce)eration of gravity and h is the height
of the fluid colu~n ~n terms of specific gravity (relative to water) I
SpGr the pressure c~rrection (in psi) is 0~434 ~ SpGr x h
For greater accurhcy or for greater transducer depths the cornshy
pressibility of the fluid must be considered I
Figure 1 is taken from
API STD 1101 (Man4al of Petroleum Measurement bullStandards Chapter 5
Section 2) and presents the compressibility o~ hydrocarbons as percent
change in volume 9r density per 1000 psi pressure change for a range
of API gravities and temperatures Dividing ~he compressibility pershy
centage obtained from figure 1 by 100000 results in a factor F such
that
d P = FdP p
where dp is the c~ange in density associated vlith a change in pressure
dP In psi
middot l middot11 _I ] ii J l ff - middot1middot -middot
lmiddotshyltl
ltfl lbullJ JJ n 0 w 0
Dr~1 r-----~d ir f ~cmiddotmiddotmiddot t- E 1 1 0~-~0n f r AC-lgt Ilei nd C L C_fJJ middotcmiddotr -cmiddotibili~v of Liquid Ii-C-xmiddotirlmiddot~-1~ lbullo= AJ 5 I1middotJ ~7middot~i 1~iJ
~t-tbulln Con1r1middot~)11a11~ of Jiqr1d fl1r bullr11lon_~0middot1H1almmmiddotb~~____
r_c 1
~ -t c~ Ibull_~- 4-r r sngt llI
Integrating both sides results in
= F(P-Ps1
p = eF(P-P~)or PS ( 1 )
where the subscript s indicates surface cdnditions Equation (1)
relates the density 2t any depth in the fluid column to the pressure at that point
For a small change in fluid depth dP =pgdh (2)
where dh is the change in depth Substituting eq~ation (1) into (2)
dP =p geF(P-Ps)dh s
-F(P-P ) or p gdh= e s dP s
Integrating from the surface to a total depth D
-F(P-P ) -F(P -P )1 s e D s + 1= - e = shyf fI
-Rearranging we have
or I
It is interesting to note that gp 5D is the pressure head expected for an incompressible fluid If FgrsDlaquo l (that is the fluid is nearly incompressible) then equation 3 simplifies to
Po-Ps = gPsD
(note lnl+x) ~ x for x laquo 1)
For an example of the type of error that might occur if compressibility
is not considered assume gp 5D = 4000 psi (as it would for an ~gproxi mately 10000 ft deep subsea completion) and that F = 2 x 10 psi Thus
4Po-Ps = -5 x 10 ln(l-008) = 4170 psi
If compressibility had been ignored the pre~sure error would have been 170 psi This analysis has assumed that temperature is constant with depth and that the compressibility of hydrocarbon liquids does not depend on pressure The APl STD 1101 values for compressibility were based on data from zero to 1000 psig
so more data may be reshyquired to assure pressure independence
For cases in which the subsea conditions have been specified (for example setting a downhole pressure for cal~bration of a transducer) the surface presure P required to establish the condition is unknown s Thus the surface density re qui red to solve equation 3 is also unknown A derivation similar to the above shows that the hydrostatic pressure
--difference in terms of subsea conditions is
P0-Ps = ~ ln 0 + fp 0gD) (4)
The density of the oil is most usually known at atmospheric pressure
so the density at pressure P0is found from the atm~spheric density p 0
from equation 1
P0 0 FP = r e D (5)
The use of the above equation assumes a constant temperature so that density varfotions in the tubing are caused only by pressure The
density at atmosp~eric pressure and the desired temperature are found by using table 23 API STD 2540 (ASTM-IP Petroleum Measurement
Tables) to correct the standard density measured at 60degF relative to I
water at 60degF (Sp Gr 6060degF) Specific gravity may be found from
API gravity by usi 1
ng Tible 3 from API STD 2540 or from the equationI I
Sp Gr 6060~F = 1415(APl Gravity at 60degF + 1315)
In the follo~ing paragraphs several examples will be worked to I
demonstrate the uSJe of the equations and to show t~e effect of a
temperature gradi~nt in the oil from the ocean floor to the surface I
The example will i 1nclude two different oils 20deg and 60deg API 6060degF)
at two temperatur~s (70degF and 120degF) and two completion depths
(l000 ft and 101 000 ft) The equations wil1 be solved for surface
pressure assuming a sea bottom transducer is being calibrated at l000 psi
for the 1000 ft 1deep completion and at 5000
psi for the 10000 ft
deep completion The 1000 ft- depth was chosen because H represents I
present capa bi 1 i ties for subsea completion l Q 000 ft las chosen as a maximum depth fqr completions in the foreseeable future (in
areas such as the ~leutian Basin)
i I __ _l__
-Example 1
1000 ft completion -- = 1000 psiP0 20deg API 6060~F -- Sp Gr = 09340
Temp From Fig 1 From Table 23 (API STD 2540) I
70degF F = 039 x 10-5 ps1middot-T Sp Gr = 09305 -5 -1 J
120degF F = 050 x 10 psi Sp Gr bull 09130 At 1000 psi gpl~OO = gp x lOOO = 0434 x (=~middot Gr )0 x lOOO
0
At 70F gplOOO =0434 (09305) e039 x cO x 1000 1 bull
=0405 p~~
-5 0 ( ) eo 50 x 10 x 1000
At 120 F gplOOO ~ 0434 09130
o0398 poundft 1Po - PS =-F- ln (1 + F~D gD)
At 70degFmiddot P P - l ln (1 + 039 x 10-5 x 0405 x 1000) D - S - 039 x 10-S
= 405 psi Ps = lopo - 405 = 595 psi
At 120degF Po - p = l ln (l + ~50 x 10-5 x 0398 x 1000) s 050 x 10-5
= 398 psi P~ = 1000 - 398 = 60 psi
Thus if the $urface pressure P5 were setat 599 psi the pressure
at the sea bottom transducer 1~ould be 1000 4 psi even if the temperature
of the 20deg API gravity oil varied between 70 and 120degF
bull
Example 2 I
1000 ft completion -- P~ = 1000 psi I
I
60deg API 6060deg F -- Sp Gri = 0 7389 From Pi_g__j_ From Table 23 (API STD 25401
70degF F = 0~80 x 10-5 psi-1 Sp Gr bull 07344 -5 -1
120degF F = l10 x 10 psi Sp Gr bull 07117 At 1000 psi pg middot = gp eF x 1000 = 0434middotx (Sp Gr) eF x 1000
1000 o middot o i 080 ~ 10~5 x 1000
At 70degF 9P]OOO bull 0434 (07344) e bull 0321 psift I
1 i o x i o~s x 1 oooAt 120degF gP1000 bull 0434 (07117)e
I = 03]2 psift
PD - Ps = F1 1 n (1 + F PD9 D)
1At 70degF PD
I
- Ps = _ ln (1 +1080 x io-5 x 0321 x 1000)5
080 x 10 = 321 psi
PS bull 679 psi
At 120degF P~ --1----~5 ln (1 + 1 1lO x 10-5 x 0312 x 1000) 110 x 10
= 311 psi Ps = 689 psi
Thus if the surtace pressure P5 were set atmiddot684psi the pressure at the sea bottom transducer would be 1000 plusmn_ 5 psi ~ven if the temperature of the 60deg API gravity oil varied between 70deg and 120degF
bull
I
From the foregoing examples it is apparrnt that for subsea compleshytions up to 1000 ft there is little effect on the calculated
I
pressure at a suhsea transducer due to compressibility and temperature bull
The pressure ca~ be accurately calculated from ~ I bullr
PD - PS = 0434 x Sp Gr x D where the specific gravity of the oil at sta~dard conditions has been corrected to the observed temperature (using an average between the subsea and surface oil temperatures) and 1 i ne pressure Example 3
10000 ft c~mpletion -- P0 = 5000 psi 20deg API 6060degF Sp Gr = 09340
From Fi9 l From Teble 23 (API STD 2540)
70deg F = 039 x l0-5psi-l Sp Gr = 09305 120deg F = 050 x l0-5psi-l Sp Gr = 09130
F x 5000 F x 5000At 5000 psi gp5poo = gp e = 0434 x
I
(=~middotGr ) e0 0
At 70F 9P5poo = 0434 (09305)e039 x 10 x 5000
= 0412 psift I
50 x 5000At 120F 9P~ooo = 0434 (09130)e0middot x 10 -5
= 0406 psift 1
PD - PS= -F- ln (l + Fp gD)0 __L__-=s 1nAt 70degF P ~ (l + 0~39 x 10-5 x 0412 x 10000
D I
P5 039 x 10 = 4087 psi ~ 5000 - 4087 = 913 psir5
At l20F P - P =--1-- ln (l + 050 x 10-5 x 0406 x 10000) D S 050 x l0- 5
- -p~ = 4019 psi P = 981 psi ~
I
Thus if the 1surface pressure r5 were set at 947 the pressure at the
sea bottom trans~ucer would be 5000 +- 34 psi even if the temperature of
the 20degAPI gravity oil varied between 70deg and l20degF
Example 4
I 110000 ft ~omp etion P f 5000 psi0
60deg API 6060degF Sp Gr = 07389 Temp
70degF
l 20degF
From Fig l I ~ -5 -1
F = Oi80 x 10 psi I middot -5 -1F = 110 x 10 psmiddotiI
From Table 23 (API----middotmiddot Sp Gr = 07344
Sp Gr= 07117
STD 2540)
middot F x 5000 F x 5000At 5000 ps1 1 gp 5000 = gp = 0~34 x (Sp Gr)e e0 0
80At 70degF gp middot = 0434 (o 7344)e0middot x 10-5 x 5000
~ooo = o332 psift
_ llxl0_ 5 x5oooAt 120degF gp5000 - 0434 (07117)e
= 0326 psift P ~ P ~ t ln (1 + fp gD)D S D
At 70degF Po_ p = ~__]-____ ln (l + Q80 x lo- 5 x 0332 x 10000) s 080 x 10-~
= 3277 psi I P5 ~ 5000 - 3277 = 1723 psi
At l20degF PD - PS = l 5 ln (l + l l x 10-5 x 0326 x 10000) llOxlOshy
= 3203 psi
PS = 5000 - 3202 = 1797 psi
shybull
Thus if the surface pressure P5 were set at 1760 psi the presshy
sure at the sea ~ottom transducer would be 5000 + 37 psi even if the I shy
temperature cf the 60deg API gravity oil varied between 70deg and 120degF
From these pxample calculations for a 10000 ft completion it is
apparent that temperature variations cause r~latively small errors in I
sea floor ca 1 i bration pressures even for sue~ a great depth If the
pressures are needed more acet1rately than this then the temperature
profile in the tubing would be needed
It has thus been shown that relatively simple calculations of
liquid hydrostatic head result in accurate pressure values for calishy
bration of subsea transducers I
The calibration of gas pressure transdutersmiddot is somewhat different
For low pressures and shallow depth little correction need be made to
the pressure measured at the surface For a gas specific gravity SG
(relative to ai~ at 20degC and 147 psia) pressure P(psia) and depth I
D(ft) the pressure correction AP is given by
-5AP = 356 x 10 x SG x P x D
This equation assumes that the ideal gas law holds and that tPP
is small The equation nay be modified to include the super-compresshy
sibility factor z as follows 0
AP= 356 x 10-Sx SG x D x Pz
For a 1000 ft deep subsea completion line pressure of 1000 psia
(assuming SG ~ 1 and z = 1) AF= 36 psi It is thus apparent that even with large errors in specific gravity and z the pressure correction
1
for hydrostatic head of the gqs is small for depths up to 1000 ft
-bull
Again for a line pressure of 1000 psi but a 10000 ft deep comshy
pletion llP = 3~0 psi so the assumption of PP being small no longer
holds An integration would thus be needed to determine the transducer
pressure and t~e vaHable z factor should be included in thi~ integral Thus a closed form solution similar to tha~ found for liquids cannot
be obtained an~ numerical integration is necessary However for a wide range of conditions the equations pre~ented for both liquids and
I II gases a11 ow acc4ra te cal i bratfon of sea bottom pressure transducers
through the production tubing~ I
I
- -
6 J_nspection_B$9YJrcment_~and Te~t Proc~dures j
The OCS Ord~rs ~ere reviewed for those item~ pertinent to a subsea system The OCS inspection requirements and the suggested general
inspection procedures for these items are discussed in the following
paragraphs Tubing PLtg_
I
Inspection Requirements (OCS Order No 5)I
1 T~e s~~tained liquid leakage flow should not exceed I
400 ccmin 2 The ga~ leakage flo~1 should nGt e)ceed 15 cu ftmin
General Pro~middotedure
The first step i~ this procedure is to isolate a column of fluid
between the tubing plug and the inspector with the valves opened as
for production except that the tubing plug is in pl ace Any fl ow reaching the inspector at the surface is a direct indication of leakage past the tubing plug Thermal equilibrium may b~ required if the
maximum allowabl~ leakage is too small Theflow volume can be measured at the surface in the same manner as for conventionlt1 platform systems
I
middotShut-in Tubi9_ls_e_sur~
Inspection Requirements (OCS Order No I
5)
1 Wells with a shut-in tubing ptessure of 4000 psig or
greater sha11 be equj pped with a subsurface-~ontro11 ed subsurface safety device
-J
2 When the shut-in tubing pressure declines below 4000 I
psig a remotely sontrolled subsurface safety device shall be installed
when the tubing is first removed and reinstalled
General Procedure
To determine if the shut-i~ tubing pressure i~ greater than 4000 psig I
a pressure sensor should be located ~1here the shut-in pressure can be sensed
A convenient arrangement is to locate a pressure s~nsor between the master
valve and wing valve on each tubing With the downhole safety valve and
master valve opened and the wing valve close~ the shmicrot-in tubing pressure
as indicated by the sensor is noted
Calibration of the pressure sensor can be accomplished by applying
a known pressure ~t the surface to a closed cdlumn of fluid connecting I
the surface with the sensor with corrections calculated as explained
in Section 5
Subsurface Safety Device
Inspection Requirements (OCS Order No 5) 1 A surface-controlled subsurface safety device shall be
test operated every six months
2 A subsurface-controlled subsurface safety device shall
be removed inspected and repaired every 12 mdnths 1
General Procedure To test a surface-controlled subsurface safety device the well
should be opened for production and the command then given to close
the subsurface Sifety device The leakage flqw volume if any is
measured at the surface in the same manner as for conventional plat shy
form sys terns bull
1
-)
Pressure Relief Valves Inspection Requtrements (0CS Order No 8)
All pressure reli-f valve~ shall be either bench tested for opershy
ation or tested with an external pressure source (if the valve is somiddot
equipped)annually Jtbt Wf SJJS~+ General Procedure
To test a pressure relief valve for operation the vessel or line
should be pressunizeq to the pressure necessary to open the valve by
using the method suggested in Section 5 Uriless remote position inshy
dicators are provided a means to determine ~hether or not the valve
has actually ope1ed would have to be devised bullfor each subsea system
by observing the effect on the pressure sensors Pressure Sensors
Inspection Requirements (OCS Order No 8)
All pressure sensors shall be tested at least once each month
General Procedure
To remotely test and cal i~rate a subsea bullpressure sensor it is
necessary to
(1) isolate a closed column of fluid irom the surface to
the subsea sensor by properly arranging the ~ys terns va1ves
(2) determine the specific gravity compressibility and the
column height of the fluid
(3) select the pressure required at the subsea sensor
(4) apply the appropriate pressure at the surface end of
the column and
(5) compare the telemetered press4re signal or indication
with the pressur~ applied to the sensor
Automatic Hellhead Safety Devices -~~__--r---
Inspection 8equiremcnts (OCS Order No 8) All automatic wellhead safety devices shall be tested for operation
I
and holding pres~ureonce each1month
I
- -
bull )
General Prooedure
To test the operation of the automatic well head safety devices
the out-of-the-tolerance condition (usually ~igh or low pressure) which actuates the devices should be simulated Urless position 1ndicators
I
are provided a means to deterrl1ine whether 011 not the valves have
actually closed ~ust be devised for each indi1vidu~l system because of
the peculiarities
in each syste m J I
L~ 6 - Jlaquo4 sfSf~ rCheck Valves ~J0141d 11tJt NC Uf~ l(I -v-
Inspection Requirements (OCS Order No ~)
A11 check valves on a11 fl ow 1i nes sha11 be tested for opera ti on
and holding pressure once each month
General Procedures
To test the check valve ft will have to be back pressured The
check valve fails to operate properly if any back flo~1 through the I
valve occurs
~iguid Level Shut-in Controls I
Inspection Requirements (9cs Order No 8)
All liquid-l 1
evel shut-in controls shall be tested once each month
by raising or lowering liquid level across the leyel-control detector
General Pro~edure I
The preferable way to test the liquid-level sh~t-in controls is to
simulate the out-of-tolerance conditions (1 iquid Jevel either low or I
high) at the sensor This sim~lation should cau~e either the inlet
shutoff va1ve to close or the discharge shutoff valve to close In
this manner both the control YStem and the automatif valves are tested I
A means will have to be devised for each subsea system to determine I
if the out-of-tolerance condition actually occurred at the sensor if
it was properly Jetected and i~ it caused thd proper actuation I
Vessel Automatic~Inlet-Shutoff Valves I
Inspection ~equirement (OCS Order No 8)I
-I I
bull ) ~ J) All automatic~~~~~-shutoff valves actuated by vessel~~
I
~fsensorj shalil be tested for operation onle each month General Procedure
Described above under gene~al procedure for Liquid-Level Shut-
In Controls Vessel AutomaJi c-Di sc_b~_g_e-Sh_ll__Dff__Y_ii_l ves
Inspection RequireiT1ent (OCS Order No 8) All automatic-discharge-shutoff valves actuated by vessel lowshy
level sensors shall be tested for operation qnce each month
General Proc~dure
Described above under Liquid-Level Shut-tn Controls
High-tempera_ure Coniprc2_()r-Sh_t1tdow_ri_Co~_o1s Inspection Requirement (OCS Order No 8)i
High temperature controls which protect the compressor against
abnormal pressure~ soltiY by such temperature
safety devices shall be tested annually
General Procedure Because of the danger involved in elevating the temperature suffi shy
ciently to cause + temperature device to actuate it is recommended that each temperature device be pre-tested and replaced each year rather than be tested remotely
Oil Spil 1 Detection E_g_t_pmen~
Inspection Requirements (OCS Order 7) All platforms and structures are require~ to have curbs gutters
and spill pans connected to a tank or sump fhis equipment is required to collect all hydrocarbon spillage on the platform It is recommended that this requirement be extencjed to require all unenclosed subsea
equipment to be covered by inverted spill pans with hydrocarbon sensors
and sumps to rem~ve spillage
General Procedure To test the hydrocarbon spi 11 age detection and removal system
a controlled spill should be made in each ar~a or section of spill
- bull
pans while th~ SUljlPI
pumps are monitored for proper operation This I I
metbod will require a signal to the surface to indicate directly when the pumps are running or indirectly by indicating a pressure rise in
I i
the affected pipeline due to the pun1ping action The indirect method is preferablebec~use the pressure rise not only indicates the pumps are running b~t indicates they also are pumpi~g fluid One additional safeguard should ~e employed A TV camera should be used to observe
I
the spill pans in the vicinity of the spill to assure that they are not leaking due to damage or inadequacy of de~ign Hydrocarbon S~nsors
IInspection Requirements
Hydrocarbon sensors are not covered in tbe OCS Qrders presently
in effect General Procedure The general test procedure for the oil-spill-detection equipment
above will test the hydrocarbon sensors for operation In addition
I bull some means of knowing when each separate hydrocarbon sensor in the
spill pan assemblies hus sensed hydrocarbon will provide additional I
protection by warning of system degradation b~fore the system is comshypletely inoperable
7 Summary and RecQ)enda tions This report deal~ with the inspection problems that have arisen
as a result of the present trend of the offshore oil industry towards
subsea completion and production of deep water petroleum reservoirs I
Inspection techniques for completion and prod~ction equipment are inshyvestigated but inspection of fiser systems submersibles and strucshy
tures are not inc~uded in the scope of this wprk
A technique ~as been detailed for calibr1ttion of subsea sensors I
and for verifying the proper OReration of va1ves The technique reshy
quires only that the inspector 1 have access to production tubing at
- bull
I I
the surface By actuating subsurface control valves from the surface
the inspector can isolate a closed fluid path1 to the point of interest I
Pressures read at the surface (when corrected for hydraulic gradients)
may then be used to ca 1 i brate subsurface tran1sducers Flow rates
measured at the surface can be used to I
indicate leakage rates bull
from
subsurface valves I
but fluid in the tubing must be allow
ed to reach
sufficient therma1l equilibriumwith its surroundings so that a false leakage rate is riot indicated due to thermal expansion of the fluid
I bull
This technique has been used to work ou~ an inspection procedure
for the Exxon Sulisea Production System The 1procedure demonstrates I I
that the necessany closed fluid paths can be obtained to permit inshyspection of all necessary points Thus from 1a theoretical point of et
j9aYYew 1 t has ~en established that accurate euroVa 1ua tion of subsea con- J
ditions can be made from the surface (io implement the procedures I
it would first be necessary to conduct an experimental program with field
tests to determi~e operational problems) tAtti e
bull
- Inspection of subsea production systems
-
-Another alternative is the use of an unmanned submersible The J ~ 1
i 1t~ use of unmanned reniote controlled underwater vehicles 1~ith television -middot
I -- - IL
and manipulators would eliminate personnel danger Hov1ever extra costs and possible technical limitations make a third alternative deshy
sirable if feasi 1
ble This alternative is tomiddot provide remote read-out 71 1shy1 bullbull -- ____ - ___~ lt l
1so that inspectors may perform the inspections from aboard the pro- -~r l middot
duction-supp_ort vess9ls or deep-water platforms already in use by the middot i
lessees The alter~ative would require that t_echniques be used to -~
sense the item i1
n question at the subsea v1el1head or production equ1 shyI J I
ment and transmi~t this critical information to the surface This I
sensing may req~ire fnstallation of pgsition pressure and thermal I ) t
transducers in ~lv_gs pipes pumps etc located in the subsea enshy1 I -~middot-middotmiddotmiddotmiddot--- ---shy
vi ronment Tele111etering the information to the surface could involve
ultrasonic hydrltaulic electric-wire or other transmission techniquesI
The information 1di sp 1ays could in lcude vi sual gages or meters and comshy
Iputer controlled cathode-ray tubes (CRTs)
The consid~rations discussed above place inspection techniques
and procedures 1ln three categories ie those performed by manned
submersibles by unmanned submersible and by remote controldisplay lrf Ultimately it liould appear that emphasis should be placed on sensors
1 _on the subsea s11ste111 with data display or readout at the surface-- ---
vessel or platfdrm Increased use of sensors however will require 10
the development of methods for their calibration A method for cali shy
brating pressure transducers and determining existence and magnitude of
leakage through closed valves is presented in the next secion of this
report This approach v1ould eliminate the need for very costly submersible
bull
vehicles and th~ support ships required for I
them as well as avoid a -fJ possible so4rce
1
of risk to USGS inspectors --- I I
4 Calibration and Jn~fiectiq~hni_~
Production or service tubing that is accessible at the surface
can be used formiddot calibration of pressure sensors and determining valve
leakage if a tu~ing path to the component tq be monitored can be isoshy
lated by remotely actuated va1ves If a closed volume of fluid can
be obtained in this way net leakage into or out of the volume can
be determined by a pressure rise or drop respectively which is meashy
sured at the surface If leakage occurs the magnitude of the leak
can be determined by measuring the flow rate required to hold the I
surface pressure constant while bleeding fluid from or pumping fluid
into the tubing(assuming the fluid in the tubing is in thermal equilishy brium with the surroundings) If there is no leakage or if the leakage
is very small the process may be used to calibrate subsurface presshy
sure transducers Surface readings of pressure in the closed volume
can be used to calibrate the remote read out of subsurface transducers I
monitoring the pressure in the volume if th~ surface readings are comshy
pensated for the hydraulic gradient in the enclosed fluid This com-middot
pensation and a~sociated errors are discuss~d in the following section
This technique for calibration and inspection of subsea transducers I
and valving requires only that the inspector have access to the pipe- middot
lines that connect the subsea system to its middotsurface production and I
distribution systems Closed volumes are oqtained in these pipelines
by appropriately setting (turning on or off) various valves in the
pipeline and subsea systems Appendix A of this report applies this
technique to the Exxon SPS and shows that the necessary closed volumes
can be obtained for this system to permit inspection of all necessary
points
I
- - ~e~ Df1 J 11 ~ 5 Pressure Transducer Ca1i brati on l)t a() fh IS
If a pressure transducer at the bottom o~ a long column of fluid
(liquid or gas) is to be calibrated by applying pressure at the topI
then the pressure 1read at the top must be cor~ected for the fluid
pressure gradient in the column to obtain a correct value for presshy sure at the transducer If themiddot transducer depth bene~th the surface
is le_ss than about I
1000 ft and the calibrating fluid is a liquid
then a constant liquid density may be assumed with Jess than one pershy cent errQJ The Bressmicrore correction is then given by Pgh where P is lt--middot -- the fluid densityi g t~e acce)eration of gravity and h is the height
of the fluid colu~n ~n terms of specific gravity (relative to water) I
SpGr the pressure c~rrection (in psi) is 0~434 ~ SpGr x h
For greater accurhcy or for greater transducer depths the cornshy
pressibility of the fluid must be considered I
Figure 1 is taken from
API STD 1101 (Man4al of Petroleum Measurement bullStandards Chapter 5
Section 2) and presents the compressibility o~ hydrocarbons as percent
change in volume 9r density per 1000 psi pressure change for a range
of API gravities and temperatures Dividing ~he compressibility pershy
centage obtained from figure 1 by 100000 results in a factor F such
that
d P = FdP p
where dp is the c~ange in density associated vlith a change in pressure
dP In psi
middot l middot11 _I ] ii J l ff - middot1middot -middot
lmiddotshyltl
ltfl lbullJ JJ n 0 w 0
Dr~1 r-----~d ir f ~cmiddotmiddotmiddot t- E 1 1 0~-~0n f r AC-lgt Ilei nd C L C_fJJ middotcmiddotr -cmiddotibili~v of Liquid Ii-C-xmiddotirlmiddot~-1~ lbullo= AJ 5 I1middotJ ~7middot~i 1~iJ
~t-tbulln Con1r1middot~)11a11~ of Jiqr1d fl1r bullr11lon_~0middot1H1almmmiddotb~~____
r_c 1
~ -t c~ Ibull_~- 4-r r sngt llI
Integrating both sides results in
= F(P-Ps1
p = eF(P-P~)or PS ( 1 )
where the subscript s indicates surface cdnditions Equation (1)
relates the density 2t any depth in the fluid column to the pressure at that point
For a small change in fluid depth dP =pgdh (2)
where dh is the change in depth Substituting eq~ation (1) into (2)
dP =p geF(P-Ps)dh s
-F(P-P ) or p gdh= e s dP s
Integrating from the surface to a total depth D
-F(P-P ) -F(P -P )1 s e D s + 1= - e = shyf fI
-Rearranging we have
or I
It is interesting to note that gp 5D is the pressure head expected for an incompressible fluid If FgrsDlaquo l (that is the fluid is nearly incompressible) then equation 3 simplifies to
Po-Ps = gPsD
(note lnl+x) ~ x for x laquo 1)
For an example of the type of error that might occur if compressibility
is not considered assume gp 5D = 4000 psi (as it would for an ~gproxi mately 10000 ft deep subsea completion) and that F = 2 x 10 psi Thus
4Po-Ps = -5 x 10 ln(l-008) = 4170 psi
If compressibility had been ignored the pre~sure error would have been 170 psi This analysis has assumed that temperature is constant with depth and that the compressibility of hydrocarbon liquids does not depend on pressure The APl STD 1101 values for compressibility were based on data from zero to 1000 psig
so more data may be reshyquired to assure pressure independence
For cases in which the subsea conditions have been specified (for example setting a downhole pressure for cal~bration of a transducer) the surface presure P required to establish the condition is unknown s Thus the surface density re qui red to solve equation 3 is also unknown A derivation similar to the above shows that the hydrostatic pressure
--difference in terms of subsea conditions is
P0-Ps = ~ ln 0 + fp 0gD) (4)
The density of the oil is most usually known at atmospheric pressure
so the density at pressure P0is found from the atm~spheric density p 0
from equation 1
P0 0 FP = r e D (5)
The use of the above equation assumes a constant temperature so that density varfotions in the tubing are caused only by pressure The
density at atmosp~eric pressure and the desired temperature are found by using table 23 API STD 2540 (ASTM-IP Petroleum Measurement
Tables) to correct the standard density measured at 60degF relative to I
water at 60degF (Sp Gr 6060degF) Specific gravity may be found from
API gravity by usi 1
ng Tible 3 from API STD 2540 or from the equationI I
Sp Gr 6060~F = 1415(APl Gravity at 60degF + 1315)
In the follo~ing paragraphs several examples will be worked to I
demonstrate the uSJe of the equations and to show t~e effect of a
temperature gradi~nt in the oil from the ocean floor to the surface I
The example will i 1nclude two different oils 20deg and 60deg API 6060degF)
at two temperatur~s (70degF and 120degF) and two completion depths
(l000 ft and 101 000 ft) The equations wil1 be solved for surface
pressure assuming a sea bottom transducer is being calibrated at l000 psi
for the 1000 ft 1deep completion and at 5000
psi for the 10000 ft
deep completion The 1000 ft- depth was chosen because H represents I
present capa bi 1 i ties for subsea completion l Q 000 ft las chosen as a maximum depth fqr completions in the foreseeable future (in
areas such as the ~leutian Basin)
i I __ _l__
-Example 1
1000 ft completion -- = 1000 psiP0 20deg API 6060~F -- Sp Gr = 09340
Temp From Fig 1 From Table 23 (API STD 2540) I
70degF F = 039 x 10-5 ps1middot-T Sp Gr = 09305 -5 -1 J
120degF F = 050 x 10 psi Sp Gr bull 09130 At 1000 psi gpl~OO = gp x lOOO = 0434 x (=~middot Gr )0 x lOOO
0
At 70F gplOOO =0434 (09305) e039 x cO x 1000 1 bull
=0405 p~~
-5 0 ( ) eo 50 x 10 x 1000
At 120 F gplOOO ~ 0434 09130
o0398 poundft 1Po - PS =-F- ln (1 + F~D gD)
At 70degFmiddot P P - l ln (1 + 039 x 10-5 x 0405 x 1000) D - S - 039 x 10-S
= 405 psi Ps = lopo - 405 = 595 psi
At 120degF Po - p = l ln (l + ~50 x 10-5 x 0398 x 1000) s 050 x 10-5
= 398 psi P~ = 1000 - 398 = 60 psi
Thus if the $urface pressure P5 were setat 599 psi the pressure
at the sea bottom transducer 1~ould be 1000 4 psi even if the temperature
of the 20deg API gravity oil varied between 70 and 120degF
bull
Example 2 I
1000 ft completion -- P~ = 1000 psi I
I
60deg API 6060deg F -- Sp Gri = 0 7389 From Pi_g__j_ From Table 23 (API STD 25401
70degF F = 0~80 x 10-5 psi-1 Sp Gr bull 07344 -5 -1
120degF F = l10 x 10 psi Sp Gr bull 07117 At 1000 psi pg middot = gp eF x 1000 = 0434middotx (Sp Gr) eF x 1000
1000 o middot o i 080 ~ 10~5 x 1000
At 70degF 9P]OOO bull 0434 (07344) e bull 0321 psift I
1 i o x i o~s x 1 oooAt 120degF gP1000 bull 0434 (07117)e
I = 03]2 psift
PD - Ps = F1 1 n (1 + F PD9 D)
1At 70degF PD
I
- Ps = _ ln (1 +1080 x io-5 x 0321 x 1000)5
080 x 10 = 321 psi
PS bull 679 psi
At 120degF P~ --1----~5 ln (1 + 1 1lO x 10-5 x 0312 x 1000) 110 x 10
= 311 psi Ps = 689 psi
Thus if the surtace pressure P5 were set atmiddot684psi the pressure at the sea bottom transducer would be 1000 plusmn_ 5 psi ~ven if the temperature of the 60deg API gravity oil varied between 70deg and 120degF
bull
I
From the foregoing examples it is apparrnt that for subsea compleshytions up to 1000 ft there is little effect on the calculated
I
pressure at a suhsea transducer due to compressibility and temperature bull
The pressure ca~ be accurately calculated from ~ I bullr
PD - PS = 0434 x Sp Gr x D where the specific gravity of the oil at sta~dard conditions has been corrected to the observed temperature (using an average between the subsea and surface oil temperatures) and 1 i ne pressure Example 3
10000 ft c~mpletion -- P0 = 5000 psi 20deg API 6060degF Sp Gr = 09340
From Fi9 l From Teble 23 (API STD 2540)
70deg F = 039 x l0-5psi-l Sp Gr = 09305 120deg F = 050 x l0-5psi-l Sp Gr = 09130
F x 5000 F x 5000At 5000 psi gp5poo = gp e = 0434 x
I
(=~middotGr ) e0 0
At 70F 9P5poo = 0434 (09305)e039 x 10 x 5000
= 0412 psift I
50 x 5000At 120F 9P~ooo = 0434 (09130)e0middot x 10 -5
= 0406 psift 1
PD - PS= -F- ln (l + Fp gD)0 __L__-=s 1nAt 70degF P ~ (l + 0~39 x 10-5 x 0412 x 10000
D I
P5 039 x 10 = 4087 psi ~ 5000 - 4087 = 913 psir5
At l20F P - P =--1-- ln (l + 050 x 10-5 x 0406 x 10000) D S 050 x l0- 5
- -p~ = 4019 psi P = 981 psi ~
I
Thus if the 1surface pressure r5 were set at 947 the pressure at the
sea bottom trans~ucer would be 5000 +- 34 psi even if the temperature of
the 20degAPI gravity oil varied between 70deg and l20degF
Example 4
I 110000 ft ~omp etion P f 5000 psi0
60deg API 6060degF Sp Gr = 07389 Temp
70degF
l 20degF
From Fig l I ~ -5 -1
F = Oi80 x 10 psi I middot -5 -1F = 110 x 10 psmiddotiI
From Table 23 (API----middotmiddot Sp Gr = 07344
Sp Gr= 07117
STD 2540)
middot F x 5000 F x 5000At 5000 ps1 1 gp 5000 = gp = 0~34 x (Sp Gr)e e0 0
80At 70degF gp middot = 0434 (o 7344)e0middot x 10-5 x 5000
~ooo = o332 psift
_ llxl0_ 5 x5oooAt 120degF gp5000 - 0434 (07117)e
= 0326 psift P ~ P ~ t ln (1 + fp gD)D S D
At 70degF Po_ p = ~__]-____ ln (l + Q80 x lo- 5 x 0332 x 10000) s 080 x 10-~
= 3277 psi I P5 ~ 5000 - 3277 = 1723 psi
At l20degF PD - PS = l 5 ln (l + l l x 10-5 x 0326 x 10000) llOxlOshy
= 3203 psi
PS = 5000 - 3202 = 1797 psi
shybull
Thus if the surface pressure P5 were set at 1760 psi the presshy
sure at the sea ~ottom transducer would be 5000 + 37 psi even if the I shy
temperature cf the 60deg API gravity oil varied between 70deg and 120degF
From these pxample calculations for a 10000 ft completion it is
apparent that temperature variations cause r~latively small errors in I
sea floor ca 1 i bration pressures even for sue~ a great depth If the
pressures are needed more acet1rately than this then the temperature
profile in the tubing would be needed
It has thus been shown that relatively simple calculations of
liquid hydrostatic head result in accurate pressure values for calishy
bration of subsea transducers I
The calibration of gas pressure transdutersmiddot is somewhat different
For low pressures and shallow depth little correction need be made to
the pressure measured at the surface For a gas specific gravity SG
(relative to ai~ at 20degC and 147 psia) pressure P(psia) and depth I
D(ft) the pressure correction AP is given by
-5AP = 356 x 10 x SG x P x D
This equation assumes that the ideal gas law holds and that tPP
is small The equation nay be modified to include the super-compresshy
sibility factor z as follows 0
AP= 356 x 10-Sx SG x D x Pz
For a 1000 ft deep subsea completion line pressure of 1000 psia
(assuming SG ~ 1 and z = 1) AF= 36 psi It is thus apparent that even with large errors in specific gravity and z the pressure correction
1
for hydrostatic head of the gqs is small for depths up to 1000 ft
-bull
Again for a line pressure of 1000 psi but a 10000 ft deep comshy
pletion llP = 3~0 psi so the assumption of PP being small no longer
holds An integration would thus be needed to determine the transducer
pressure and t~e vaHable z factor should be included in thi~ integral Thus a closed form solution similar to tha~ found for liquids cannot
be obtained an~ numerical integration is necessary However for a wide range of conditions the equations pre~ented for both liquids and
I II gases a11 ow acc4ra te cal i bratfon of sea bottom pressure transducers
through the production tubing~ I
I
- -
6 J_nspection_B$9YJrcment_~and Te~t Proc~dures j
The OCS Ord~rs ~ere reviewed for those item~ pertinent to a subsea system The OCS inspection requirements and the suggested general
inspection procedures for these items are discussed in the following
paragraphs Tubing PLtg_
I
Inspection Requirements (OCS Order No 5)I
1 T~e s~~tained liquid leakage flow should not exceed I
400 ccmin 2 The ga~ leakage flo~1 should nGt e)ceed 15 cu ftmin
General Pro~middotedure
The first step i~ this procedure is to isolate a column of fluid
between the tubing plug and the inspector with the valves opened as
for production except that the tubing plug is in pl ace Any fl ow reaching the inspector at the surface is a direct indication of leakage past the tubing plug Thermal equilibrium may b~ required if the
