Subject; 30” x 1-½” conductor Jetting - My-Spread Ganges Delta... · 2018-05-16 · 2. Both...

Well No; GS – 29 - AC Rig; Sagar Bhushan

Author; Peter Aird, ONGC Drilling Advisor. Tuesday, 27 October 2009

Subject; 30” x 1-½” conductor Jetting

Summary of key aspects and recommendations 1. For wells jetted in this operating region in a water depth range of 150m – 500m.

a. To meet BOP, riser, and wellhead design requirements, the 30” x 1 ½” wall thickness conductor supplied far exceeded requirements.

Recommendation; A 30” x 1” wall thickness conductor would better suit soft sedimentary conditions experienced. This size would afford all design requirements, would be easier to handle and provide far less weight for final shear strength support needed.

2. Both pilot hole and conductor jetting exhibited similar characteristics. i.e.

a. Very soft ‘washable’ sediments from mud line at 175m to +/-223m. b. Change in stratigraphy from 223m apparent through WOB trend required. c. At re-spud location formations did appear to be somewhat more consistent

and slightly firmer. d. Setting depth of +/- 240m was viewed as an ideal depth for conductor shoe.

3. Lower bound shear average soil strength determined from field set down weights

were evaluated to be in the region of 720-760lb/ft2. Further assessment is required in this area on future well to obtain a better understanding of geo-mechanics present.

4. Basis of design should be further reviewed and assessed for future wells. See

appendices. Options to consider include. a. Jetting one more joint of conductor. (Pro’s and con’s!) b. Reduce conductor weight. (Run 30” x 1” WT.) c. Evaluate conductor loading, axial strength set up, surface string needs and

preferred procedures to be executed. E.g. May have to cement and hold surface string in tension on these well as a preferred ‘best practice’.

5. A minimalist ‘washing’ approach is recommended in such operational extremes to

produce best foundation results. E.g. a. Pump at as low rates as possible, ensuring conductor returns are

maintained. b. Attain maximum slack off attainable as conductor is lowered. c. Employ a one trip method and avoid picking up and wiping string. d. Compensate on last 15m approaching TD depth to minimise disturbance. e. Optimise 26” jetting / bit cleaning capability. E.g. 3 x 20, 1 x 16CJ nozzles.

6. SG-5 Drill-ahead tool requires ‘J’ slot malfunction to be rectified. 7. All drilling instrumentation on future wells to be functional and calibrated prior to

conducting a jetting job. Particularly standpipe pressure readings.



Introduction Due to the soft top and surface sediments present in this deltaic river area to be explored and based on previous drilling difficulties experienced. Conductor jetting was viewed as the most preferred option for surface and BOP casing foundation requirements. Furthermore as that this was the Sagar Bushan’s first jetting operation, assistance was provided by an ONGC Drilling advisor and a Vetco field service engineer. 30” elevators, insert bowls, bull-tongs and C plate were mobilised from the ONGC on-hire deepwater drillship the Discoverer Seven Seas. Additionally, a 30” SG-5 drill-ahead tool belonging to ONGC was mobilised. Prior to the job, the drill-ahead tool cam actuation and ‘J’ slot release was functioned. Cam actuating device was deemed fit for service, but the ‘J’ slot mechanism could not be released where it was decided that the tool would be run in ‘Run and release’ mode only. Accurate and precise BHA and conductor measurement ensured conductor was cut to provide 6” of 26” bit stick with the drill-ahead tool made up and locked into the 30” wellhead housing. Pre job basis of design conducted by ONGC advisor ‘based on assumptions and scant values obtained from pilot-hole’ drilling concluded that 65m of conductor would ‘theoretically’ meet all conductor and surface string requirements with a minimal soaking time period required, if successfully jetted with minimal disturbance resulted. A pre job meeting was held in the Sagar Bhushan conference room with drilling personnel to outline conductor theory, design, job implementation and controls required. This was fully engaged by all personnel attending to meet expectations. Key hazards identified were very soft sediments from 175m to 223m, a heavy conductor string i.e. 456lbs/ft, and perhaps lower than anticipated soil bound strengths. Initial design and operational discussion based on problems anticipated concluded that a minimalist ‘washing and jetting’ process would be required to attain the formation shear strength and conductor support required.



