Water Frac Application
Transcript of Water Frac Application
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SPE 36459
Sociaty of PetroleumEngineers
WATER FRAC APPLICATIONS IN HIGH ISLAND 384 FIELD
E, B. CLAIBORNE JR*, ORYX ENERGY COMPANY, R. SAUCIER*, BAKER HUGHES INTEQ
CONSULTANT, and T. W. WILKINSON*, ORYX ENERGY COMPANY
* SPE Member
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ABSTRACT
A frac pack technique using water, herein referred to
as a water frac, has ken developd for use in wells
where the goal is to achieve effective sand control at
minimal cost while bypassing wellbore skin thus
increasing well productivities.
This increased
productivity is accomplished by a properly designed,
length Iimitedj hydraulic tlacture, created and
propped with non-damaging fluid/prop that provides
a highly conductive flow path through the wellbore
damaged zone, in conjunction with a proper gravel
packed completion. The process is applicable to
intervals comprised of mulliple pay zones by using a
multi-stage water frac technique. The ent]re process
of
creating
and packing the fracture(s) and gravel
packing is accomplished using a properly defined gel
free brine,
The multi-stage water frac process has been applied
and evaluated in the High Island 384 Field Job
evaluations herein illustrate the process.
The
process has also been applied using uncrosslinkcd
gelled fluids in this field as well, with the
evaluations to date indicating the water frac results
to be superior, Comparisons with larger sized frac
packs in a similar area also indicate the water fracs
to be equaJ or superior to the frac packs in well
performance,
In the following, the process of a water frac will be
described, typical field pumping techniques will be
provided and field applications and results wrll b
presented.
INTRODUCTION
B}passing near wellbore damage in relatively high
permeability formations using a propped hydraulic
fracture is an increasingly well known and
commonly applied practice. 23 Wellbore damage is
g-pically relatively close to the wellbore (ie: three
times wellbore radius)4 and hence to bypass wellbore
damage requires only a short fracture (+/- 2 ft).
More generally, for relatively high permeability
formations, the fracture does not have to be long to
opt imize the production rate, as illustrated by Figure
1, Figure 1 shows that a fracture length of 5-10 ft
will deliver virtually all that can be produced from
many high permeability formations,
The small
fractures can be created and propped effectively with
brine, as opposed to more viscous, highly complex
fluids3s, These type treatments are herein referred to
as Water Fracs (wF),
These short conductive
frac[urcs that bypass damage, coupled with an
cffcctivc grakcl pack constitute an effective,
sand
free,
high productivity completion. This WF
process is not to be confused with high rate water
packs that are pumped below fracture pressure.
The following describes the water frac process, and
applications on the HI 379B platform. Also included
is a brief background and history of the HI 384 area
leading to the application of the WF process, as well
as typical treatments and pumping techniques.
Discussion of results follow and include the
evaluation of field data via history matching, post
frac buildup analysis (both initially and over time),
other observations from the data, results, and
conclusions,
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and/or continuing pressure application through the
treatment.
THE WATER FRAC PROCESS
From the preceding, it is clear that short fractures
can bypass wellbore darnage and provide excellent
completions in high permeabity formations. As
stated,
such short fractures can be created and
packed with brine, Figure 2 illustrates via field step
rate test data, the creation and propagation of a
hydraulic fracture using brine. To create and prop
the hydraulic fracture requires, as typical of all
hydraulic fractures,
a pad fluid to create an
appropriate fracture followed by a properly designed
slurry. This proper design of the pad and slurry is
accomplished with the use of a psuedo 3-D computer
modelb. An illustration of typical design dimensions
for a single pay sand is seen in Figure 3.
Many long intervals consist of numerous pay or sub-
zones separated by non- pay or shalcy sections. Each
of these sub-zones will have different properties that
determine fracturability (ie: stress, toughness,
permeability, etc.) and thus all will not fracture at
the same time. The weakest sub-zone will fracture
first, and as bottom hole treating pressure builds ,
the pressure level will reach a point where the next
sub-zone may be fractured, and so on. Thus, if a
single pad is provided, the majority of it will likely
be spent on only one sub-zone, and when pressure
increases stilciently to induce a fracture in the next
sub-zone, only slurry will be present.