maximum allowabl~ leakage is too small Theflow volume can be measured at the surface in the same manner as for conventionlt1 platform systems
I
middotShut-in Tubi9_ls_e_sur~
Inspection Requirements (OCS Order No I
5)
1 Wells with a shut-in tubing ptessure of 4000 psig or
greater sha11 be equj pped with a subsurface-~ontro11 ed subsurface safety device
-J
2 When the shut-in tubing pressure declines below 4000 I
psig a remotely sontrolled subsurface safety device shall be installed
when the tubing is first removed and reinstalled
General Procedure
To determine if the shut-i~ tubing pressure i~ greater than 4000 psig I
a pressure sensor should be located ~1here the shut-in pressure can be sensed
A convenient arrangement is to locate a pressure s~nsor between the master
valve and wing valve on each tubing With the downhole safety valve and
master valve opened and the wing valve close~ the shmicrot-in tubing pressure
as indicated by the sensor is noted
Calibration of the pressure sensor can be accomplished by applying
a known pressure ~t the surface to a closed cdlumn of fluid connecting I
the surface with the sensor with corrections calculated as explained
in Section 5
Subsurface Safety Device
Inspection Requirements (OCS Order No 5) 1 A surface-controlled subsurface safety device shall be
test operated every six months
2 A subsurface-controlled subsurface safety device shall
be removed inspected and repaired every 12 mdnths 1
General Procedure To test a surface-controlled subsurface safety device the well
should be opened for production and the command then given to close
the subsurface Sifety device The leakage flqw volume if any is
measured at the surface in the same manner as for conventional plat shy
form sys terns bull
1
-)
Pressure Relief Valves Inspection Requtrements (0CS Order No 8)
All pressure reli-f valve~ shall be either bench tested for opershy
ation or tested with an external pressure source (if the valve is somiddot
equipped)annually Jtbt Wf SJJS~+ General Procedure
To test a pressure relief valve for operation the vessel or line
should be pressunizeq to the pressure necessary to open the valve by
using the method suggested in Section 5 Uriless remote position inshy
dicators are provided a means to determine ~hether or not the valve
has actually ope1ed would have to be devised bullfor each subsea system
by observing the effect on the pressure sensors Pressure Sensors
Inspection Requirements (OCS Order No 8)
All pressure sensors shall be tested at least once each month
General Procedure
To remotely test and cal i~rate a subsea bullpressure sensor it is
necessary to
(1) isolate a closed column of fluid irom the surface to
the subsea sensor by properly arranging the ~ys terns va1ves
(2) determine the specific gravity compressibility and the
column height of the fluid
(3) select the pressure required at the subsea sensor
(4) apply the appropriate pressure at the surface end of
the column and
(5) compare the telemetered press4re signal or indication
with the pressur~ applied to the sensor
Automatic Hellhead Safety Devices -~~__--r---
Inspection 8equiremcnts (OCS Order No 8) All automatic wellhead safety devices shall be tested for operation
I
and holding pres~ureonce each1month
I
- -
bull )
General Prooedure
To test the operation of the automatic well head safety devices
the out-of-the-tolerance condition (usually ~igh or low pressure) which actuates the devices should be simulated Urless position 1ndicators
I
are provided a means to deterrl1ine whether 011 not the valves have
actually closed ~ust be devised for each indi1vidu~l system because of
the peculiarities
in each syste m J I
L~ 6 - Jlaquo4 sfSf~ rCheck Valves ~J0141d 11tJt NC Uf~ l(I -v-
Inspection Requirements (OCS Order No ~)
A11 check valves on a11 fl ow 1i nes sha11 be tested for opera ti on
and holding pressure once each month
General Procedures
To test the check valve ft will have to be back pressured The
check valve fails to operate properly if any back flo~1 through the I
valve occurs
~iguid Level Shut-in Controls I
Inspection Requirements (9cs Order No 8)
All liquid-l 1
evel shut-in controls shall be tested once each month
by raising or lowering liquid level across the leyel-control detector
General Pro~edure I
The preferable way to test the liquid-level sh~t-in controls is to
simulate the out-of-tolerance conditions (1 iquid Jevel either low or I
high) at the sensor This sim~lation should cau~e either the inlet
shutoff va1ve to close or the discharge shutoff valve to close In
this manner both the control YStem and the automatif valves are tested I
A means will have to be devised for each subsea system to determine I
if the out-of-tolerance condition actually occurred at the sensor if
it was properly Jetected and i~ it caused thd proper actuation I
Vessel Automatic~Inlet-Shutoff Valves I
Inspection ~equirement (OCS Order No 8)I
-I I
bull ) ~ J) All automatic~~~~~-shutoff valves actuated by vessel~~
I
~fsensorj shalil be tested for operation onle each month General Procedure
Described above under gene~al procedure for Liquid-Level Shut-
In Controls Vessel AutomaJi c-Di sc_b~_g_e-Sh_ll__Dff__Y_ii_l ves
Inspection RequireiT1ent (OCS Order No 8) All automatic-discharge-shutoff valves actuated by vessel lowshy
level sensors shall be tested for operation qnce each month
General Proc~dure
Described above under Liquid-Level Shut-tn Controls
High-tempera_ure Coniprc2_()r-Sh_t1tdow_ri_Co~_o1s Inspection Requirement (OCS Order No 8)i
High temperature controls which protect the compressor against
abnormal pressure~ soltiY by such temperature
safety devices shall be tested annually
General Procedure Because of the danger involved in elevating the temperature suffi shy
ciently to cause + temperature device to actuate it is recommended that each temperature device be pre-tested and replaced each year rather than be tested remotely
Oil Spil 1 Detection E_g_t_pmen~
Inspection Requirements (OCS Order 7) All platforms and structures are require~ to have curbs gutters
and spill pans connected to a tank or sump fhis equipment is required to collect all hydrocarbon spillage on the platform It is recommended that this requirement be extencjed to require all unenclosed subsea
equipment to be covered by inverted spill pans with hydrocarbon sensors
and sumps to rem~ve spillage
General Procedure To test the hydrocarbon spi 11 age detection and removal system
a controlled spill should be made in each ar~a or section of spill
- bull
pans while th~ SUljlPI
pumps are monitored for proper operation This I I
metbod will require a signal to the surface to indicate directly when the pumps are running or indirectly by indicating a pressure rise in
I i
the affected pipeline due to the pun1ping action The indirect method is preferablebec~use the pressure rise not only indicates the pumps are running b~t indicates they also are pumpi~g fluid One additional safeguard should ~e employed A TV camera should be used to observe
I
the spill pans in the vicinity of the spill to assure that they are not leaking due to damage or inadequacy of de~ign Hydrocarbon S~nsors
IInspection Requirements
Hydrocarbon sensors are not covered in tbe OCS Qrders presently
in effect General Procedure The general test procedure for the oil-spill-detection equipment
above will test the hydrocarbon sensors for operation In addition
I bull some means of knowing when each separate hydrocarbon sensor in the
spill pan assemblies hus sensed hydrocarbon will provide additional I
protection by warning of system degradation b~fore the system is comshypletely inoperable
7 Summary and RecQ)enda tions This report deal~ with the inspection problems that have arisen
as a result of the present trend of the offshore oil industry towards
subsea completion and production of deep water petroleum reservoirs I
Inspection techniques for completion and prod~ction equipment are inshyvestigated but inspection of fiser systems submersibles and strucshy
tures are not inc~uded in the scope of this wprk
A technique ~as been detailed for calibr1ttion of subsea sensors I
and for verifying the proper OReration of va1ves The technique reshy
quires only that the inspector 1 have access to production tubing at
- bull
I I
the surface By actuating subsurface control valves from the surface
the inspector can isolate a closed fluid path1 to the point of interest I
Pressures read at the surface (when corrected for hydraulic gradients)
may then be used to ca 1 i brate subsurface tran1sducers Flow rates
measured at the surface can be used to I
indicate leakage rates bull
from
subsurface valves I
but fluid in the tubing must be allow
ed to reach
sufficient therma1l equilibriumwith its surroundings so that a false leakage rate is riot indicated due to thermal expansion of the fluid
I bull
This technique has been used to work ou~ an inspection procedure
for the Exxon Sulisea Production System The 1procedure demonstrates I I
that the necessany closed fluid paths can be obtained to permit inshyspection of all necessary points Thus from 1a theoretical point of et
j9aYYew 1 t has ~en established that accurate euroVa 1ua tion of subsea con- J
ditions can be made from the surface (io implement the procedures I
it would first be necessary to conduct an experimental program with field
tests to determi~e operational problems) tAtti e
bull
- Inspection of subsea production systems
-
bull
vehicles and th~ support ships required for I
them as well as avoid a -fJ possible so4rce
1
of risk to USGS inspectors --- I I
4 Calibration and Jn~fiectiq~hni_~
Production or service tubing that is accessible at the surface
can be used formiddot calibration of pressure sensors and determining valve
leakage if a tu~ing path to the component tq be monitored can be isoshy
lated by remotely actuated va1ves If a closed volume of fluid can
be obtained in this way net leakage into or out of the volume can
be determined by a pressure rise or drop respectively which is meashy
sured at the surface If leakage occurs the magnitude of the leak
can be determined by measuring the flow rate required to hold the I
surface pressure constant while bleeding fluid from or pumping fluid
into the tubing(assuming the fluid in the tubing is in thermal equilishy brium with the surroundings) If there is no leakage or if the leakage
is very small the process may be used to calibrate subsurface presshy
sure transducers Surface readings of pressure in the closed volume
can be used to calibrate the remote read out of subsurface transducers I
monitoring the pressure in the volume if th~ surface readings are comshy
pensated for the hydraulic gradient in the enclosed fluid This com-middot
pensation and a~sociated errors are discuss~d in the following section
This technique for calibration and inspection of subsea transducers I
and valving requires only that the inspector have access to the pipe- middot
lines that connect the subsea system to its middotsurface production and I
distribution systems Closed volumes are oqtained in these pipelines
by appropriately setting (turning on or off) various valves in the
pipeline and subsea systems Appendix A of this report applies this
technique to the Exxon SPS and shows that the necessary closed volumes
can be obtained for this system to permit inspection of all necessary
points
I
- - ~e~ Df1 J 11 ~ 5 Pressure Transducer Ca1i brati on l)t a() fh IS
If a pressure transducer at the bottom o~ a long column of fluid
(liquid or gas) is to be calibrated by applying pressure at the topI
then the pressure 1read at the top must be cor~ected for the fluid
pressure gradient in the column to obtain a correct value for presshy sure at the transducer If themiddot transducer depth bene~th the surface
is le_ss than about I
1000 ft and the calibrating fluid is a liquid
then a constant liquid density may be assumed with Jess than one pershy cent errQJ The Bressmicrore correction is then given by Pgh where P is lt--middot -- the fluid densityi g t~e acce)eration of gravity and h is the height
of the fluid colu~n ~n terms of specific gravity (relative to water) I
SpGr the pressure c~rrection (in psi) is 0~434 ~ SpGr x h
For greater accurhcy or for greater transducer depths the cornshy
pressibility of the fluid must be considered I
Figure 1 is taken from
API STD 1101 (Man4al of Petroleum Measurement bullStandards Chapter 5
Section 2) and presents the compressibility o~ hydrocarbons as percent
change in volume 9r density per 1000 psi pressure change for a range
of API gravities and temperatures Dividing ~he compressibility pershy
centage obtained from figure 1 by 100000 results in a factor F such
that
d P = FdP p
where dp is the c~ange in density associated vlith a change in pressure
dP In psi
middot l middot11 _I ] ii J l ff - middot1middot -middot
lmiddotshyltl
ltfl lbullJ JJ n 0 w 0
Dr~1 r-----~d ir f ~cmiddotmiddotmiddot t- E 1 1 0~-~0n f r AC-lgt Ilei nd C L C_fJJ middotcmiddotr -cmiddotibili~v of Liquid Ii-C-xmiddotirlmiddot~-1~ lbullo= AJ 5 I1middotJ ~7middot~i 1~iJ
~t-tbulln Con1r1middot~)11a11~ of Jiqr1d fl1r bullr11lon_~0middot1H1almmmiddotb~~____
r_c 1
~ -t c~ Ibull_~- 4-r r sngt llI
Integrating both sides results in
= F(P-Ps1
p = eF(P-P~)or PS ( 1 )
where the subscript s indicates surface cdnditions Equation (1)
relates the density 2t any depth in the fluid column to the pressure at that point
For a small change in fluid depth dP =pgdh (2)
where dh is the change in depth Substituting eq~ation (1) into (2)
dP =p geF(P-Ps)dh s
-F(P-P ) or p gdh= e s dP s
Integrating from the surface to a total depth D
-F(P-P ) -F(P -P )1 s e D s + 1= - e = shyf fI
-Rearranging we have
or I
It is interesting to note that gp 5D is the pressure head expected for an incompressible fluid If FgrsDlaquo l (that is the fluid is nearly incompressible) then equation 3 simplifies to
Po-Ps = gPsD
(note lnl+x) ~ x for x laquo 1)
For an example of the type of error that might occur if compressibility
is not considered assume gp 5D = 4000 psi (as it would for an ~gproxi mately 10000 ft deep subsea completion) and that F = 2 x 10 psi Thus
4Po-Ps = -5 x 10 ln(l-008) = 4170 psi
If compressibility had been ignored the pre~sure error would have been 170 psi This analysis has assumed that temperature is constant with depth and that the compressibility of hydrocarbon liquids does not depend on pressure The APl STD 1101 values for compressibility were based on data from zero to 1000 psig
so more data may be reshyquired to assure pressure independence
For cases in which the subsea conditions have been specified (for example setting a downhole pressure for cal~bration of a transducer) the surface presure P required to establish the condition is unknown s Thus the surface density re qui red to solve equation 3 is also unknown A derivation similar to the above shows that the hydrostatic pressure
--difference in terms of subsea conditions is
P0-Ps = ~ ln 0 + fp 0gD) (4)
The density of the oil is most usually known at atmospheric pressure
so the density at pressure P0is found from the atm~spheric density p 0
from equation 1
P0 0 FP = r e D (5)
The use of the above equation assumes a constant temperature so that density varfotions in the tubing are caused only by pressure The
density at atmosp~eric pressure and the desired temperature are found by using table 23 API STD 2540 (ASTM-IP Petroleum Measurement
Tables) to correct the standard density measured at 60degF relative to I
water at 60degF (Sp Gr 6060degF) Specific gravity may be found from
API gravity by usi 1
ng Tible 3 from API STD 2540 or from the equationI I
Sp Gr 6060~F = 1415(APl Gravity at 60degF + 1315)
In the follo~ing paragraphs several examples will be worked to I
demonstrate the uSJe of the equations and to show t~e effect of a
temperature gradi~nt in the oil from the ocean floor to the surface I
The example will i 1nclude two different oils 20deg and 60deg API 6060degF)
at two temperatur~s (70degF and 120degF) and two completion depths
(l000 ft and 101 000 ft) The equations wil1 be solved for surface
pressure assuming a sea bottom transducer is being calibrated at l000 psi
for the 1000 ft 1deep completion and at 5000
psi for the 10000 ft
deep completion The 1000 ft- depth was chosen because H represents I
present capa bi 1 i ties for subsea completion l Q 000 ft las chosen as a maximum depth fqr completions in the foreseeable future (in
areas such as the ~leutian Basin)
i I __ _l__
-Example 1
1000 ft completion -- = 1000 psiP0 20deg API 6060~F -- Sp Gr = 09340
Temp From Fig 1 From Table 23 (API STD 2540) I
70degF F = 039 x 10-5 ps1middot-T Sp Gr = 09305 -5 -1 J
120degF F = 050 x 10 psi Sp Gr bull 09130 At 1000 psi gpl~OO = gp x lOOO = 0434 x (=~middot Gr )0 x lOOO
0
At 70F gplOOO =0434 (09305) e039 x cO x 1000 1 bull
=0405 p~~
-5 0 ( ) eo 50 x 10 x 1000
At 120 F gplOOO ~ 0434 09130
o0398 poundft 1Po - PS =-F- ln (1 + F~D gD)
At 70degFmiddot P P - l ln (1 + 039 x 10-5 x 0405 x 1000) D - S - 039 x 10-S
= 405 psi Ps = lopo - 405 = 595 psi
At 120degF Po - p = l ln (l + ~50 x 10-5 x 0398 x 1000) s 050 x 10-5
= 398 psi P~ = 1000 - 398 = 60 psi
Thus if the $urface pressure P5 were setat 599 psi the pressure
at the sea bottom transducer 1~ould be 1000 4 psi even if the temperature
of the 20deg API gravity oil varied between 70 and 120degF
bull
Example 2 I
1000 ft completion -- P~ = 1000 psi I
I
60deg API 6060deg F -- Sp Gri = 0 7389 From Pi_g__j_ From Table 23 (API STD 25401
70degF F = 0~80 x 10-5 psi-1 Sp Gr bull 07344 -5 -1
120degF F = l10 x 10 psi Sp Gr bull 07117 At 1000 psi pg middot = gp eF x 1000 = 0434middotx (Sp Gr) eF x 1000
1000 o middot o i 080 ~ 10~5 x 1000
At 70degF 9P]OOO bull 0434 (07344) e bull 0321 psift I
1 i o x i o~s x 1 oooAt 120degF gP1000 bull 0434 (07117)e
I = 03]2 psift
PD - Ps = F1 1 n (1 + F PD9 D)
1At 70degF PD
I
- Ps = _ ln (1 +1080 x io-5 x 0321 x 1000)5
080 x 10 = 321 psi
PS bull 679 psi
At 120degF P~ --1----~5 ln (1 + 1 1lO x 10-5 x 0312 x 1000) 110 x 10
= 311 psi Ps = 689 psi
Thus if the surtace pressure P5 were set atmiddot684psi the pressure at the sea bottom transducer would be 1000 plusmn_ 5 psi ~ven if the temperature of the 60deg API gravity oil varied between 70deg and 120degF
bull
I
From the foregoing examples it is apparrnt that for subsea compleshytions up to 1000 ft there is little effect on the calculated
I
pressure at a suhsea transducer due to compressibility and temperature bull
The pressure ca~ be accurately calculated from ~ I bullr
PD - PS = 0434 x Sp Gr x D where the specific gravity of the oil at sta~dard conditions has been corrected to the observed temperature (using an average between the subsea and surface oil temperatures) and 1 i ne pressure Example 3
10000 ft c~mpletion -- P0 = 5000 psi 20deg API 6060degF Sp Gr = 09340
From Fi9 l From Teble 23 (API STD 2540)
70deg F = 039 x l0-5psi-l Sp Gr = 09305 120deg F = 050 x l0-5psi-l Sp Gr = 09130
F x 5000 F x 5000At 5000 psi gp5poo = gp e = 0434 x
I
(=~middotGr ) e0 0
At 70F 9P5poo = 0434 (09305)e039 x 10 x 5000
= 0412 psift I
50 x 5000At 120F 9P~ooo = 0434 (09130)e0middot x 10 -5
= 0406 psift 1
PD - PS= -F- ln (l + Fp gD)0 __L__-=s 1nAt 70degF P ~ (l + 0~39 x 10-5 x 0412 x 10000
D I
P5 039 x 10 = 4087 psi ~ 5000 - 4087 = 913 psir5
At l20F P - P =--1-- ln (l + 050 x 10-5 x 0406 x 10000) D S 050 x l0- 5
- -p~ = 4019 psi P = 981 psi ~
I
Thus if the 1surface pressure r5 were set at 947 the pressure at the
sea bottom trans~ucer would be 5000 +- 34 psi even if the temperature of
the 20degAPI gravity oil varied between 70deg and l20degF
Example 4
I 110000 ft ~omp etion P f 5000 psi0
60deg API 6060degF Sp Gr = 07389 Temp
70degF
l 20degF
From Fig l I ~ -5 -1
F = Oi80 x 10 psi I middot -5 -1F = 110 x 10 psmiddotiI
From Table 23 (API----middotmiddot Sp Gr = 07344
Sp Gr= 07117
STD 2540)
middot F x 5000 F x 5000At 5000 ps1 1 gp 5000 = gp = 0~34 x (Sp Gr)e e0 0
80At 70degF gp middot = 0434 (o 7344)e0middot x 10-5 x 5000
~ooo = o332 psift
_ llxl0_ 5 x5oooAt 120degF gp5000 - 0434 (07117)e
= 0326 psift P ~ P ~ t ln (1 + fp gD)D S D
At 70degF Po_ p = ~__]-____ ln (l + Q80 x lo- 5 x 0332 x 10000) s 080 x 10-~
= 3277 psi I P5 ~ 5000 - 3277 = 1723 psi
At l20degF PD - PS = l 5 ln (l + l l x 10-5 x 0326 x 10000) llOxlOshy
= 3203 psi
PS = 5000 - 3202 = 1797 psi
shybull
Thus if the surface pressure P5 were set at 1760 psi the presshy
sure at the sea ~ottom transducer would be 5000 + 37 psi even if the I shy
temperature cf the 60deg API gravity oil varied between 70deg and 120degF
From these pxample calculations for a 10000 ft completion it is
apparent that temperature variations cause r~latively small errors in I
sea floor ca 1 i bration pressures even for sue~ a great depth If the
pressures are needed more acet1rately than this then the temperature
profile in the tubing would be needed
It has thus been shown that relatively simple calculations of
liquid hydrostatic head result in accurate pressure values for calishy
bration of subsea transducers I
The calibration of gas pressure transdutersmiddot is somewhat different
For low pressures and shallow depth little correction need be made to
the pressure measured at the surface For a gas specific gravity SG
(relative to ai~ at 20degC and 147 psia) pressure P(psia) and depth I
D(ft) the pressure correction AP is given by
-5AP = 356 x 10 x SG x P x D
This equation assumes that the ideal gas law holds and that tPP
is small The equation nay be modified to include the super-compresshy
sibility factor z as follows 0
AP= 356 x 10-Sx SG x D x Pz
For a 1000 ft deep subsea completion line pressure of 1000 psia
(assuming SG ~ 1 and z = 1) AF= 36 psi It is thus apparent that even with large errors in specific gravity and z the pressure correction
1
for hydrostatic head of the gqs is small for depths up to 1000 ft
-bull
Again for a line pressure of 1000 psi but a 10000 ft deep comshy
pletion llP = 3~0 psi so the assumption of PP being small no longer
holds An integration would thus be needed to determine the transducer
pressure and t~e vaHable z factor should be included in thi~ integral Thus a closed form solution similar to tha~ found for liquids cannot
be obtained an~ numerical integration is necessary However for a wide range of conditions the equations pre~ented for both liquids and
I II gases a11 ow acc4ra te cal i bratfon of sea bottom pressure transducers
through the production tubing~ I
I
- -
6 J_nspection_B$9YJrcment_~and Te~t Proc~dures j
The OCS Ord~rs ~ere reviewed for those item~ pertinent to a subsea system The OCS inspection requirements and the suggested general
inspection procedures for these items are discussed in the following
paragraphs Tubing PLtg_
I
Inspection Requirements (OCS Order No 5)I
1 T~e s~~tained liquid leakage flow should not exceed I
400 ccmin 2 The ga~ leakage flo~1 should nGt e)ceed 15 cu ftmin
General Pro~middotedure
The first step i~ this procedure is to isolate a column of fluid
between the tubing plug and the inspector with the valves opened as
for production except that the tubing plug is in pl ace Any fl ow reaching the inspector at the surface is a direct indication of leakage past the tubing plug Thermal equilibrium may b~ required if the
maximum allowabl~ leakage is too small Theflow volume can be measured at the surface in the same manner as for conventionlt1 platform systems
I
middotShut-in Tubi9_ls_e_sur~
Inspection Requirements (OCS Order No I
5)
1 Wells with a shut-in tubing ptessure of 4000 psig or
greater sha11 be equj pped with a subsurface-~ontro11 ed subsurface safety device
-J
2 When the shut-in tubing pressure declines below 4000 I
psig a remotely sontrolled subsurface safety device shall be installed
when the tubing is first removed and reinstalled
General Procedure
To determine if the shut-i~ tubing pressure i~ greater than 4000 psig I
a pressure sensor should be located ~1here the shut-in pressure can be sensed
A convenient arrangement is to locate a pressure s~nsor between the master
valve and wing valve on each tubing With the downhole safety valve and
master valve opened and the wing valve close~ the shmicrot-in tubing pressure
as indicated by the sensor is noted
Calibration of the pressure sensor can be accomplished by applying
a known pressure ~t the surface to a closed cdlumn of fluid connecting I
the surface with the sensor with corrections calculated as explained
in Section 5
Subsurface Safety Device
Inspection Requirements (OCS Order No 5) 1 A surface-controlled subsurface safety device shall be
test operated every six months
2 A subsurface-controlled subsurface safety device shall
be removed inspected and repaired every 12 mdnths 1
General Procedure To test a surface-controlled subsurface safety device the well
should be opened for production and the command then given to close
the subsurface Sifety device The leakage flqw volume if any is
measured at the surface in the same manner as for conventional plat shy
form sys terns bull
1
-)
Pressure Relief Valves Inspection Requtrements (0CS Order No 8)
All pressure reli-f valve~ shall be either bench tested for opershy
ation or tested with an external pressure source (if the valve is somiddot
equipped)annually Jtbt Wf SJJS~+ General Procedure
To test a pressure relief valve for operation the vessel or line
should be pressunizeq to the pressure necessary to open the valve by
using the method suggested in Section 5 Uriless remote position inshy
dicators are provided a means to determine ~hether or not the valve
has actually ope1ed would have to be devised bullfor each subsea system
by observing the effect on the pressure sensors Pressure Sensors
Inspection Requirements (OCS Order No 8)
All pressure sensors shall be tested at least once each month
General Procedure
To remotely test and cal i~rate a subsea bullpressure sensor it is
necessary to
(1) isolate a closed column of fluid irom the surface to
the subsea sensor by properly arranging the ~ys terns va1ves
(2) determine the specific gravity compressibility and the
column height of the fluid
(3) select the pressure required at the subsea sensor
(4) apply the appropriate pressure at the surface end of
the column and
(5) compare the telemetered press4re signal or indication
with the pressur~ applied to the sensor
Automatic Hellhead Safety Devices -~~__--r---
Inspection 8equiremcnts (OCS Order No 8) All automatic wellhead safety devices shall be tested for operation
I
and holding pres~ureonce each1month
I
- -
bull )
General Prooedure
To test the operation of the automatic well head safety devices
the out-of-the-tolerance condition (usually ~igh or low pressure) which actuates the devices should be simulated Urless position 1ndicators
I
are provided a means to deterrl1ine whether 011 not the valves have
actually closed ~ust be devised for each indi1vidu~l system because of
the peculiarities
in each syste m J I
L~ 6 - Jlaquo4 sfSf~ rCheck Valves ~J0141d 11tJt NC Uf~ l(I -v-
Inspection Requirements (OCS Order No ~)
A11 check valves on a11 fl ow 1i nes sha11 be tested for opera ti on
and holding pressure once each month
General Procedures
To test the check valve ft will have to be back pressured The
check valve fails to operate properly if any back flo~1 through the I
valve occurs
~iguid Level Shut-in Controls I
Inspection Requirements (9cs Order No 8)
All liquid-l 1
evel shut-in controls shall be tested once each month
by raising or lowering liquid level across the leyel-control detector
General Pro~edure I
The preferable way to test the liquid-level sh~t-in controls is to
simulate the out-of-tolerance conditions (1 iquid Jevel either low or I
high) at the sensor This sim~lation should cau~e either the inlet
shutoff va1ve to close or the discharge shutoff valve to close In
this manner both the control YStem and the automatif valves are tested I
A means will have to be devised for each subsea system to determine I
if the out-of-tolerance condition actually occurred at the sensor if
it was properly Jetected and i~ it caused thd proper actuation I
Vessel Automatic~Inlet-Shutoff Valves I
Inspection ~equirement (OCS Order No 8)I
-I I
bull ) ~ J) All automatic~~~~~-shutoff valves actuated by vessel~~
I
~fsensorj shalil be tested for operation onle each month General Procedure
Described above under gene~al procedure for Liquid-Level Shut-
In Controls Vessel AutomaJi c-Di sc_b~_g_e-Sh_ll__Dff__Y_ii_l ves
Inspection RequireiT1ent (OCS Order No 8) All automatic-discharge-shutoff valves actuated by vessel lowshy
level sensors shall be tested for operation qnce each month
General Proc~dure
Described above under Liquid-Level Shut-tn Controls
High-tempera_ure Coniprc2_()r-Sh_t1tdow_ri_Co~_o1s Inspection Requirement (OCS Order No 8)i
High temperature controls which protect the compressor against
abnormal pressure~ soltiY by such temperature
safety devices shall be tested annually
General Procedure Because of the danger involved in elevating the temperature suffi shy
ciently to cause + temperature device to actuate it is recommended that each temperature device be pre-tested and replaced each year rather than be tested remotely
Oil Spil 1 Detection E_g_t_pmen~
Inspection Requirements (OCS Order 7) All platforms and structures are require~ to have curbs gutters
and spill pans connected to a tank or sump fhis equipment is required to collect all hydrocarbon spillage on the platform It is recommended that this requirement be extencjed to require all unenclosed subsea
equipment to be covered by inverted spill pans with hydrocarbon sensors
and sumps to rem~ve spillage
General Procedure To test the hydrocarbon spi 11 age detection and removal system
a controlled spill should be made in each ar~a or section of spill
- bull
pans while th~ SUljlPI
pumps are monitored for proper operation This I I
metbod will require a signal to the surface to indicate directly when the pumps are running or indirectly by indicating a pressure rise in
I i
the affected pipeline due to the pun1ping action The indirect method is preferablebec~use the pressure rise not only indicates the pumps are running b~t indicates they also are pumpi~g fluid One additional safeguard should ~e employed A TV camera should be used to observe
I
the spill pans in the vicinity of the spill to assure that they are not leaking due to damage or inadequacy of de~ign Hydrocarbon S~nsors
IInspection Requirements
Hydrocarbon sensors are not covered in tbe OCS Qrders presently
in effect General Procedure The general test procedure for the oil-spill-detection equipment
above will test the hydrocarbon sensors for operation In addition
I bull some means of knowing when each separate hydrocarbon sensor in the
spill pan assemblies hus sensed hydrocarbon will provide additional I
protection by warning of system degradation b~fore the system is comshypletely inoperable
7 Summary and RecQ)enda tions This report deal~ with the inspection problems that have arisen
as a result of the present trend of the offshore oil industry towards
subsea completion and production of deep water petroleum reservoirs I
Inspection techniques for completion and prod~ction equipment are inshyvestigated but inspection of fiser systems submersibles and strucshy
tures are not inc~uded in the scope of this wprk
A technique ~as been detailed for calibr1ttion of subsea sensors I
and for verifying the proper OReration of va1ves The technique reshy
quires only that the inspector 1 have access to production tubing at
- bull
I I
the surface By actuating subsurface control valves from the surface
the inspector can isolate a closed fluid path1 to the point of interest I
Pressures read at the surface (when corrected for hydraulic gradients)
may then be used to ca 1 i brate subsurface tran1sducers Flow rates
measured at the surface can be used to I
indicate leakage rates bull
from
subsurface valves I
but fluid in the tubing must be allow
ed to reach
sufficient therma1l equilibriumwith its surroundings so that a false leakage rate is riot indicated due to thermal expansion of the fluid
I bull
This technique has been used to work ou~ an inspection procedure
for the Exxon Sulisea Production System The 1procedure demonstrates I I
that the necessany closed fluid paths can be obtained to permit inshyspection of all necessary points Thus from 1a theoretical point of et
j9aYYew 1 t has ~en established that accurate euroVa 1ua tion of subsea con- J
ditions can be made from the surface (io implement the procedures I
it would first be necessary to conduct an experimental program with field
tests to determi~e operational problems) tAtti e
bull
- Inspection of subsea production systems
-
- - ~e~ Df1 J 11 ~ 5 Pressure Transducer Ca1i brati on l)t a() fh IS
If a pressure transducer at the bottom o~ a long column of fluid
(liquid or gas) is to be calibrated by applying pressure at the topI
then the pressure 1read at the top must be cor~ected for the fluid
pressure gradient in the column to obtain a correct value for presshy sure at the transducer If themiddot transducer depth bene~th the surface
is le_ss than about I
1000 ft and the calibrating fluid is a liquid
then a constant liquid density may be assumed with Jess than one pershy cent errQJ The Bressmicrore correction is then given by Pgh where P is lt--middot -- the fluid densityi g t~e acce)eration of gravity and h is the height
of the fluid colu~n ~n terms of specific gravity (relative to water) I
SpGr the pressure c~rrection (in psi) is 0~434 ~ SpGr x h
For greater accurhcy or for greater transducer depths the cornshy
pressibility of the fluid must be considered I
Figure 1 is taken from
API STD 1101 (Man4al of Petroleum Measurement bullStandards Chapter 5
Section 2) and presents the compressibility o~ hydrocarbons as percent
change in volume 9r density per 1000 psi pressure change for a range
of API gravities and temperatures Dividing ~he compressibility pershy
centage obtained from figure 1 by 100000 results in a factor F such
that
d P = FdP p
where dp is the c~ange in density associated vlith a change in pressure
dP In psi
middot l middot11 _I ] ii J l ff - middot1middot -middot
lmiddotshyltl
ltfl lbullJ JJ n 0 w 0
Dr~1 r-----~d ir f ~cmiddotmiddotmiddot t- E 1 1 0~-~0n f r AC-lgt Ilei nd C L C_fJJ middotcmiddotr -cmiddotibili~v of Liquid Ii-C-xmiddotirlmiddot~-1~ lbullo= AJ 5 I1middotJ ~7middot~i 1~iJ
~t-tbulln Con1r1middot~)11a11~ of Jiqr1d fl1r bullr11lon_~0middot1H1almmmiddotb~~____
r_c 1
~ -t c~ Ibull_~- 4-r r sngt llI
Integrating both sides results in
= F(P-Ps1
p = eF(P-P~)or PS ( 1 )
where the subscript s indicates surface cdnditions Equation (1)
relates the density 2t any depth in the fluid column to the pressure at that point
For a small change in fluid depth dP =pgdh (2)
where dh is the change in depth Substituting eq~ation (1) into (2)
dP =p geF(P-Ps)dh s
-F(P-P ) or p gdh= e s dP s
Integrating from the surface to a total depth D
-F(P-P ) -F(P -P )1 s e D s + 1= - e = shyf fI
-Rearranging we have
or I
It is interesting to note that gp 5D is the pressure head expected for an incompressible fluid If FgrsDlaquo l (that is the fluid is nearly incompressible) then equation 3 simplifies to
Po-Ps = gPsD
(note lnl+x) ~ x for x laquo 1)
For an example of the type of error that might occur if compressibility
is not considered assume gp 5D = 4000 psi (as it would for an ~gproxi mately 10000 ft deep subsea completion) and that F = 2 x 10 psi Thus
4Po-Ps = -5 x 10 ln(l-008) = 4170 psi
If compressibility had been ignored the pre~sure error would have been 170 psi This analysis has assumed that temperature is constant with depth and that the compressibility of hydrocarbon liquids does not depend on pressure The APl STD 1101 values for compressibility were based on data from zero to 1000 psig
so more data may be reshyquired to assure pressure independence
For cases in which the subsea conditions have been specified (for example setting a downhole pressure for cal~bration of a transducer) the surface presure P required to establish the condition is unknown s Thus the surface density re qui red to solve equation 3 is also unknown A derivation similar to the above shows that the hydrostatic pressure
--difference in terms of subsea conditions is
P0-Ps = ~ ln 0 + fp 0gD) (4)