Pilot hole The pilot-hole 12 ¼” slick assembly with a 12 ¼” 1-3-5 bit dressed with 4 x 14/32nd nozzles was washed without minimal pump and no rotation from the mud line depth of +/-175m to 245m i.e. 70m below the mud line prior to drilling the pilot hole ahead as per normal pilot hole drilling practices. The pilot hole total depth then proceeded to be drilled to the 20” setting depth at 575m. During washing and jetting ‘Pilot hole’ assembly only 0-3MT WOB was required throughout with pumps being stage to a maximum rate of 450gpm throughout the section, indicating how easily formations could be washed. Of note from drilling characteristics was that the formations appeared to be 100% Claystone and more evident with consistent weight of 2-3MT being observed from approximately 225m onwards. From these results and based on facts that;

- Max Wob of 3mt noted from 217m onwards. - Flow-rate and jet impact force used at this depth. - Surface soil lower bound condition of 75 lb/ft2 assumed

The soil strength was further evaluated for the conductor section to be jetted. (see appendix 1.) These calculations i.e. based on IADC deepwater well control guideline ‘rule of thumb’ used as a comparative, evaluated that the shear strength conditions of the soil was much less than anticipated. From this it was evaluated and concluded that all joints should be run. A fuller review of basis of design using lower soil strength figures obtained also indicated that the design still afforded a safety factor of 1.5 resided even if disturbed conditions resulted in the execution phase. (Appendix 2.)

Running conductor The shoe joint with an inside cut bevel of 45degrees was picked from the main pipe deck with the vessels starboard crane, with the 30” side-door elevators already pre installed to the drill floor. A double linked bail configuration then linked the elevators to the rigs hoisting system and the joint was picked up and lowered until the elevator resided on the rotary table where the bail links were then removed. Second and subsequent joints were then picked up in a similar fashion with each joints being lowered into the rotary table joint box end up. Bull tongs were installed, conductor joints made up to the recommended torque of 35,000ft.lbs and two anti rotation lock tabs then tabbed on each connection.\Note: 27 Bull-tong links being the required linkage to make up 30” conductor Final conductor wellhead housing was then picked up with the bail links now secured and shackled to the pad eyes that had been welded to the housing joint located +/- 0.5m below the wellhead. Housing made up to conductor joint as per Vetco make up procedures, complete assembly picked up and pad eyes lowered to rest on rotary table.



Note: No difficulties were experienced using this afore mentioned running procedure although care has to be exercised lifting the heavy conductor i.e. 17,000lbs per joint to the rig floor what with high elevation of drill floor above main pipe deck and vessel movement that existed. In the future long 100tons slings would be preferred for easier handling and installation of interface between elevators and hoisting equipment.

BHA Installation Motor BHA stand, one 8” drill collar single and the final BHA drill collar stand was run using a C plate and zip type elevators to secure collars on the C plate. This allowed the drill collar handling subs to be removed with ease. Drill-ahead tool was picked up, made up to BHA, C plate removed and drill-ahead tool cam lock functioned. Again ‘J’ slot drill function was attempted but could not be released. Pad eyes were cut off, with conductor and BHA then run and secured into PGB located in the moon-pool. Bulls-eye was then validated prior to running at 0- ¼ deg fwd. Finally during this period the ROV was launched and confirmed the 26” bit was protruding 6” out of the conductor as planned. PGB conductor and landing string then run to seabed slacking off guide-wires in the moon-pool as needed.