The new
fracture not having any available pad left at this
point, will not propagate significantly with slurry
only. To accommodate this condition , a pad and
slurry arc provided for each sub-zone in what is
defined as a multi-stage water frac (MS-WF).
The MS-WF is a self diverting system that provides
a maximum opportunity for frac creation and
packing of the multiple sub-zones in long intervals
as illustrated by Figure 4. The first pad creales the
first frac, slurry enters, tip screenat (TSO) occurs,
pressure increases, and a frac is created in the next
sub-zone. The next pad can propagate the second
frac through TSO, pressure increases again, and the
diversion process thus continues. The system order
is not predictable, but that in itself is not a
requirement to provide the maximum opportunity for
fracing and packing the multiple sub-zones of a long
internal. Complete packing of a sub-zone is not
required before diversion either, The annular gravel
pack operation to follow can continue to till the
fractures that are held open by the parlial propping
APPLICATIONS TO HI 384 FIELD
Background & History:
The HI 384 Field is located approximately 125 miles
south of Sabine Pass, Texas.
Expiration &
appraisal drilling was conducted in late 1970s &
early 1980s, In late 1990, Oryx set the HI 384-A
platform, a 4-pile gas-only platform.
In 1992-93, Oryx leased additional blocks based on
an off-structure oil prospect developed utilizing 3D
seismic. The HI 379 l was drilled in the summer
of 1993, discovering 177 of net oil pay in several
Trim sands ranging in depth from -4500 to -5100
SS. After finding stacked oil pay sands in two
appraisal wells, O~x reached platform threshold for
the oil development in October, 1993 and began
platform fabrication. Concurrently, OVX discovered
Basal Nebraskan gas-condensate pay in an adjacent
block (HI 385) and made plans for a satellite
platform development. In all, five wells were pre-
drilled from two surface locations and saved, High
Island blocks 378,379,384, and 385 were unitized
with Oryx as 100/0 working interest owner shortly
therafter.
In October, 1994, installation began on two new
platforms in approximately 360 water depth. HI
379-B is a 24-slot, drilling-capable, 4-pile oil & gas
platform with full processing and export facilities.
HI 385-C is a 4-slot, tripod satellite platform with
minimal processing facilities. Additionally, a 14-
mile oil export pipeline and several intrtileld
pipelines were installed. The pre-drilled wells were
tied back and completed, with first production in
January, 1995. Continued platform drilling of 15
additional HI 379-B wells has added to the
production and reserve base, Platform drilling will
likely continue throughout the remainder of 1996.
Additional oil and gas satellite plafforms HI 385-D
and HI 379-E will be installed in late 1996.
Oil and condensate production from the HI 384 Field
peaked in May, 1995 at 12,500 BOPD. Current
production (June, 1996) is 8,500 BOPD, 42 MMPD,
and 8,000 BWPD. The two new platforms (HI 379-B
and HI 385-C) have produced more than 5 MMBO
and 17 BCF in the first 1-1/2 years.
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This paper concentrates on the gravel pack
treatments on the HI 379-B platform wells,
consisting of 15 completed wells and 32 gravel pack
jobs to date. Peak oil rates from individual
completions on HI 379-B platform have ranged from
400 to 2,800 BOPD.
GEOLOGY AND RESERVOIR REVIEW OF HI
384 FIELD
The High Island 384 Field lies on the northern flank
of the salt dome underlying the West Flower
Gardens Bank. Drilling and production performance
have indicated the presence of complex faulting and
stratigraphy.
The field is trapped on a mid-
Trimosina A paleo structure,
which was
subsequently rotated and collapsed by salt
withdrawal and dome growth to the south of the
frcld. The primary trapping feature are a series of
old east west trending faults, which are antithetic
and parallel to the current salt dome. A series of
radial faults, related to Iatc salt movement, further
compartmentalizes the ticld.
Multiple stages of
movement
arc
evidenced by varing fluid
characteristics in adjacent fault blocks and the
presence of breached hydrocarbon contacts in some
Wells.
Development drilling continues to find
hydrocarbon traps further off structure to the north of
the salt dome.