The density of the oil is most usually known at atmospheric pressure
so the density at pressure P0is found from the atm~spheric density p 0
from equation 1
P0 0 FP = r e D (5)
The use of the above equation assumes a constant temperature so that density varfotions in the tubing are caused only by pressure The
density at atmosp~eric pressure and the desired temperature are found by using table 23 API STD 2540 (ASTM-IP Petroleum Measurement
Tables) to correct the standard density measured at 60degF relative to I
water at 60degF (Sp Gr 6060degF) Specific gravity may be found from
API gravity by usi 1
ng Tible 3 from API STD 2540 or from the equationI I
Sp Gr 6060~F = 1415(APl Gravity at 60degF + 1315)
In the follo~ing paragraphs several examples will be worked to I
demonstrate the uSJe of the equations and to show t~e effect of a
temperature gradi~nt in the oil from the ocean floor to the surface I
The example will i 1nclude two different oils 20deg and 60deg API 6060degF)
at two temperatur~s (70degF and 120degF) and two completion depths
(l000 ft and 101 000 ft) The equations wil1 be solved for surface
pressure assuming a sea bottom transducer is being calibrated at l000 psi
for the 1000 ft 1deep completion and at 5000
psi for the 10000 ft
deep completion The 1000 ft- depth was chosen because H represents I
present capa bi 1 i ties for subsea completion l Q 000 ft las chosen as a maximum depth fqr completions in the foreseeable future (in
areas such as the ~leutian Basin)
i I __ _l__
-Example 1
1000 ft completion -- = 1000 psiP0 20deg API 6060~F -- Sp Gr = 09340
Temp From Fig 1 From Table 23 (API STD 2540) I
70degF F = 039 x 10-5 ps1middot-T Sp Gr = 09305 -5 -1 J
120degF F = 050 x 10 psi Sp Gr bull 09130 At 1000 psi gpl~OO = gp x lOOO = 0434 x (=~middot Gr )0 x lOOO
0
At 70F gplOOO =0434 (09305) e039 x cO x 1000 1 bull
=0405 p~~
-5 0 ( ) eo 50 x 10 x 1000
At 120 F gplOOO ~ 0434 09130
o0398 poundft 1Po - PS =-F- ln (1 + F~D gD)
At 70degFmiddot P P - l ln (1 + 039 x 10-5 x 0405 x 1000) D - S - 039 x 10-S
= 405 psi Ps = lopo - 405 = 595 psi
At 120degF Po - p = l ln (l + ~50 x 10-5 x 0398 x 1000) s 050 x 10-5
= 398 psi P~ = 1000 - 398 = 60 psi
Thus if the $urface pressure P5 were setat 599 psi the pressure
at the sea bottom transducer 1~ould be 1000 4 psi even if the temperature
of the 20deg API gravity oil varied between 70 and 120degF
bull
Example 2 I
1000 ft completion -- P~ = 1000 psi I
I
60deg API 6060deg F -- Sp Gri = 0 7389 From Pi_g__j_ From Table 23 (API STD 25401
70degF F = 0~80 x 10-5 psi-1 Sp Gr bull 07344 -5 -1
120degF F = l10 x 10 psi Sp Gr bull 07117 At 1000 psi pg middot = gp eF x 1000 = 0434middotx (Sp Gr) eF x 1000
1000 o middot o i 080 ~ 10~5 x 1000
At 70degF 9P]OOO bull 0434 (07344) e bull 0321 psift I
1 i o x i o~s x 1 oooAt 120degF gP1000 bull 0434 (07117)e
I = 03]2 psift
PD - Ps = F1 1 n (1 + F PD9 D)
1At 70degF PD
I
- Ps = _ ln (1 +1080 x io-5 x 0321 x 1000)5
080 x 10 = 321 psi
PS bull 679 psi
At 120degF P~ --1----~5 ln (1 + 1 1lO x 10-5 x 0312 x 1000) 110 x 10
= 311 psi Ps = 689 psi
Thus if the surtace pressure P5 were set atmiddot684psi the pressure at the sea bottom transducer would be 1000 plusmn_ 5 psi ~ven if the temperature of the 60deg API gravity oil varied between 70deg and 120degF
bull
I
From the foregoing examples it is apparrnt that for subsea compleshytions up to 1000 ft there is little effect on the calculated
I
pressure at a suhsea transducer due to compressibility and temperature bull
The pressure ca~ be accurately calculated from ~ I bullr
PD - PS = 0434 x Sp Gr x D where the specific gravity of the oil at sta~dard conditions has been corrected to the observed temperature (using an average between the subsea and surface oil temperatures) and 1 i ne pressure Example 3
10000 ft c~mpletion -- P0 = 5000 psi 20deg API 6060degF Sp Gr = 09340
From Fi9 l From Teble 23 (API STD 2540)
70deg F = 039 x l0-5psi-l Sp Gr = 09305 120deg F = 050 x l0-5psi-l Sp Gr = 09130
F x 5000 F x 5000At 5000 psi gp5poo = gp e = 0434 x
I
(=~middotGr ) e0 0
At 70F 9P5poo = 0434 (09305)e039 x 10 x 5000
= 0412 psift I
50 x 5000At 120F 9P~ooo = 0434 (09130)e0middot x 10 -5
= 0406 psift 1
PD - PS= -F- ln (l + Fp gD)0 __L__-=s 1nAt 70degF P ~ (l + 0~39 x 10-5 x 0412 x 10000
D I
P5 039 x 10 = 4087 psi ~ 5000 - 4087 = 913 psir5
At l20F P - P =--1-- ln (l + 050 x 10-5 x 0406 x 10000) D S 050 x l0- 5
- -p~ = 4019 psi P = 981 psi ~
I
Thus if the 1surface pressure r5 were set at 947 the pressure at the
sea bottom trans~ucer would be 5000 +- 34 psi even if the temperature of
the 20degAPI gravity oil varied between 70deg and l20degF
Example 4
I 110000 ft ~omp etion P f 5000 psi0
60deg API 6060degF Sp Gr = 07389 Temp
70degF
l 20degF
From Fig l I ~ -5 -1
F = Oi80 x 10 psi I middot -5 -1F = 110 x 10 psmiddotiI
From Table 23 (API----middotmiddot Sp Gr = 07344
Sp Gr= 07117
STD 2540)
middot F x 5000 F x 5000At 5000 ps1 1 gp 5000 = gp = 0~34 x (Sp Gr)e e0 0
80At 70degF gp middot = 0434 (o 7344)e0middot x 10-5 x 5000
~ooo = o332 psift
_ llxl0_ 5 x5oooAt 120degF gp5000 - 0434 (07117)e
= 0326 psift P ~ P ~ t ln (1 + fp gD)D S D
At 70degF Po_ p = ~__]-____ ln (l + Q80 x lo- 5 x 0332 x 10000) s 080 x 10-~
= 3277 psi I P5 ~ 5000 - 3277 = 1723 psi
At l20degF PD - PS = l 5 ln (l + l l x 10-5 x 0326 x 10000) llOxlOshy
= 3203 psi
PS = 5000 - 3202 = 1797 psi
shybull
Thus if the surface pressure P5 were set at 1760 psi the presshy
sure at the sea ~ottom transducer would be 5000 + 37 psi even if the I shy
temperature cf the 60deg API gravity oil varied between 70deg and 120degF
From these pxample calculations for a 10000 ft completion it is
apparent that temperature variations cause r~latively small errors in I
sea floor ca 1 i bration pressures even for sue~ a great depth If the
pressures are needed more acet1rately than this then the temperature
profile in the tubing would be needed
It has thus been shown that relatively simple calculations of
liquid hydrostatic head result in accurate pressure values for calishy
bration of subsea transducers I
The calibration of gas pressure transdutersmiddot is somewhat different
For low pressures and shallow depth little correction need be made to
the pressure measured at the surface For a gas specific gravity SG
(relative to ai~ at 20degC and 147 psia) pressure P(psia) and depth I
D(ft) the pressure correction AP is given by
-5AP = 356 x 10 x SG x P x D
This equation assumes that the ideal gas law holds and that tPP
is small The equation nay be modified to include the super-compresshy
sibility factor z as follows 0
AP= 356 x 10-Sx SG x D x Pz
For a 1000 ft deep subsea completion line pressure of 1000 psia
(assuming SG ~ 1 and z = 1) AF= 36 psi It is thus apparent that even with large errors in specific gravity and z the pressure correction
1
for hydrostatic head of the gqs is small for depths up to 1000 ft
-bull
Again for a line pressure of 1000 psi but a 10000 ft deep comshy
pletion llP = 3~0 psi so the assumption of PP being small no longer
holds An integration would thus be needed to determine the transducer
pressure and t~e vaHable z factor should be included in thi~ integral Thus a closed form solution similar to tha~ found for liquids cannot
be obtained an~ numerical integration is necessary However for a wide range of conditions the equations pre~ented for both liquids and
I II gases a11 ow acc4ra te cal i bratfon of sea bottom pressure transducers
through the production tubing~ I
I
- -
6 J_nspection_B$9YJrcment_~and Te~t Proc~dures j
The OCS Ord~rs ~ere reviewed for those item~ pertinent to a subsea system The OCS inspection requirements and the suggested general
inspection procedures for these items are discussed in the following
paragraphs Tubing PLtg_
I
Inspection Requirements (OCS Order No 5)I
1 T~e s~~tained liquid leakage flow should not exceed I
400 ccmin 2 The ga~ leakage flo~1 should nGt e)ceed 15 cu ftmin
General Pro~middotedure
The first step i~ this procedure is to isolate a column of fluid
between the tubing plug and the inspector with the valves opened as
for production except that the tubing plug is in pl ace Any fl ow reaching the inspector at the surface is a direct indication of leakage past the tubing plug Thermal equilibrium may b~ required if the
maximum allowabl~ leakage is too small Theflow volume can be measured at the surface in the same manner as for conventionlt1 platform systems
I
middotShut-in Tubi9_ls_e_sur~
Inspection Requirements (OCS Order No I
5)
1 Wells with a shut-in tubing ptessure of 4000 psig or
greater sha11 be equj pped with a subsurface-~ontro11 ed subsurface safety device
-J
2 When the shut-in tubing pressure declines below 4000 I
psig a remotely sontrolled subsurface safety device shall be installed
when the tubing is first removed and reinstalled
General Procedure
To determine if the shut-i~ tubing pressure i~ greater than 4000 psig I
a pressure sensor should be located ~1here the shut-in pressure can be sensed
A convenient arrangement is to locate a pressure s~nsor between the master
valve and wing valve on each tubing With the downhole safety valve and
master valve opened and the wing valve close~ the shmicrot-in tubing pressure
as indicated by the sensor is noted
Calibration of the pressure sensor can be accomplished by applying
a known pressure ~t the surface to a closed cdlumn of fluid connecting I
the surface with the sensor with corrections calculated as explained
in Section 5
Subsurface Safety Device
Inspection Requirements (OCS Order No 5) 1 A surface-controlled subsurface safety device shall be
test operated every six months
2 A subsurface-controlled subsurface safety device shall
be removed inspected and repaired every 12 mdnths 1
General Procedure To test a surface-controlled subsurface safety device the well
should be opened for production and the command then given to close
the subsurface Sifety device The leakage flqw volume if any is
measured at the surface in the same manner as for conventional plat shy
form sys terns bull
1
-)
Pressure Relief Valves Inspection Requtrements (0CS Order No 8)
All pressure reli-f valve~ shall be either bench tested for opershy
ation or tested with an external pressure source (if the valve is somiddot
equipped)annually Jtbt Wf SJJS~+ General Procedure
To test a pressure relief valve for operation the vessel or line
should be pressunizeq to the pressure necessary to open the valve by
using the method suggested in Section 5 Uriless remote position inshy
dicators are provided a means to determine ~hether or not the valve
has actually ope1ed would have to be devised bullfor each subsea system
by observing the effect on the pressure sensors Pressure Sensors
Inspection Requirements (OCS Order No 8)
All pressure sensors shall be tested at least once each month
General Procedure
To remotely test and cal i~rate a subsea bullpressure sensor it is
necessary to
(1) isolate a closed column of fluid irom the surface to
the subsea sensor by properly arranging the ~ys terns va1ves
(2) determine the specific gravity compressibility and the
column height of the fluid
(3) select the pressure required at the subsea sensor
(4) apply the appropriate pressure at the surface end of
the column and
(5) compare the telemetered press4re signal or indication
with the pressur~ applied to the sensor
Automatic Hellhead Safety Devices -~~__--r---
Inspection 8equiremcnts (OCS Order No 8) All automatic wellhead safety devices shall be tested for operation
I
and holding pres~ureonce each1month
I
- -
bull )
General Prooedure
To test the operation of the automatic well head safety devices
the out-of-the-tolerance condition (usually ~igh or low pressure) which actuates the devices should be simulated Urless position 1ndicators
I
are provided a means to deterrl1ine whether 011 not the valves have
actually closed ~ust be devised for each indi1vidu~l system because of
the peculiarities
in each syste m J I
L~ 6 - Jlaquo4 sfSf~ rCheck Valves ~J0141d 11tJt NC Uf~ l(I -v-
Inspection Requirements (OCS Order No ~)
A11 check valves on a11 fl ow 1i nes sha11 be tested for opera ti on
and holding pressure once each month
General Procedures
To test the check valve ft will have to be back pressured The
check valve fails to operate properly if any back flo~1 through the I
valve occurs
~iguid Level Shut-in Controls I
Inspection Requirements (9cs Order No 8)
All liquid-l 1
evel shut-in controls shall be tested once each month
by raising or lowering liquid level across the leyel-control detector
General Pro~edure I
The preferable way to test the liquid-level sh~t-in controls is to
simulate the out-of-tolerance conditions (1 iquid Jevel either low or I
high) at the sensor This sim~lation should cau~e either the inlet
shutoff va1ve to close or the discharge shutoff valve to close In
this manner both the control YStem and the automatif valves are tested I
A means will have to be devised for each subsea system to determine I
if the out-of-tolerance condition actually occurred at the sensor if
it was properly Jetected and i~ it caused thd proper actuation I
Vessel Automatic~Inlet-Shutoff Valves I
Inspection ~equirement (OCS Order No 8)I
-I I
bull ) ~ J) All automatic~~~~~-shutoff valves actuated by vessel~~
I
~fsensorj shalil be tested for operation onle each month General Procedure
Described above under gene~al procedure for Liquid-Level Shut-
In Controls Vessel AutomaJi c-Di sc_b~_g_e-Sh_ll__Dff__Y_ii_l ves
Inspection RequireiT1ent (OCS Order No 8) All automatic-discharge-shutoff valves actuated by vessel lowshy
level sensors shall be tested for operation qnce each month
General Proc~dure
Described above under Liquid-Level Shut-tn Controls
High-tempera_ure Coniprc2_()r-Sh_t1tdow_ri_Co~_o1s Inspection Requirement (OCS Order No 8)i
High temperature controls which protect the compressor against
abnormal pressure~ soltiY by such temperature
safety devices shall be tested annually
General Procedure Because of the danger involved in elevating the temperature suffi shy
ciently to cause + temperature device to actuate it is recommended that each temperature device be pre-tested and replaced each year rather than be tested remotely
Oil Spil 1 Detection E_g_t_pmen~
Inspection Requirements (OCS Order 7) All platforms and structures are require~ to have curbs gutters
and spill pans connected to a tank or sump fhis equipment is required to collect all hydrocarbon spillage on the platform It is recommended that this requirement be extencjed to require all unenclosed subsea
equipment to be covered by inverted spill pans with hydrocarbon sensors
and sumps to rem~ve spillage
General Procedure To test the hydrocarbon spi 11 age detection and removal system
a controlled spill should be made in each ar~a or section of spill
- bull
pans while th~ SUljlPI
pumps are monitored for proper operation This I I
metbod will require a signal to the surface to indicate directly when the pumps are running or indirectly by indicating a pressure rise in
I i
the affected pipeline due to the pun1ping action The indirect method is preferablebec~use the pressure rise not only indicates the pumps are running b~t indicates they also are pumpi~g fluid One additional safeguard should ~e employed A TV camera should be used to observe
I
the spill pans in the vicinity of the spill to assure that they are not leaking due to damage or inadequacy of de~ign Hydrocarbon S~nsors
IInspection Requirements
Hydrocarbon sensors are not covered in tbe OCS Qrders presently
in effect General Procedure The general test procedure for the oil-spill-detection equipment
above will test the hydrocarbon sensors for operation In addition
I bull some means of knowing when each separate hydrocarbon sensor in the
spill pan assemblies hus sensed hydrocarbon will provide additional I
protection by warning of system degradation b~fore the system is comshypletely inoperable
7 Summary and RecQ)enda tions This report deal~ with the inspection problems that have arisen
as a result of the present trend of the offshore oil industry towards
subsea completion and production of deep water petroleum reservoirs I
Inspection techniques for completion and prod~ction equipment are inshyvestigated but inspection of fiser systems submersibles and strucshy
tures are not inc~uded in the scope of this wprk
A technique ~as been detailed for calibr1ttion of subsea sensors I
and for verifying the proper OReration of va1ves The technique reshy
quires only that the inspector 1 have access to production tubing at
- bull
I I
the surface By actuating subsurface control valves from the surface
the inspector can isolate a closed fluid path1 to the point of interest I
Pressures read at the surface (when corrected for hydraulic gradients)
may then be used to ca 1 i brate subsurface tran1sducers Flow rates
measured at the surface can be used to I
indicate leakage rates bull
from
subsurface valves I
but fluid in the tubing must be allow
ed to reach
sufficient therma1l equilibriumwith its surroundings so that a false leakage rate is riot indicated due to thermal expansion of the fluid
I bull
This technique has been used to work ou~ an inspection procedure
for the Exxon Sulisea Production System The 1procedure demonstrates I I
that the necessany closed fluid paths can be obtained to permit inshyspection of all necessary points Thus from 1a theoretical point of et
j9aYYew 1 t has ~en established that accurate euroVa 1ua tion of subsea con- J
ditions can be made from the surface (io implement the procedures I
it would first be necessary to conduct an experimental program with field
tests to determi~e operational problems) tAtti e
bull
- Inspection of subsea production systems
-
middot l middot11 _I ] ii J l ff - middot1middot -middot
lmiddotshyltl
ltfl lbullJ JJ n 0 w 0
Dr~1 r-----~d ir f ~cmiddotmiddotmiddot t- E 1 1 0~-~0n f r AC-lgt Ilei nd C L C_fJJ middotcmiddotr -cmiddotibili~v of Liquid Ii-C-xmiddotirlmiddot~-1~ lbullo= AJ 5 I1middotJ ~7middot~i 1~iJ
~t-tbulln Con1r1middot~)11a11~ of Jiqr1d fl1r bullr11lon_~0middot1H1almmmiddotb~~____
r_c 1
~ -t c~ Ibull_~- 4-r r sngt llI
Integrating both sides results in
= F(P-Ps1
p = eF(P-P~)or PS ( 1 )
where the subscript s indicates surface cdnditions Equation (1)
relates the density 2t any depth in the fluid column to the pressure at that point
For a small change in fluid depth dP =pgdh (2)
where dh is the change in depth Substituting eq~ation (1) into (2)
dP =p geF(P-Ps)dh s
-F(P-P ) or p gdh= e s dP s
Integrating from the surface to a total depth D
-F(P-P ) -F(P -P )1 s e D s + 1= - e = shyf fI
-Rearranging we have
or I
It is interesting to note that gp 5D is the pressure head expected for an incompressible fluid If FgrsDlaquo l (that is the fluid is nearly incompressible) then equation 3 simplifies to
Po-Ps = gPsD
(note lnl+x) ~ x for x laquo 1)
For an example of the type of error that might occur if compressibility
is not considered assume gp 5D = 4000 psi (as it would for an ~gproxi mately 10000 ft deep subsea completion) and that F = 2 x 10 psi Thus
4Po-Ps = -5 x 10 ln(l-008) = 4170 psi
If compressibility had been ignored the pre~sure error would have been 170 psi This analysis has assumed that temperature is constant with depth and that the compressibility of hydrocarbon liquids does not depend on pressure The APl STD 1101 values for compressibility were based on data from zero to 1000 psig
so more data may be reshyquired to assure pressure independence
For cases in which the subsea conditions have been specified (for example setting a downhole pressure for cal~bration of a transducer) the surface presure P required to establish the condition is unknown s Thus the surface density re qui red to solve equation 3 is also unknown A derivation similar to the above shows that the hydrostatic pressure
--difference in terms of subsea conditions is
P0-Ps = ~ ln 0 + fp 0gD) (4)
The density of the oil is most usually known at atmospheric pressure
so the density at pressure P0is found from the atm~spheric density p 0
from equation 1
P0 0 FP = r e D (5)
The use of the above equation assumes a constant temperature so that density varfotions in the tubing are caused only by pressure The
density at atmosp~eric pressure and the desired temperature are found by using table 23 API STD 2540 (ASTM-IP Petroleum Measurement
Tables) to correct the standard density measured at 60degF relative to I
water at 60degF (Sp Gr 6060degF) Specific gravity may be found from
API gravity by usi 1
ng Tible 3 from API STD 2540 or from the equationI I
Sp Gr 6060~F = 1415(APl Gravity at 60degF + 1315)
In the follo~ing paragraphs several examples will be worked to I
demonstrate the uSJe of the equations and to show t~e effect of a
temperature gradi~nt in the oil from the ocean floor to the surface I
The example will i 1nclude two different oils 20deg and 60deg API 6060degF)
at two temperatur~s (70degF and 120degF) and two completion depths
(l000 ft and 101 000 ft) The equations wil1 be solved for surface
pressure assuming a sea bottom transducer is being calibrated at l000 psi
for the 1000 ft 1deep completion and at 5000
psi for the 10000 ft
deep completion The 1000 ft- depth was chosen because H represents I
present capa bi 1 i ties for subsea completion l Q 000 ft las chosen as a maximum depth fqr completions in the foreseeable future (in
areas such as the ~leutian Basin)
i I __ _l__
-Example 1
1000 ft completion -- = 1000 psiP0 20deg API 6060~F -- Sp Gr = 09340
Temp From Fig 1 From Table 23 (API STD 2540) I
70degF F = 039 x 10-5 ps1middot-T Sp Gr = 09305 -5 -1 J
120degF F = 050 x 10 psi Sp Gr bull 09130 At 1000 psi gpl~OO = gp x lOOO = 0434 x (=~middot Gr )0 x lOOO
0
At 70F gplOOO =0434 (09305) e039 x cO x 1000 1 bull
=0405 p~~
-5 0 ( ) eo 50 x 10 x 1000
At 120 F gplOOO ~ 0434 09130
o0398 poundft 1Po - PS =-F- ln (1 + F~D gD)
At 70degFmiddot P P - l ln (1 + 039 x 10-5 x 0405 x 1000) D - S - 039 x 10-S
= 405 psi Ps = lopo - 405 = 595 psi
At 120degF Po - p = l ln (l + ~50 x 10-5 x 0398 x 1000) s 050 x 10-5
= 398 psi P~ = 1000 - 398 = 60 psi
Thus if the $urface pressure P5 were setat 599 psi the pressure
at the sea bottom transducer 1~ould be 1000 4 psi even if the temperature
of the 20deg API gravity oil varied between 70 and 120degF
bull
Example 2 I
1000 ft completion -- P~ = 1000 psi I
I
60deg API 6060deg F -- Sp Gri = 0 7389 From Pi_g__j_ From Table 23 (API STD 25401
70degF F = 0~80 x 10-5 psi-1 Sp Gr bull 07344 -5 -1
120degF F = l10 x 10 psi Sp Gr bull 07117 At 1000 psi pg middot = gp eF x 1000 = 0434middotx (Sp Gr) eF x 1000
1000 o middot o i 080 ~ 10~5 x 1000
At 70degF 9P]OOO bull 0434 (07344) e bull 0321 psift I
1 i o x i o~s x 1 oooAt 120degF gP1000 bull 0434 (07117)e
I = 03]2 psift
PD - Ps = F1 1 n (1 + F PD9 D)
1At 70degF PD
I
- Ps = _ ln (1 +1080 x io-5 x 0321 x 1000)5
080 x 10 = 321 psi
PS bull 679 psi
At 120degF P~ --1----~5 ln (1 + 1 1lO x 10-5 x 0312 x 1000) 110 x 10
= 311 psi Ps = 689 psi
Thus if the surtace pressure P5 were set atmiddot684psi the pressure at the sea bottom transducer would be 1000 plusmn_ 5 psi ~ven if the temperature of the 60deg API gravity oil varied between 70deg and 120degF
bull
I
From the foregoing examples it is apparrnt that for subsea compleshytions up to 1000 ft there is little effect on the calculated
I
pressure at a suhsea transducer due to compressibility and temperature bull
The pressure ca~ be accurately calculated from ~ I bullr
PD - PS = 0434 x Sp Gr x D where the specific gravity of the oil at sta~dard conditions has been corrected to the observed temperature (using an average between the subsea and surface oil temperatures) and 1 i ne pressure Example 3
10000 ft c~mpletion -- P0 = 5000 psi 20deg API 6060degF Sp Gr = 09340
From Fi9 l From Teble 23 (API STD 2540)
70deg F = 039 x l0-5psi-l Sp Gr = 09305 120deg F = 050 x l0-5psi-l Sp Gr = 09130
F x 5000 F x 5000At 5000 psi gp5poo = gp e = 0434 x
I
(=~middotGr ) e0 0
At 70F 9P5poo = 0434 (09305)e039 x 10 x 5000
= 0412 psift I
50 x 5000At 120F 9P~ooo = 0434 (09130)e0middot x 10 -5
= 0406 psift 1
PD - PS= -F- ln (l + Fp gD)0 __L__-=s 1nAt 70degF P ~ (l + 0~39 x 10-5 x 0412 x 10000
D I
P5 039 x 10 = 4087 psi ~ 5000 - 4087 = 913 psir5
At l20F P - P =--1-- ln (l + 050 x 10-5 x 0406 x 10000) D S 050 x l0- 5
- -p~ = 4019 psi P = 981 psi ~
I
Thus if the 1surface pressure r5 were set at 947 the pressure at the
sea bottom trans~ucer would be 5000 +- 34 psi even if the temperature of
the 20degAPI gravity oil varied between 70deg and l20degF
Example 4
I 110000 ft ~omp etion P f 5000 psi0
60deg API 6060degF Sp Gr = 07389 Temp
70degF
l 20degF
From Fig l I ~ -5 -1
F = Oi80 x 10 psi I middot -5 -1F = 110 x 10 psmiddotiI
From Table 23 (API----middotmiddot Sp Gr = 07344
Sp Gr= 07117
STD 2540)
middot F x 5000 F x 5000At 5000 ps1 1 gp 5000 = gp = 0~34 x (Sp Gr)e e0 0
80At 70degF gp middot = 0434 (o 7344)e0middot x 10-5 x 5000
~ooo = o332 psift
_ llxl0_ 5 x5oooAt 120degF gp5000 - 0434 (07117)e
= 0326 psift P ~ P ~ t ln (1 + fp gD)D S D
At 70degF Po_ p = ~__]-____ ln (l + Q80 x lo- 5 x 0332 x 10000) s 080 x 10-~
= 3277 psi I P5 ~ 5000 - 3277 = 1723 psi
At l20degF PD - PS = l 5 ln (l + l l x 10-5 x 0326 x 10000) llOxlOshy
= 3203 psi
PS = 5000 - 3202 = 1797 psi
shybull
Thus if the surface pressure P5 were set at 1760 psi the presshy
sure at the sea ~ottom transducer would be 5000 + 37 psi even if the I shy
temperature cf the 60deg API gravity oil varied between 70deg and 120degF
From these pxample calculations for a 10000 ft completion it is
apparent that temperature variations cause r~latively small errors in I
sea floor ca 1 i bration pressures even for sue~ a great depth If the
pressures are needed more acet1rately than this then the temperature
profile in the tubing would be needed
It has thus been shown that relatively simple calculations of
liquid hydrostatic head result in accurate pressure values for calishy
bration of subsea transducers I
The calibration of gas pressure transdutersmiddot is somewhat different
For low pressures and shallow depth little correction need be made to
the pressure measured at the surface For a gas specific gravity SG
(relative to ai~ at 20degC and 147 psia) pressure P(psia) and depth I
D(ft) the pressure correction AP is given by
-5AP = 356 x 10 x SG x P x D
This equation assumes that the ideal gas law holds and that tPP
is small The equation nay be modified to include the super-compresshy
sibility factor z as follows 0
AP= 356 x 10-Sx SG x D x Pz
For a 1000 ft deep subsea completion line pressure of 1000 psia
(assuming SG ~ 1 and z = 1) AF= 36 psi It is thus apparent that even with large errors in specific gravity and z the pressure correction
1
for hydrostatic head of the gqs is small for depths up to 1000 ft
-bull
Again for a line pressure of 1000 psi but a 10000 ft deep comshy
pletion llP = 3~0 psi so the assumption of PP being small no longer
holds An integration would thus be needed to determine the transducer
pressure and t~e vaHable z factor should be included in thi~ integral Thus a closed form solution similar to tha~ found for liquids cannot
be obtained an~ numerical integration is necessary However for a wide range of conditions the equations pre~ented for both liquids and
I II gases a11 ow acc4ra te cal i bratfon of sea bottom pressure transducers
through the production tubing~ I
I
- -
6 J_nspection_B$9YJrcment_~and Te~t Proc~dures j
The OCS Ord~rs ~ere reviewed for those item~ pertinent to a subsea system The OCS inspection requirements and the suggested general
inspection procedures for these items are discussed in the following
paragraphs Tubing PLtg_
I
Inspection Requirements (OCS Order No 5)I
1 T~e s~~tained liquid leakage flow should not exceed I
400 ccmin 2 The ga~ leakage flo~1 should nGt e)ceed 15 cu ftmin
General Pro~middotedure
The first step i~ this procedure is to isolate a column of fluid
between the tubing plug and the inspector with the valves opened as
for production except that the tubing plug is in pl ace Any fl ow reaching the inspector at the surface is a direct indication of leakage past the tubing plug Thermal equilibrium may b~ required if the
maximum allowabl~ leakage is too small Theflow volume can be measured at the surface in the same manner as for conventionlt1 platform systems
I
middotShut-in Tubi9_ls_e_sur~
Inspection Requirements (OCS Order No I
5)
1 Wells with a shut-in tubing ptessure of 4000 psig or
greater sha11 be equj pped with a subsurface-~ontro11 ed subsurface safety device
-J
2 When the shut-in tubing pressure declines below 4000 I
psig a remotely sontrolled subsurface safety device shall be installed
when the tubing is first removed and reinstalled
General Procedure
To determine if the shut-i~ tubing pressure i~ greater than 4000 psig I
a pressure sensor should be located ~1here the shut-in pressure can be sensed
A convenient arrangement is to locate a pressure s~nsor between the master
valve and wing valve on each tubing With the downhole safety valve and
master valve opened and the wing valve close~ the shmicrot-in tubing pressure
as indicated by the sensor is noted
Calibration of the pressure sensor can be accomplished by applying
a known pressure ~t the surface to a closed cdlumn of fluid connecting I
the surface with the sensor with corrections calculated as explained
in Section 5
Subsurface Safety Device
Inspection Requirements (OCS Order No 5) 1 A surface-controlled subsurface safety device shall be
test operated every six months
2 A subsurface-controlled subsurface safety device shall
be removed inspected and repaired every 12 mdnths 1
General Procedure To test a surface-controlled subsurface safety device the well
should be opened for production and the command then given to close
the subsurface Sifety device The leakage flqw volume if any is
measured at the surface in the same manner as for conventional plat shy
form sys terns bull
1
-)
Pressure Relief Valves Inspection Requtrements (0CS Order No 8)
All pressure reli-f valve~ shall be either bench tested for opershy
ation or tested with an external pressure source (if the valve is somiddot
equipped)annually Jtbt Wf SJJS~+ General Procedure
To test a pressure relief valve for operation the vessel or line
should be pressunizeq to the pressure necessary to open the valve by
using the method suggested in Section 5 Uriless remote position inshy
dicators are provided a means to determine ~hether or not the valve
has actually ope1ed would have to be devised bullfor each subsea system
by observing the effect on the pressure sensors Pressure Sensors
Inspection Requirements (OCS Order No 8)
All pressure sensors shall be tested at least once each month
General Procedure
To remotely test and cal i~rate a subsea bullpressure sensor it is
necessary to
(1) isolate a closed column of fluid irom the surface to
the subsea sensor by properly arranging the ~ys terns va1ves
(2) determine the specific gravity compressibility and the
column height of the fluid
(3) select the pressure required at the subsea sensor
(4) apply the appropriate pressure at the surface end of
the column and
(5) compare the telemetered press4re signal or indication
with the pressur~ applied to the sensor
Automatic Hellhead Safety Devices -~~__--r---
Inspection 8equiremcnts (OCS Order No 8) All automatic wellhead safety devices shall be tested for operation
I
and holding pres~ureonce each1month
I
- -
bull )
General Prooedure
To test the operation of the automatic well head safety devices
the out-of-the-tolerance condition (usually ~igh or low pressure) which actuates the devices should be simulated Urless position 1ndicators
I
are provided a means to deterrl1ine whether 011 not the valves have
actually closed ~ust be devised for each indi1vidu~l system because of
the peculiarities
in each syste m J I
L~ 6 - Jlaquo4 sfSf~ rCheck Valves ~J0141d 11tJt NC Uf~ l(I -v-
Inspection Requirements (OCS Order No ~)
A11 check valves on a11 fl ow 1i nes sha11 be tested for opera ti on
and holding pressure once each month
General Procedures
To test the check valve ft will have to be back pressured The
check valve fails to operate properly if any back flo~1 through the I
valve occurs
~iguid Level Shut-in Controls I
Inspection Requirements (9cs Order No 8)
All liquid-l 1
evel shut-in controls shall be tested once each month
by raising or lowering liquid level across the leyel-control detector
General Pro~edure I
The preferable way to test the liquid-level sh~t-in controls is to
simulate the out-of-tolerance conditions (1 iquid Jevel either low or I
high) at the sensor This sim~lation should cau~e either the inlet
shutoff va1ve to close or the discharge shutoff valve to close In
this manner both the control YStem and the automatif valves are tested I
A means will have to be devised for each subsea system to determine I
if the out-of-tolerance condition actually occurred at the sensor if
it was properly Jetected and i~ it caused thd proper actuation I
Vessel Automatic~Inlet-Shutoff Valves I
Inspection ~equirement (OCS Order No 8)I
-I I
bull ) ~ J) All automatic~~~~~-shutoff valves actuated by vessel~~
I
~fsensorj shalil be tested for operation onle each month General Procedure
Described above under gene~al procedure for Liquid-Level Shut-
In Controls Vessel AutomaJi c-Di sc_b~_g_e-Sh_ll__Dff__Y_ii_l ves
Inspection RequireiT1ent (OCS Order No 8) All automatic-discharge-shutoff valves actuated by vessel lowshy
level sensors shall be tested for operation qnce each month
General Proc~dure
Described above under Liquid-Level Shut-tn Controls
High-tempera_ure Coniprc2_()r-Sh_t1tdow_ri_Co~_o1s Inspection Requirement (OCS Order No 8)i
High temperature controls which protect the compressor against
abnormal pressure~ soltiY by such temperature
safety devices shall be tested annually
General Procedure Because of the danger involved in elevating the temperature suffi shy
ciently to cause + temperature device to actuate it is recommended that each temperature device be pre-tested and replaced each year rather than be tested remotely
Oil Spil 1 Detection E_g_t_pmen~
Inspection Requirements (OCS Order 7) All platforms and structures are require~ to have curbs gutters
and spill pans connected to a tank or sump fhis equipment is required to collect all hydrocarbon spillage on the platform It is recommended that this requirement be extencjed to require all unenclosed subsea
equipment to be covered by inverted spill pans with hydrocarbon sensors
and sumps to rem~ve spillage
General Procedure To test the hydrocarbon spi 11 age detection and removal system
a controlled spill should be made in each ar~a or section of spill
- bull
pans while th~ SUljlPI
pumps are monitored for proper operation This I I
metbod will require a signal to the surface to indicate directly when the pumps are running or indirectly by indicating a pressure rise in
I i
the affected pipeline due to the pun1ping action The indirect method is preferablebec~use the pressure rise not only indicates the pumps are running b~t indicates they also are pumpi~g fluid One additional safeguard should ~e employed A TV camera should be used to observe
I
the spill pans in the vicinity of the spill to assure that they are not leaking due to damage or inadequacy of de~ign Hydrocarbon S~nsors
IInspection Requirements
Hydrocarbon sensors are not covered in tbe OCS Qrders presently
in effect General Procedure The general test procedure for the oil-spill-detection equipment
above will test the hydrocarbon sensors for operation In addition
I bull some means of knowing when each separate hydrocarbon sensor in the
spill pan assemblies hus sensed hydrocarbon will provide additional I
protection by warning of system degradation b~fore the system is comshypletely inoperable
7 Summary and RecQ)enda tions This report deal~ with the inspection problems that have arisen
as a result of the present trend of the offshore oil industry towards
subsea completion and production of deep water petroleum reservoirs I
Inspection techniques for completion and prod~ction equipment are inshyvestigated but inspection of fiser systems submersibles and strucshy
tures are not inc~uded in the scope of this wprk
A technique ~as been detailed for calibr1ttion of subsea sensors I
and for verifying the proper OReration of va1ves The technique reshy