Conductor jetting As this was a ‘Kelly’ rig and had no top drive. Jetting was conducted using the rigs 60ft cement hose standpipe a circulating valve, chicksan elbow etc. made up to ‘single-doubles’ in the mouse-hole that were then installed to jetting string. With blocks locked, and clay-bound mudline validated at 175m. The first conductor ‘single-double’ was washed to +/- 189m i.e. 14m below the mud line, staging up pump from 50spm (250gall/min) to 80spm (400gpm). No weight resistance or pressure increase being noted through the apparent soft section that was known to exist i.e. observed as similar to that experienced from pilot hole assembly washing over this interval!. A 5 minute circulation period was applied as a precaution to ensure the conductor was circulated clean. Note: Conductor was not picked up at all, and on connection no backflow was observed! The second ‘single-double’ was then picked up in the same manner and washed at 80spm (400gpm) to 208.7m with intermittent resistance noted to increasing incrementally to +/- 1-4tons max. Note: Exact weight being difficult to asses due to low weight noted, heave and wt indicator reading. Again, no pressure increase was observed during washing the double and no backflow observed on connection. Indicating perhaps that the conductor was not overloaded with cuttings and that clay was most likely dispersing into sea-water where hence no sweep was deemed required. The third ‘single-double continued to be washed to 227.23m where a more significant weight increase trend up to 23tons was noted from approximately 223m onwards. Again this corresponded well to the pilot hole washing over this interval. Pump was now increased to 100spm and up to a 200psi pressure increase was noted.



The final ‘single double’ was washed to the planned conductor depth of 241m, facilitating a 2.5m stick up above the mud line. Here slack off weight now was more consistent and increasing up to a maximum of 35-40tons. Note: Pipe was only worked once at 234m where normal drag was noted as being very quickly re-established. Again exact weight was difficult due to heave and lack of stretch in pipe and weight indicator fluctuations that were present. From 234m onwards, pumps were increased to 2 x 60spm (600gpm) then to 2 x 70 spm (700gpm) by 236m. At section depth a 15m3 hi viscous circulated the conductor clean. Note; During viscous sweep circulation, ROV confirmed stick up of +/- 2.5m, full returns via drill-ahead ports and a bulls-eye of < 0-1/4deg. Implementation of washing i.e. 175m – 223m and jetting 223- 241m from start to finish including connections taking 2hrs rig time in total. Total string (23MT), conductor (43MT) and blocks wt (53MT) 117MT was recorded. Final weight over last 5m recorded as 80-85MT, i.e. 27-32Mt slack off applied.

Soaking period Sunday 6th June Based on slack off weights required of at end of washing/jetting @ 15.30hrs By 16.00hrs 15m3 hi-viscous TD sweep had been pumped and compensator engaged with 15MT wt slack off applied. Conductor holding OK, bulls-eye 0 – ¼ deg. 16.00 – 18.00 hrs Over a period of 2hrs weight was increased to conductor wt of 45MT. A final ROV check then indicated guide base movement had not been observed where PGB was found to resting on the mud line. 18.00hrs String was picked up 2m with 153MT recorded. (i.e. 36MT over-pull.) 18.30hrs 15MT was slacked off with conductor supporting this wt with 2m stick up. 21.00hrs Tide had increased slack off to 20MT. 21.00hrs Slack off increased to 27MT, conductor marking observed to move +/-2” down at mud line. 23.30 Discussions with town resulted in slacking off wt to conclude conductor holding capacity or not and/or then to initiate release drill ahead or plan to re-spud well . 23.45hrs. With 37 tons slack off wt applied, conductor was observed to have broken formation shear strength resistance and dropped 1.5m to mud line. Decision was evident to re-spud well.