The reservoir sands are upper Trimosina A to mid
Trimosina A in age. A majority of the reserves arc
associated with the oil prone mid Trim sands. These
sands were deposited as a series of offset stacked
slope channels and associated fan facies, which were
sourced from the north. The channel character of
the sands adds a stratigraphic component to the
trapping of the field, and to the complexity of both
interpretation and development. The upper Trim A
sands arc distal deltaic and tend to have more lateral
continuity, but are gas prone and comprise a small
portion of the field rescmcs
Most of the development wells have encountered
stacked multiple pay zones, but with considerable
variation in sand quality. Pcrmcabilitics range from
3 millidarcies (fans) to 3 Darcies (channels). Oil
gravities associated with the mid Trim sands (PL 1-4
thru PL I-7) are generally in the range of 33-40
degrees API. Initial resewoir pressures are slightly
ovcrprcssurcd (0,55 to 0.70 psi/ft).
Drive
mechanisms range from strong water drives to
pressure depiction.
Primary development drilling is limited to one to two
WCIISper fault bbck, Large casing programs were
included to facilitate future re-development through
sidetracking.
INITIAL GRAVEL PACK DEVELOPMENTS
ON HI 379-B PLATFORM
In reviewing the issues on whether to initiate a frac-
pack program versus a water frac program, the
following were reviewed:
What system would provide the highest PI
gravel pack and insure sand free production at
the most optimum cost?
With this 20-22 WCII development program
consisting of many single selective and dual
selective completions, the logistics of having
stimulation VCSSCIS accessible over a ve~
uncertain time window between packs, as well
as the weather unpredictability in the interim
could add costs and time to the program.
What was an acceptable skin/ drawdown
for
this area in view of the platforms ability to
process/compress/gas lift combined with the
drive mechanisms of the reservoir,etc
Past work with gravel pack completions using 60
pounds per thousand gallons (pptg) HEC w/ 40-60
proppant in
diverter stage(s), in several
developments including Oryxs deep water Miss
Canyon area,
indicated our ability to achieve
rclati~wly low skins ( +/-10 ) & drawdowns ( 30-70
psi ), on high rate producers. On HI 379-B it was
felt the use of stimulation vessels necessary to pump
the large sand volumes and gel prevalent for frac
packs would be significantly more expensive
compared to using more compact platform based
equipment with Icss horscpower,proppant, and fluid.
In the literature ,this added cost is estimated at +/-
$50,000. Completion plans revolved around drilling
3 WCIIS sequentially then changing over to the
completion phase for the 3 well package, before
continuing with additional drilling, This operational
plan allowed us to initiate a cash flow early in the
program, thus allowing the project to become self-
funding very soon after the initial 3 wells were
complctcd.
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With this scenario, the pumping equipment, once set
on the deck for completion operations, was not
removed till drilling operations were re-initiated,
thus minimizing the logistical concerns greatly. All
fluids were premixed into mixing tanks and
proppant loaded for each job concurrent with other
ongoing operations (ie: POOH w/ TCP guns,RIH w/
gp assembly, etc.). This setup minimized any
potential waiting on weather (WOW) delays from
high seas etc., as all pertinent materials could be on
board and the job pumped regardless of the seas. Use
of stimulation vessels which are very dependent on
the seas,wind direction, etc. along with the
completion program complexities between packs,
would have made pumping work from these vessels
logistically difficult at best. Now, with several
dynamically positionable vessels in the GOM, the
weather limitations may be somewhat less, but at an
added cost for the user.
Maximum withdrawal rates of 1500-2000 BFPD
were planned based on reservoir size, expected
perms/porosities, etc.
Well tubulars flowlines,
manifolds, productionhest vessels, dehys, etc. were
then designed accordingly, Nodal analysis indicated
only minimal drawdowns were necessary to produce
at the required rates. The goal was to have
completions with skins below 10. Permanent
downhole gauges were also installed in (2) wells in
order to optimize these wells deliverabilities, allow
evaluation of skinQPIs over time, as well as
ascertaining whether further enhancements could be
made to the MS-WF process.