quires only that the inspector 1 have access to production tubing at
- bull
I I
the surface By actuating subsurface control valves from the surface
the inspector can isolate a closed fluid path1 to the point of interest I
Pressures read at the surface (when corrected for hydraulic gradients)
may then be used to ca 1 i brate subsurface tran1sducers Flow rates
measured at the surface can be used to I
indicate leakage rates bull
from
subsurface valves I
but fluid in the tubing must be allow
ed to reach
sufficient therma1l equilibriumwith its surroundings so that a false leakage rate is riot indicated due to thermal expansion of the fluid
I bull
This technique has been used to work ou~ an inspection procedure
for the Exxon Sulisea Production System The 1procedure demonstrates I I
that the necessany closed fluid paths can be obtained to permit inshyspection of all necessary points Thus from 1a theoretical point of et
j9aYYew 1 t has ~en established that accurate euroVa 1ua tion of subsea con- J
ditions can be made from the surface (io implement the procedures I
it would first be necessary to conduct an experimental program with field
tests to determi~e operational problems) tAtti e
bull
- Inspection of subsea production systems
-
Integrating both sides results in
= F(P-Ps1
p = eF(P-P~)or PS ( 1 )
where the subscript s indicates surface cdnditions Equation (1)
relates the density 2t any depth in the fluid column to the pressure at that point
For a small change in fluid depth dP =pgdh (2)
where dh is the change in depth Substituting eq~ation (1) into (2)
dP =p geF(P-Ps)dh s
-F(P-P ) or p gdh= e s dP s
Integrating from the surface to a total depth D
-F(P-P ) -F(P -P )1 s e D s + 1= - e = shyf fI
-Rearranging we have
or I
It is interesting to note that gp 5D is the pressure head expected for an incompressible fluid If FgrsDlaquo l (that is the fluid is nearly incompressible) then equation 3 simplifies to
Po-Ps = gPsD
(note lnl+x) ~ x for x laquo 1)
For an example of the type of error that might occur if compressibility
is not considered assume gp 5D = 4000 psi (as it would for an ~gproxi mately 10000 ft deep subsea completion) and that F = 2 x 10 psi Thus
4Po-Ps = -5 x 10 ln(l-008) = 4170 psi
If compressibility had been ignored the pre~sure error would have been 170 psi This analysis has assumed that temperature is constant with depth and that the compressibility of hydrocarbon liquids does not depend on pressure The APl STD 1101 values for compressibility were based on data from zero to 1000 psig
so more data may be reshyquired to assure pressure independence
For cases in which the subsea conditions have been specified (for example setting a downhole pressure for cal~bration of a transducer) the surface presure P required to establish the condition is unknown s Thus the surface density re qui red to solve equation 3 is also unknown A derivation similar to the above shows that the hydrostatic pressure
--difference in terms of subsea conditions is
P0-Ps = ~ ln 0 + fp 0gD) (4)
The density of the oil is most usually known at atmospheric pressure
so the density at pressure P0is found from the atm~spheric density p 0
from equation 1
P0 0 FP = r e D (5)
The use of the above equation assumes a constant temperature so that density varfotions in the tubing are caused only by pressure The
density at atmosp~eric pressure and the desired temperature are found by using table 23 API STD 2540 (ASTM-IP Petroleum Measurement
Tables) to correct the standard density measured at 60degF relative to I
water at 60degF (Sp Gr 6060degF) Specific gravity may be found from
API gravity by usi 1
ng Tible 3 from API STD 2540 or from the equationI I
Sp Gr 6060~F = 1415(APl Gravity at 60degF + 1315)
In the follo~ing paragraphs several examples will be worked to I
demonstrate the uSJe of the equations and to show t~e effect of a
temperature gradi~nt in the oil from the ocean floor to the surface I
The example will i 1nclude two different oils 20deg and 60deg API 6060degF)
at two temperatur~s (70degF and 120degF) and two completion depths
(l000 ft and 101 000 ft) The equations wil1 be solved for surface
pressure assuming a sea bottom transducer is being calibrated at l000 psi
for the 1000 ft 1deep completion and at 5000
psi for the 10000 ft
deep completion The 1000 ft- depth was chosen because H represents I
present capa bi 1 i ties for subsea completion l Q 000 ft las chosen as a maximum depth fqr completions in the foreseeable future (in
areas such as the ~leutian Basin)
i I __ _l__
-Example 1
1000 ft completion -- = 1000 psiP0 20deg API 6060~F -- Sp Gr = 09340
Temp From Fig 1 From Table 23 (API STD 2540) I
70degF F = 039 x 10-5 ps1middot-T Sp Gr = 09305 -5 -1 J
120degF F = 050 x 10 psi Sp Gr bull 09130 At 1000 psi gpl~OO = gp x lOOO = 0434 x (=~middot Gr )0 x lOOO
0
At 70F gplOOO =0434 (09305) e039 x cO x 1000 1 bull
=0405 p~~
-5 0 ( ) eo 50 x 10 x 1000
At 120 F gplOOO ~ 0434 09130
o0398 poundft 1Po - PS =-F- ln (1 + F~D gD)
At 70degFmiddot P P - l ln (1 + 039 x 10-5 x 0405 x 1000) D - S - 039 x 10-S
= 405 psi Ps = lopo - 405 = 595 psi
At 120degF Po - p = l ln (l + ~50 x 10-5 x 0398 x 1000) s 050 x 10-5
= 398 psi P~ = 1000 - 398 = 60 psi
Thus if the $urface pressure P5 were setat 599 psi the pressure
at the sea bottom transducer 1~ould be 1000 4 psi even if the temperature
of the 20deg API gravity oil varied between 70 and 120degF
bull
Example 2 I
1000 ft completion -- P~ = 1000 psi I
I
60deg API 6060deg F -- Sp Gri = 0 7389 From Pi_g__j_ From Table 23 (API STD 25401
70degF F = 0~80 x 10-5 psi-1 Sp Gr bull 07344 -5 -1
120degF F = l10 x 10 psi Sp Gr bull 07117 At 1000 psi pg middot = gp eF x 1000 = 0434middotx (Sp Gr) eF x 1000
1000 o middot o i 080 ~ 10~5 x 1000
At 70degF 9P]OOO bull 0434 (07344) e bull 0321 psift I
1 i o x i o~s x 1 oooAt 120degF gP1000 bull 0434 (07117)e
I = 03]2 psift
PD - Ps = F1 1 n (1 + F PD9 D)
1At 70degF PD
I
- Ps = _ ln (1 +1080 x io-5 x 0321 x 1000)5
080 x 10 = 321 psi
PS bull 679 psi
At 120degF P~ --1----~5 ln (1 + 1 1lO x 10-5 x 0312 x 1000) 110 x 10
= 311 psi Ps = 689 psi
Thus if the surtace pressure P5 were set atmiddot684psi the pressure at the sea bottom transducer would be 1000 plusmn_ 5 psi ~ven if the temperature of the 60deg API gravity oil varied between 70deg and 120degF
bull
I
From the foregoing examples it is apparrnt that for subsea compleshytions up to 1000 ft there is little effect on the calculated
I
pressure at a suhsea transducer due to compressibility and temperature bull
The pressure ca~ be accurately calculated from ~ I bullr
PD - PS = 0434 x Sp Gr x D where the specific gravity of the oil at sta~dard conditions has been corrected to the observed temperature (using an average between the subsea and surface oil temperatures) and 1 i ne pressure Example 3
10000 ft c~mpletion -- P0 = 5000 psi 20deg API 6060degF Sp Gr = 09340
From Fi9 l From Teble 23 (API STD 2540)
70deg F = 039 x l0-5psi-l Sp Gr = 09305 120deg F = 050 x l0-5psi-l Sp Gr = 09130
F x 5000 F x 5000At 5000 psi gp5poo = gp e = 0434 x
I
(=~middotGr ) e0 0
At 70F 9P5poo = 0434 (09305)e039 x 10 x 5000
= 0412 psift I
50 x 5000At 120F 9P~ooo = 0434 (09130)e0middot x 10 -5
= 0406 psift 1
PD - PS= -F- ln (l + Fp gD)0 __L__-=s 1nAt 70degF P ~ (l + 0~39 x 10-5 x 0412 x 10000
D I
P5 039 x 10 = 4087 psi ~ 5000 - 4087 = 913 psir5
At l20F P - P =--1-- ln (l + 050 x 10-5 x 0406 x 10000) D S 050 x l0- 5
- -p~ = 4019 psi P = 981 psi ~
I
Thus if the 1surface pressure r5 were set at 947 the pressure at the
sea bottom trans~ucer would be 5000 +- 34 psi even if the temperature of
the 20degAPI gravity oil varied between 70deg and l20degF
Example 4
I 110000 ft ~omp etion P f 5000 psi0
60deg API 6060degF Sp Gr = 07389 Temp
70degF
l 20degF
From Fig l I ~ -5 -1
F = Oi80 x 10 psi I middot -5 -1F = 110 x 10 psmiddotiI
From Table 23 (API----middotmiddot Sp Gr = 07344
Sp Gr= 07117
STD 2540)
middot F x 5000 F x 5000At 5000 ps1 1 gp 5000 = gp = 0~34 x (Sp Gr)e e0 0
80At 70degF gp middot = 0434 (o 7344)e0middot x 10-5 x 5000
~ooo = o332 psift
_ llxl0_ 5 x5oooAt 120degF gp5000 - 0434 (07117)e
= 0326 psift P ~ P ~ t ln (1 + fp gD)D S D
At 70degF Po_ p = ~__]-____ ln (l + Q80 x lo- 5 x 0332 x 10000) s 080 x 10-~
= 3277 psi I P5 ~ 5000 - 3277 = 1723 psi
At l20degF PD - PS = l 5 ln (l + l l x 10-5 x 0326 x 10000) llOxlOshy
= 3203 psi
PS = 5000 - 3202 = 1797 psi
shybull
Thus if the surface pressure P5 were set at 1760 psi the presshy
sure at the sea ~ottom transducer would be 5000 + 37 psi even if the I shy
temperature cf the 60deg API gravity oil varied between 70deg and 120degF
From these pxample calculations for a 10000 ft completion it is
apparent that temperature variations cause r~latively small errors in I
sea floor ca 1 i bration pressures even for sue~ a great depth If the
pressures are needed more acet1rately than this then the temperature
profile in the tubing would be needed
It has thus been shown that relatively simple calculations of
liquid hydrostatic head result in accurate pressure values for calishy
bration of subsea transducers I
The calibration of gas pressure transdutersmiddot is somewhat different
For low pressures and shallow depth little correction need be made to
the pressure measured at the surface For a gas specific gravity SG
(relative to ai~ at 20degC and 147 psia) pressure P(psia) and depth I
D(ft) the pressure correction AP is given by
-5AP = 356 x 10 x SG x P x D
This equation assumes that the ideal gas law holds and that tPP
is small The equation nay be modified to include the super-compresshy
sibility factor z as follows 0
AP= 356 x 10-Sx SG x D x Pz
For a 1000 ft deep subsea completion line pressure of 1000 psia
(assuming SG ~ 1 and z = 1) AF= 36 psi It is thus apparent that even with large errors in specific gravity and z the pressure correction
1
for hydrostatic head of the gqs is small for depths up to 1000 ft
-bull
Again for a line pressure of 1000 psi but a 10000 ft deep comshy
pletion llP = 3~0 psi so the assumption of PP being small no longer
holds An integration would thus be needed to determine the transducer
pressure and t~e vaHable z factor should be included in thi~ integral Thus a closed form solution similar to tha~ found for liquids cannot
be obtained an~ numerical integration is necessary However for a wide range of conditions the equations pre~ented for both liquids and
I II gases a11 ow acc4ra te cal i bratfon of sea bottom pressure transducers
through the production tubing~ I
I
- -
6 J_nspection_B$9YJrcment_~and Te~t Proc~dures j
The OCS Ord~rs ~ere reviewed for those item~ pertinent to a subsea system The OCS inspection requirements and the suggested general
inspection procedures for these items are discussed in the following
paragraphs Tubing PLtg_
I
Inspection Requirements (OCS Order No 5)I
1 T~e s~~tained liquid leakage flow should not exceed I
400 ccmin 2 The ga~ leakage flo~1 should nGt e)ceed 15 cu ftmin
General Pro~middotedure
The first step i~ this procedure is to isolate a column of fluid
between the tubing plug and the inspector with the valves opened as
for production except that the tubing plug is in pl ace Any fl ow reaching the inspector at the surface is a direct indication of leakage past the tubing plug Thermal equilibrium may b~ required if the
maximum allowabl~ leakage is too small Theflow volume can be measured at the surface in the same manner as for conventionlt1 platform systems
I
middotShut-in Tubi9_ls_e_sur~
Inspection Requirements (OCS Order No I
5)
1 Wells with a shut-in tubing ptessure of 4000 psig or
greater sha11 be equj pped with a subsurface-~ontro11 ed subsurface safety device
-J
2 When the shut-in tubing pressure declines below 4000 I
psig a remotely sontrolled subsurface safety device shall be installed
when the tubing is first removed and reinstalled
General Procedure
To determine if the shut-i~ tubing pressure i~ greater than 4000 psig I
a pressure sensor should be located ~1here the shut-in pressure can be sensed
A convenient arrangement is to locate a pressure s~nsor between the master
valve and wing valve on each tubing With the downhole safety valve and
master valve opened and the wing valve close~ the shmicrot-in tubing pressure
as indicated by the sensor is noted
Calibration of the pressure sensor can be accomplished by applying
a known pressure ~t the surface to a closed cdlumn of fluid connecting I
the surface with the sensor with corrections calculated as explained
in Section 5
Subsurface Safety Device
Inspection Requirements (OCS Order No 5) 1 A surface-controlled subsurface safety device shall be
test operated every six months
2 A subsurface-controlled subsurface safety device shall
be removed inspected and repaired every 12 mdnths 1
General Procedure To test a surface-controlled subsurface safety device the well
should be opened for production and the command then given to close
the subsurface Sifety device The leakage flqw volume if any is
measured at the surface in the same manner as for conventional plat shy
form sys terns bull
1
-)
Pressure Relief Valves Inspection Requtrements (0CS Order No 8)
All pressure reli-f valve~ shall be either bench tested for opershy
ation or tested with an external pressure source (if the valve is somiddot
equipped)annually Jtbt Wf SJJS~+ General Procedure
To test a pressure relief valve for operation the vessel or line
should be pressunizeq to the pressure necessary to open the valve by
using the method suggested in Section 5 Uriless remote position inshy
dicators are provided a means to determine ~hether or not the valve
has actually ope1ed would have to be devised bullfor each subsea system
by observing the effect on the pressure sensors Pressure Sensors
Inspection Requirements (OCS Order No 8)
All pressure sensors shall be tested at least once each month
General Procedure
To remotely test and cal i~rate a subsea bullpressure sensor it is
necessary to
(1) isolate a closed column of fluid irom the surface to
the subsea sensor by properly arranging the ~ys terns va1ves
(2) determine the specific gravity compressibility and the
column height of the fluid
(3) select the pressure required at the subsea sensor
(4) apply the appropriate pressure at the surface end of
the column and
(5) compare the telemetered press4re signal or indication
with the pressur~ applied to the sensor
Automatic Hellhead Safety Devices -~~__--r---
Inspection 8equiremcnts (OCS Order No 8) All automatic wellhead safety devices shall be tested for operation
I
and holding pres~ureonce each1month
I
- -
bull )
General Prooedure
To test the operation of the automatic well head safety devices
the out-of-the-tolerance condition (usually ~igh or low pressure) which actuates the devices should be simulated Urless position 1ndicators
I
are provided a means to deterrl1ine whether 011 not the valves have
actually closed ~ust be devised for each indi1vidu~l system because of
the peculiarities
in each syste m J I
L~ 6 - Jlaquo4 sfSf~ rCheck Valves ~J0141d 11tJt NC Uf~ l(I -v-
Inspection Requirements (OCS Order No ~)
A11 check valves on a11 fl ow 1i nes sha11 be tested for opera ti on
and holding pressure once each month
General Procedures
To test the check valve ft will have to be back pressured The
check valve fails to operate properly if any back flo~1 through the I
valve occurs
~iguid Level Shut-in Controls I
Inspection Requirements (9cs Order No 8)
All liquid-l 1
evel shut-in controls shall be tested once each month
by raising or lowering liquid level across the leyel-control detector
General Pro~edure I
The preferable way to test the liquid-level sh~t-in controls is to
simulate the out-of-tolerance conditions (1 iquid Jevel either low or I
high) at the sensor This sim~lation should cau~e either the inlet
shutoff va1ve to close or the discharge shutoff valve to close In
this manner both the control YStem and the automatif valves are tested I
A means will have to be devised for each subsea system to determine I
if the out-of-tolerance condition actually occurred at the sensor if
it was properly Jetected and i~ it caused thd proper actuation I
Vessel Automatic~Inlet-Shutoff Valves I
Inspection ~equirement (OCS Order No 8)I
-I I
bull ) ~ J) All automatic~~~~~-shutoff valves actuated by vessel~~
I
~fsensorj shalil be tested for operation onle each month General Procedure
Described above under gene~al procedure for Liquid-Level Shut-
In Controls Vessel AutomaJi c-Di sc_b~_g_e-Sh_ll__Dff__Y_ii_l ves
Inspection RequireiT1ent (OCS Order No 8) All automatic-discharge-shutoff valves actuated by vessel lowshy
level sensors shall be tested for operation qnce each month
General Proc~dure
Described above under Liquid-Level Shut-tn Controls
High-tempera_ure Coniprc2_()r-Sh_t1tdow_ri_Co~_o1s Inspection Requirement (OCS Order No 8)i
High temperature controls which protect the compressor against
abnormal pressure~ soltiY by such temperature
safety devices shall be tested annually
General Procedure Because of the danger involved in elevating the temperature suffi shy
ciently to cause + temperature device to actuate it is recommended that each temperature device be pre-tested and replaced each year rather than be tested remotely
Oil Spil 1 Detection E_g_t_pmen~
Inspection Requirements (OCS Order 7) All platforms and structures are require~ to have curbs gutters
and spill pans connected to a tank or sump fhis equipment is required to collect all hydrocarbon spillage on the platform It is recommended that this requirement be extencjed to require all unenclosed subsea
equipment to be covered by inverted spill pans with hydrocarbon sensors
and sumps to rem~ve spillage
General Procedure To test the hydrocarbon spi 11 age detection and removal system
a controlled spill should be made in each ar~a or section of spill
- bull
pans while th~ SUljlPI
pumps are monitored for proper operation This I I
metbod will require a signal to the surface to indicate directly when the pumps are running or indirectly by indicating a pressure rise in
I i
the affected pipeline due to the pun1ping action The indirect method is preferablebec~use the pressure rise not only indicates the pumps are running b~t indicates they also are pumpi~g fluid One additional safeguard should ~e employed A TV camera should be used to observe
I
the spill pans in the vicinity of the spill to assure that they are not leaking due to damage or inadequacy of de~ign Hydrocarbon S~nsors
IInspection Requirements
Hydrocarbon sensors are not covered in tbe OCS Qrders presently
in effect General Procedure The general test procedure for the oil-spill-detection equipment
above will test the hydrocarbon sensors for operation In addition
I bull some means of knowing when each separate hydrocarbon sensor in the
spill pan assemblies hus sensed hydrocarbon will provide additional I
protection by warning of system degradation b~fore the system is comshypletely inoperable
7 Summary and RecQ)enda tions This report deal~ with the inspection problems that have arisen
as a result of the present trend of the offshore oil industry towards
subsea completion and production of deep water petroleum reservoirs I
Inspection techniques for completion and prod~ction equipment are inshyvestigated but inspection of fiser systems submersibles and strucshy
tures are not inc~uded in the scope of this wprk
A technique ~as been detailed for calibr1ttion of subsea sensors I
and for verifying the proper OReration of va1ves The technique reshy
quires only that the inspector 1 have access to production tubing at
- bull
I I
the surface By actuating subsurface control valves from the surface
the inspector can isolate a closed fluid path1 to the point of interest I
Pressures read at the surface (when corrected for hydraulic gradients)
may then be used to ca 1 i brate subsurface tran1sducers Flow rates
measured at the surface can be used to I
indicate leakage rates bull
from
subsurface valves I
but fluid in the tubing must be allow
ed to reach
sufficient therma1l equilibriumwith its surroundings so that a false leakage rate is riot indicated due to thermal expansion of the fluid
I bull
This technique has been used to work ou~ an inspection procedure
for the Exxon Sulisea Production System The 1procedure demonstrates I I
that the necessany closed fluid paths can be obtained to permit inshyspection of all necessary points Thus from 1a theoretical point of et
j9aYYew 1 t has ~en established that accurate euroVa 1ua tion of subsea con- J
ditions can be made from the surface (io implement the procedures I
it would first be necessary to conduct an experimental program with field
tests to determi~e operational problems) tAtti e
bull
- Inspection of subsea production systems
-
-Rearranging we have
or I
It is interesting to note that gp 5D is the pressure head expected for an incompressible fluid If FgrsDlaquo l (that is the fluid is nearly incompressible) then equation 3 simplifies to
Po-Ps = gPsD
(note lnl+x) ~ x for x laquo 1)
For an example of the type of error that might occur if compressibility
is not considered assume gp 5D = 4000 psi (as it would for an ~gproxi mately 10000 ft deep subsea completion) and that F = 2 x 10 psi Thus
4Po-Ps = -5 x 10 ln(l-008) = 4170 psi
If compressibility had been ignored the pre~sure error would have been 170 psi This analysis has assumed that temperature is constant with depth and that the compressibility of hydrocarbon liquids does not depend on pressure The APl STD 1101 values for compressibility were based on data from zero to 1000 psig
so more data may be reshyquired to assure pressure independence
For cases in which the subsea conditions have been specified (for example setting a downhole pressure for cal~bration of a transducer) the surface presure P required to establish the condition is unknown s Thus the surface density re qui red to solve equation 3 is also unknown A derivation similar to the above shows that the hydrostatic pressure
--difference in terms of subsea conditions is
P0-Ps = ~ ln 0 + fp 0gD) (4)
The density of the oil is most usually known at atmospheric pressure
so the density at pressure P0is found from the atm~spheric density p 0
from equation 1
P0 0 FP = r e D (5)
The use of the above equation assumes a constant temperature so that density varfotions in the tubing are caused only by pressure The
density at atmosp~eric pressure and the desired temperature are found by using table 23 API STD 2540 (ASTM-IP Petroleum Measurement
Tables) to correct the standard density measured at 60degF relative to I
water at 60degF (Sp Gr 6060degF) Specific gravity may be found from
API gravity by usi 1
ng Tible 3 from API STD 2540 or from the equationI I
Sp Gr 6060~F = 1415(APl Gravity at 60degF + 1315)
In the follo~ing paragraphs several examples will be worked to I
demonstrate the uSJe of the equations and to show t~e effect of a
temperature gradi~nt in the oil from the ocean floor to the surface I
The example will i 1nclude two different oils 20deg and 60deg API 6060degF)
at two temperatur~s (70degF and 120degF) and two completion depths
(l000 ft and 101 000 ft) The equations wil1 be solved for surface
pressure assuming a sea bottom transducer is being calibrated at l000 psi
for the 1000 ft 1deep completion and at 5000
psi for the 10000 ft
deep completion The 1000 ft- depth was chosen because H represents I
present capa bi 1 i ties for subsea completion l Q 000 ft las chosen as a maximum depth fqr completions in the foreseeable future (in
areas such as the ~leutian Basin)
i I __ _l__
-Example 1
1000 ft completion -- = 1000 psiP0 20deg API 6060~F -- Sp Gr = 09340
Temp From Fig 1 From Table 23 (API STD 2540) I
70degF F = 039 x 10-5 ps1middot-T Sp Gr = 09305 -5 -1 J
120degF F = 050 x 10 psi Sp Gr bull 09130 At 1000 psi gpl~OO = gp x lOOO = 0434 x (=~middot Gr )0 x lOOO
0
At 70F gplOOO =0434 (09305) e039 x cO x 1000 1 bull
=0405 p~~
-5 0 ( ) eo 50 x 10 x 1000
At 120 F gplOOO ~ 0434 09130
o0398 poundft 1Po - PS =-F- ln (1 + F~D gD)
At 70degFmiddot P P - l ln (1 + 039 x 10-5 x 0405 x 1000) D - S - 039 x 10-S
= 405 psi Ps = lopo - 405 = 595 psi
At 120degF Po - p = l ln (l + ~50 x 10-5 x 0398 x 1000) s 050 x 10-5
= 398 psi P~ = 1000 - 398 = 60 psi
Thus if the $urface pressure P5 were setat 599 psi the pressure
at the sea bottom transducer 1~ould be 1000 4 psi even if the temperature
of the 20deg API gravity oil varied between 70 and 120degF
bull
Example 2 I
1000 ft completion -- P~ = 1000 psi I
I
60deg API 6060deg F -- Sp Gri = 0 7389 From Pi_g__j_ From Table 23 (API STD 25401
70degF F = 0~80 x 10-5 psi-1 Sp Gr bull 07344 -5 -1
120degF F = l10 x 10 psi Sp Gr bull 07117 At 1000 psi pg middot = gp eF x 1000 = 0434middotx (Sp Gr) eF x 1000
1000 o middot o i 080 ~ 10~5 x 1000
At 70degF 9P]OOO bull 0434 (07344) e bull 0321 psift I
1 i o x i o~s x 1 oooAt 120degF gP1000 bull 0434 (07117)e
I = 03]2 psift
PD - Ps = F1 1 n (1 + F PD9 D)
1At 70degF PD
I
- Ps = _ ln (1 +1080 x io-5 x 0321 x 1000)5
080 x 10 = 321 psi
PS bull 679 psi
At 120degF P~ --1----~5 ln (1 + 1 1lO x 10-5 x 0312 x 1000) 110 x 10
= 311 psi Ps = 689 psi
Thus if the surtace pressure P5 were set atmiddot684psi the pressure at the sea bottom transducer would be 1000 plusmn_ 5 psi ~ven if the temperature of the 60deg API gravity oil varied between 70deg and 120degF
bull
I
From the foregoing examples it is apparrnt that for subsea compleshytions up to 1000 ft there is little effect on the calculated
I
pressure at a suhsea transducer due to compressibility and temperature bull
The pressure ca~ be accurately calculated from ~ I bullr
PD - PS = 0434 x Sp Gr x D where the specific gravity of the oil at sta~dard conditions has been corrected to the observed temperature (using an average between the subsea and surface oil temperatures) and 1 i ne pressure Example 3
10000 ft c~mpletion -- P0 = 5000 psi 20deg API 6060degF Sp Gr = 09340
From Fi9 l From Teble 23 (API STD 2540)
70deg F = 039 x l0-5psi-l Sp Gr = 09305 120deg F = 050 x l0-5psi-l Sp Gr = 09130
F x 5000 F x 5000At 5000 psi gp5poo = gp e = 0434 x
I
(=~middotGr ) e0 0
At 70F 9P5poo = 0434 (09305)e039 x 10 x 5000
= 0412 psift I
50 x 5000At 120F 9P~ooo = 0434 (09130)e0middot x 10 -5
= 0406 psift 1
PD - PS= -F- ln (l + Fp gD)0 __L__-=s 1nAt 70degF P ~ (l + 0~39 x 10-5 x 0412 x 10000
D I
P5 039 x 10 = 4087 psi ~ 5000 - 4087 = 913 psir5
At l20F P - P =--1-- ln (l + 050 x 10-5 x 0406 x 10000) D S 050 x l0- 5
- -p~ = 4019 psi P = 981 psi ~
I
Thus if the 1surface pressure r5 were set at 947 the pressure at the
sea bottom trans~ucer would be 5000 +- 34 psi even if the temperature of
the 20degAPI gravity oil varied between 70deg and l20degF
Example 4
I 110000 ft ~omp etion P f 5000 psi0
60deg API 6060degF Sp Gr = 07389 Temp
70degF
l 20degF
From Fig l I ~ -5 -1
F = Oi80 x 10 psi I middot -5 -1F = 110 x 10 psmiddotiI
From Table 23 (API----middotmiddot Sp Gr = 07344
Sp Gr= 07117
STD 2540)
middot F x 5000 F x 5000At 5000 ps1 1 gp 5000 = gp = 0~34 x (Sp Gr)e e0 0
80At 70degF gp middot = 0434 (o 7344)e0middot x 10-5 x 5000
~ooo = o332 psift
_ llxl0_ 5 x5oooAt 120degF gp5000 - 0434 (07117)e
= 0326 psift P ~ P ~ t ln (1 + fp gD)D S D
At 70degF Po_ p = ~__]-____ ln (l + Q80 x lo- 5 x 0332 x 10000) s 080 x 10-~
= 3277 psi I P5 ~ 5000 - 3277 = 1723 psi
At l20degF PD - PS = l 5 ln (l + l l x 10-5 x 0326 x 10000) llOxlOshy
= 3203 psi
PS = 5000 - 3202 = 1797 psi
shybull
Thus if the surface pressure P5 were set at 1760 psi the presshy
sure at the sea ~ottom transducer would be 5000 + 37 psi even if the I shy
temperature cf the 60deg API gravity oil varied between 70deg and 120degF
From these pxample calculations for a 10000 ft completion it is
apparent that temperature variations cause r~latively small errors in I
sea floor ca 1 i bration pressures even for sue~ a great depth If the
pressures are needed more acet1rately than this then the temperature
profile in the tubing would be needed
It has thus been shown that relatively simple calculations of
liquid hydrostatic head result in accurate pressure values for calishy
bration of subsea transducers I
The calibration of gas pressure transdutersmiddot is somewhat different
For low pressures and shallow depth little correction need be made to
the pressure measured at the surface For a gas specific gravity SG
(relative to ai~ at 20degC and 147 psia) pressure P(psia) and depth I
D(ft) the pressure correction AP is given by
-5AP = 356 x 10 x SG x P x D
This equation assumes that the ideal gas law holds and that tPP
is small The equation nay be modified to include the super-compresshy
sibility factor z as follows 0
AP= 356 x 10-Sx SG x D x Pz
For a 1000 ft deep subsea completion line pressure of 1000 psia
(assuming SG ~ 1 and z = 1) AF= 36 psi It is thus apparent that even with large errors in specific gravity and z the pressure correction
1
for hydrostatic head of the gqs is small for depths up to 1000 ft
-bull
Again for a line pressure of 1000 psi but a 10000 ft deep comshy
pletion llP = 3~0 psi so the assumption of PP being small no longer
holds An integration would thus be needed to determine the transducer
pressure and t~e vaHable z factor should be included in thi~ integral Thus a closed form solution similar to tha~ found for liquids cannot
be obtained an~ numerical integration is necessary However for a wide range of conditions the equations pre~ented for both liquids and
I II gases a11 ow acc4ra te cal i bratfon of sea bottom pressure transducers
through the production tubing~ I
I
- -
6 J_nspection_B$9YJrcment_~and Te~t Proc~dures j
The OCS Ord~rs ~ere reviewed for those item~ pertinent to a subsea system The OCS inspection requirements and the suggested general
inspection procedures for these items are discussed in the following
paragraphs Tubing PLtg_
I
Inspection Requirements (OCS Order No 5)I
1 T~e s~~tained liquid leakage flow should not exceed I
400 ccmin 2 The ga~ leakage flo~1 should nGt e)ceed 15 cu ftmin
General Pro~middotedure
The first step i~ this procedure is to isolate a column of fluid
between the tubing plug and the inspector with the valves opened as
for production except that the tubing plug is in pl ace Any fl ow reaching the inspector at the surface is a direct indication of leakage past the tubing plug Thermal equilibrium may b~ required if the
maximum allowabl~ leakage is too small Theflow volume can be measured at the surface in the same manner as for conventionlt1 platform systems
I
middotShut-in Tubi9_ls_e_sur~
Inspection Requirements (OCS Order No I
5)
1 Wells with a shut-in tubing ptessure of 4000 psig or
greater sha11 be equj pped with a subsurface-~ontro11 ed subsurface safety device
-J
2 When the shut-in tubing pressure declines below 4000 I
psig a remotely sontrolled subsurface safety device shall be installed
when the tubing is first removed and reinstalled
General Procedure
To determine if the shut-i~ tubing pressure i~ greater than 4000 psig I
a pressure sensor should be located ~1here the shut-in pressure can be sensed
A convenient arrangement is to locate a pressure s~nsor between the master
valve and wing valve on each tubing With the downhole safety valve and
master valve opened and the wing valve close~ the shmicrot-in tubing pressure
as indicated by the sensor is noted
Calibration of the pressure sensor can be accomplished by applying
a known pressure ~t the surface to a closed cdlumn of fluid connecting I
the surface with the sensor with corrections calculated as explained
in Section 5
Subsurface Safety Device
Inspection Requirements (OCS Order No 5) 1 A surface-controlled subsurface safety device shall be
test operated every six months
2 A subsurface-controlled subsurface safety device shall
be removed inspected and repaired every 12 mdnths 1
General Procedure To test a surface-controlled subsurface safety device the well
should be opened for production and the command then given to close
the subsurface Sifety device The leakage flqw volume if any is
measured at the surface in the same manner as for conventional plat shy
form sys terns bull
1
-)
Pressure Relief Valves Inspection Requtrements (0CS Order No 8)
All pressure reli-f valve~ shall be either bench tested for opershy
ation or tested with an external pressure source (if the valve is somiddot
equipped)annually Jtbt Wf SJJS~+ General Procedure
To test a pressure relief valve for operation the vessel or line
should be pressunizeq to the pressure necessary to open the valve by
using the method suggested in Section 5 Uriless remote position inshy
dicators are provided a means to determine ~hether or not the valve
has actually ope1ed would have to be devised bullfor each subsea system
by observing the effect on the pressure sensors Pressure Sensors
Inspection Requirements (OCS Order No 8)
All pressure sensors shall be tested at least once each month
General Procedure
To remotely test and cal i~rate a subsea bullpressure sensor it is
necessary to
(1) isolate a closed column of fluid irom the surface to
the subsea sensor by properly arranging the ~ys terns va1ves
(2) determine the specific gravity compressibility and the
column height of the fluid
(3) select the pressure required at the subsea sensor
(4) apply the appropriate pressure at the surface end of
the column and
(5) compare the telemetered press4re signal or indication
with the pressur~ applied to the sensor
Automatic Hellhead Safety Devices -~~__--r---
Inspection 8equiremcnts (OCS Order No 8) All automatic wellhead safety devices shall be tested for operation
I
and holding pres~ureonce each1month
I
- -
bull )
General Prooedure
To test the operation of the automatic well head safety devices
the out-of-the-tolerance condition (usually ~igh or low pressure) which actuates the devices should be simulated Urless position 1ndicators
I
are provided a means to deterrl1ine whether 011 not the valves have
actually closed ~ust be devised for each indi1vidu~l system because of
the peculiarities
in each syste m J I
L~ 6 - Jlaquo4 sfSf~ rCheck Valves ~J0141d 11tJt NC Uf~ l(I -v-
Inspection Requirements (OCS Order No ~)
A11 check valves on a11 fl ow 1i nes sha11 be tested for opera ti on
and holding pressure once each month
General Procedures
To test the check valve ft will have to be back pressured The
check valve fails to operate properly if any back flo~1 through the I
valve occurs
~iguid Level Shut-in Controls I
Inspection Requirements (9cs Order No 8)
All liquid-l 1
evel shut-in controls shall be tested once each month
by raising or lowering liquid level across the leyel-control detector
General Pro~edure I
The preferable way to test the liquid-level sh~t-in controls is to
simulate the out-of-tolerance conditions (1 iquid Jevel either low or I
high) at the sensor This sim~lation should cau~e either the inlet
shutoff va1ve to close or the discharge shutoff valve to close In
this manner both the control YStem and the automatif valves are tested I
A means will have to be devised for each subsea system to determine I
if the out-of-tolerance condition actually occurred at the sensor if
it was properly Jetected and i~ it caused thd proper actuation I
Vessel Automatic~Inlet-Shutoff Valves I
Inspection ~equirement (OCS Order No 8)I
-I I
bull ) ~ J) All automatic~~~~~-shutoff valves actuated by vessel~~
I
~fsensorj shalil be tested for operation onle each month General Procedure
Described above under gene~al procedure for Liquid-Level Shut-
In Controls Vessel AutomaJi c-Di sc_b~_g_e-Sh_ll__Dff__Y_ii_l ves
Inspection RequireiT1ent (OCS Order No 8) All automatic-discharge-shutoff valves actuated by vessel lowshy
level sensors shall be tested for operation qnce each month
General Proc~dure
Described above under Liquid-Level Shut-tn Controls
High-tempera_ure Coniprc2_()r-Sh_t1tdow_ri_Co~_o1s Inspection Requirement (OCS Order No 8)i
High temperature controls which protect the compressor against
abnormal pressure~ soltiY by such temperature
safety devices shall be tested annually
General Procedure Because of the danger involved in elevating the temperature suffi shy
ciently to cause + temperature device to actuate it is recommended that each temperature device be pre-tested and replaced each year rather than be tested remotely
Oil Spil 1 Detection E_g_t_pmen~
Inspection Requirements (OCS Order 7) All platforms and structures are require~ to have curbs gutters