Re-spud Monday 7th June. Eight singles were picked up and laid out. Rig then waited 12hrs, until no one Anchor winch motor change out had been completed prior to moving rig to re-spud position 10m east of location. Washing and jetting was again conducted using the rigs 60ft cement hose standpipe a circulating valve, chicksan elbow etc. made up to ‘single-doubles’ as previous. With blocks locked, and clay-bound mudline validated again at 175m. The first conductor ‘single-double’ was washed to +/- 189m i.e. 14m below the mud line, staging up pump from 50spm (250gall/min) to 70spm (350gpm). Light weight resistance of 2-3MT being on this occasion observed at re-spud location. A 2 minute circulation period was applied as a precaution to ensure the conductor was circulated clean. The second ‘single-double’ was then picked up in the same manner and washed increasing pumps from 70spm (350gpm) to 100spm (500gpm) by connection depth of 208.7m. A steady increase in resistance on this occasion was noted to 5MT, then to 10MT at the end of the double. A 400psi pressure differential from the bit/motor was also noted as pumps were increased to 100spm during washing the double base on reaction to on and off bottom conditions. A 10m3 hi-viscous sweep was pumped and circulated into the conductor prior to making the connection. The third ‘single-double continued to be washed to 227m where a definite linear weight trend continued to increase over the double up to 25/35tons. Compensator was attempted from 210onwards with little success where it was quickly evident through a sharp weight increase that the string could not be slacked off any further within designed safety limits. Additionally a pressure spike was noted at 215m of 1300psi where 1m later the String was required to be worked free, with one wipe only! at 217m. Pump was then increased to 130spm (650gpm) at 215m and thereafter to 140spm (700gpm) from 220m onwards where a more consistent pressure range and linear weight trend increase was then observed to be followed. i.e. 600-950psi on/off bottom bit/motor pressure and weight increasing from 0/10MT to 25/35MT by 227m. Again a 10m3 hi-viscous sweep was circulated into the conductor prior to connection. The final ‘single double’ was washed the first two metres to ensure movement. The compensator was then engaged as planned where from this point onwards until section depth, progress was consistently made by adding weight to the string from initially 25MT up to a final weight of 45MT, resulting in a 2.5m stick up of the PGB above the mud line. Pumps while jetting this interval were decreased from 140spm (700gpm) from 233m to a final pump rate of 40spm at final jetted depth from 239-241m. At section depth a 20m3 hi viscous was circulated to ensure the conductor was clean. Note; During this viscous sweep circulation, ROV confirmed stick up of +/- 2.5m, full returns were noted via drill-ahead ports and a bulls-eye of < 0deg.



Washing and jetting from 175m to 241m from start to finish including connections required 3hrs rig time in total. Total string (23MT), conductor (43MT) and blocks wt (53MT) 117MT. Final wt over last 72MT, i.e. 45Mt slack off being recorded. A 2 ½ hr precautionary soaking period was employed. Weight was then slackened off to 57MT. A 6m3 pill was spotted on bottom and the running tool then released with 3 right hand turns applied with conductor string wt of 45MT slackened off i.e. 75MT on weight indicator.



Appendices

Appendix 1



Offshore subsea well design Riser-less drilling design 1 Pilot hole set down test & formation strength evaluation Prior to jetting structural line pipe, the soil strength was equated as illustrated in this pilot hole set down weight, field units worksheet example shown.

1.1 Data Input. Weight applied to penetrate below mud line by bit, WOB (lb) (Pumps idling at 30spm) Pilot hole Size of bit, Bs, (in) Depth of penetration Pend, (m)

Mud line formation strength Mfs, lb/ft2

(Typically around 75lb/ft2 Gulf of Mexico) Pump rate impact force Pfs, lb/ft2 Final penetration below the mud line, Cdepth (m)

Wob 6000lbf:=

Bs 12.25in:=

Cdepth

50

55

60

62.5

65

67.5

m:= Pend 42m:=

Mfs 75lbf

ft2:=

Pfs 65lbf

ft2:=

Note; care must be exercised when setting down weight on a pilot hole string. ROV must be able to fully view string and assess string bending that may occurs. However in soft sea bottoms setting 2-3tons weight down and achieving >30 metres of penetration is highly probable.

1.2 Set down calculations and soil shear strength evaluation

Step 1; Calculate the cross sectional area of the bit, Csa, ft2

Csaπ Bs

2⋅

4:= Csa 0.818 ft2=

Step 2; Calculate soil strength (Sfs, psi) for penetration depth achieved at Wob applied.

SfsWob

CsaPend

m⋅

Mfs+ Pfs+:= Sfs 314.543lbf

ft2= Sfs 2.184psi=

Step 3; Calculate the formation strength increase per ft.

FsiSfs Pfs+ Mfs−

Pend

m

:= Fsi 7.251lbf

ft2= Fsi 0.05psi=



Step 4; Calculated formation strength at anticipated conductor depth (Fsd) jetted below mud line.