CHANGE TO MS-WF PROCESS
The initial gravel packing designs in the field used
an acid-gel diversion process to pack perforations in
the multiple sub-zones prior to gravel packing the
annulus with brine. Downhole pressure gauge
interpretation revealed that fracturing during the
process was occurring. Further evaluation
demonstrated that formation fracturing could be
initiated with brine only, indicating that the MS-WF
process could provide a self diverting frac packing
mechanism for packing behind pipe as well as
providing the gravel pack. Thus, field trials of the
MS-WF process were undertaken. Initial evaluations
indicated that skins for the first three MS-WF
operations averaged S=3 in contrast with the first
four acid-gel prepack operations showing an average
skin of S=15.7. Thus, operations were changed to
the MS-WF for the rest of the field development.
TYPICAL PROCESS/DESIGN
Typical MS-WF treatments consisted of a pad
followed by a slurry for each sub-zone, designed
using the pseudo 3-D fracture simulator. Each pad
fluid consisted of a low weight brine (ie: 3 7.
NH4CL), followed by a moderate volume of 100/.
HCL & 13 1/2 - 1 1/2?4. mud acid followed by a
diverter stage containing 1.5-2 ppg proppant in 3V0
NH4CL. Following the last stage of the MS-WF,
the gravel pack would continue using completion
fluid in a proper gravel pack design. All fluids used
minimum
amounts of
mutual
solvents,iron
sequestering agents,
and corrosion inhibitors.
Friction
reducers were
added whenfwhere
appropriate.
In the design process, determination of the
mechanical characteristics of the interval, including
the estimated stress profile over the interval, were
guided largely by Iithological indications of the
gamma log and
experience from previous
measurements and applications. In situ stresses for
the pay sections were estimated by the well known
Eatons Equation relating stress to Poissons Ratio,
overburden pressure, reservoir pressure, and tme
vertical depth. Based on typical core and log data,
Poissons Ratio of 0.25 was used for sandstone.
Stresss for dirty sands to shales were stepped up
from the sandstone stress in 30-50 psi increments to
provide consemative fracture growth behavior
indications. Estimates of adjacent stresses with water
present were often less. Youngs Modulus was based
on other typical core data and usually taken as
150,000 psi for sandstone increasing to 200,000-
300,000 psi for shales, These parameters were
increased somewhat for increasing depth and are
largely estimates, but they have proven to be
adequate for this type of job design.
RESULTS:
EVALUATION OF FIELD DATA
Table 1 is a compilation of the data showing job
volumes and well performances. These data will be
referenced in subsequent analysis.
Data from a reasonably typical well is evaluated here
to illustrate stage definition and the MS-WF prcxess
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of field data analysis and results Figure 5 illustrates
the log section of well 4-D. In the upper sand, two
possible sub-zones are indicated and thus two stages
would typically be defined. In this case, a third pad
was specifkd and prop ramping using completion
fluid was used to end the job.
Figure 6 shows fracture creation and propagation via
the step rate test (SRT) using a 3 % NH4CL brine.
Pre frac well data was used to estimate in-situ stress
and fluid leakoff. The Pseudo 3-D model was used to
attempt to history match the observed job net
pressure assuming, firm a single fracture. The
results indicated by Figure 7 show a pr match. The
model for a single frac would have net pressure
continuing to rise with time after a TSO. The field
data obviously does not agree with this hypothesis of
a single fracture (Fig 7), thus a single fracture does
not seem likely.
Examination of the data shown as Figure 8 indicates
evidence of multi-stage behavior as postulated for
the MS-WF fracture. Figure 9 supports this by
evaluating the slopes in the net pressure. Pre frac
data was thus re-evaluated to obtain a new fluid
loss coefllcient using the premise that a multi-stage
fracture process was likely. The new fluid loss
coefllcient was then used to history match the first
stage into sub-zone one with the results shown as
figure 10, This is considered a good match, and
hence supports the hypothesis of multi-stage
behavior. The resultant fracture cross section is as
illustrated by Figure 11. In a similar way, stage 2
into sub-zone 2 results in the history match of Figure
12.
The preceding type of result from multiple job
analysis indicate that single fracture formation is not
likely in these well intervals,
The multi-stage
behavior that seems a more reasonable expectation
appears to be supported by the field data evaluations.