and spill pans connected to a tank or sump fhis equipment is required to collect all hydrocarbon spillage on the platform It is recommended that this requirement be extencjed to require all unenclosed subsea
equipment to be covered by inverted spill pans with hydrocarbon sensors
and sumps to rem~ve spillage
General Procedure To test the hydrocarbon spi 11 age detection and removal system
a controlled spill should be made in each ar~a or section of spill
- bull
pans while th~ SUljlPI
pumps are monitored for proper operation This I I
metbod will require a signal to the surface to indicate directly when the pumps are running or indirectly by indicating a pressure rise in
I i
the affected pipeline due to the pun1ping action The indirect method is preferablebec~use the pressure rise not only indicates the pumps are running b~t indicates they also are pumpi~g fluid One additional safeguard should ~e employed A TV camera should be used to observe
I
the spill pans in the vicinity of the spill to assure that they are not leaking due to damage or inadequacy of de~ign Hydrocarbon S~nsors
IInspection Requirements
Hydrocarbon sensors are not covered in tbe OCS Qrders presently
in effect General Procedure The general test procedure for the oil-spill-detection equipment
above will test the hydrocarbon sensors for operation In addition
I bull some means of knowing when each separate hydrocarbon sensor in the
spill pan assemblies hus sensed hydrocarbon will provide additional I
protection by warning of system degradation b~fore the system is comshypletely inoperable
7 Summary and RecQ)enda tions This report deal~ with the inspection problems that have arisen
as a result of the present trend of the offshore oil industry towards
subsea completion and production of deep water petroleum reservoirs I
Inspection techniques for completion and prod~ction equipment are inshyvestigated but inspection of fiser systems submersibles and strucshy
tures are not inc~uded in the scope of this wprk
A technique ~as been detailed for calibr1ttion of subsea sensors I
and for verifying the proper OReration of va1ves The technique reshy
quires only that the inspector 1 have access to production tubing at
- bull
I I
the surface By actuating subsurface control valves from the surface
the inspector can isolate a closed fluid path1 to the point of interest I
Pressures read at the surface (when corrected for hydraulic gradients)
may then be used to ca 1 i brate subsurface tran1sducers Flow rates
measured at the surface can be used to I
indicate leakage rates bull
from
subsurface valves I
but fluid in the tubing must be allow
ed to reach
sufficient therma1l equilibriumwith its surroundings so that a false leakage rate is riot indicated due to thermal expansion of the fluid
I bull
This technique has been used to work ou~ an inspection procedure
for the Exxon Sulisea Production System The 1procedure demonstrates I I
that the necessany closed fluid paths can be obtained to permit inshyspection of all necessary points Thus from 1a theoretical point of et
j9aYYew 1 t has ~en established that accurate euroVa 1ua tion of subsea con- J
ditions can be made from the surface (io implement the procedures I
it would first be necessary to conduct an experimental program with field
tests to determi~e operational problems) tAtti e
bull
- Inspection of subsea production systems
-
--difference in terms of subsea conditions is
P0-Ps = ~ ln 0 + fp 0gD) (4)
The density of the oil is most usually known at atmospheric pressure
so the density at pressure P0is found from the atm~spheric density p 0
from equation 1
P0 0 FP = r e D (5)
The use of the above equation assumes a constant temperature so that density varfotions in the tubing are caused only by pressure The
density at atmosp~eric pressure and the desired temperature are found by using table 23 API STD 2540 (ASTM-IP Petroleum Measurement
Tables) to correct the standard density measured at 60degF relative to I
water at 60degF (Sp Gr 6060degF) Specific gravity may be found from
API gravity by usi 1
ng Tible 3 from API STD 2540 or from the equationI I
Sp Gr 6060~F = 1415(APl Gravity at 60degF + 1315)
In the follo~ing paragraphs several examples will be worked to I
demonstrate the uSJe of the equations and to show t~e effect of a
temperature gradi~nt in the oil from the ocean floor to the surface I
The example will i 1nclude two different oils 20deg and 60deg API 6060degF)
at two temperatur~s (70degF and 120degF) and two completion depths
(l000 ft and 101 000 ft) The equations wil1 be solved for surface
pressure assuming a sea bottom transducer is being calibrated at l000 psi
for the 1000 ft 1deep completion and at 5000
psi for the 10000 ft
deep completion The 1000 ft- depth was chosen because H represents I
present capa bi 1 i ties for subsea completion l Q 000 ft las chosen as a maximum depth fqr completions in the foreseeable future (in
areas such as the ~leutian Basin)
i I __ _l__
-Example 1
1000 ft completion -- = 1000 psiP0 20deg API 6060~F -- Sp Gr = 09340
Temp From Fig 1 From Table 23 (API STD 2540) I
70degF F = 039 x 10-5 ps1middot-T Sp Gr = 09305 -5 -1 J
120degF F = 050 x 10 psi Sp Gr bull 09130 At 1000 psi gpl~OO = gp x lOOO = 0434 x (=~middot Gr )0 x lOOO
0
At 70F gplOOO =0434 (09305) e039 x cO x 1000 1 bull
=0405 p~~
-5 0 ( ) eo 50 x 10 x 1000
At 120 F gplOOO ~ 0434 09130
o0398 poundft 1Po - PS =-F- ln (1 + F~D gD)
At 70degFmiddot P P - l ln (1 + 039 x 10-5 x 0405 x 1000) D - S - 039 x 10-S
= 405 psi Ps = lopo - 405 = 595 psi
At 120degF Po - p = l ln (l + ~50 x 10-5 x 0398 x 1000) s 050 x 10-5
= 398 psi P~ = 1000 - 398 = 60 psi
Thus if the $urface pressure P5 were setat 599 psi the pressure
at the sea bottom transducer 1~ould be 1000 4 psi even if the temperature
of the 20deg API gravity oil varied between 70 and 120degF
bull
Example 2 I
1000 ft completion -- P~ = 1000 psi I
I
60deg API 6060deg F -- Sp Gri = 0 7389 From Pi_g__j_ From Table 23 (API STD 25401
70degF F = 0~80 x 10-5 psi-1 Sp Gr bull 07344 -5 -1
120degF F = l10 x 10 psi Sp Gr bull 07117 At 1000 psi pg middot = gp eF x 1000 = 0434middotx (Sp Gr) eF x 1000
1000 o middot o i 080 ~ 10~5 x 1000
At 70degF 9P]OOO bull 0434 (07344) e bull 0321 psift I
1 i o x i o~s x 1 oooAt 120degF gP1000 bull 0434 (07117)e
I = 03]2 psift
PD - Ps = F1 1 n (1 + F PD9 D)
1At 70degF PD
I
- Ps = _ ln (1 +1080 x io-5 x 0321 x 1000)5
080 x 10 = 321 psi
PS bull 679 psi
At 120degF P~ --1----~5 ln (1 + 1 1lO x 10-5 x 0312 x 1000) 110 x 10
= 311 psi Ps = 689 psi
Thus if the surtace pressure P5 were set atmiddot684psi the pressure at the sea bottom transducer would be 1000 plusmn_ 5 psi ~ven if the temperature of the 60deg API gravity oil varied between 70deg and 120degF
bull
I
From the foregoing examples it is apparrnt that for subsea compleshytions up to 1000 ft there is little effect on the calculated
I
pressure at a suhsea transducer due to compressibility and temperature bull
The pressure ca~ be accurately calculated from ~ I bullr
PD - PS = 0434 x Sp Gr x D where the specific gravity of the oil at sta~dard conditions has been corrected to the observed temperature (using an average between the subsea and surface oil temperatures) and 1 i ne pressure Example 3
10000 ft c~mpletion -- P0 = 5000 psi 20deg API 6060degF Sp Gr = 09340
From Fi9 l From Teble 23 (API STD 2540)
70deg F = 039 x l0-5psi-l Sp Gr = 09305 120deg F = 050 x l0-5psi-l Sp Gr = 09130
F x 5000 F x 5000At 5000 psi gp5poo = gp e = 0434 x
I
(=~middotGr ) e0 0
At 70F 9P5poo = 0434 (09305)e039 x 10 x 5000
= 0412 psift I
50 x 5000At 120F 9P~ooo = 0434 (09130)e0middot x 10 -5
= 0406 psift 1
PD - PS= -F- ln (l + Fp gD)0 __L__-=s 1nAt 70degF P ~ (l + 0~39 x 10-5 x 0412 x 10000
D I
P5 039 x 10 = 4087 psi ~ 5000 - 4087 = 913 psir5
At l20F P - P =--1-- ln (l + 050 x 10-5 x 0406 x 10000) D S 050 x l0- 5
- -p~ = 4019 psi P = 981 psi ~
I
Thus if the 1surface pressure r5 were set at 947 the pressure at the
sea bottom trans~ucer would be 5000 +- 34 psi even if the temperature of
the 20degAPI gravity oil varied between 70deg and l20degF
Example 4
I 110000 ft ~omp etion P f 5000 psi0
60deg API 6060degF Sp Gr = 07389 Temp
70degF
l 20degF
From Fig l I ~ -5 -1
F = Oi80 x 10 psi I middot -5 -1F = 110 x 10 psmiddotiI
From Table 23 (API----middotmiddot Sp Gr = 07344
Sp Gr= 07117
STD 2540)
middot F x 5000 F x 5000At 5000 ps1 1 gp 5000 = gp = 0~34 x (Sp Gr)e e0 0
80At 70degF gp middot = 0434 (o 7344)e0middot x 10-5 x 5000
~ooo = o332 psift
_ llxl0_ 5 x5oooAt 120degF gp5000 - 0434 (07117)e
= 0326 psift P ~ P ~ t ln (1 + fp gD)D S D
At 70degF Po_ p = ~__]-____ ln (l + Q80 x lo- 5 x 0332 x 10000) s 080 x 10-~
= 3277 psi I P5 ~ 5000 - 3277 = 1723 psi
At l20degF PD - PS = l 5 ln (l + l l x 10-5 x 0326 x 10000) llOxlOshy
= 3203 psi
PS = 5000 - 3202 = 1797 psi
shybull
Thus if the surface pressure P5 were set at 1760 psi the presshy
sure at the sea ~ottom transducer would be 5000 + 37 psi even if the I shy
temperature cf the 60deg API gravity oil varied between 70deg and 120degF
From these pxample calculations for a 10000 ft completion it is
apparent that temperature variations cause r~latively small errors in I
sea floor ca 1 i bration pressures even for sue~ a great depth If the
pressures are needed more acet1rately than this then the temperature
profile in the tubing would be needed
It has thus been shown that relatively simple calculations of
liquid hydrostatic head result in accurate pressure values for calishy
bration of subsea transducers I
The calibration of gas pressure transdutersmiddot is somewhat different
For low pressures and shallow depth little correction need be made to
the pressure measured at the surface For a gas specific gravity SG
(relative to ai~ at 20degC and 147 psia) pressure P(psia) and depth I
D(ft) the pressure correction AP is given by
-5AP = 356 x 10 x SG x P x D
This equation assumes that the ideal gas law holds and that tPP
is small The equation nay be modified to include the super-compresshy
sibility factor z as follows 0
AP= 356 x 10-Sx SG x D x Pz
For a 1000 ft deep subsea completion line pressure of 1000 psia
(assuming SG ~ 1 and z = 1) AF= 36 psi It is thus apparent that even with large errors in specific gravity and z the pressure correction
1
for hydrostatic head of the gqs is small for depths up to 1000 ft
-bull
Again for a line pressure of 1000 psi but a 10000 ft deep comshy
pletion llP = 3~0 psi so the assumption of PP being small no longer
holds An integration would thus be needed to determine the transducer
pressure and t~e vaHable z factor should be included in thi~ integral Thus a closed form solution similar to tha~ found for liquids cannot
be obtained an~ numerical integration is necessary However for a wide range of conditions the equations pre~ented for both liquids and
I II gases a11 ow acc4ra te cal i bratfon of sea bottom pressure transducers
through the production tubing~ I
I
- -
6 J_nspection_B$9YJrcment_~and Te~t Proc~dures j
The OCS Ord~rs ~ere reviewed for those item~ pertinent to a subsea system The OCS inspection requirements and the suggested general
inspection procedures for these items are discussed in the following
paragraphs Tubing PLtg_
I
Inspection Requirements (OCS Order No 5)I
1 T~e s~~tained liquid leakage flow should not exceed I
400 ccmin 2 The ga~ leakage flo~1 should nGt e)ceed 15 cu ftmin
General Pro~middotedure
The first step i~ this procedure is to isolate a column of fluid
between the tubing plug and the inspector with the valves opened as
for production except that the tubing plug is in pl ace Any fl ow reaching the inspector at the surface is a direct indication of leakage past the tubing plug Thermal equilibrium may b~ required if the
maximum allowabl~ leakage is too small Theflow volume can be measured at the surface in the same manner as for conventionlt1 platform systems
I
middotShut-in Tubi9_ls_e_sur~
Inspection Requirements (OCS Order No I
5)
1 Wells with a shut-in tubing ptessure of 4000 psig or
greater sha11 be equj pped with a subsurface-~ontro11 ed subsurface safety device
-J
2 When the shut-in tubing pressure declines below 4000 I
psig a remotely sontrolled subsurface safety device shall be installed
when the tubing is first removed and reinstalled
General Procedure
To determine if the shut-i~ tubing pressure i~ greater than 4000 psig I
a pressure sensor should be located ~1here the shut-in pressure can be sensed
A convenient arrangement is to locate a pressure s~nsor between the master
valve and wing valve on each tubing With the downhole safety valve and
master valve opened and the wing valve close~ the shmicrot-in tubing pressure
as indicated by the sensor is noted
Calibration of the pressure sensor can be accomplished by applying
a known pressure ~t the surface to a closed cdlumn of fluid connecting I
the surface with the sensor with corrections calculated as explained
in Section 5
Subsurface Safety Device
Inspection Requirements (OCS Order No 5) 1 A surface-controlled subsurface safety device shall be
test operated every six months
2 A subsurface-controlled subsurface safety device shall
be removed inspected and repaired every 12 mdnths 1
General Procedure To test a surface-controlled subsurface safety device the well
should be opened for production and the command then given to close
the subsurface Sifety device The leakage flqw volume if any is
measured at the surface in the same manner as for conventional plat shy
form sys terns bull
1
-)
Pressure Relief Valves Inspection Requtrements (0CS Order No 8)
All pressure reli-f valve~ shall be either bench tested for opershy
ation or tested with an external pressure source (if the valve is somiddot
equipped)annually Jtbt Wf SJJS~+ General Procedure
To test a pressure relief valve for operation the vessel or line
should be pressunizeq to the pressure necessary to open the valve by
using the method suggested in Section 5 Uriless remote position inshy
dicators are provided a means to determine ~hether or not the valve
has actually ope1ed would have to be devised bullfor each subsea system
by observing the effect on the pressure sensors Pressure Sensors
Inspection Requirements (OCS Order No 8)
All pressure sensors shall be tested at least once each month
General Procedure
To remotely test and cal i~rate a subsea bullpressure sensor it is
necessary to
(1) isolate a closed column of fluid irom the surface to
the subsea sensor by properly arranging the ~ys terns va1ves
(2) determine the specific gravity compressibility and the
column height of the fluid
(3) select the pressure required at the subsea sensor
(4) apply the appropriate pressure at the surface end of
the column and
(5) compare the telemetered press4re signal or indication
with the pressur~ applied to the sensor
Automatic Hellhead Safety Devices -~~__--r---
Inspection 8equiremcnts (OCS Order No 8) All automatic wellhead safety devices shall be tested for operation
I
and holding pres~ureonce each1month
I
- -
bull )
General Prooedure
To test the operation of the automatic well head safety devices
the out-of-the-tolerance condition (usually ~igh or low pressure) which actuates the devices should be simulated Urless position 1ndicators
I
are provided a means to deterrl1ine whether 011 not the valves have
actually closed ~ust be devised for each indi1vidu~l system because of
the peculiarities
in each syste m J I
L~ 6 - Jlaquo4 sfSf~ rCheck Valves ~J0141d 11tJt NC Uf~ l(I -v-
Inspection Requirements (OCS Order No ~)
A11 check valves on a11 fl ow 1i nes sha11 be tested for opera ti on
and holding pressure once each month
General Procedures
To test the check valve ft will have to be back pressured The
check valve fails to operate properly if any back flo~1 through the I
valve occurs
~iguid Level Shut-in Controls I
Inspection Requirements (9cs Order No 8)
All liquid-l 1
evel shut-in controls shall be tested once each month
by raising or lowering liquid level across the leyel-control detector
General Pro~edure I
The preferable way to test the liquid-level sh~t-in controls is to
simulate the out-of-tolerance conditions (1 iquid Jevel either low or I
high) at the sensor This sim~lation should cau~e either the inlet
shutoff va1ve to close or the discharge shutoff valve to close In
this manner both the control YStem and the automatif valves are tested I
A means will have to be devised for each subsea system to determine I
if the out-of-tolerance condition actually occurred at the sensor if
it was properly Jetected and i~ it caused thd proper actuation I
Vessel Automatic~Inlet-Shutoff Valves I
Inspection ~equirement (OCS Order No 8)I
-I I
bull ) ~ J) All automatic~~~~~-shutoff valves actuated by vessel~~
I
~fsensorj shalil be tested for operation onle each month General Procedure
Described above under gene~al procedure for Liquid-Level Shut-
In Controls Vessel AutomaJi c-Di sc_b~_g_e-Sh_ll__Dff__Y_ii_l ves
Inspection RequireiT1ent (OCS Order No 8) All automatic-discharge-shutoff valves actuated by vessel lowshy
level sensors shall be tested for operation qnce each month
General Proc~dure
Described above under Liquid-Level Shut-tn Controls
High-tempera_ure Coniprc2_()r-Sh_t1tdow_ri_Co~_o1s Inspection Requirement (OCS Order No 8)i
High temperature controls which protect the compressor against
abnormal pressure~ soltiY by such temperature
safety devices shall be tested annually
General Procedure Because of the danger involved in elevating the temperature suffi shy
ciently to cause + temperature device to actuate it is recommended that each temperature device be pre-tested and replaced each year rather than be tested remotely
Oil Spil 1 Detection E_g_t_pmen~
Inspection Requirements (OCS Order 7) All platforms and structures are require~ to have curbs gutters
and spill pans connected to a tank or sump fhis equipment is required to collect all hydrocarbon spillage on the platform It is recommended that this requirement be extencjed to require all unenclosed subsea
equipment to be covered by inverted spill pans with hydrocarbon sensors
and sumps to rem~ve spillage
General Procedure To test the hydrocarbon spi 11 age detection and removal system
a controlled spill should be made in each ar~a or section of spill
- bull
pans while th~ SUljlPI
pumps are monitored for proper operation This I I
metbod will require a signal to the surface to indicate directly when the pumps are running or indirectly by indicating a pressure rise in
I i
the affected pipeline due to the pun1ping action The indirect method is preferablebec~use the pressure rise not only indicates the pumps are running b~t indicates they also are pumpi~g fluid One additional safeguard should ~e employed A TV camera should be used to observe
I
the spill pans in the vicinity of the spill to assure that they are not leaking due to damage or inadequacy of de~ign Hydrocarbon S~nsors
IInspection Requirements
Hydrocarbon sensors are not covered in tbe OCS Qrders presently
in effect General Procedure The general test procedure for the oil-spill-detection equipment
above will test the hydrocarbon sensors for operation In addition
I bull some means of knowing when each separate hydrocarbon sensor in the
spill pan assemblies hus sensed hydrocarbon will provide additional I
protection by warning of system degradation b~fore the system is comshypletely inoperable
7 Summary and RecQ)enda tions This report deal~ with the inspection problems that have arisen
as a result of the present trend of the offshore oil industry towards
subsea completion and production of deep water petroleum reservoirs I
Inspection techniques for completion and prod~ction equipment are inshyvestigated but inspection of fiser systems submersibles and strucshy
tures are not inc~uded in the scope of this wprk
A technique ~as been detailed for calibr1ttion of subsea sensors I
and for verifying the proper OReration of va1ves The technique reshy
quires only that the inspector 1 have access to production tubing at
- bull
I I
the surface By actuating subsurface control valves from the surface
the inspector can isolate a closed fluid path1 to the point of interest I
Pressures read at the surface (when corrected for hydraulic gradients)
may then be used to ca 1 i brate subsurface tran1sducers Flow rates
measured at the surface can be used to I
indicate leakage rates bull
from
subsurface valves I
but fluid in the tubing must be allow
ed to reach
sufficient therma1l equilibriumwith its surroundings so that a false leakage rate is riot indicated due to thermal expansion of the fluid
I bull
This technique has been used to work ou~ an inspection procedure
for the Exxon Sulisea Production System The 1procedure demonstrates I I
that the necessany closed fluid paths can be obtained to permit inshyspection of all necessary points Thus from 1a theoretical point of et
j9aYYew 1 t has ~en established that accurate euroVa 1ua tion of subsea con- J
ditions can be made from the surface (io implement the procedures I
it would first be necessary to conduct an experimental program with field
tests to determi~e operational problems) tAtti e
bull
- Inspection of subsea production systems
-
-Example 1
1000 ft completion -- = 1000 psiP0 20deg API 6060~F -- Sp Gr = 09340
Temp From Fig 1 From Table 23 (API STD 2540) I
70degF F = 039 x 10-5 ps1middot-T Sp Gr = 09305 -5 -1 J
120degF F = 050 x 10 psi Sp Gr bull 09130 At 1000 psi gpl~OO = gp x lOOO = 0434 x (=~middot Gr )0 x lOOO
0
At 70F gplOOO =0434 (09305) e039 x cO x 1000 1 bull
=0405 p~~
-5 0 ( ) eo 50 x 10 x 1000
At 120 F gplOOO ~ 0434 09130
o0398 poundft 1Po - PS =-F- ln (1 + F~D gD)
At 70degFmiddot P P - l ln (1 + 039 x 10-5 x 0405 x 1000) D - S - 039 x 10-S
= 405 psi Ps = lopo - 405 = 595 psi
At 120degF Po - p = l ln (l + ~50 x 10-5 x 0398 x 1000) s 050 x 10-5
= 398 psi P~ = 1000 - 398 = 60 psi
Thus if the $urface pressure P5 were setat 599 psi the pressure
at the sea bottom transducer 1~ould be 1000 4 psi even if the temperature
of the 20deg API gravity oil varied between 70 and 120degF
bull
Example 2 I
1000 ft completion -- P~ = 1000 psi I
I
60deg API 6060deg F -- Sp Gri = 0 7389 From Pi_g__j_ From Table 23 (API STD 25401
70degF F = 0~80 x 10-5 psi-1 Sp Gr bull 07344 -5 -1
120degF F = l10 x 10 psi Sp Gr bull 07117 At 1000 psi pg middot = gp eF x 1000 = 0434middotx (Sp Gr) eF x 1000
1000 o middot o i 080 ~ 10~5 x 1000
At 70degF 9P]OOO bull 0434 (07344) e bull 0321 psift I
1 i o x i o~s x 1 oooAt 120degF gP1000 bull 0434 (07117)e
I = 03]2 psift
PD - Ps = F1 1 n (1 + F PD9 D)
1At 70degF PD
I
- Ps = _ ln (1 +1080 x io-5 x 0321 x 1000)5
080 x 10 = 321 psi
PS bull 679 psi
At 120degF P~ --1----~5 ln (1 + 1 1lO x 10-5 x 0312 x 1000) 110 x 10
= 311 psi Ps = 689 psi
Thus if the surtace pressure P5 were set atmiddot684psi the pressure at the sea bottom transducer would be 1000 plusmn_ 5 psi ~ven if the temperature of the 60deg API gravity oil varied between 70deg and 120degF
bull
I
From the foregoing examples it is apparrnt that for subsea compleshytions up to 1000 ft there is little effect on the calculated
I
pressure at a suhsea transducer due to compressibility and temperature bull
The pressure ca~ be accurately calculated from ~ I bullr
PD - PS = 0434 x Sp Gr x D where the specific gravity of the oil at sta~dard conditions has been corrected to the observed temperature (using an average between the subsea and surface oil temperatures) and 1 i ne pressure Example 3
10000 ft c~mpletion -- P0 = 5000 psi 20deg API 6060degF Sp Gr = 09340
From Fi9 l From Teble 23 (API STD 2540)
70deg F = 039 x l0-5psi-l Sp Gr = 09305 120deg F = 050 x l0-5psi-l Sp Gr = 09130
F x 5000 F x 5000At 5000 psi gp5poo = gp e = 0434 x
I
(=~middotGr ) e0 0
At 70F 9P5poo = 0434 (09305)e039 x 10 x 5000
= 0412 psift I
50 x 5000At 120F 9P~ooo = 0434 (09130)e0middot x 10 -5
= 0406 psift 1
PD - PS= -F- ln (l + Fp gD)0 __L__-=s 1nAt 70degF P ~ (l + 0~39 x 10-5 x 0412 x 10000
D I
P5 039 x 10 = 4087 psi ~ 5000 - 4087 = 913 psir5
At l20F P - P =--1-- ln (l + 050 x 10-5 x 0406 x 10000) D S 050 x l0- 5
- -p~ = 4019 psi P = 981 psi ~
I
Thus if the 1surface pressure r5 were set at 947 the pressure at the
sea bottom trans~ucer would be 5000 +- 34 psi even if the temperature of
the 20degAPI gravity oil varied between 70deg and l20degF
Example 4
I 110000 ft ~omp etion P f 5000 psi0
60deg API 6060degF Sp Gr = 07389 Temp
70degF
l 20degF
From Fig l I ~ -5 -1
F = Oi80 x 10 psi I middot -5 -1F = 110 x 10 psmiddotiI
From Table 23 (API----middotmiddot Sp Gr = 07344
Sp Gr= 07117
STD 2540)
middot F x 5000 F x 5000At 5000 ps1 1 gp 5000 = gp = 0~34 x (Sp Gr)e e0 0
80At 70degF gp middot = 0434 (o 7344)e0middot x 10-5 x 5000
~ooo = o332 psift
_ llxl0_ 5 x5oooAt 120degF gp5000 - 0434 (07117)e
= 0326 psift P ~ P ~ t ln (1 + fp gD)D S D
At 70degF Po_ p = ~__]-____ ln (l + Q80 x lo- 5 x 0332 x 10000) s 080 x 10-~
= 3277 psi I P5 ~ 5000 - 3277 = 1723 psi
At l20degF PD - PS = l 5 ln (l + l l x 10-5 x 0326 x 10000) llOxlOshy
= 3203 psi
PS = 5000 - 3202 = 1797 psi
shybull
Thus if the surface pressure P5 were set at 1760 psi the presshy
sure at the sea ~ottom transducer would be 5000 + 37 psi even if the I shy
temperature cf the 60deg API gravity oil varied between 70deg and 120degF
From these pxample calculations for a 10000 ft completion it is
apparent that temperature variations cause r~latively small errors in I
sea floor ca 1 i bration pressures even for sue~ a great depth If the
pressures are needed more acet1rately than this then the temperature
profile in the tubing would be needed
It has thus been shown that relatively simple calculations of
liquid hydrostatic head result in accurate pressure values for calishy
bration of subsea transducers I
The calibration of gas pressure transdutersmiddot is somewhat different
For low pressures and shallow depth little correction need be made to
the pressure measured at the surface For a gas specific gravity SG
(relative to ai~ at 20degC and 147 psia) pressure P(psia) and depth I
D(ft) the pressure correction AP is given by
-5AP = 356 x 10 x SG x P x D
This equation assumes that the ideal gas law holds and that tPP
is small The equation nay be modified to include the super-compresshy
sibility factor z as follows 0
AP= 356 x 10-Sx SG x D x Pz
For a 1000 ft deep subsea completion line pressure of 1000 psia
(assuming SG ~ 1 and z = 1) AF= 36 psi It is thus apparent that even with large errors in specific gravity and z the pressure correction
1
for hydrostatic head of the gqs is small for depths up to 1000 ft
-bull
Again for a line pressure of 1000 psi but a 10000 ft deep comshy
pletion llP = 3~0 psi so the assumption of PP being small no longer
holds An integration would thus be needed to determine the transducer
pressure and t~e vaHable z factor should be included in thi~ integral Thus a closed form solution similar to tha~ found for liquids cannot
be obtained an~ numerical integration is necessary However for a wide range of conditions the equations pre~ented for both liquids and
I II gases a11 ow acc4ra te cal i bratfon of sea bottom pressure transducers
through the production tubing~ I
I
- -
6 J_nspection_B$9YJrcment_~and Te~t Proc~dures j
The OCS Ord~rs ~ere reviewed for those item~ pertinent to a subsea system The OCS inspection requirements and the suggested general
inspection procedures for these items are discussed in the following
paragraphs Tubing PLtg_
I
Inspection Requirements (OCS Order No 5)I
1 T~e s~~tained liquid leakage flow should not exceed I
400 ccmin 2 The ga~ leakage flo~1 should nGt e)ceed 15 cu ftmin
General Pro~middotedure
The first step i~ this procedure is to isolate a column of fluid
between the tubing plug and the inspector with the valves opened as
for production except that the tubing plug is in pl ace Any fl ow reaching the inspector at the surface is a direct indication of leakage past the tubing plug Thermal equilibrium may b~ required if the
maximum allowabl~ leakage is too small Theflow volume can be measured at the surface in the same manner as for conventionlt1 platform systems
I
middotShut-in Tubi9_ls_e_sur~
Inspection Requirements (OCS Order No I
5)
1 Wells with a shut-in tubing ptessure of 4000 psig or
greater sha11 be equj pped with a subsurface-~ontro11 ed subsurface safety device
-J
2 When the shut-in tubing pressure declines below 4000 I
psig a remotely sontrolled subsurface safety device shall be installed
when the tubing is first removed and reinstalled
General Procedure
To determine if the shut-i~ tubing pressure i~ greater than 4000 psig I
a pressure sensor should be located ~1here the shut-in pressure can be sensed
A convenient arrangement is to locate a pressure s~nsor between the master
valve and wing valve on each tubing With the downhole safety valve and
master valve opened and the wing valve close~ the shmicrot-in tubing pressure
as indicated by the sensor is noted
Calibration of the pressure sensor can be accomplished by applying
a known pressure ~t the surface to a closed cdlumn of fluid connecting I
the surface with the sensor with corrections calculated as explained
in Section 5
Subsurface Safety Device
Inspection Requirements (OCS Order No 5) 1 A surface-controlled subsurface safety device shall be
test operated every six months
2 A subsurface-controlled subsurface safety device shall
be removed inspected and repaired every 12 mdnths 1
General Procedure To test a surface-controlled subsurface safety device the well
should be opened for production and the command then given to close
the subsurface Sifety device The leakage flqw volume if any is
measured at the surface in the same manner as for conventional plat shy
form sys terns bull
1
-)
Pressure Relief Valves Inspection Requtrements (0CS Order No 8)
All pressure reli-f valve~ shall be either bench tested for opershy
ation or tested with an external pressure source (if the valve is somiddot
equipped)annually Jtbt Wf SJJS~+ General Procedure
To test a pressure relief valve for operation the vessel or line
should be pressunizeq to the pressure necessary to open the valve by
using the method suggested in Section 5 Uriless remote position inshy
dicators are provided a means to determine ~hether or not the valve
has actually ope1ed would have to be devised bullfor each subsea system
by observing the effect on the pressure sensors Pressure Sensors
Inspection Requirements (OCS Order No 8)
All pressure sensors shall be tested at least once each month
General Procedure
To remotely test and cal i~rate a subsea bullpressure sensor it is
necessary to
(1) isolate a closed column of fluid irom the surface to
the subsea sensor by properly arranging the ~ys terns va1ves
(2) determine the specific gravity compressibility and the
column height of the fluid
(3) select the pressure required at the subsea sensor
(4) apply the appropriate pressure at the surface end of
the column and
(5) compare the telemetered press4re signal or indication
with the pressur~ applied to the sensor
Automatic Hellhead Safety Devices -~~__--r---
Inspection 8equiremcnts (OCS Order No 8) All automatic wellhead safety devices shall be tested for operation
I
and holding pres~ureonce each1month
I
- -
bull )
General Prooedure
To test the operation of the automatic well head safety devices
the out-of-the-tolerance condition (usually ~igh or low pressure) which actuates the devices should be simulated Urless position 1ndicators
I
are provided a means to deterrl1ine whether 011 not the valves have
actually closed ~ust be devised for each indi1vidu~l system because of
the peculiarities
in each syste m J I
L~ 6 - Jlaquo4 sfSf~ rCheck Valves ~J0141d 11tJt NC Uf~ l(I -v-
Inspection Requirements (OCS Order No ~)
A11 check valves on a11 fl ow 1i nes sha11 be tested for opera ti on
and holding pressure once each month
General Procedures
To test the check valve ft will have to be back pressured The
check valve fails to operate properly if any back flo~1 through the I
valve occurs
~iguid Level Shut-in Controls I
Inspection Requirements (9cs Order No 8)
All liquid-l 1
evel shut-in controls shall be tested once each month
by raising or lowering liquid level across the leyel-control detector
General Pro~edure I
The preferable way to test the liquid-level sh~t-in controls is to
simulate the out-of-tolerance conditions (1 iquid Jevel either low or I
high) at the sensor This sim~lation should cau~e either the inlet
shutoff va1ve to close or the discharge shutoff valve to close In
this manner both the control YStem and the automatif valves are tested I
A means will have to be devised for each subsea system to determine I
if the out-of-tolerance condition actually occurred at the sensor if
it was properly Jetected and i~ it caused thd proper actuation I
Vessel Automatic~Inlet-Shutoff Valves I
Inspection ~equirement (OCS Order No 8)I
-I I
bull ) ~ J) All automatic~~~~~-shutoff valves actuated by vessel~~
I
~fsensorj shalil be tested for operation onle each month General Procedure
Described above under gene~al procedure for Liquid-Level Shut-
In Controls Vessel AutomaJi c-Di sc_b~_g_e-Sh_ll__Dff__Y_ii_l ves
Inspection RequireiT1ent (OCS Order No 8) All automatic-discharge-shutoff valves actuated by vessel lowshy
level sensors shall be tested for operation qnce each month
General Proc~dure
Described above under Liquid-Level Shut-tn Controls
High-tempera_ure Coniprc2_()r-Sh_t1tdow_ri_Co~_o1s Inspection Requirement (OCS Order No 8)i
High temperature controls which protect the compressor against
abnormal pressure~ soltiY by such temperature
safety devices shall be tested annually
General Procedure Because of the danger involved in elevating the temperature suffi shy
ciently to cause + temperature device to actuate it is recommended that each temperature device be pre-tested and replaced each year rather than be tested remotely
Oil Spil 1 Detection E_g_t_pmen~
Inspection Requirements (OCS Order 7) All platforms and structures are require~ to have curbs gutters
and spill pans connected to a tank or sump fhis equipment is required to collect all hydrocarbon spillage on the platform It is recommended that this requirement be extencjed to require all unenclosed subsea
equipment to be covered by inverted spill pans with hydrocarbon sensors
and sumps to rem~ve spillage
General Procedure To test the hydrocarbon spi 11 age detection and removal system
a controlled spill should be made in each ar~a or section of spill
- bull
pans while th~ SUljlPI
pumps are monitored for proper operation This I I
metbod will require a signal to the surface to indicate directly when the pumps are running or indirectly by indicating a pressure rise in
I i
the affected pipeline due to the pun1ping action The indirect method is preferablebec~use the pressure rise not only indicates the pumps are running b~t indicates they also are pumpi~g fluid One additional safeguard should ~e employed A TV camera should be used to observe
I
the spill pans in the vicinity of the spill to assure that they are not leaking due to damage or inadequacy of de~ign Hydrocarbon S~nsors
IInspection Requirements
Hydrocarbon sensors are not covered in tbe OCS Qrders presently
in effect General Procedure The general test procedure for the oil-spill-detection equipment
above will test the hydrocarbon sensors for operation In addition
I bull some means of knowing when each separate hydrocarbon sensor in the
spill pan assemblies hus sensed hydrocarbon will provide additional I
protection by warning of system degradation b~fore the system is comshypletely inoperable
7 Summary and RecQ)enda tions This report deal~ with the inspection problems that have arisen
as a result of the present trend of the offshore oil industry towards
subsea completion and production of deep water petroleum reservoirs I
Inspection techniques for completion and prod~ction equipment are inshyvestigated but inspection of fiser systems submersibles and strucshy
tures are not inc~uded in the scope of this wprk
A technique ~as been detailed for calibr1ttion of subsea sensors I
and for verifying the proper OReration of va1ves The technique reshy
quires only that the inspector 1 have access to production tubing at
- bull
I I
the surface By actuating subsurface control valves from the surface
the inspector can isolate a closed fluid path1 to the point of interest I
Pressures read at the surface (when corrected for hydraulic gradients)