KPa 1000Pa:= Fsd MfsFsift

Cdepth⋅+:=

Fsd

1264.5

1383.4

1502.4

1561.8

1621.3

1680.8

lbf

ft2= Fsd

8.78

9.61

10.43

10.85

11.26

11.67

psi= Fsd

60.54

66.24

71.93

74.78

77.63

80.48

KPa= Cdepth

50

55

60

62.5

65

67.5

m=

1200 1315 1430 1545 1660

50

52.92

55.83

58.75

61.67

64.58

67.5

Conductor penetration evaluation

Soil shear strength

Con

duct

or p

enet

ratio

n

Cdepth

m

Fsdlbf

ft2



Offshore subsea well design 1.0 Foundation design

02 Soil resistance calculations and axial loading capacity This soil resistance calculations and axial loading capacity for a foundation (conductor string) was based on the conductor data and formation shear strength evaluated as follows.

2.1 Data Input. Foundation length, FL (ft) Foundation outside diameter Fo, (in) Foundation wall thickness Fw, (in)

Density of steel, Sd, lb/in3

FL 65m:= Kip 1000lbf:=

Fo 30in:= Klbf 1000lbf:=

Fw 1.5in:= Sd 0.283lbf

in3:=

Fi Fo 2 Fw⋅−:= Fi 27 in=

2.2 Formulae and calculations. Step 1; Calculate dry foundation string weight (Fsw) lbs/ft from dimensions listed above

Fsw Sdπ

4Fo

2 Fi2

−

⋅

⋅:= Fsw 456.1lbfft

=

Step 2 Average soil shear strength resistance (ρav, lbs/ft) from penetration test. ρpav 720

lbf

ft2:=

Step 3 Calculate the soil shear strength resistance (ρo) lbs/ft based on the following relationship (Ref IADC deepwater well control guidelines.)

ρo1600180

lbf

ft3⋅

FL⋅:= ρo 1896lbf

ft2=

ρoavρo2

:= ρoav 948lbf

ft2=

Step 4 Selects lowest average shear strength for section length to be jetted below the mud line.

ρav ρpav ρpav ρoav<if

ρoav otherwise

:=



Step 5 Calculate ultimate axial loading capacity on the foundation string (Uc) Klbs. Note: figure for average soil resistance over conductor length (rav) is assumed.

Uc 0.40ρav π⋅ Fo⋅ FL⋅:= Uc 482Klbf=


Note: The formula in step 4 assumes skin friction (adhesion) is equal to the shear strength of the soil and integrates this along the length of the foundation string. End bearing loads are not included. 0.4 reduction factor is used where soil disturbance is considered minimised. If disturbed 0.25 reduction factor derived from (Beck and Jackson , 1991.) should be used.



Offshore subsea well design 01 Foundation design

Klbf 1000lbf:= bbl 42gal:= 03 Conductor safety factor The safety factor of the conductor axial loads required to support a defined length of a structural 'surface casing' support string while landing off prior to cementing was evaluated as follows. Note: Mud outside and seawater assumed inside structural string assumed.

3.1 Data Input. Steel density, Sd lbf/in3 Surface length, SL (m) Surface casing external diameter Co, (in) Surface casing wall thickness, Sw, (in) Surface casing internal diameter Ci, (in) is calculated as shown opposite Foundation OD, and wall thickness Fo, Fw (in) Foundation Id, Fi, (in) calculated as shown Mud weight ρmw, (lbf/gal, or ppg) Sea water gradient ρsw (lbf/gal or ppg)

SL 500m:= Sd 0.283lbf

in3:=

Sw58

in:= Co 20in:=

Ci Co 2 Sw⋅−:= Ci 18.75 in=

Fo

Fw

30

1.5

in:=


ρmw 10.0lbfgal

:= ρsw 8.6lbfgal

:=

3.2 Formulae and calculations

Step 1; Calculate dry weight of surface casing strings (Scw) lbf/ft entered above

Scw Sdπ

4⋅ Co

2 Ci2

−

:= Scw 129

lbfft

=

Step 2 Calculate buoyancy factor for mud (Bfm) (dimensionless)