OBSERVATIONS / ADDED DEVELOPMENTS
Several observations and ensuing changes in our
treatment program have occurred as we moved
forward with this field development, The majority of
all the treaments cleaned up quickly with most wells
flowing to sales within 6-8 hrs tier initiating
flowback. Of the (32) WFs on line, no failure has
occurred to date. The use of acids, both HCL and HF
have been dramatically reduced over time.
Treatments are now pumped with pad stages
containing 20-25 gallons.hl (gpf) acid versus past
jobs containing 75-100 gpf with no adverse effects
on the resultant completions. Initially all treatments
were designed with 40-60 us mesh proppant. A
review of the recent literature in this area along with
evaluations of sidewall cores indicated that a 30-40
mesh would likely be Satisfactorys. Besides the
certain ability to provide competent sand control, the
three- fold gain in proppant permeability by using
the 30-40 vs the 40-60 presumably has enhanced the
gravel packed completion as well. This enhancement
is discussed by other authors work in the literature
as well. glo. This change was made early in the
program as mentioned previously, and all wells have
produced sand free with no evidence of productivity
impairment to date. Several of these wells are
currently flowing with water cuts above 60% at rates
in excess of 500-800 BWPD ( for over 12 months ),
and 2000 BTFPD without any sand problems. As
many factors were changing simultaneously, the
effkct of this change was impossible to quantifi, but
the well performance seemed satisfactory and the
change is
in the direction of improved well
productivity.
A rather simplistic association between log quality
and leakoff coeftlcient was obtained from the data
and is detailed in Table 2. The program values
listed on the table were those generated by the
pseudo 3-D model and seemed to under-estimate the
fluid loss values, The values listed under design
heading were based on experience and used for
actual modelling in order to attempt to be more
realist ic, The post job evaluation values were then
inferred by the history matching process described
above. These post job figures were then analysed in
an effort to arrive at some values that could be used
as a general field guideline for future job designs (ie:
Figure 13), This would then allow us to minimize
our time spent pumping minifracs,etc. This
technique may be applicable in other fields in
helping with initial fluid loss designs before arrival
on-site and can be of assistance in further analysis
for fluid leakoff during field development.
Some evidence of a lack of sub-zone containment
was obsetved by the relative behavior of adjacent
sub-zones in several wells. If a first, usually lower
interval took much larger volumes of proppant than
expected and a subsequent adjacent upper sub-zone
or zone took less proppant than expected, this was
considered possible evidence that the first frac had
communicated with the second sub-zone or zone.
Such data is summarized in Table 3. From Table 3,
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it is indicated that pay separation in excess of 10-15
feet is required for frac containment in some of these
wells, Not all of these wells show evidence of
fracture communication behavior hence this
phenomenon could be in part due to fracturing
through non-pay, poor cement bond, andJor other
factors, Additional analysis/study in this area is
needed to help quantifi frac containment behavior.
Packing efficiency is also indicated by the amount of
proppant behind pipe. Data from Table 1 through
Well B-15 Sel, indicate that the first four jobs placed
(using 65 pptg HEC gel and the acid prepack
process) 136 lb/ft proppant average. The 23 jobs
using brine therafter , placed an average of 180 lb/ft
of proppant.
This indicated the water to be as
effective a earner as the gel under the specifically
designed conditions in which it was used. If the
wells discussed above that may have communicated
(resulting in lower than expected volumes behind
pipe ) are removed, then the average for the brine
prcpack operations is over 200 lb/ft.
The data
indicate that the gel was possibly worse than the
brine in prepack operations using similar rates and
volumes.
WELL PERFORMANCE EVALUATION
Two oil wells ( B-2 and B-8) have permanent
bottom hole pressure gauges installed that
continuously read and record downhole pressure and
temperature. Pressure transient data was collected in
six additional oil wells ( B-1, B-lD, B-4, B-4D,
B-5 and B-5D) with wireline bottomhole pressure
gauges. Buildups were run during the first month of
production to determine initial permeability and skin
for these eight completions. Four of these were gel
packs and four were MS-WF packs. Results from
the buildups are included in Table 1.