may then be used to ca 1 i brate subsurface tran1sducers Flow rates
measured at the surface can be used to I
indicate leakage rates bull
from
subsurface valves I
but fluid in the tubing must be allow
ed to reach
sufficient therma1l equilibriumwith its surroundings so that a false leakage rate is riot indicated due to thermal expansion of the fluid
I bull
This technique has been used to work ou~ an inspection procedure
for the Exxon Sulisea Production System The 1procedure demonstrates I I
that the necessany closed fluid paths can be obtained to permit inshyspection of all necessary points Thus from 1a theoretical point of et
j9aYYew 1 t has ~en established that accurate euroVa 1ua tion of subsea con- J
ditions can be made from the surface (io implement the procedures I
it would first be necessary to conduct an experimental program with field
tests to determi~e operational problems) tAtti e
bull
- Inspection of subsea production systems
-
bull
Example 2 I
1000 ft completion -- P~ = 1000 psi I
I
60deg API 6060deg F -- Sp Gri = 0 7389 From Pi_g__j_ From Table 23 (API STD 25401
70degF F = 0~80 x 10-5 psi-1 Sp Gr bull 07344 -5 -1
120degF F = l10 x 10 psi Sp Gr bull 07117 At 1000 psi pg middot = gp eF x 1000 = 0434middotx (Sp Gr) eF x 1000
1000 o middot o i 080 ~ 10~5 x 1000
At 70degF 9P]OOO bull 0434 (07344) e bull 0321 psift I
1 i o x i o~s x 1 oooAt 120degF gP1000 bull 0434 (07117)e
I = 03]2 psift
PD - Ps = F1 1 n (1 + F PD9 D)
1At 70degF PD
I
- Ps = _ ln (1 +1080 x io-5 x 0321 x 1000)5
080 x 10 = 321 psi
PS bull 679 psi
At 120degF P~ --1----~5 ln (1 + 1 1lO x 10-5 x 0312 x 1000) 110 x 10
= 311 psi Ps = 689 psi
Thus if the surtace pressure P5 were set atmiddot684psi the pressure at the sea bottom transducer would be 1000 plusmn_ 5 psi ~ven if the temperature of the 60deg API gravity oil varied between 70deg and 120degF
bull
I
From the foregoing examples it is apparrnt that for subsea compleshytions up to 1000 ft there is little effect on the calculated
I
pressure at a suhsea transducer due to compressibility and temperature bull
The pressure ca~ be accurately calculated from ~ I bullr
PD - PS = 0434 x Sp Gr x D where the specific gravity of the oil at sta~dard conditions has been corrected to the observed temperature (using an average between the subsea and surface oil temperatures) and 1 i ne pressure Example 3
10000 ft c~mpletion -- P0 = 5000 psi 20deg API 6060degF Sp Gr = 09340
From Fi9 l From Teble 23 (API STD 2540)
70deg F = 039 x l0-5psi-l Sp Gr = 09305 120deg F = 050 x l0-5psi-l Sp Gr = 09130
F x 5000 F x 5000At 5000 psi gp5poo = gp e = 0434 x
I
(=~middotGr ) e0 0
At 70F 9P5poo = 0434 (09305)e039 x 10 x 5000
= 0412 psift I
50 x 5000At 120F 9P~ooo = 0434 (09130)e0middot x 10 -5
= 0406 psift 1
PD - PS= -F- ln (l + Fp gD)0 __L__-=s 1nAt 70degF P ~ (l + 0~39 x 10-5 x 0412 x 10000
D I
P5 039 x 10 = 4087 psi ~ 5000 - 4087 = 913 psir5
At l20F P - P =--1-- ln (l + 050 x 10-5 x 0406 x 10000) D S 050 x l0- 5
- -p~ = 4019 psi P = 981 psi ~
I
Thus if the 1surface pressure r5 were set at 947 the pressure at the
sea bottom trans~ucer would be 5000 +- 34 psi even if the temperature of
the 20degAPI gravity oil varied between 70deg and l20degF
Example 4
I 110000 ft ~omp etion P f 5000 psi0
60deg API 6060degF Sp Gr = 07389 Temp
70degF
l 20degF
From Fig l I ~ -5 -1
F = Oi80 x 10 psi I middot -5 -1F = 110 x 10 psmiddotiI
From Table 23 (API----middotmiddot Sp Gr = 07344
Sp Gr= 07117
STD 2540)
middot F x 5000 F x 5000At 5000 ps1 1 gp 5000 = gp = 0~34 x (Sp Gr)e e0 0
80At 70degF gp middot = 0434 (o 7344)e0middot x 10-5 x 5000
~ooo = o332 psift
_ llxl0_ 5 x5oooAt 120degF gp5000 - 0434 (07117)e
= 0326 psift P ~ P ~ t ln (1 + fp gD)D S D
At 70degF Po_ p = ~__]-____ ln (l + Q80 x lo- 5 x 0332 x 10000) s 080 x 10-~
= 3277 psi I P5 ~ 5000 - 3277 = 1723 psi
At l20degF PD - PS = l 5 ln (l + l l x 10-5 x 0326 x 10000) llOxlOshy
= 3203 psi
PS = 5000 - 3202 = 1797 psi
shybull
Thus if the surface pressure P5 were set at 1760 psi the presshy
sure at the sea ~ottom transducer would be 5000 + 37 psi even if the I shy
temperature cf the 60deg API gravity oil varied between 70deg and 120degF
From these pxample calculations for a 10000 ft completion it is
apparent that temperature variations cause r~latively small errors in I
sea floor ca 1 i bration pressures even for sue~ a great depth If the
pressures are needed more acet1rately than this then the temperature
profile in the tubing would be needed
It has thus been shown that relatively simple calculations of
liquid hydrostatic head result in accurate pressure values for calishy
bration of subsea transducers I
The calibration of gas pressure transdutersmiddot is somewhat different
For low pressures and shallow depth little correction need be made to
the pressure measured at the surface For a gas specific gravity SG
(relative to ai~ at 20degC and 147 psia) pressure P(psia) and depth I
D(ft) the pressure correction AP is given by
-5AP = 356 x 10 x SG x P x D
This equation assumes that the ideal gas law holds and that tPP
is small The equation nay be modified to include the super-compresshy
sibility factor z as follows 0
AP= 356 x 10-Sx SG x D x Pz
For a 1000 ft deep subsea completion line pressure of 1000 psia
(assuming SG ~ 1 and z = 1) AF= 36 psi It is thus apparent that even with large errors in specific gravity and z the pressure correction
1
for hydrostatic head of the gqs is small for depths up to 1000 ft
-bull
Again for a line pressure of 1000 psi but a 10000 ft deep comshy
pletion llP = 3~0 psi so the assumption of PP being small no longer
holds An integration would thus be needed to determine the transducer
pressure and t~e vaHable z factor should be included in thi~ integral Thus a closed form solution similar to tha~ found for liquids cannot
be obtained an~ numerical integration is necessary However for a wide range of conditions the equations pre~ented for both liquids and
I II gases a11 ow acc4ra te cal i bratfon of sea bottom pressure transducers
through the production tubing~ I
I
- -
6 J_nspection_B$9YJrcment_~and Te~t Proc~dures j
The OCS Ord~rs ~ere reviewed for those item~ pertinent to a subsea system The OCS inspection requirements and the suggested general
inspection procedures for these items are discussed in the following
paragraphs Tubing PLtg_
I
Inspection Requirements (OCS Order No 5)I
1 T~e s~~tained liquid leakage flow should not exceed I
400 ccmin 2 The ga~ leakage flo~1 should nGt e)ceed 15 cu ftmin
General Pro~middotedure
The first step i~ this procedure is to isolate a column of fluid
between the tubing plug and the inspector with the valves opened as
for production except that the tubing plug is in pl ace Any fl ow reaching the inspector at the surface is a direct indication of leakage past the tubing plug Thermal equilibrium may b~ required if the
maximum allowabl~ leakage is too small Theflow volume can be measured at the surface in the same manner as for conventionlt1 platform systems
I
middotShut-in Tubi9_ls_e_sur~
Inspection Requirements (OCS Order No I
5)
1 Wells with a shut-in tubing ptessure of 4000 psig or
greater sha11 be equj pped with a subsurface-~ontro11 ed subsurface safety device
-J
2 When the shut-in tubing pressure declines below 4000 I
psig a remotely sontrolled subsurface safety device shall be installed
when the tubing is first removed and reinstalled
General Procedure
To determine if the shut-i~ tubing pressure i~ greater than 4000 psig I
a pressure sensor should be located ~1here the shut-in pressure can be sensed
A convenient arrangement is to locate a pressure s~nsor between the master
valve and wing valve on each tubing With the downhole safety valve and
master valve opened and the wing valve close~ the shmicrot-in tubing pressure
as indicated by the sensor is noted
Calibration of the pressure sensor can be accomplished by applying
a known pressure ~t the surface to a closed cdlumn of fluid connecting I
the surface with the sensor with corrections calculated as explained
in Section 5
Subsurface Safety Device
Inspection Requirements (OCS Order No 5) 1 A surface-controlled subsurface safety device shall be
test operated every six months
2 A subsurface-controlled subsurface safety device shall
be removed inspected and repaired every 12 mdnths 1
General Procedure To test a surface-controlled subsurface safety device the well
should be opened for production and the command then given to close
the subsurface Sifety device The leakage flqw volume if any is
measured at the surface in the same manner as for conventional plat shy
form sys terns bull
1
-)
Pressure Relief Valves Inspection Requtrements (0CS Order No 8)
All pressure reli-f valve~ shall be either bench tested for opershy
ation or tested with an external pressure source (if the valve is somiddot
equipped)annually Jtbt Wf SJJS~+ General Procedure
To test a pressure relief valve for operation the vessel or line
should be pressunizeq to the pressure necessary to open the valve by
using the method suggested in Section 5 Uriless remote position inshy
dicators are provided a means to determine ~hether or not the valve
has actually ope1ed would have to be devised bullfor each subsea system
by observing the effect on the pressure sensors Pressure Sensors
Inspection Requirements (OCS Order No 8)
All pressure sensors shall be tested at least once each month
General Procedure
To remotely test and cal i~rate a subsea bullpressure sensor it is
necessary to
(1) isolate a closed column of fluid irom the surface to
the subsea sensor by properly arranging the ~ys terns va1ves
(2) determine the specific gravity compressibility and the
column height of the fluid
(3) select the pressure required at the subsea sensor
(4) apply the appropriate pressure at the surface end of
the column and
(5) compare the telemetered press4re signal or indication
with the pressur~ applied to the sensor
Automatic Hellhead Safety Devices -~~__--r---
Inspection 8equiremcnts (OCS Order No 8) All automatic wellhead safety devices shall be tested for operation
I
and holding pres~ureonce each1month
I
- -
bull )
General Prooedure
To test the operation of the automatic well head safety devices
the out-of-the-tolerance condition (usually ~igh or low pressure) which actuates the devices should be simulated Urless position 1ndicators
I
are provided a means to deterrl1ine whether 011 not the valves have
actually closed ~ust be devised for each indi1vidu~l system because of
the peculiarities
in each syste m J I
L~ 6 - Jlaquo4 sfSf~ rCheck Valves ~J0141d 11tJt NC Uf~ l(I -v-
Inspection Requirements (OCS Order No ~)
A11 check valves on a11 fl ow 1i nes sha11 be tested for opera ti on
and holding pressure once each month
General Procedures
To test the check valve ft will have to be back pressured The
check valve fails to operate properly if any back flo~1 through the I
valve occurs
~iguid Level Shut-in Controls I
Inspection Requirements (9cs Order No 8)
All liquid-l 1
evel shut-in controls shall be tested once each month
by raising or lowering liquid level across the leyel-control detector
General Pro~edure I
The preferable way to test the liquid-level sh~t-in controls is to
simulate the out-of-tolerance conditions (1 iquid Jevel either low or I
high) at the sensor This sim~lation should cau~e either the inlet
shutoff va1ve to close or the discharge shutoff valve to close In
this manner both the control YStem and the automatif valves are tested I
A means will have to be devised for each subsea system to determine I
if the out-of-tolerance condition actually occurred at the sensor if
it was properly Jetected and i~ it caused thd proper actuation I
Vessel Automatic~Inlet-Shutoff Valves I
Inspection ~equirement (OCS Order No 8)I
-I I
bull ) ~ J) All automatic~~~~~-shutoff valves actuated by vessel~~
I
~fsensorj shalil be tested for operation onle each month General Procedure
Described above under gene~al procedure for Liquid-Level Shut-
In Controls Vessel AutomaJi c-Di sc_b~_g_e-Sh_ll__Dff__Y_ii_l ves
Inspection RequireiT1ent (OCS Order No 8) All automatic-discharge-shutoff valves actuated by vessel lowshy
level sensors shall be tested for operation qnce each month
General Proc~dure
Described above under Liquid-Level Shut-tn Controls
High-tempera_ure Coniprc2_()r-Sh_t1tdow_ri_Co~_o1s Inspection Requirement (OCS Order No 8)i
High temperature controls which protect the compressor against
abnormal pressure~ soltiY by such temperature
safety devices shall be tested annually
General Procedure Because of the danger involved in elevating the temperature suffi shy
ciently to cause + temperature device to actuate it is recommended that each temperature device be pre-tested and replaced each year rather than be tested remotely
Oil Spil 1 Detection E_g_t_pmen~
Inspection Requirements (OCS Order 7) All platforms and structures are require~ to have curbs gutters
and spill pans connected to a tank or sump fhis equipment is required to collect all hydrocarbon spillage on the platform It is recommended that this requirement be extencjed to require all unenclosed subsea
equipment to be covered by inverted spill pans with hydrocarbon sensors
and sumps to rem~ve spillage
General Procedure To test the hydrocarbon spi 11 age detection and removal system
a controlled spill should be made in each ar~a or section of spill
- bull
pans while th~ SUljlPI
pumps are monitored for proper operation This I I
metbod will require a signal to the surface to indicate directly when the pumps are running or indirectly by indicating a pressure rise in
I i
the affected pipeline due to the pun1ping action The indirect method is preferablebec~use the pressure rise not only indicates the pumps are running b~t indicates they also are pumpi~g fluid One additional safeguard should ~e employed A TV camera should be used to observe
I
the spill pans in the vicinity of the spill to assure that they are not leaking due to damage or inadequacy of de~ign Hydrocarbon S~nsors
IInspection Requirements
Hydrocarbon sensors are not covered in tbe OCS Qrders presently
in effect General Procedure The general test procedure for the oil-spill-detection equipment
above will test the hydrocarbon sensors for operation In addition
I bull some means of knowing when each separate hydrocarbon sensor in the
spill pan assemblies hus sensed hydrocarbon will provide additional I
protection by warning of system degradation b~fore the system is comshypletely inoperable
7 Summary and RecQ)enda tions This report deal~ with the inspection problems that have arisen
as a result of the present trend of the offshore oil industry towards
subsea completion and production of deep water petroleum reservoirs I
Inspection techniques for completion and prod~ction equipment are inshyvestigated but inspection of fiser systems submersibles and strucshy
tures are not inc~uded in the scope of this wprk
A technique ~as been detailed for calibr1ttion of subsea sensors I
and for verifying the proper OReration of va1ves The technique reshy
quires only that the inspector 1 have access to production tubing at
- bull
I I
the surface By actuating subsurface control valves from the surface
the inspector can isolate a closed fluid path1 to the point of interest I
Pressures read at the surface (when corrected for hydraulic gradients)
may then be used to ca 1 i brate subsurface tran1sducers Flow rates
measured at the surface can be used to I
indicate leakage rates bull
from
subsurface valves I
but fluid in the tubing must be allow
ed to reach
sufficient therma1l equilibriumwith its surroundings so that a false leakage rate is riot indicated due to thermal expansion of the fluid
I bull
This technique has been used to work ou~ an inspection procedure
for the Exxon Sulisea Production System The 1procedure demonstrates I I
that the necessany closed fluid paths can be obtained to permit inshyspection of all necessary points Thus from 1a theoretical point of et
j9aYYew 1 t has ~en established that accurate euroVa 1ua tion of subsea con- J
ditions can be made from the surface (io implement the procedures I
it would first be necessary to conduct an experimental program with field
tests to determi~e operational problems) tAtti e
bull
- Inspection of subsea production systems
-
bull
I
From the foregoing examples it is apparrnt that for subsea compleshytions up to 1000 ft there is little effect on the calculated
I
pressure at a suhsea transducer due to compressibility and temperature bull
The pressure ca~ be accurately calculated from ~ I bullr
PD - PS = 0434 x Sp Gr x D where the specific gravity of the oil at sta~dard conditions has been corrected to the observed temperature (using an average between the subsea and surface oil temperatures) and 1 i ne pressure Example 3
10000 ft c~mpletion -- P0 = 5000 psi 20deg API 6060degF Sp Gr = 09340
From Fi9 l From Teble 23 (API STD 2540)
70deg F = 039 x l0-5psi-l Sp Gr = 09305 120deg F = 050 x l0-5psi-l Sp Gr = 09130
F x 5000 F x 5000At 5000 psi gp5poo = gp e = 0434 x
I
(=~middotGr ) e0 0
At 70F 9P5poo = 0434 (09305)e039 x 10 x 5000
= 0412 psift I
50 x 5000At 120F 9P~ooo = 0434 (09130)e0middot x 10 -5
= 0406 psift 1
PD - PS= -F- ln (l + Fp gD)0 __L__-=s 1nAt 70degF P ~ (l + 0~39 x 10-5 x 0412 x 10000
D I
P5 039 x 10 = 4087 psi ~ 5000 - 4087 = 913 psir5
At l20F P - P =--1-- ln (l + 050 x 10-5 x 0406 x 10000) D S 050 x l0- 5
- -p~ = 4019 psi P = 981 psi ~
I
Thus if the 1surface pressure r5 were set at 947 the pressure at the
sea bottom trans~ucer would be 5000 +- 34 psi even if the temperature of
the 20degAPI gravity oil varied between 70deg and l20degF
Example 4
I 110000 ft ~omp etion P f 5000 psi0
60deg API 6060degF Sp Gr = 07389 Temp
70degF
l 20degF
From Fig l I ~ -5 -1
F = Oi80 x 10 psi I middot -5 -1F = 110 x 10 psmiddotiI
From Table 23 (API----middotmiddot Sp Gr = 07344
Sp Gr= 07117
STD 2540)
middot F x 5000 F x 5000At 5000 ps1 1 gp 5000 = gp = 0~34 x (Sp Gr)e e0 0
80At 70degF gp middot = 0434 (o 7344)e0middot x 10-5 x 5000
~ooo = o332 psift
_ llxl0_ 5 x5oooAt 120degF gp5000 - 0434 (07117)e
= 0326 psift P ~ P ~ t ln (1 + fp gD)D S D
At 70degF Po_ p = ~__]-____ ln (l + Q80 x lo- 5 x 0332 x 10000) s 080 x 10-~
= 3277 psi I P5 ~ 5000 - 3277 = 1723 psi
At l20degF PD - PS = l 5 ln (l + l l x 10-5 x 0326 x 10000) llOxlOshy
= 3203 psi
PS = 5000 - 3202 = 1797 psi
shybull
Thus if the surface pressure P5 were set at 1760 psi the presshy
sure at the sea ~ottom transducer would be 5000 + 37 psi even if the I shy
temperature cf the 60deg API gravity oil varied between 70deg and 120degF
From these pxample calculations for a 10000 ft completion it is
apparent that temperature variations cause r~latively small errors in I
sea floor ca 1 i bration pressures even for sue~ a great depth If the
pressures are needed more acet1rately than this then the temperature
profile in the tubing would be needed
It has thus been shown that relatively simple calculations of
liquid hydrostatic head result in accurate pressure values for calishy
bration of subsea transducers I
The calibration of gas pressure transdutersmiddot is somewhat different
For low pressures and shallow depth little correction need be made to
the pressure measured at the surface For a gas specific gravity SG
(relative to ai~ at 20degC and 147 psia) pressure P(psia) and depth I
D(ft) the pressure correction AP is given by
-5AP = 356 x 10 x SG x P x D
This equation assumes that the ideal gas law holds and that tPP
is small The equation nay be modified to include the super-compresshy
sibility factor z as follows 0
AP= 356 x 10-Sx SG x D x Pz
For a 1000 ft deep subsea completion line pressure of 1000 psia
(assuming SG ~ 1 and z = 1) AF= 36 psi It is thus apparent that even with large errors in specific gravity and z the pressure correction
1
for hydrostatic head of the gqs is small for depths up to 1000 ft
-bull
Again for a line pressure of 1000 psi but a 10000 ft deep comshy
pletion llP = 3~0 psi so the assumption of PP being small no longer
holds An integration would thus be needed to determine the transducer
pressure and t~e vaHable z factor should be included in thi~ integral Thus a closed form solution similar to tha~ found for liquids cannot
be obtained an~ numerical integration is necessary However for a wide range of conditions the equations pre~ented for both liquids and
I II gases a11 ow acc4ra te cal i bratfon of sea bottom pressure transducers
through the production tubing~ I
I
- -
6 J_nspection_B$9YJrcment_~and Te~t Proc~dures j
The OCS Ord~rs ~ere reviewed for those item~ pertinent to a subsea system The OCS inspection requirements and the suggested general
inspection procedures for these items are discussed in the following
paragraphs Tubing PLtg_
I
Inspection Requirements (OCS Order No 5)I
1 T~e s~~tained liquid leakage flow should not exceed I
400 ccmin 2 The ga~ leakage flo~1 should nGt e)ceed 15 cu ftmin
General Pro~middotedure
The first step i~ this procedure is to isolate a column of fluid
between the tubing plug and the inspector with the valves opened as
for production except that the tubing plug is in pl ace Any fl ow reaching the inspector at the surface is a direct indication of leakage past the tubing plug Thermal equilibrium may b~ required if the
maximum allowabl~ leakage is too small Theflow volume can be measured at the surface in the same manner as for conventionlt1 platform systems
I
middotShut-in Tubi9_ls_e_sur~
Inspection Requirements (OCS Order No I
5)
1 Wells with a shut-in tubing ptessure of 4000 psig or
greater sha11 be equj pped with a subsurface-~ontro11 ed subsurface safety device
-J
2 When the shut-in tubing pressure declines below 4000 I
psig a remotely sontrolled subsurface safety device shall be installed
when the tubing is first removed and reinstalled
General Procedure
To determine if the shut-i~ tubing pressure i~ greater than 4000 psig I
a pressure sensor should be located ~1here the shut-in pressure can be sensed
A convenient arrangement is to locate a pressure s~nsor between the master
valve and wing valve on each tubing With the downhole safety valve and
master valve opened and the wing valve close~ the shmicrot-in tubing pressure
as indicated by the sensor is noted
Calibration of the pressure sensor can be accomplished by applying
a known pressure ~t the surface to a closed cdlumn of fluid connecting I
the surface with the sensor with corrections calculated as explained
in Section 5
Subsurface Safety Device
Inspection Requirements (OCS Order No 5) 1 A surface-controlled subsurface safety device shall be
test operated every six months
2 A subsurface-controlled subsurface safety device shall
be removed inspected and repaired every 12 mdnths 1
General Procedure To test a surface-controlled subsurface safety device the well
should be opened for production and the command then given to close
the subsurface Sifety device The leakage flqw volume if any is
measured at the surface in the same manner as for conventional plat shy
form sys terns bull
1
-)
Pressure Relief Valves Inspection Requtrements (0CS Order No 8)
All pressure reli-f valve~ shall be either bench tested for opershy
ation or tested with an external pressure source (if the valve is somiddot
equipped)annually Jtbt Wf SJJS~+ General Procedure
To test a pressure relief valve for operation the vessel or line
should be pressunizeq to the pressure necessary to open the valve by
using the method suggested in Section 5 Uriless remote position inshy
dicators are provided a means to determine ~hether or not the valve
has actually ope1ed would have to be devised bullfor each subsea system
by observing the effect on the pressure sensors Pressure Sensors
Inspection Requirements (OCS Order No 8)
All pressure sensors shall be tested at least once each month
General Procedure
To remotely test and cal i~rate a subsea bullpressure sensor it is
necessary to
(1) isolate a closed column of fluid irom the surface to
the subsea sensor by properly arranging the ~ys terns va1ves
(2) determine the specific gravity compressibility and the
column height of the fluid
(3) select the pressure required at the subsea sensor
(4) apply the appropriate pressure at the surface end of
the column and
(5) compare the telemetered press4re signal or indication
with the pressur~ applied to the sensor
Automatic Hellhead Safety Devices -~~__--r---
Inspection 8equiremcnts (OCS Order No 8) All automatic wellhead safety devices shall be tested for operation
I
and holding pres~ureonce each1month
I
- -
bull )
General Prooedure
To test the operation of the automatic well head safety devices
the out-of-the-tolerance condition (usually ~igh or low pressure) which actuates the devices should be simulated Urless position 1ndicators
I
are provided a means to deterrl1ine whether 011 not the valves have
actually closed ~ust be devised for each indi1vidu~l system because of
the peculiarities
in each syste m J I
L~ 6 - Jlaquo4 sfSf~ rCheck Valves ~J0141d 11tJt NC Uf~ l(I -v-
Inspection Requirements (OCS Order No ~)
A11 check valves on a11 fl ow 1i nes sha11 be tested for opera ti on
and holding pressure once each month
General Procedures
To test the check valve ft will have to be back pressured The
check valve fails to operate properly if any back flo~1 through the I
valve occurs
~iguid Level Shut-in Controls I
Inspection Requirements (9cs Order No 8)
All liquid-l 1
evel shut-in controls shall be tested once each month
by raising or lowering liquid level across the leyel-control detector
General Pro~edure I
The preferable way to test the liquid-level sh~t-in controls is to
simulate the out-of-tolerance conditions (1 iquid Jevel either low or I
high) at the sensor This sim~lation should cau~e either the inlet
shutoff va1ve to close or the discharge shutoff valve to close In
this manner both the control YStem and the automatif valves are tested I
A means will have to be devised for each subsea system to determine I
if the out-of-tolerance condition actually occurred at the sensor if
it was properly Jetected and i~ it caused thd proper actuation I
Vessel Automatic~Inlet-Shutoff Valves I
Inspection ~equirement (OCS Order No 8)I
-I I
bull ) ~ J) All automatic~~~~~-shutoff valves actuated by vessel~~
I
~fsensorj shalil be tested for operation onle each month General Procedure
Described above under gene~al procedure for Liquid-Level Shut-
In Controls Vessel AutomaJi c-Di sc_b~_g_e-Sh_ll__Dff__Y_ii_l ves
Inspection RequireiT1ent (OCS Order No 8) All automatic-discharge-shutoff valves actuated by vessel lowshy
level sensors shall be tested for operation qnce each month
General Proc~dure
Described above under Liquid-Level Shut-tn Controls
High-tempera_ure Coniprc2_()r-Sh_t1tdow_ri_Co~_o1s Inspection Requirement (OCS Order No 8)i
High temperature controls which protect the compressor against
abnormal pressure~ soltiY by such temperature
safety devices shall be tested annually
General Procedure Because of the danger involved in elevating the temperature suffi shy
ciently to cause + temperature device to actuate it is recommended that each temperature device be pre-tested and replaced each year rather than be tested remotely
Oil Spil 1 Detection E_g_t_pmen~
Inspection Requirements (OCS Order 7) All platforms and structures are require~ to have curbs gutters
and spill pans connected to a tank or sump fhis equipment is required to collect all hydrocarbon spillage on the platform It is recommended that this requirement be extencjed to require all unenclosed subsea
equipment to be covered by inverted spill pans with hydrocarbon sensors
and sumps to rem~ve spillage
General Procedure To test the hydrocarbon spi 11 age detection and removal system
a controlled spill should be made in each ar~a or section of spill
- bull
pans while th~ SUljlPI
pumps are monitored for proper operation This I I
metbod will require a signal to the surface to indicate directly when the pumps are running or indirectly by indicating a pressure rise in
I i
the affected pipeline due to the pun1ping action The indirect method is preferablebec~use the pressure rise not only indicates the pumps are running b~t indicates they also are pumpi~g fluid One additional safeguard should ~e employed A TV camera should be used to observe
I
the spill pans in the vicinity of the spill to assure that they are not leaking due to damage or inadequacy of de~ign Hydrocarbon S~nsors
IInspection Requirements
Hydrocarbon sensors are not covered in tbe OCS Qrders presently
in effect General Procedure The general test procedure for the oil-spill-detection equipment
above will test the hydrocarbon sensors for operation In addition
I bull some means of knowing when each separate hydrocarbon sensor in the
spill pan assemblies hus sensed hydrocarbon will provide additional I
protection by warning of system degradation b~fore the system is comshypletely inoperable
7 Summary and RecQ)enda tions This report deal~ with the inspection problems that have arisen
as a result of the present trend of the offshore oil industry towards
subsea completion and production of deep water petroleum reservoirs I
Inspection techniques for completion and prod~ction equipment are inshyvestigated but inspection of fiser systems submersibles and strucshy
tures are not inc~uded in the scope of this wprk
A technique ~as been detailed for calibr1ttion of subsea sensors I
and for verifying the proper OReration of va1ves The technique reshy
quires only that the inspector 1 have access to production tubing at
- bull
I I
the surface By actuating subsurface control valves from the surface
the inspector can isolate a closed fluid path1 to the point of interest I
Pressures read at the surface (when corrected for hydraulic gradients)
may then be used to ca 1 i brate subsurface tran1sducers Flow rates
measured at the surface can be used to I
indicate leakage rates bull
from
subsurface valves I
but fluid in the tubing must be allow
ed to reach
sufficient therma1l equilibriumwith its surroundings so that a false leakage rate is riot indicated due to thermal expansion of the fluid
I bull
This technique has been used to work ou~ an inspection procedure
for the Exxon Sulisea Production System The 1procedure demonstrates I I
that the necessany closed fluid paths can be obtained to permit inshyspection of all necessary points Thus from 1a theoretical point of et
j9aYYew 1 t has ~en established that accurate euroVa 1ua tion of subsea con- J
ditions can be made from the surface (io implement the procedures I
it would first be necessary to conduct an experimental program with field
tests to determi~e operational problems) tAtti e
bull
- Inspection of subsea production systems
-
- -p~ = 4019 psi P = 981 psi ~
I
Thus if the 1surface pressure r5 were set at 947 the pressure at the
sea bottom trans~ucer would be 5000 +- 34 psi even if the temperature of
the 20degAPI gravity oil varied between 70deg and l20degF
Example 4
I 110000 ft ~omp etion P f 5000 psi0
60deg API 6060degF Sp Gr = 07389 Temp
70degF
l 20degF
From Fig l I ~ -5 -1
F = Oi80 x 10 psi I middot -5 -1F = 110 x 10 psmiddotiI
From Table 23 (API----middotmiddot Sp Gr = 07344
Sp Gr= 07117
STD 2540)
middot F x 5000 F x 5000At 5000 ps1 1 gp 5000 = gp = 0~34 x (Sp Gr)e e0 0
80At 70degF gp middot = 0434 (o 7344)e0middot x 10-5 x 5000
~ooo = o332 psift
_ llxl0_ 5 x5oooAt 120degF gp5000 - 0434 (07117)e
= 0326 psift P ~ P ~ t ln (1 + fp gD)D S D
At 70degF Po_ p = ~__]-____ ln (l + Q80 x lo- 5 x 0332 x 10000) s 080 x 10-~
= 3277 psi I P5 ~ 5000 - 3277 = 1723 psi
At l20degF PD - PS = l 5 ln (l + l l x 10-5 x 0326 x 10000) llOxlOshy
= 3203 psi
PS = 5000 - 3202 = 1797 psi
shybull
Thus if the surface pressure P5 were set at 1760 psi the presshy
sure at the sea ~ottom transducer would be 5000 + 37 psi even if the I shy
temperature cf the 60deg API gravity oil varied between 70deg and 120degF
From these pxample calculations for a 10000 ft completion it is
apparent that temperature variations cause r~latively small errors in I
sea floor ca 1 i bration pressures even for sue~ a great depth If the
pressures are needed more acet1rately than this then the temperature
profile in the tubing would be needed
It has thus been shown that relatively simple calculations of
liquid hydrostatic head result in accurate pressure values for calishy
bration of subsea transducers I
The calibration of gas pressure transdutersmiddot is somewhat different
For low pressures and shallow depth little correction need be made to
the pressure measured at the surface For a gas specific gravity SG
(relative to ai~ at 20degC and 147 psia) pressure P(psia) and depth I
D(ft) the pressure correction AP is given by
-5AP = 356 x 10 x SG x P x D
This equation assumes that the ideal gas law holds and that tPP
is small The equation nay be modified to include the super-compresshy
sibility factor z as follows 0
AP= 356 x 10-Sx SG x D x Pz
For a 1000 ft deep subsea completion line pressure of 1000 psia
(assuming SG ~ 1 and z = 1) AF= 36 psi It is thus apparent that even with large errors in specific gravity and z the pressure correction
1
for hydrostatic head of the gqs is small for depths up to 1000 ft
-bull
Again for a line pressure of 1000 psi but a 10000 ft deep comshy
pletion llP = 3~0 psi so the assumption of PP being small no longer
holds An integration would thus be needed to determine the transducer
pressure and t~e vaHable z factor should be included in thi~ integral Thus a closed form solution similar to tha~ found for liquids cannot
be obtained an~ numerical integration is necessary However for a wide range of conditions the equations pre~ented for both liquids and
I II gases a11 ow acc4ra te cal i bratfon of sea bottom pressure transducers
through the production tubing~ I
I
- -
6 J_nspection_B$9YJrcment_~and Te~t Proc~dures j
The OCS Ord~rs ~ere reviewed for those item~ pertinent to a subsea system The OCS inspection requirements and the suggested general
inspection procedures for these items are discussed in the following
paragraphs Tubing PLtg_
I
Inspection Requirements (OCS Order No 5)I
1 T~e s~~tained liquid leakage flow should not exceed I
400 ccmin 2 The ga~ leakage flo~1 should nGt e)ceed 15 cu ftmin
General Pro~middotedure
The first step i~ this procedure is to isolate a column of fluid
between the tubing plug and the inspector with the valves opened as
for production except that the tubing plug is in pl ace Any fl ow reaching the inspector at the surface is a direct indication of leakage past the tubing plug Thermal equilibrium may b~ required if the
maximum allowabl~ leakage is too small Theflow volume can be measured at the surface in the same manner as for conventionlt1 platform systems
I
middotShut-in Tubi9_ls_e_sur~
Inspection Requirements (OCS Order No I
5)
1 Wells with a shut-in tubing ptessure of 4000 psig or
greater sha11 be equj pped with a subsurface-~ontro11 ed subsurface safety device
-J
2 When the shut-in tubing pressure declines below 4000 I
psig a remotely sontrolled subsurface safety device shall be installed
when the tubing is first removed and reinstalled
General Procedure
To determine if the shut-i~ tubing pressure i~ greater than 4000 psig I
a pressure sensor should be located ~1here the shut-in pressure can be sensed
A convenient arrangement is to locate a pressure s~nsor between the master
valve and wing valve on each tubing With the downhole safety valve and
master valve opened and the wing valve close~ the shmicrot-in tubing pressure
as indicated by the sensor is noted
Calibration of the pressure sensor can be accomplished by applying
a known pressure ~t the surface to a closed cdlumn of fluid connecting I
the surface with the sensor with corrections calculated as explained
in Section 5
Subsurface Safety Device
Inspection Requirements (OCS Order No 5) 1 A surface-controlled subsurface safety device shall be
test operated every six months
2 A subsurface-controlled subsurface safety device shall
be removed inspected and repaired every 12 mdnths 1
General Procedure To test a surface-controlled subsurface safety device the well
should be opened for production and the command then given to close
the subsurface Sifety device The leakage flqw volume if any is
measured at the surface in the same manner as for conventional plat shy
form sys terns bull
1
-)