Bfm 1ρmw

65.5lbfgal

−:= Bfm 0.847=

Step 3 Calculate buoyancy factor for seawater (Bfs) (dimensionless)

Bfs 1ρsw

65.5lbfgal

−:= Bfs 0.869=



Step 4 Calculate the volume (Hv, gal / ft) inside structural support string

Hvπ

4Ci

2⋅:= Hv 47

galm

=

Step 5 Calculate the weight per ft (Wtc, lb/ft) for sea water inside each surface casing string joint

Wtc Hv ρsw⋅:= Wtc 405lbfm

=

Step 6 Calculate buoyant volume load effect ( Hvo, gal /ft ) acting on bottom of the casing string

Hvoπ

4Co

2⋅:= Hvo 54

galm

=

Step 7 Calculate the buoyant load effect of mud (Wtco, lb/ft) acting on surface string

Wtco Hvo ρmw⋅:= Wtco 535

lbfm

=

Step 8 Calculate the nett weight effect of casing sea water and mud buoyant loading effect

Nwe Scw Wtc Wtco−( )+:= Nwe 293lbfm

=

Step 9 calculate the dry weight for the foundation string

Fv Sdπ

4⋅ Fo

2 Fi2

−

⋅:= Fv 1496

lbfm

=

Step 10 Calculate the buoyant weight of conductor string

Fvw Fv Bfs⋅:= Fvw 1 103×

lbfm

=

Step 11 Length of foundation string (FL, ft) and average soil resistance for the foundation string (ρav, lbs/ft) from previous calculations

ρav 720lbf

ft2:=

FL 65m:=

Step 12 Calculate loading on foundation (Lf) lbs when structural string is landed

Lf SL Nwe⋅( ) Fvw FL⋅( )+:= Lf 231Klbf=



Step 13 Calculate ultimate axial loading capacity on the foundation string, Uc Klbs. Note: figure for average soil resistance over conductor length (ρav) is assumed.


Ucd 0.25ρav π⋅ Fo⋅ FL⋅:= Ucd 301Klbf=

Note: The above formula assumes skin friction (adhesion) is equal to the shear strength of the soil and integrates this along the length of the foundation string. End bearing loads are not included. 0.4 reduction factor used where soil disturbance is considered minimised. If disturbed 0.25 reduction factor derived from (Beck and Jackson , 1991.) should be used.

Step 15 Calculate safety factor on the foundation (Sf)

SfUcLf

:= minimal soil disturbance Sf 2.09=

SfUcdLf

:= soil considered more disturbed Sf 1.3=



Offshore subsea well design 1.0 Foundation design. 1 Set down test and formation strength evaluation, RE-SPUD The soil strength was again equated on re-spud as illustrated in this set down weight worksheet shown.

1.1 Data Input. Weight applied to penetrate below mud line by bit and casing, WOB (lb) (No pumps applied) Outside diameter of tubular, Od = (in) Inside diameter of tubular, Id = (in) Size of bit, Bs, (in) Depth of penetration Pend, (ft) Mud line formation strength Mfs, lb/ft2

(Typically around 75lb/ft2 Gulf of Mexico) Final penetration below the mud line, Cdepth (ft)

Wob 20000lbf:= Od

Id

Bs

30

27

26

in:=

Pend 25m:= Cdepth

64

64.5

65

65.5

66

66.5

m:=

Mfs 75lbf

ft2:=

Note; care must be exercised when setting down weight on a conductor jetting string. ROV must be able to fully view string and bullseyes to ensure less than 1degree of bending occurs. In soft sea bottoms setting 5-10,000lbs weight down & achieving 4-5metres of penetration is likely.

1.2 Set down calculations and soil shear strength evaluation

Step 1; Calculate the combined cross sectional area of the casing & bit, Csa, ft2

Csaπ Od

2 Id2

−

⋅

4

π Bs2

⋅

4+:= Csa 4.62 ft2=

Step 2; Calculate soil average 'formation' strength (Sfs, psi) for penetration depth achieved for Wob applied.

SfsWob

CsaPend

m⋅

Mfs+:= Sfs 248.173lbf

ft2= Sfs 1.723psi=

Step 3; Calculate the formation strength increase per ft.