The average calculated initial skin factor for these
eight completions was 9.9. The oil productivity
index (J) averaged 9.8 BOPD/PSI. In fields with
varying perm and net pay interspersed through-out
the interval, the use of a normalized J, as discussed
in SPE 27361, is an acceptable practice to fairly
compare completion efficiencies 2, Multiplying by
10,000/(lc*h), the normalized J for all (8) Oryx
completions averaged
8.8. Given similar oil
properties and initial reservoir conditions, it is
considered acceptable to compare the completions
using the normalized J as descibed above. Based on
these average results, the completion etliciencies we
designed for have been achieved.
Going from the gelled fluids to water in the gravel
pack jobs has resulted in significantly improved
completion efficiencies. The average skin dropped
from 15.7 to 4.0 and the normalized J increased from
2,9 to 16,2 (see Table 1).
Subsequent buildups in the two wells with
permanent gauges indicate that skins have not
changed. Performance of well B-2 indicates a
moderate-to-strong water drive mechanism. The
producing GOR has remained flat at 500-600
SCF/STB, although there has been a moderate
decrease in average reservoir pressure. This well
produced 600 MBO prior to water breakthrough,
Subsequent buildups indicate the skin remained
constant at 15 to 16 for this gelled water frac
completion, To date, well B-2 has produced 940
MBO, 440 MMCF and 270 MBW.
Performance of well B-8 indicates a depletion drive
mechanism and a much smaller reservoir than well
B-2. The producing GOR began increasing very
early, as the average reservoir pressure dropped
rapidly. Results from several early buildups indicate
the skin factor constant at 7 to 8,. To date, this
completion has produced 200 MBO, 390 MMCF and
no water.
OTHER WELL COMPARISONS IN NEARBY
FIELDS: FRAC PACKS VS HI 379-B WATER
PACKS
Using the data contained in SPE 27361, detailing the
normalized J obtained for frac packing in Vermilion
331, a comparison to Oryxs HI 384 field was made.
Figure 14 shows the HI 379-B MS-WFS ( with &
without gel) vs the frac packs at Vermilion 3312. The
figure shows the normalized Js for the HI 379-B
treatments to be better than those of the frac packed
wells, Both the gelled WFs and the non-gelled WFs
showed improved performance over the frac packs.
As the fluid properties, reservoir pressures,etc. are
somewhat comparable to Vermilion 331, yet not
identical , some caution in this comparison should be
used.
More analysis fstudy of MS-WPS and frac packs in
similar areas is recommended to help quantifi the
most optimum treatment for a given area/ ield.
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CONCLUSIONS
1, Hydraulic fractures can be created and propagated
in high permeability formations using brine.
2, The Multi-S(aged Water Fracs (MS-WF) pumped
at HI 379-B provided evidence of self diverting
fracture behavior on wells with intervals comprised
of multiple sub-zones or pay sections.
3. These Muhi-Stage Water Fracs showed lower
average skins (S=4.0) than the MS-WFS pumped
with 65 pptg HEC gels (S=15.7 ),
4, Fracture containment for some wells in this field
appears to be in excess of 10-15 of the non-pay
interval.
5, Using the MS-WF technique, the efficiency of
prop placcmcnt behind pipe with brine is greater
than or equal to that of gels with similar rates and
volumes.
6, Skins on the two wells with permanent downhole
gauges have not appreciably changed with time.
7, A PI comparison with Frac Packs in a nearby area,
indicate the Multi-Stage Water Fracs at HI 379-B
have better performance based on a normalized J
comparison.
8. Lhili=tion of the MS-W techniques using
platform-based equipment has resulted in significant
reductions in cost and delay time from those
expcctcd
with frac pack treatments where
stimulation boats are typically employed for the
larger volume, higher rate jobs.
9, The volume of sand placed behind pipe does not
appear to be directly correlated to completion
eftlcicncy.
10. More work on long term comparisons between
MS-WFS and Frac Packs in reference to
skin, PIs,etc would greatly benefit the industry.
ACKNOWLEDGEMENTS
The authors wish to thank the management of Oryx
Energy Company and Baker Hughes Intcq for their
support and permission to publish this paper. Also
special thanks to Glen Fritchie & Frank Patterson,
who as past members of Oryxs HI team, have also
contributed greatly to the projects overall success.