Pressure Relief Valves Inspection Requtrements (0CS Order No 8)
All pressure reli-f valve~ shall be either bench tested for opershy
ation or tested with an external pressure source (if the valve is somiddot
equipped)annually Jtbt Wf SJJS~+ General Procedure
To test a pressure relief valve for operation the vessel or line
should be pressunizeq to the pressure necessary to open the valve by
using the method suggested in Section 5 Uriless remote position inshy
dicators are provided a means to determine ~hether or not the valve
has actually ope1ed would have to be devised bullfor each subsea system
by observing the effect on the pressure sensors Pressure Sensors
Inspection Requirements (OCS Order No 8)
All pressure sensors shall be tested at least once each month
General Procedure
To remotely test and cal i~rate a subsea bullpressure sensor it is
necessary to
(1) isolate a closed column of fluid irom the surface to
the subsea sensor by properly arranging the ~ys terns va1ves
(2) determine the specific gravity compressibility and the
column height of the fluid
(3) select the pressure required at the subsea sensor
(4) apply the appropriate pressure at the surface end of
the column and
(5) compare the telemetered press4re signal or indication
with the pressur~ applied to the sensor
Automatic Hellhead Safety Devices -~~__--r---
Inspection 8equiremcnts (OCS Order No 8) All automatic wellhead safety devices shall be tested for operation
I
and holding pres~ureonce each1month
I
- -
bull )
General Prooedure
To test the operation of the automatic well head safety devices
the out-of-the-tolerance condition (usually ~igh or low pressure) which actuates the devices should be simulated Urless position 1ndicators
I
are provided a means to deterrl1ine whether 011 not the valves have
actually closed ~ust be devised for each indi1vidu~l system because of
the peculiarities
in each syste m J I
L~ 6 - Jlaquo4 sfSf~ rCheck Valves ~J0141d 11tJt NC Uf~ l(I -v-
Inspection Requirements (OCS Order No ~)
A11 check valves on a11 fl ow 1i nes sha11 be tested for opera ti on
and holding pressure once each month
General Procedures
To test the check valve ft will have to be back pressured The
check valve fails to operate properly if any back flo~1 through the I
valve occurs
~iguid Level Shut-in Controls I
Inspection Requirements (9cs Order No 8)
All liquid-l 1
evel shut-in controls shall be tested once each month
by raising or lowering liquid level across the leyel-control detector
General Pro~edure I
The preferable way to test the liquid-level sh~t-in controls is to
simulate the out-of-tolerance conditions (1 iquid Jevel either low or I
high) at the sensor This sim~lation should cau~e either the inlet
shutoff va1ve to close or the discharge shutoff valve to close In
this manner both the control YStem and the automatif valves are tested I
A means will have to be devised for each subsea system to determine I
if the out-of-tolerance condition actually occurred at the sensor if
it was properly Jetected and i~ it caused thd proper actuation I
Vessel Automatic~Inlet-Shutoff Valves I
Inspection ~equirement (OCS Order No 8)I
-I I
bull ) ~ J) All automatic~~~~~-shutoff valves actuated by vessel~~
I
~fsensorj shalil be tested for operation onle each month General Procedure
Described above under gene~al procedure for Liquid-Level Shut-
In Controls Vessel AutomaJi c-Di sc_b~_g_e-Sh_ll__Dff__Y_ii_l ves
Inspection RequireiT1ent (OCS Order No 8) All automatic-discharge-shutoff valves actuated by vessel lowshy
level sensors shall be tested for operation qnce each month
General Proc~dure
Described above under Liquid-Level Shut-tn Controls
High-tempera_ure Coniprc2_()r-Sh_t1tdow_ri_Co~_o1s Inspection Requirement (OCS Order No 8)i
High temperature controls which protect the compressor against
abnormal pressure~ soltiY by such temperature
safety devices shall be tested annually
General Procedure Because of the danger involved in elevating the temperature suffi shy
ciently to cause + temperature device to actuate it is recommended that each temperature device be pre-tested and replaced each year rather than be tested remotely
Oil Spil 1 Detection E_g_t_pmen~
Inspection Requirements (OCS Order 7) All platforms and structures are require~ to have curbs gutters
and spill pans connected to a tank or sump fhis equipment is required to collect all hydrocarbon spillage on the platform It is recommended that this requirement be extencjed to require all unenclosed subsea
equipment to be covered by inverted spill pans with hydrocarbon sensors
and sumps to rem~ve spillage
General Procedure To test the hydrocarbon spi 11 age detection and removal system
a controlled spill should be made in each ar~a or section of spill
- bull
pans while th~ SUljlPI
pumps are monitored for proper operation This I I
metbod will require a signal to the surface to indicate directly when the pumps are running or indirectly by indicating a pressure rise in
I i
the affected pipeline due to the pun1ping action The indirect method is preferablebec~use the pressure rise not only indicates the pumps are running b~t indicates they also are pumpi~g fluid One additional safeguard should ~e employed A TV camera should be used to observe
I
the spill pans in the vicinity of the spill to assure that they are not leaking due to damage or inadequacy of de~ign Hydrocarbon S~nsors
IInspection Requirements
Hydrocarbon sensors are not covered in tbe OCS Qrders presently
in effect General Procedure The general test procedure for the oil-spill-detection equipment
above will test the hydrocarbon sensors for operation In addition
I bull some means of knowing when each separate hydrocarbon sensor in the
spill pan assemblies hus sensed hydrocarbon will provide additional I
protection by warning of system degradation b~fore the system is comshypletely inoperable
7 Summary and RecQ)enda tions This report deal~ with the inspection problems that have arisen
as a result of the present trend of the offshore oil industry towards
subsea completion and production of deep water petroleum reservoirs I
Inspection techniques for completion and prod~ction equipment are inshyvestigated but inspection of fiser systems submersibles and strucshy
tures are not inc~uded in the scope of this wprk
A technique ~as been detailed for calibr1ttion of subsea sensors I
and for verifying the proper OReration of va1ves The technique reshy
quires only that the inspector 1 have access to production tubing at
- bull
I I
the surface By actuating subsurface control valves from the surface
the inspector can isolate a closed fluid path1 to the point of interest I
Pressures read at the surface (when corrected for hydraulic gradients)
may then be used to ca 1 i brate subsurface tran1sducers Flow rates
measured at the surface can be used to I
indicate leakage rates bull
from
subsurface valves I
but fluid in the tubing must be allow
ed to reach
sufficient therma1l equilibriumwith its surroundings so that a false leakage rate is riot indicated due to thermal expansion of the fluid
I bull
This technique has been used to work ou~ an inspection procedure
for the Exxon Sulisea Production System The 1procedure demonstrates I I
that the necessany closed fluid paths can be obtained to permit inshyspection of all necessary points Thus from 1a theoretical point of et
j9aYYew 1 t has ~en established that accurate euroVa 1ua tion of subsea con- J
ditions can be made from the surface (io implement the procedures I
it would first be necessary to conduct an experimental program with field
tests to determi~e operational problems) tAtti e
bull
- Inspection of subsea production systems
-
shybull
Thus if the surface pressure P5 were set at 1760 psi the presshy
sure at the sea ~ottom transducer would be 5000 + 37 psi even if the I shy
temperature cf the 60deg API gravity oil varied between 70deg and 120degF
From these pxample calculations for a 10000 ft completion it is
apparent that temperature variations cause r~latively small errors in I
sea floor ca 1 i bration pressures even for sue~ a great depth If the
pressures are needed more acet1rately than this then the temperature
profile in the tubing would be needed
It has thus been shown that relatively simple calculations of
liquid hydrostatic head result in accurate pressure values for calishy
bration of subsea transducers I
The calibration of gas pressure transdutersmiddot is somewhat different
For low pressures and shallow depth little correction need be made to
the pressure measured at the surface For a gas specific gravity SG
(relative to ai~ at 20degC and 147 psia) pressure P(psia) and depth I
D(ft) the pressure correction AP is given by
-5AP = 356 x 10 x SG x P x D
This equation assumes that the ideal gas law holds and that tPP
is small The equation nay be modified to include the super-compresshy
sibility factor z as follows 0
AP= 356 x 10-Sx SG x D x Pz
For a 1000 ft deep subsea completion line pressure of 1000 psia
(assuming SG ~ 1 and z = 1) AF= 36 psi It is thus apparent that even with large errors in specific gravity and z the pressure correction
1
for hydrostatic head of the gqs is small for depths up to 1000 ft
-bull
Again for a line pressure of 1000 psi but a 10000 ft deep comshy
pletion llP = 3~0 psi so the assumption of PP being small no longer
holds An integration would thus be needed to determine the transducer
pressure and t~e vaHable z factor should be included in thi~ integral Thus a closed form solution similar to tha~ found for liquids cannot
be obtained an~ numerical integration is necessary However for a wide range of conditions the equations pre~ented for both liquids and
I II gases a11 ow acc4ra te cal i bratfon of sea bottom pressure transducers
through the production tubing~ I
I
- -
6 J_nspection_B$9YJrcment_~and Te~t Proc~dures j
The OCS Ord~rs ~ere reviewed for those item~ pertinent to a subsea system The OCS inspection requirements and the suggested general
inspection procedures for these items are discussed in the following
paragraphs Tubing PLtg_
I
Inspection Requirements (OCS Order No 5)I
1 T~e s~~tained liquid leakage flow should not exceed I
400 ccmin 2 The ga~ leakage flo~1 should nGt e)ceed 15 cu ftmin
General Pro~middotedure
The first step i~ this procedure is to isolate a column of fluid
between the tubing plug and the inspector with the valves opened as
for production except that the tubing plug is in pl ace Any fl ow reaching the inspector at the surface is a direct indication of leakage past the tubing plug Thermal equilibrium may b~ required if the
maximum allowabl~ leakage is too small Theflow volume can be measured at the surface in the same manner as for conventionlt1 platform systems
I
middotShut-in Tubi9_ls_e_sur~
Inspection Requirements (OCS Order No I
5)
1 Wells with a shut-in tubing ptessure of 4000 psig or
greater sha11 be equj pped with a subsurface-~ontro11 ed subsurface safety device
-J
2 When the shut-in tubing pressure declines below 4000 I
psig a remotely sontrolled subsurface safety device shall be installed
when the tubing is first removed and reinstalled
General Procedure
To determine if the shut-i~ tubing pressure i~ greater than 4000 psig I
a pressure sensor should be located ~1here the shut-in pressure can be sensed
A convenient arrangement is to locate a pressure s~nsor between the master
valve and wing valve on each tubing With the downhole safety valve and
master valve opened and the wing valve close~ the shmicrot-in tubing pressure
as indicated by the sensor is noted
Calibration of the pressure sensor can be accomplished by applying
a known pressure ~t the surface to a closed cdlumn of fluid connecting I
the surface with the sensor with corrections calculated as explained
in Section 5
Subsurface Safety Device
Inspection Requirements (OCS Order No 5) 1 A surface-controlled subsurface safety device shall be
test operated every six months
2 A subsurface-controlled subsurface safety device shall
be removed inspected and repaired every 12 mdnths 1
General Procedure To test a surface-controlled subsurface safety device the well
should be opened for production and the command then given to close
the subsurface Sifety device The leakage flqw volume if any is
measured at the surface in the same manner as for conventional plat shy
form sys terns bull
1
-)
Pressure Relief Valves Inspection Requtrements (0CS Order No 8)
All pressure reli-f valve~ shall be either bench tested for opershy
ation or tested with an external pressure source (if the valve is somiddot
equipped)annually Jtbt Wf SJJS~+ General Procedure
To test a pressure relief valve for operation the vessel or line
should be pressunizeq to the pressure necessary to open the valve by
using the method suggested in Section 5 Uriless remote position inshy
dicators are provided a means to determine ~hether or not the valve
has actually ope1ed would have to be devised bullfor each subsea system
by observing the effect on the pressure sensors Pressure Sensors
Inspection Requirements (OCS Order No 8)
All pressure sensors shall be tested at least once each month
General Procedure
To remotely test and cal i~rate a subsea bullpressure sensor it is
necessary to
(1) isolate a closed column of fluid irom the surface to
the subsea sensor by properly arranging the ~ys terns va1ves
(2) determine the specific gravity compressibility and the
column height of the fluid
(3) select the pressure required at the subsea sensor
(4) apply the appropriate pressure at the surface end of
the column and
(5) compare the telemetered press4re signal or indication
with the pressur~ applied to the sensor
Automatic Hellhead Safety Devices -~~__--r---
Inspection 8equiremcnts (OCS Order No 8) All automatic wellhead safety devices shall be tested for operation
I
and holding pres~ureonce each1month
I
- -
bull )
General Prooedure
To test the operation of the automatic well head safety devices
the out-of-the-tolerance condition (usually ~igh or low pressure) which actuates the devices should be simulated Urless position 1ndicators
I
are provided a means to deterrl1ine whether 011 not the valves have
actually closed ~ust be devised for each indi1vidu~l system because of
the peculiarities
in each syste m J I
L~ 6 - Jlaquo4 sfSf~ rCheck Valves ~J0141d 11tJt NC Uf~ l(I -v-
Inspection Requirements (OCS Order No ~)
A11 check valves on a11 fl ow 1i nes sha11 be tested for opera ti on
and holding pressure once each month
General Procedures
To test the check valve ft will have to be back pressured The
check valve fails to operate properly if any back flo~1 through the I
valve occurs
~iguid Level Shut-in Controls I
Inspection Requirements (9cs Order No 8)
All liquid-l 1
evel shut-in controls shall be tested once each month
by raising or lowering liquid level across the leyel-control detector
General Pro~edure I
The preferable way to test the liquid-level sh~t-in controls is to
simulate the out-of-tolerance conditions (1 iquid Jevel either low or I
high) at the sensor This sim~lation should cau~e either the inlet
shutoff va1ve to close or the discharge shutoff valve to close In
this manner both the control YStem and the automatif valves are tested I
A means will have to be devised for each subsea system to determine I
if the out-of-tolerance condition actually occurred at the sensor if
it was properly Jetected and i~ it caused thd proper actuation I
Vessel Automatic~Inlet-Shutoff Valves I
Inspection ~equirement (OCS Order No 8)I
-I I
bull ) ~ J) All automatic~~~~~-shutoff valves actuated by vessel~~
I
~fsensorj shalil be tested for operation onle each month General Procedure
Described above under gene~al procedure for Liquid-Level Shut-
In Controls Vessel AutomaJi c-Di sc_b~_g_e-Sh_ll__Dff__Y_ii_l ves
Inspection RequireiT1ent (OCS Order No 8) All automatic-discharge-shutoff valves actuated by vessel lowshy
level sensors shall be tested for operation qnce each month
General Proc~dure
Described above under Liquid-Level Shut-tn Controls
High-tempera_ure Coniprc2_()r-Sh_t1tdow_ri_Co~_o1s Inspection Requirement (OCS Order No 8)i
High temperature controls which protect the compressor against
abnormal pressure~ soltiY by such temperature
safety devices shall be tested annually
General Procedure Because of the danger involved in elevating the temperature suffi shy
ciently to cause + temperature device to actuate it is recommended that each temperature device be pre-tested and replaced each year rather than be tested remotely
Oil Spil 1 Detection E_g_t_pmen~
Inspection Requirements (OCS Order 7) All platforms and structures are require~ to have curbs gutters
and spill pans connected to a tank or sump fhis equipment is required to collect all hydrocarbon spillage on the platform It is recommended that this requirement be extencjed to require all unenclosed subsea
equipment to be covered by inverted spill pans with hydrocarbon sensors
and sumps to rem~ve spillage
General Procedure To test the hydrocarbon spi 11 age detection and removal system
a controlled spill should be made in each ar~a or section of spill
- bull
pans while th~ SUljlPI
pumps are monitored for proper operation This I I
metbod will require a signal to the surface to indicate directly when the pumps are running or indirectly by indicating a pressure rise in
I i
the affected pipeline due to the pun1ping action The indirect method is preferablebec~use the pressure rise not only indicates the pumps are running b~t indicates they also are pumpi~g fluid One additional safeguard should ~e employed A TV camera should be used to observe
I
the spill pans in the vicinity of the spill to assure that they are not leaking due to damage or inadequacy of de~ign Hydrocarbon S~nsors
IInspection Requirements
Hydrocarbon sensors are not covered in tbe OCS Qrders presently
in effect General Procedure The general test procedure for the oil-spill-detection equipment
above will test the hydrocarbon sensors for operation In addition
I bull some means of knowing when each separate hydrocarbon sensor in the
spill pan assemblies hus sensed hydrocarbon will provide additional I
protection by warning of system degradation b~fore the system is comshypletely inoperable
7 Summary and RecQ)enda tions This report deal~ with the inspection problems that have arisen
as a result of the present trend of the offshore oil industry towards
subsea completion and production of deep water petroleum reservoirs I
Inspection techniques for completion and prod~ction equipment are inshyvestigated but inspection of fiser systems submersibles and strucshy
tures are not inc~uded in the scope of this wprk
A technique ~as been detailed for calibr1ttion of subsea sensors I
and for verifying the proper OReration of va1ves The technique reshy
quires only that the inspector 1 have access to production tubing at
- bull
I I
the surface By actuating subsurface control valves from the surface
the inspector can isolate a closed fluid path1 to the point of interest I
Pressures read at the surface (when corrected for hydraulic gradients)
may then be used to ca 1 i brate subsurface tran1sducers Flow rates
measured at the surface can be used to I
indicate leakage rates bull
from
subsurface valves I
but fluid in the tubing must be allow
ed to reach
sufficient therma1l equilibriumwith its surroundings so that a false leakage rate is riot indicated due to thermal expansion of the fluid
I bull
This technique has been used to work ou~ an inspection procedure
for the Exxon Sulisea Production System The 1procedure demonstrates I I
that the necessany closed fluid paths can be obtained to permit inshyspection of all necessary points Thus from 1a theoretical point of et
j9aYYew 1 t has ~en established that accurate euroVa 1ua tion of subsea con- J
ditions can be made from the surface (io implement the procedures I
it would first be necessary to conduct an experimental program with field
tests to determi~e operational problems) tAtti e
bull
- Inspection of subsea production systems
-
-bull
Again for a line pressure of 1000 psi but a 10000 ft deep comshy
pletion llP = 3~0 psi so the assumption of PP being small no longer
holds An integration would thus be needed to determine the transducer
pressure and t~e vaHable z factor should be included in thi~ integral Thus a closed form solution similar to tha~ found for liquids cannot
be obtained an~ numerical integration is necessary However for a wide range of conditions the equations pre~ented for both liquids and
I II gases a11 ow acc4ra te cal i bratfon of sea bottom pressure transducers
through the production tubing~ I
I
- -
6 J_nspection_B$9YJrcment_~and Te~t Proc~dures j
The OCS Ord~rs ~ere reviewed for those item~ pertinent to a subsea system The OCS inspection requirements and the suggested general
inspection procedures for these items are discussed in the following
paragraphs Tubing PLtg_
I
Inspection Requirements (OCS Order No 5)I
1 T~e s~~tained liquid leakage flow should not exceed I
400 ccmin 2 The ga~ leakage flo~1 should nGt e)ceed 15 cu ftmin
General Pro~middotedure
The first step i~ this procedure is to isolate a column of fluid
between the tubing plug and the inspector with the valves opened as
for production except that the tubing plug is in pl ace Any fl ow reaching the inspector at the surface is a direct indication of leakage past the tubing plug Thermal equilibrium may b~ required if the
maximum allowabl~ leakage is too small Theflow volume can be measured at the surface in the same manner as for conventionlt1 platform systems
I
middotShut-in Tubi9_ls_e_sur~
Inspection Requirements (OCS Order No I
5)
1 Wells with a shut-in tubing ptessure of 4000 psig or
greater sha11 be equj pped with a subsurface-~ontro11 ed subsurface safety device
-J
2 When the shut-in tubing pressure declines below 4000 I
psig a remotely sontrolled subsurface safety device shall be installed
when the tubing is first removed and reinstalled
General Procedure
To determine if the shut-i~ tubing pressure i~ greater than 4000 psig I
a pressure sensor should be located ~1here the shut-in pressure can be sensed
A convenient arrangement is to locate a pressure s~nsor between the master
valve and wing valve on each tubing With the downhole safety valve and
master valve opened and the wing valve close~ the shmicrot-in tubing pressure
as indicated by the sensor is noted
Calibration of the pressure sensor can be accomplished by applying
a known pressure ~t the surface to a closed cdlumn of fluid connecting I
the surface with the sensor with corrections calculated as explained
in Section 5
Subsurface Safety Device
Inspection Requirements (OCS Order No 5) 1 A surface-controlled subsurface safety device shall be
test operated every six months
2 A subsurface-controlled subsurface safety device shall
be removed inspected and repaired every 12 mdnths 1
General Procedure To test a surface-controlled subsurface safety device the well
should be opened for production and the command then given to close
the subsurface Sifety device The leakage flqw volume if any is
measured at the surface in the same manner as for conventional plat shy
form sys terns bull
1
-)
Pressure Relief Valves Inspection Requtrements (0CS Order No 8)
All pressure reli-f valve~ shall be either bench tested for opershy
ation or tested with an external pressure source (if the valve is somiddot
equipped)annually Jtbt Wf SJJS~+ General Procedure
To test a pressure relief valve for operation the vessel or line
should be pressunizeq to the pressure necessary to open the valve by
using the method suggested in Section 5 Uriless remote position inshy
dicators are provided a means to determine ~hether or not the valve
has actually ope1ed would have to be devised bullfor each subsea system
by observing the effect on the pressure sensors Pressure Sensors
Inspection Requirements (OCS Order No 8)
All pressure sensors shall be tested at least once each month
General Procedure
To remotely test and cal i~rate a subsea bullpressure sensor it is
necessary to
(1) isolate a closed column of fluid irom the surface to
the subsea sensor by properly arranging the ~ys terns va1ves
(2) determine the specific gravity compressibility and the
column height of the fluid
(3) select the pressure required at the subsea sensor
(4) apply the appropriate pressure at the surface end of
the column and
(5) compare the telemetered press4re signal or indication
with the pressur~ applied to the sensor
Automatic Hellhead Safety Devices -~~__--r---
Inspection 8equiremcnts (OCS Order No 8) All automatic wellhead safety devices shall be tested for operation
I
and holding pres~ureonce each1month
I
- -
bull )
General Prooedure
To test the operation of the automatic well head safety devices
the out-of-the-tolerance condition (usually ~igh or low pressure) which actuates the devices should be simulated Urless position 1ndicators
I
are provided a means to deterrl1ine whether 011 not the valves have
actually closed ~ust be devised for each indi1vidu~l system because of
the peculiarities
in each syste m J I
L~ 6 - Jlaquo4 sfSf~ rCheck Valves ~J0141d 11tJt NC Uf~ l(I -v-
Inspection Requirements (OCS Order No ~)
A11 check valves on a11 fl ow 1i nes sha11 be tested for opera ti on
and holding pressure once each month
General Procedures
To test the check valve ft will have to be back pressured The
check valve fails to operate properly if any back flo~1 through the I
valve occurs
~iguid Level Shut-in Controls I
Inspection Requirements (9cs Order No 8)
All liquid-l 1
evel shut-in controls shall be tested once each month
by raising or lowering liquid level across the leyel-control detector
General Pro~edure I
The preferable way to test the liquid-level sh~t-in controls is to
simulate the out-of-tolerance conditions (1 iquid Jevel either low or I
high) at the sensor This sim~lation should cau~e either the inlet
shutoff va1ve to close or the discharge shutoff valve to close In
this manner both the control YStem and the automatif valves are tested I
A means will have to be devised for each subsea system to determine I
if the out-of-tolerance condition actually occurred at the sensor if
it was properly Jetected and i~ it caused thd proper actuation I
Vessel Automatic~Inlet-Shutoff Valves I
Inspection ~equirement (OCS Order No 8)I
-I I
bull ) ~ J) All automatic~~~~~-shutoff valves actuated by vessel~~
I
~fsensorj shalil be tested for operation onle each month General Procedure
Described above under gene~al procedure for Liquid-Level Shut-
In Controls Vessel AutomaJi c-Di sc_b~_g_e-Sh_ll__Dff__Y_ii_l ves
Inspection RequireiT1ent (OCS Order No 8) All automatic-discharge-shutoff valves actuated by vessel lowshy
level sensors shall be tested for operation qnce each month
General Proc~dure
Described above under Liquid-Level Shut-tn Controls
High-tempera_ure Coniprc2_()r-Sh_t1tdow_ri_Co~_o1s Inspection Requirement (OCS Order No 8)i
High temperature controls which protect the compressor against
abnormal pressure~ soltiY by such temperature
safety devices shall be tested annually
General Procedure Because of the danger involved in elevating the temperature suffi shy
ciently to cause + temperature device to actuate it is recommended that each temperature device be pre-tested and replaced each year rather than be tested remotely
Oil Spil 1 Detection E_g_t_pmen~
Inspection Requirements (OCS Order 7) All platforms and structures are require~ to have curbs gutters
and spill pans connected to a tank or sump fhis equipment is required to collect all hydrocarbon spillage on the platform It is recommended that this requirement be extencjed to require all unenclosed subsea
equipment to be covered by inverted spill pans with hydrocarbon sensors
and sumps to rem~ve spillage
General Procedure To test the hydrocarbon spi 11 age detection and removal system
a controlled spill should be made in each ar~a or section of spill
- bull
pans while th~ SUljlPI
pumps are monitored for proper operation This I I
metbod will require a signal to the surface to indicate directly when the pumps are running or indirectly by indicating a pressure rise in
I i
the affected pipeline due to the pun1ping action The indirect method is preferablebec~use the pressure rise not only indicates the pumps are running b~t indicates they also are pumpi~g fluid One additional safeguard should ~e employed A TV camera should be used to observe
I
the spill pans in the vicinity of the spill to assure that they are not leaking due to damage or inadequacy of de~ign Hydrocarbon S~nsors
IInspection Requirements
Hydrocarbon sensors are not covered in tbe OCS Qrders presently
in effect General Procedure The general test procedure for the oil-spill-detection equipment
above will test the hydrocarbon sensors for operation In addition
I bull some means of knowing when each separate hydrocarbon sensor in the
spill pan assemblies hus sensed hydrocarbon will provide additional I
protection by warning of system degradation b~fore the system is comshypletely inoperable
7 Summary and RecQ)enda tions This report deal~ with the inspection problems that have arisen
as a result of the present trend of the offshore oil industry towards
subsea completion and production of deep water petroleum reservoirs I
Inspection techniques for completion and prod~ction equipment are inshyvestigated but inspection of fiser systems submersibles and strucshy
tures are not inc~uded in the scope of this wprk
A technique ~as been detailed for calibr1ttion of subsea sensors I
and for verifying the proper OReration of va1ves The technique reshy
quires only that the inspector 1 have access to production tubing at
- bull
I I
the surface By actuating subsurface control valves from the surface
the inspector can isolate a closed fluid path1 to the point of interest I
Pressures read at the surface (when corrected for hydraulic gradients)
may then be used to ca 1 i brate subsurface tran1sducers Flow rates
measured at the surface can be used to I
indicate leakage rates bull
from
subsurface valves I
but fluid in the tubing must be allow
ed to reach
sufficient therma1l equilibriumwith its surroundings so that a false leakage rate is riot indicated due to thermal expansion of the fluid
I bull
This technique has been used to work ou~ an inspection procedure
for the Exxon Sulisea Production System The 1procedure demonstrates I I
that the necessany closed fluid paths can be obtained to permit inshyspection of all necessary points Thus from 1a theoretical point of et
j9aYYew 1 t has ~en established that accurate euroVa 1ua tion of subsea con- J
ditions can be made from the surface (io implement the procedures I
it would first be necessary to conduct an experimental program with field
tests to determi~e operational problems) tAtti e
bull
- Inspection of subsea production systems
-
- -
6 J_nspection_B$9YJrcment_~and Te~t Proc~dures j
The OCS Ord~rs ~ere reviewed for those item~ pertinent to a subsea system The OCS inspection requirements and the suggested general
inspection procedures for these items are discussed in the following
paragraphs Tubing PLtg_
I
Inspection Requirements (OCS Order No 5)I
1 T~e s~~tained liquid leakage flow should not exceed I
400 ccmin 2 The ga~ leakage flo~1 should nGt e)ceed 15 cu ftmin
General Pro~middotedure
The first step i~ this procedure is to isolate a column of fluid
between the tubing plug and the inspector with the valves opened as
for production except that the tubing plug is in pl ace Any fl ow reaching the inspector at the surface is a direct indication of leakage past the tubing plug Thermal equilibrium may b~ required if the
maximum allowabl~ leakage is too small Theflow volume can be measured at the surface in the same manner as for conventionlt1 platform systems
I
middotShut-in Tubi9_ls_e_sur~
Inspection Requirements (OCS Order No I
5)
1 Wells with a shut-in tubing ptessure of 4000 psig or
greater sha11 be equj pped with a subsurface-~ontro11 ed subsurface safety device
-J
2 When the shut-in tubing pressure declines below 4000 I
psig a remotely sontrolled subsurface safety device shall be installed
when the tubing is first removed and reinstalled
General Procedure
To determine if the shut-i~ tubing pressure i~ greater than 4000 psig I
a pressure sensor should be located ~1here the shut-in pressure can be sensed
A convenient arrangement is to locate a pressure s~nsor between the master
valve and wing valve on each tubing With the downhole safety valve and
master valve opened and the wing valve close~ the shmicrot-in tubing pressure
as indicated by the sensor is noted
Calibration of the pressure sensor can be accomplished by applying
a known pressure ~t the surface to a closed cdlumn of fluid connecting I
the surface with the sensor with corrections calculated as explained
in Section 5
Subsurface Safety Device
Inspection Requirements (OCS Order No 5) 1 A surface-controlled subsurface safety device shall be
test operated every six months
2 A subsurface-controlled subsurface safety device shall
be removed inspected and repaired every 12 mdnths 1
General Procedure To test a surface-controlled subsurface safety device the well
should be opened for production and the command then given to close
the subsurface Sifety device The leakage flqw volume if any is
measured at the surface in the same manner as for conventional plat shy
form sys terns bull
1
-)
Pressure Relief Valves Inspection Requtrements (0CS Order No 8)
All pressure reli-f valve~ shall be either bench tested for opershy
ation or tested with an external pressure source (if the valve is somiddot
equipped)annually Jtbt Wf SJJS~+ General Procedure
To test a pressure relief valve for operation the vessel or line
should be pressunizeq to the pressure necessary to open the valve by
using the method suggested in Section 5 Uriless remote position inshy
dicators are provided a means to determine ~hether or not the valve
has actually ope1ed would have to be devised bullfor each subsea system
by observing the effect on the pressure sensors Pressure Sensors
Inspection Requirements (OCS Order No 8)
All pressure sensors shall be tested at least once each month
General Procedure
To remotely test and cal i~rate a subsea bullpressure sensor it is
necessary to
(1) isolate a closed column of fluid irom the surface to
the subsea sensor by properly arranging the ~ys terns va1ves
(2) determine the specific gravity compressibility and the
column height of the fluid
(3) select the pressure required at the subsea sensor
(4) apply the appropriate pressure at the surface end of
the column and
(5) compare the telemetered press4re signal or indication
with the pressur~ applied to the sensor
Automatic Hellhead Safety Devices -~~__--r---
Inspection 8equiremcnts (OCS Order No 8) All automatic wellhead safety devices shall be tested for operation
I
and holding pres~ureonce each1month
I
- -
bull )
General Prooedure
To test the operation of the automatic well head safety devices
the out-of-the-tolerance condition (usually ~igh or low pressure) which actuates the devices should be simulated Urless position 1ndicators
I
are provided a means to deterrl1ine whether 011 not the valves have
actually closed ~ust be devised for each indi1vidu~l system because of
the peculiarities
in each syste m J I
L~ 6 - Jlaquo4 sfSf~ rCheck Valves ~J0141d 11tJt NC Uf~ l(I -v-
Inspection Requirements (OCS Order No ~)
A11 check valves on a11 fl ow 1i nes sha11 be tested for opera ti on
and holding pressure once each month
General Procedures
To test the check valve ft will have to be back pressured The
check valve fails to operate properly if any back flo~1 through the I
valve occurs
~iguid Level Shut-in Controls I
Inspection Requirements (9cs Order No 8)
All liquid-l 1
evel shut-in controls shall be tested once each month
by raising or lowering liquid level across the leyel-control detector
General Pro~edure I
The preferable way to test the liquid-level sh~t-in controls is to
simulate the out-of-tolerance conditions (1 iquid Jevel either low or I
high) at the sensor This sim~lation should cau~e either the inlet
shutoff va1ve to close or the discharge shutoff valve to close In
this manner both the control YStem and the automatif valves are tested I
A means will have to be devised for each subsea system to determine I