FsiSfs Mfs−

Pend

m

:= Fsi 6.927lbf

ft2= Fsi 0.048psi=



Step 4; Calculated formation strength (Fsd) at conductor penetration depth below the mud line.

KPa 1000Pa:= Fsd MfsFsift

Cdepth⋅+:=

Fsd

1529.5

1540.8

1552.2

1563.6

1574.9

1586.3

lbf

ft2= Fsd

10.62

10.7

10.78

10.86

10.94

11.02

psi= Fsd

73.23

73.78

74.32

74.86

75.41

75.95

KPa= Cdepth

64

64.5

65

65.5

66

66.5

m=

Step 5; Depicts formation shear strenghts evaluated from set down test and penetration made.

1500 1525 1550 1575 1600

64

64.5

65

65.5

66

66.5

67

Conductor penetration evaluation

Soil shear strength

Con

duct

or p

enet

ratio

n

Cdepth

m

Fsdlbf

ft2



Offshore subsea well design. 1.0 Foundation design

Set up time, re-spud evaluation. Klbf 1000lbf:= Kip 1000lbf:= The set up time required for the foundation (conductor) string is based on formulae derived from SPE paper 77537. The worksheet determines and considers, soil shear strength, conductor diameter, length and the impact of support strength if the jetted soil formation has been disturbed or not during the jetting process.

Sd 0.283lbf

in3:=

4.1Data Input Density of steel , Sd, lbf/in3 SUPPORTED Foundation length, FL (ft) Foundation outside diameter Fo, (in) Foundation wall thickness Fw, (in)

FL 55m:=

Fo 30in:= Fw 1.5in:=


4.2 Set up time formula and calculations

Step 1; Calculates dry foundation string weight (Fsw) lbf/ft from dimensions listed above

Fsw Sdπ

4⋅ Fo

2 Fi2

−

⋅:= Fsw 456

lbfft

=

Step 2 Average soil shear strength resistance (ρav, lbs/ft) from penetration test. ρpav 783

lbf

ft2:=

Step 3 Otherwise calculate the soil shear strength resistance (ρo) lbs/ft based on the following relationship (Ref IADC deepwater well control guidelines.)

ρo1600180

lbf

ft3⋅

FL⋅:= ρo 1604lbf

ft2=

ρoavρo2

:= ρoav 802lbf

ft2=

Step 4 Selects average shear strength for section length to be jetted below the mud line (assume 2m conductor stick up)

ρav ρpav ρpav ρoav<if

ρoav otherwise

:=



4.3 Input bottom hole assembly components; Outside and inside diameters of drill collars (in) Length of drill collars, (ft) Safety factor. (sf), dimensionless Weight of wellhead, Wellhead, Klbf Weight of drill ahead tools, Drillahead, Klbf

Dco

Dco2

Dci

Dci2

9.5

8

3

2.812

in:=

Dc1

Dc2

20

45

m:= sf 0.90:=

Whead

Dahd

PGB

5

5

6

Klbf:=

Note: Drill collar 'BHA' components will cover the full conductor length to be jetted. Hence drill collar length should equate to length of conductor being jetted.

Step 4 Calculates buoyancy factor for steel (conductor, drilling tools etc.) in seawater. Bf 1

8.66lbfgal

65.5lbfgal

−:= Bf 0.87=

Step 5 Calculates max weight on bit (Klbf.) for conductor bottom hole assembly (BHA, ft) run.

Dcw1 Sdπ

4⋅ Dco2 Dci2−( ) Dc1⋅:= Dcw1 14Klbf=

Dcw2 Sdπ

4⋅ Dco22 Dci22

−( ) Dc2⋅:= Dcw2 22Klbf=

WOB Bf Dcw1 Dcw2+( )⋅:= WOB 32Klbf=

Step 6 Calculates the Max weight on bit (Wobmax) that can be safely applied during jetting, i.e. based on length of conductor, BHA, wellhead and drill ahead tools weight to be jetted.