if the out-of-tolerance condition actually occurred at the sensor if
it was properly Jetected and i~ it caused thd proper actuation I
Vessel Automatic~Inlet-Shutoff Valves I
Inspection ~equirement (OCS Order No 8)I
-I I
bull ) ~ J) All automatic~~~~~-shutoff valves actuated by vessel~~
I
~fsensorj shalil be tested for operation onle each month General Procedure
Described above under gene~al procedure for Liquid-Level Shut-
In Controls Vessel AutomaJi c-Di sc_b~_g_e-Sh_ll__Dff__Y_ii_l ves
Inspection RequireiT1ent (OCS Order No 8) All automatic-discharge-shutoff valves actuated by vessel lowshy
level sensors shall be tested for operation qnce each month
General Proc~dure
Described above under Liquid-Level Shut-tn Controls
High-tempera_ure Coniprc2_()r-Sh_t1tdow_ri_Co~_o1s Inspection Requirement (OCS Order No 8)i
High temperature controls which protect the compressor against
abnormal pressure~ soltiY by such temperature
safety devices shall be tested annually
General Procedure Because of the danger involved in elevating the temperature suffi shy
ciently to cause + temperature device to actuate it is recommended that each temperature device be pre-tested and replaced each year rather than be tested remotely
Oil Spil 1 Detection E_g_t_pmen~
Inspection Requirements (OCS Order 7) All platforms and structures are require~ to have curbs gutters
and spill pans connected to a tank or sump fhis equipment is required to collect all hydrocarbon spillage on the platform It is recommended that this requirement be extencjed to require all unenclosed subsea
equipment to be covered by inverted spill pans with hydrocarbon sensors
and sumps to rem~ve spillage
General Procedure To test the hydrocarbon spi 11 age detection and removal system
a controlled spill should be made in each ar~a or section of spill
- bull
pans while th~ SUljlPI
pumps are monitored for proper operation This I I
metbod will require a signal to the surface to indicate directly when the pumps are running or indirectly by indicating a pressure rise in
I i
the affected pipeline due to the pun1ping action The indirect method is preferablebec~use the pressure rise not only indicates the pumps are running b~t indicates they also are pumpi~g fluid One additional safeguard should ~e employed A TV camera should be used to observe
I
the spill pans in the vicinity of the spill to assure that they are not leaking due to damage or inadequacy of de~ign Hydrocarbon S~nsors
IInspection Requirements
Hydrocarbon sensors are not covered in tbe OCS Qrders presently
in effect General Procedure The general test procedure for the oil-spill-detection equipment
above will test the hydrocarbon sensors for operation In addition
I bull some means of knowing when each separate hydrocarbon sensor in the
spill pan assemblies hus sensed hydrocarbon will provide additional I
protection by warning of system degradation b~fore the system is comshypletely inoperable
7 Summary and RecQ)enda tions This report deal~ with the inspection problems that have arisen
as a result of the present trend of the offshore oil industry towards
subsea completion and production of deep water petroleum reservoirs I
Inspection techniques for completion and prod~ction equipment are inshyvestigated but inspection of fiser systems submersibles and strucshy
tures are not inc~uded in the scope of this wprk
A technique ~as been detailed for calibr1ttion of subsea sensors I
and for verifying the proper OReration of va1ves The technique reshy
quires only that the inspector 1 have access to production tubing at
- bull
I I
the surface By actuating subsurface control valves from the surface
the inspector can isolate a closed fluid path1 to the point of interest I
Pressures read at the surface (when corrected for hydraulic gradients)
may then be used to ca 1 i brate subsurface tran1sducers Flow rates
measured at the surface can be used to I
indicate leakage rates bull
from
subsurface valves I
but fluid in the tubing must be allow
ed to reach
sufficient therma1l equilibriumwith its surroundings so that a false leakage rate is riot indicated due to thermal expansion of the fluid
I bull
This technique has been used to work ou~ an inspection procedure
for the Exxon Sulisea Production System The 1procedure demonstrates I I
that the necessany closed fluid paths can be obtained to permit inshyspection of all necessary points Thus from 1a theoretical point of et
j9aYYew 1 t has ~en established that accurate euroVa 1ua tion of subsea con- J
ditions can be made from the surface (io implement the procedures I
it would first be necessary to conduct an experimental program with field
tests to determi~e operational problems) tAtti e
bull
- Inspection of subsea production systems
-
-J
2 When the shut-in tubing pressure declines below 4000 I
psig a remotely sontrolled subsurface safety device shall be installed
when the tubing is first removed and reinstalled
General Procedure
To determine if the shut-i~ tubing pressure i~ greater than 4000 psig I
a pressure sensor should be located ~1here the shut-in pressure can be sensed
A convenient arrangement is to locate a pressure s~nsor between the master
valve and wing valve on each tubing With the downhole safety valve and
master valve opened and the wing valve close~ the shmicrot-in tubing pressure
as indicated by the sensor is noted
Calibration of the pressure sensor can be accomplished by applying
a known pressure ~t the surface to a closed cdlumn of fluid connecting I
the surface with the sensor with corrections calculated as explained
in Section 5
Subsurface Safety Device
Inspection Requirements (OCS Order No 5) 1 A surface-controlled subsurface safety device shall be
test operated every six months
2 A subsurface-controlled subsurface safety device shall
be removed inspected and repaired every 12 mdnths 1
General Procedure To test a surface-controlled subsurface safety device the well
should be opened for production and the command then given to close
the subsurface Sifety device The leakage flqw volume if any is
measured at the surface in the same manner as for conventional plat shy
form sys terns bull
1
-)
Pressure Relief Valves Inspection Requtrements (0CS Order No 8)
All pressure reli-f valve~ shall be either bench tested for opershy
ation or tested with an external pressure source (if the valve is somiddot
equipped)annually Jtbt Wf SJJS~+ General Procedure
To test a pressure relief valve for operation the vessel or line
should be pressunizeq to the pressure necessary to open the valve by
using the method suggested in Section 5 Uriless remote position inshy
dicators are provided a means to determine ~hether or not the valve
has actually ope1ed would have to be devised bullfor each subsea system
by observing the effect on the pressure sensors Pressure Sensors
Inspection Requirements (OCS Order No 8)
All pressure sensors shall be tested at least once each month
General Procedure
To remotely test and cal i~rate a subsea bullpressure sensor it is
necessary to
(1) isolate a closed column of fluid irom the surface to
the subsea sensor by properly arranging the ~ys terns va1ves
(2) determine the specific gravity compressibility and the
column height of the fluid
(3) select the pressure required at the subsea sensor
(4) apply the appropriate pressure at the surface end of
the column and
(5) compare the telemetered press4re signal or indication
with the pressur~ applied to the sensor
Automatic Hellhead Safety Devices -~~__--r---
Inspection 8equiremcnts (OCS Order No 8) All automatic wellhead safety devices shall be tested for operation
I
and holding pres~ureonce each1month
I
- -
bull )
General Prooedure
To test the operation of the automatic well head safety devices
the out-of-the-tolerance condition (usually ~igh or low pressure) which actuates the devices should be simulated Urless position 1ndicators
I
are provided a means to deterrl1ine whether 011 not the valves have
actually closed ~ust be devised for each indi1vidu~l system because of
the peculiarities
in each syste m J I
L~ 6 - Jlaquo4 sfSf~ rCheck Valves ~J0141d 11tJt NC Uf~ l(I -v-
Inspection Requirements (OCS Order No ~)
A11 check valves on a11 fl ow 1i nes sha11 be tested for opera ti on
and holding pressure once each month
General Procedures
To test the check valve ft will have to be back pressured The
check valve fails to operate properly if any back flo~1 through the I
valve occurs
~iguid Level Shut-in Controls I
Inspection Requirements (9cs Order No 8)
All liquid-l 1
evel shut-in controls shall be tested once each month
by raising or lowering liquid level across the leyel-control detector
General Pro~edure I
The preferable way to test the liquid-level sh~t-in controls is to
simulate the out-of-tolerance conditions (1 iquid Jevel either low or I
high) at the sensor This sim~lation should cau~e either the inlet
shutoff va1ve to close or the discharge shutoff valve to close In
this manner both the control YStem and the automatif valves are tested I
A means will have to be devised for each subsea system to determine I
if the out-of-tolerance condition actually occurred at the sensor if
it was properly Jetected and i~ it caused thd proper actuation I
Vessel Automatic~Inlet-Shutoff Valves I
Inspection ~equirement (OCS Order No 8)I
-I I
bull ) ~ J) All automatic~~~~~-shutoff valves actuated by vessel~~
I
~fsensorj shalil be tested for operation onle each month General Procedure
Described above under gene~al procedure for Liquid-Level Shut-
In Controls Vessel AutomaJi c-Di sc_b~_g_e-Sh_ll__Dff__Y_ii_l ves
Inspection RequireiT1ent (OCS Order No 8) All automatic-discharge-shutoff valves actuated by vessel lowshy
level sensors shall be tested for operation qnce each month
General Proc~dure
Described above under Liquid-Level Shut-tn Controls
High-tempera_ure Coniprc2_()r-Sh_t1tdow_ri_Co~_o1s Inspection Requirement (OCS Order No 8)i
High temperature controls which protect the compressor against
abnormal pressure~ soltiY by such temperature
safety devices shall be tested annually
General Procedure Because of the danger involved in elevating the temperature suffi shy
ciently to cause + temperature device to actuate it is recommended that each temperature device be pre-tested and replaced each year rather than be tested remotely
Oil Spil 1 Detection E_g_t_pmen~
Inspection Requirements (OCS Order 7) All platforms and structures are require~ to have curbs gutters
and spill pans connected to a tank or sump fhis equipment is required to collect all hydrocarbon spillage on the platform It is recommended that this requirement be extencjed to require all unenclosed subsea
equipment to be covered by inverted spill pans with hydrocarbon sensors
and sumps to rem~ve spillage
General Procedure To test the hydrocarbon spi 11 age detection and removal system
a controlled spill should be made in each ar~a or section of spill
- bull
pans while th~ SUljlPI
pumps are monitored for proper operation This I I
metbod will require a signal to the surface to indicate directly when the pumps are running or indirectly by indicating a pressure rise in
I i
the affected pipeline due to the pun1ping action The indirect method is preferablebec~use the pressure rise not only indicates the pumps are running b~t indicates they also are pumpi~g fluid One additional safeguard should ~e employed A TV camera should be used to observe
I
the spill pans in the vicinity of the spill to assure that they are not leaking due to damage or inadequacy of de~ign Hydrocarbon S~nsors
IInspection Requirements
Hydrocarbon sensors are not covered in tbe OCS Qrders presently
in effect General Procedure The general test procedure for the oil-spill-detection equipment
above will test the hydrocarbon sensors for operation In addition
I bull some means of knowing when each separate hydrocarbon sensor in the
spill pan assemblies hus sensed hydrocarbon will provide additional I
protection by warning of system degradation b~fore the system is comshypletely inoperable
7 Summary and RecQ)enda tions This report deal~ with the inspection problems that have arisen
as a result of the present trend of the offshore oil industry towards
subsea completion and production of deep water petroleum reservoirs I
Inspection techniques for completion and prod~ction equipment are inshyvestigated but inspection of fiser systems submersibles and strucshy
tures are not inc~uded in the scope of this wprk
A technique ~as been detailed for calibr1ttion of subsea sensors I
and for verifying the proper OReration of va1ves The technique reshy
quires only that the inspector 1 have access to production tubing at
- bull
I I
the surface By actuating subsurface control valves from the surface
the inspector can isolate a closed fluid path1 to the point of interest I
Pressures read at the surface (when corrected for hydraulic gradients)
may then be used to ca 1 i brate subsurface tran1sducers Flow rates
measured at the surface can be used to I
indicate leakage rates bull
from
subsurface valves I
but fluid in the tubing must be allow
ed to reach
sufficient therma1l equilibriumwith its surroundings so that a false leakage rate is riot indicated due to thermal expansion of the fluid
I bull
This technique has been used to work ou~ an inspection procedure
for the Exxon Sulisea Production System The 1procedure demonstrates I I
that the necessany closed fluid paths can be obtained to permit inshyspection of all necessary points Thus from 1a theoretical point of et
j9aYYew 1 t has ~en established that accurate euroVa 1ua tion of subsea con- J
ditions can be made from the surface (io implement the procedures I
it would first be necessary to conduct an experimental program with field
tests to determi~e operational problems) tAtti e
bull
- Inspection of subsea production systems
-
-)
Pressure Relief Valves Inspection Requtrements (0CS Order No 8)
All pressure reli-f valve~ shall be either bench tested for opershy
ation or tested with an external pressure source (if the valve is somiddot
equipped)annually Jtbt Wf SJJS~+ General Procedure
To test a pressure relief valve for operation the vessel or line
should be pressunizeq to the pressure necessary to open the valve by
using the method suggested in Section 5 Uriless remote position inshy
dicators are provided a means to determine ~hether or not the valve
has actually ope1ed would have to be devised bullfor each subsea system
by observing the effect on the pressure sensors Pressure Sensors
Inspection Requirements (OCS Order No 8)
All pressure sensors shall be tested at least once each month
General Procedure
To remotely test and cal i~rate a subsea bullpressure sensor it is
necessary to
(1) isolate a closed column of fluid irom the surface to
the subsea sensor by properly arranging the ~ys terns va1ves
(2) determine the specific gravity compressibility and the
column height of the fluid
(3) select the pressure required at the subsea sensor
(4) apply the appropriate pressure at the surface end of
the column and
(5) compare the telemetered press4re signal or indication
with the pressur~ applied to the sensor
Automatic Hellhead Safety Devices -~~__--r---
Inspection 8equiremcnts (OCS Order No 8) All automatic wellhead safety devices shall be tested for operation
I
and holding pres~ureonce each1month
I
- -
bull )
General Prooedure
To test the operation of the automatic well head safety devices
the out-of-the-tolerance condition (usually ~igh or low pressure) which actuates the devices should be simulated Urless position 1ndicators
I
are provided a means to deterrl1ine whether 011 not the valves have
actually closed ~ust be devised for each indi1vidu~l system because of
the peculiarities
in each syste m J I
L~ 6 - Jlaquo4 sfSf~ rCheck Valves ~J0141d 11tJt NC Uf~ l(I -v-
Inspection Requirements (OCS Order No ~)
A11 check valves on a11 fl ow 1i nes sha11 be tested for opera ti on
and holding pressure once each month
General Procedures
To test the check valve ft will have to be back pressured The
check valve fails to operate properly if any back flo~1 through the I
valve occurs
~iguid Level Shut-in Controls I
Inspection Requirements (9cs Order No 8)
All liquid-l 1
evel shut-in controls shall be tested once each month
by raising or lowering liquid level across the leyel-control detector
General Pro~edure I
The preferable way to test the liquid-level sh~t-in controls is to
simulate the out-of-tolerance conditions (1 iquid Jevel either low or I
high) at the sensor This sim~lation should cau~e either the inlet
shutoff va1ve to close or the discharge shutoff valve to close In
this manner both the control YStem and the automatif valves are tested I
A means will have to be devised for each subsea system to determine I
if the out-of-tolerance condition actually occurred at the sensor if
it was properly Jetected and i~ it caused thd proper actuation I
Vessel Automatic~Inlet-Shutoff Valves I
Inspection ~equirement (OCS Order No 8)I
-I I
bull ) ~ J) All automatic~~~~~-shutoff valves actuated by vessel~~
I
~fsensorj shalil be tested for operation onle each month General Procedure
Described above under gene~al procedure for Liquid-Level Shut-
In Controls Vessel AutomaJi c-Di sc_b~_g_e-Sh_ll__Dff__Y_ii_l ves
Inspection RequireiT1ent (OCS Order No 8) All automatic-discharge-shutoff valves actuated by vessel lowshy
level sensors shall be tested for operation qnce each month
General Proc~dure
Described above under Liquid-Level Shut-tn Controls
High-tempera_ure Coniprc2_()r-Sh_t1tdow_ri_Co~_o1s Inspection Requirement (OCS Order No 8)i
High temperature controls which protect the compressor against
abnormal pressure~ soltiY by such temperature
safety devices shall be tested annually
General Procedure Because of the danger involved in elevating the temperature suffi shy
ciently to cause + temperature device to actuate it is recommended that each temperature device be pre-tested and replaced each year rather than be tested remotely
Oil Spil 1 Detection E_g_t_pmen~
Inspection Requirements (OCS Order 7) All platforms and structures are require~ to have curbs gutters
and spill pans connected to a tank or sump fhis equipment is required to collect all hydrocarbon spillage on the platform It is recommended that this requirement be extencjed to require all unenclosed subsea
equipment to be covered by inverted spill pans with hydrocarbon sensors
and sumps to rem~ve spillage
General Procedure To test the hydrocarbon spi 11 age detection and removal system
a controlled spill should be made in each ar~a or section of spill
- bull
pans while th~ SUljlPI
pumps are monitored for proper operation This I I
metbod will require a signal to the surface to indicate directly when the pumps are running or indirectly by indicating a pressure rise in
I i
the affected pipeline due to the pun1ping action The indirect method is preferablebec~use the pressure rise not only indicates the pumps are running b~t indicates they also are pumpi~g fluid One additional safeguard should ~e employed A TV camera should be used to observe
I
the spill pans in the vicinity of the spill to assure that they are not leaking due to damage or inadequacy of de~ign Hydrocarbon S~nsors
IInspection Requirements
Hydrocarbon sensors are not covered in tbe OCS Qrders presently
in effect General Procedure The general test procedure for the oil-spill-detection equipment
above will test the hydrocarbon sensors for operation In addition
I bull some means of knowing when each separate hydrocarbon sensor in the
spill pan assemblies hus sensed hydrocarbon will provide additional I
protection by warning of system degradation b~fore the system is comshypletely inoperable
7 Summary and RecQ)enda tions This report deal~ with the inspection problems that have arisen
as a result of the present trend of the offshore oil industry towards
subsea completion and production of deep water petroleum reservoirs I
Inspection techniques for completion and prod~ction equipment are inshyvestigated but inspection of fiser systems submersibles and strucshy
tures are not inc~uded in the scope of this wprk
A technique ~as been detailed for calibr1ttion of subsea sensors I
and for verifying the proper OReration of va1ves The technique reshy
quires only that the inspector 1 have access to production tubing at
- bull
I I
the surface By actuating subsurface control valves from the surface
the inspector can isolate a closed fluid path1 to the point of interest I
Pressures read at the surface (when corrected for hydraulic gradients)
may then be used to ca 1 i brate subsurface tran1sducers Flow rates
measured at the surface can be used to I
indicate leakage rates bull
from
subsurface valves I
but fluid in the tubing must be allow
ed to reach
sufficient therma1l equilibriumwith its surroundings so that a false leakage rate is riot indicated due to thermal expansion of the fluid
I bull
This technique has been used to work ou~ an inspection procedure
for the Exxon Sulisea Production System The 1procedure demonstrates I I
that the necessany closed fluid paths can be obtained to permit inshyspection of all necessary points Thus from 1a theoretical point of et
j9aYYew 1 t has ~en established that accurate euroVa 1ua tion of subsea con- J
ditions can be made from the surface (io implement the procedures I
it would first be necessary to conduct an experimental program with field
tests to determi~e operational problems) tAtti e
bull
- Inspection of subsea production systems
-
- -
bull )
General Prooedure
To test the operation of the automatic well head safety devices
the out-of-the-tolerance condition (usually ~igh or low pressure) which actuates the devices should be simulated Urless position 1ndicators
I
are provided a means to deterrl1ine whether 011 not the valves have
actually closed ~ust be devised for each indi1vidu~l system because of
the peculiarities
in each syste m J I
L~ 6 - Jlaquo4 sfSf~ rCheck Valves ~J0141d 11tJt NC Uf~ l(I -v-
Inspection Requirements (OCS Order No ~)
A11 check valves on a11 fl ow 1i nes sha11 be tested for opera ti on
and holding pressure once each month
General Procedures
To test the check valve ft will have to be back pressured The
check valve fails to operate properly if any back flo~1 through the I
valve occurs
~iguid Level Shut-in Controls I
Inspection Requirements (9cs Order No 8)
All liquid-l 1
evel shut-in controls shall be tested once each month
by raising or lowering liquid level across the leyel-control detector
General Pro~edure I
The preferable way to test the liquid-level sh~t-in controls is to
simulate the out-of-tolerance conditions (1 iquid Jevel either low or I
high) at the sensor This sim~lation should cau~e either the inlet
shutoff va1ve to close or the discharge shutoff valve to close In
this manner both the control YStem and the automatif valves are tested I
A means will have to be devised for each subsea system to determine I
if the out-of-tolerance condition actually occurred at the sensor if
it was properly Jetected and i~ it caused thd proper actuation I
Vessel Automatic~Inlet-Shutoff Valves I
Inspection ~equirement (OCS Order No 8)I
-I I
bull ) ~ J) All automatic~~~~~-shutoff valves actuated by vessel~~
I
~fsensorj shalil be tested for operation onle each month General Procedure
Described above under gene~al procedure for Liquid-Level Shut-
In Controls Vessel AutomaJi c-Di sc_b~_g_e-Sh_ll__Dff__Y_ii_l ves
Inspection RequireiT1ent (OCS Order No 8) All automatic-discharge-shutoff valves actuated by vessel lowshy
level sensors shall be tested for operation qnce each month
General Proc~dure
Described above under Liquid-Level Shut-tn Controls
High-tempera_ure Coniprc2_()r-Sh_t1tdow_ri_Co~_o1s Inspection Requirement (OCS Order No 8)i
High temperature controls which protect the compressor against
abnormal pressure~ soltiY by such temperature
safety devices shall be tested annually
General Procedure Because of the danger involved in elevating the temperature suffi shy
ciently to cause + temperature device to actuate it is recommended that each temperature device be pre-tested and replaced each year rather than be tested remotely
Oil Spil 1 Detection E_g_t_pmen~
Inspection Requirements (OCS Order 7) All platforms and structures are require~ to have curbs gutters
and spill pans connected to a tank or sump fhis equipment is required to collect all hydrocarbon spillage on the platform It is recommended that this requirement be extencjed to require all unenclosed subsea
equipment to be covered by inverted spill pans with hydrocarbon sensors
and sumps to rem~ve spillage
General Procedure To test the hydrocarbon spi 11 age detection and removal system
a controlled spill should be made in each ar~a or section of spill
- bull
pans while th~ SUljlPI
pumps are monitored for proper operation This I I
metbod will require a signal to the surface to indicate directly when the pumps are running or indirectly by indicating a pressure rise in
I i
the affected pipeline due to the pun1ping action The indirect method is preferablebec~use the pressure rise not only indicates the pumps are running b~t indicates they also are pumpi~g fluid One additional safeguard should ~e employed A TV camera should be used to observe
I
the spill pans in the vicinity of the spill to assure that they are not leaking due to damage or inadequacy of de~ign Hydrocarbon S~nsors
IInspection Requirements
Hydrocarbon sensors are not covered in tbe OCS Qrders presently
in effect General Procedure The general test procedure for the oil-spill-detection equipment
above will test the hydrocarbon sensors for operation In addition
I bull some means of knowing when each separate hydrocarbon sensor in the
spill pan assemblies hus sensed hydrocarbon will provide additional I
protection by warning of system degradation b~fore the system is comshypletely inoperable
7 Summary and RecQ)enda tions This report deal~ with the inspection problems that have arisen
as a result of the present trend of the offshore oil industry towards
subsea completion and production of deep water petroleum reservoirs I
Inspection techniques for completion and prod~ction equipment are inshyvestigated but inspection of fiser systems submersibles and strucshy
tures are not inc~uded in the scope of this wprk
A technique ~as been detailed for calibr1ttion of subsea sensors I
and for verifying the proper OReration of va1ves The technique reshy
quires only that the inspector 1 have access to production tubing at
- bull
I I
the surface By actuating subsurface control valves from the surface
the inspector can isolate a closed fluid path1 to the point of interest I
Pressures read at the surface (when corrected for hydraulic gradients)
may then be used to ca 1 i brate subsurface tran1sducers Flow rates
measured at the surface can be used to I
indicate leakage rates bull
from
subsurface valves I
but fluid in the tubing must be allow
ed to reach
sufficient therma1l equilibriumwith its surroundings so that a false leakage rate is riot indicated due to thermal expansion of the fluid
I bull
This technique has been used to work ou~ an inspection procedure
for the Exxon Sulisea Production System The 1procedure demonstrates I I
that the necessany closed fluid paths can be obtained to permit inshyspection of all necessary points Thus from 1a theoretical point of et
j9aYYew 1 t has ~en established that accurate euroVa 1ua tion of subsea con- J
ditions can be made from the surface (io implement the procedures I
it would first be necessary to conduct an experimental program with field
tests to determi~e operational problems) tAtti e
bull
- Inspection of subsea production systems
-
-I I
bull ) ~ J) All automatic~~~~~-shutoff valves actuated by vessel~~
I
~fsensorj shalil be tested for operation onle each month General Procedure
Described above under gene~al procedure for Liquid-Level Shut-
In Controls Vessel AutomaJi c-Di sc_b~_g_e-Sh_ll__Dff__Y_ii_l ves
Inspection RequireiT1ent (OCS Order No 8) All automatic-discharge-shutoff valves actuated by vessel lowshy
level sensors shall be tested for operation qnce each month
General Proc~dure
Described above under Liquid-Level Shut-tn Controls
High-tempera_ure Coniprc2_()r-Sh_t1tdow_ri_Co~_o1s Inspection Requirement (OCS Order No 8)i
High temperature controls which protect the compressor against
abnormal pressure~ soltiY by such temperature
safety devices shall be tested annually
General Procedure Because of the danger involved in elevating the temperature suffi shy
ciently to cause + temperature device to actuate it is recommended that each temperature device be pre-tested and replaced each year rather than be tested remotely
Oil Spil 1 Detection E_g_t_pmen~
Inspection Requirements (OCS Order 7) All platforms and structures are require~ to have curbs gutters
and spill pans connected to a tank or sump fhis equipment is required to collect all hydrocarbon spillage on the platform It is recommended that this requirement be extencjed to require all unenclosed subsea
equipment to be covered by inverted spill pans with hydrocarbon sensors
and sumps to rem~ve spillage
General Procedure To test the hydrocarbon spi 11 age detection and removal system
a controlled spill should be made in each ar~a or section of spill
- bull
pans while th~ SUljlPI
pumps are monitored for proper operation This I I
metbod will require a signal to the surface to indicate directly when the pumps are running or indirectly by indicating a pressure rise in
I i
the affected pipeline due to the pun1ping action The indirect method is preferablebec~use the pressure rise not only indicates the pumps are running b~t indicates they also are pumpi~g fluid One additional safeguard should ~e employed A TV camera should be used to observe
I
the spill pans in the vicinity of the spill to assure that they are not leaking due to damage or inadequacy of de~ign Hydrocarbon S~nsors
IInspection Requirements
Hydrocarbon sensors are not covered in tbe OCS Qrders presently
in effect General Procedure The general test procedure for the oil-spill-detection equipment
above will test the hydrocarbon sensors for operation In addition
I bull some means of knowing when each separate hydrocarbon sensor in the
spill pan assemblies hus sensed hydrocarbon will provide additional I
protection by warning of system degradation b~fore the system is comshypletely inoperable
7 Summary and RecQ)enda tions This report deal~ with the inspection problems that have arisen
as a result of the present trend of the offshore oil industry towards
subsea completion and production of deep water petroleum reservoirs I
Inspection techniques for completion and prod~ction equipment are inshyvestigated but inspection of fiser systems submersibles and strucshy
tures are not inc~uded in the scope of this wprk
A technique ~as been detailed for calibr1ttion of subsea sensors I
and for verifying the proper OReration of va1ves The technique reshy
quires only that the inspector 1 have access to production tubing at
- bull
I I
the surface By actuating subsurface control valves from the surface
the inspector can isolate a closed fluid path1 to the point of interest I
Pressures read at the surface (when corrected for hydraulic gradients)
may then be used to ca 1 i brate subsurface tran1sducers Flow rates
measured at the surface can be used to I
indicate leakage rates bull
from
subsurface valves I
but fluid in the tubing must be allow
ed to reach
sufficient therma1l equilibriumwith its surroundings so that a false leakage rate is riot indicated due to thermal expansion of the fluid
I bull
This technique has been used to work ou~ an inspection procedure
for the Exxon Sulisea Production System The 1procedure demonstrates I I
that the necessany closed fluid paths can be obtained to permit inshyspection of all necessary points Thus from 1a theoretical point of et
j9aYYew 1 t has ~en established that accurate euroVa 1ua tion of subsea con- J
ditions can be made from the surface (io implement the procedures I
it would first be necessary to conduct an experimental program with field
tests to determi~e operational problems) tAtti e
bull
- Inspection of subsea production systems
-
- bull
pans while th~ SUljlPI
pumps are monitored for proper operation This I I
metbod will require a signal to the surface to indicate directly when the pumps are running or indirectly by indicating a pressure rise in
I i
the affected pipeline due to the pun1ping action The indirect method is preferablebec~use the pressure rise not only indicates the pumps are running b~t indicates they also are pumpi~g fluid One additional safeguard should ~e employed A TV camera should be used to observe
I
the spill pans in the vicinity of the spill to assure that they are not leaking due to damage or inadequacy of de~ign Hydrocarbon S~nsors
IInspection Requirements
Hydrocarbon sensors are not covered in tbe OCS Qrders presently
in effect General Procedure The general test procedure for the oil-spill-detection equipment
above will test the hydrocarbon sensors for operation In addition
I bull some means of knowing when each separate hydrocarbon sensor in the
spill pan assemblies hus sensed hydrocarbon will provide additional I
protection by warning of system degradation b~fore the system is comshypletely inoperable
7 Summary and RecQ)enda tions This report deal~ with the inspection problems that have arisen
as a result of the present trend of the offshore oil industry towards
subsea completion and production of deep water petroleum reservoirs I
Inspection techniques for completion and prod~ction equipment are inshyvestigated but inspection of fiser systems submersibles and strucshy
tures are not inc~uded in the scope of this wprk
A technique ~as been detailed for calibr1ttion of subsea sensors I
and for verifying the proper OReration of va1ves The technique reshy
quires only that the inspector 1 have access to production tubing at
- bull
I I
the surface By actuating subsurface control valves from the surface
the inspector can isolate a closed fluid path1 to the point of interest I
Pressures read at the surface (when corrected for hydraulic gradients)
may then be used to ca 1 i brate subsurface tran1sducers Flow rates
measured at the surface can be used to I
indicate leakage rates bull
from
subsurface valves I
but fluid in the tubing must be allow
ed to reach
sufficient therma1l equilibriumwith its surroundings so that a false leakage rate is riot indicated due to thermal expansion of the fluid
I bull
This technique has been used to work ou~ an inspection procedure
for the Exxon Sulisea Production System The 1procedure demonstrates I I
that the necessany closed fluid paths can be obtained to permit inshyspection of all necessary points Thus from 1a theoretical point of et
j9aYYew 1 t has ~en established that accurate euroVa 1ua tion of subsea con- J
ditions can be made from the surface (io implement the procedures I
it would first be necessary to conduct an experimental program with field
tests to determi~e operational problems) tAtti e
bull
- Inspection of subsea production systems
-
- bull
I I
the surface By actuating subsurface control valves from the surface
the inspector can isolate a closed fluid path1 to the point of interest I
Pressures read at the surface (when corrected for hydraulic gradients)
may then be used to ca 1 i brate subsurface tran1sducers Flow rates
measured at the surface can be used to I
indicate leakage rates bull
from
subsurface valves I
but fluid in the tubing must be allow
ed to reach
sufficient therma1l equilibriumwith its surroundings so that a false leakage rate is riot indicated due to thermal expansion of the fluid
I bull
This technique has been used to work ou~ an inspection procedure
for the Exxon Sulisea Production System The 1procedure demonstrates I I
that the necessany closed fluid paths can be obtained to permit inshyspection of all necessary points Thus from 1a theoretical point of et
j9aYYew 1 t has ~en established that accurate euroVa 1ua tion of subsea con- J
ditions can be made from the surface (io implement the procedures I
it would first be necessary to conduct an experimental program with field
tests to determi~e operational problems) tAtti e
bull
- Inspection of subsea production systems
-