WOBmax WOB Dahd Whead+ PGB+( ) Bf⋅ + Fsw FL⋅( )+ sf⋅:= WOBmax 115Klbf=

Note; Weight would start at zero as conductor initially penetrates below the mud line. For the first 30m and more! 'Minimal pumping is recommended to minimise soil disturbance. Once resistance is noted and set down test is completed, weight application and pumping would be initiated. From here penetration weight would be linearly increased as per a step up graph to the WOBmax value that would results when all conductor length has been jetted.



Step 5 Calculates theoretical conductor setting strength capacity at (t, days) based on a.) Maximum load set down after jetting b.) Formulae as derived. Ref SPE 77357; Innovative design for deepwater surface strings) Then evaluates restored conductor strength after input time periods entered, (t, day).

t

0.1

0.25

0.5

1

3

5

7

:=

t1 0.055 2 log t( )+( )⋅:=

Qt WOBmax t1 π Fo⋅ FL⋅ ρav⋅( ) +:= Qt

176

200

219

237

266

280

289

Klbf= t

0.1

0.25

0.5

1

3

5

7

dayday

=

This method includes inherent conservatism. i.e. average soil strengths are used and in practice soils may tend to build up strength much faster. This however can be determined from regional experience. In reality, particularly in new exploration block with no soil strength information 1-2hrs soaking is often taken even if jetting has proceeded without problems (i.e. QA1 as illustrated below, ) where there has been no requirement to reciprocate string. On the other hand, if string had to be reciprocated during jetting, (i.e. Qd as illustrated below) then a longer waiting period is perhaps put into effect i.e 3-4hrs. Finally if sediments exhibit no strength in first 20-30m washed then a full revaluation of these figures would need to be considered.

Step 9 Calculates theoretical resistance based on further applied safety factors. Ref. IADC deepwater well control guidelines, section 1.1.5, (Ref Beck & Jackson, 1991)

9a. Calculates conductor strength that will be achieved (QA1), where Jetting was conducted with minimal problem and no reciprocation 0.5 safety factor applied. 9b. Calculates conductor strength achieved (Qd) , where Jetting required reciprocation and where operational problems were experienced, 0.25 safety factor applied.

QA1 WOBmax t1 π Fo⋅ FL⋅ ρav⋅ 0.5⋅( ) +:=

Qd WOBmax t1 π Fo⋅ FL⋅ ρav⋅ 0.25⋅( ) +:= QA1

145

158

167

176

191

197

202

Klbf= Qd

130

136

141

145

153

156

158

Klbf=

WOBmax WOB Dahd Whead+ PGB+( ) Bf⋅ + Fsw FL⋅( )+ := WOBmax 128Klbf=

As long as QA1 and Qd 'set up time' resistance is greater than maximum weight of conductor and BHA. Then the drill-ahead tool can be safely released and drilling commenced once strength is obtained.



Step 10 Plots time vs. conductor support strength.

130 150 170 190 210

0.09

0.095

0.1

0.105

0.11

0.115

0.12

0.125

0.13

0.135

0.14

Minimal soil disturbanceDisturbed soil

Conductor set up time required

Conductor setting strength (Klbf)

Tim

e (d

ays) t1

t1

QA1

Klbf

Qd

Klbf,

4.5 Summary. Using a determined and evaluative approach as presented in this worksheet, the conductor axial resistance achieved after a period of time (t) can be calculated. Therefore through experience and based on both local, regional and well specific information. Inherent operational risks that resides in conductor jetting operations can be more confidently pre-planned, well engineered, managed and mitigated against during implementation to ensure not only sufficient conductor length is designed with safety applied. But that jetting can be achieved at optimal operational and minimal waiting time during jetting to obtain wellhead and support loads required. Further reference; Beck, RD Jackson, C.W, and Hamilton TK (1991); Reliable deepwater structural casing installation using controlled Jetting, (SPE No 22542)

Subject; 30” x 1-½” conductor Jetting - My-Spread Ganges Delta... · 2018-05-16 · 2. Both...

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Transcript of Subject; 30” x 1-½” conductor Jetting - My-Spread Ganges Delta... · 2018-05-16 · 2. Both...