REFERENCES
1. Ayoub, J. et al. : Hydraulic Fracturing of Soft
Formations in the Gulf Coast, SPE 23805 presented
at the 1992 Formation Damage Control Symposium,
Lafayette, LA, Fcb, 26-27
2. Mullen, M, et, al. : Productivity Comparison of
Sand Control Techniques Used for Completions in
Vermilion 331 Field, SPE 27361 presented at the
1994 SPE Formation Damage Control Symposium,
Lafayette, La., Feb, 9-10
3, Patel, Y. et. al. : High-rate Pre-Packing Using
Non-Viscous Carner Fluid Results in Higher
Production Rates in South Pass Block61 Field, SPE
28531, presented at the 1994 SPE Annual Technical
Conference and Exibition, New Orleans, La., Sept.
25-28
4. Morales, R.H. et al,:
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European Formation Damage Conference, The
Hague, The Netherlands,May 15-16
9. Hannah, R.R et al,: A Field Study of a
Fracturing/Gravel Packing Completion Technique
on the Amberjack, Mississippi Canyon 109 Field,
SPE 26562 presentd at the 1993 SPE Annual
Technical Conference and Exhibition, Houston,Tx.,
October 3-6
10. Leone, J.A. et al,: Gravel Sizing Criteria for
Sand control and Productivity (lptimizatio~ SPE
20029 presented at the 60th California Regional
Meeting, Ventur&Ca., April 4-6
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TABLE
1: Field Well Treatment and Data
Review
Chart
Well
Hp Hole
Frac Pmp
Diverter type
10/. hcl MA Sand
Main Pack
Sand S PI k kh
Nrmld J
Angle Grad Rate
& Cone
(mf) (I@)
Size
Cone
( /ft )
(red) (md-ft)
@jkh)*lOM
B-1
B-lD
B-2
B-3
B-3 Sel
B-4
B-4 Sel
B-4D
B-5
B-SD
B-6
B4 Sel
B-7
B-7 Sel
&
w
B-8
B-8 Sel
B-9
B-9 Sel
B-n
B-llD
B-5Z
B-13
B-13 SEL
B-13D
B-12
B-12S
B-14
B- 14Se1
B-10
B-1OD
B-15
B-15Se1
22
40
76
40
55
20
60
32
28
40
130
84
56
28
88
98
30
115
34
46
50
26
39
32
43
84
76
93
43
50
46
39
0
0
29
68
68
8
8
8
48
48
57
57
46
46
46
46
64
66
40
40
48.8
36
34
27.5
43.6
44.4
43.5
44
38.7
39
42.1
42.8
0.72
0.72
0.60
0.65
0.65
0.74
0.77
0.77
0.75
0.86
0.85
0.85
0.63
0.75
0.68
0.61
0.64
0.64
0.75
0.72
0.75
0.69
0.82
0.59
0.72
0.66
8
8
12
9
8
8
10
9
9
9
10
9
10
8
11
10
9
7.5
10
10
11
9
9
9
9
9
9
9
8
4.5
9
9
65 pptg gelf2 ppa
65 pptg gel12 ppa
65 pptg gel /2 ppa
65 pptg gel /2 ppa
65 pptg gelJ2 ppa
65 pptg gel/2 ppa
65 pptg gel12 ppa
Wtrl 2ppa
wtr/1.5 ppa
wtr/1.5 ppa
65 pptg gel /2 ppa
Wtrl 2 ppa
wtr/1.5 ppa
wtr/1.5 ppa
wtr/1.5 ppa
wtr/1.5 ppa
wtr/1.5 ppa
wtr/1.5 ppa
wtr/1.5 ppg
wtr/1.5 ppg
wtr/1.5 ppg
wtr/1.5 ppg
wtr/1.5 ppg
wtr/1.5 ppg
wtr/1.5 ppg
wtr/1.5 ppg
wtr/1.5 ppg
wtr/1.5 ppg
wtr/1.5 ppg
wtr/1.5 ppg
wtr/1.5 ppg
wtr/1.5 ppg
45
50
53
75
73
100
50
100
71
75
30
48
36
68
45
31
50
26
66
54
36
32
29
26
52
27
26
43
19
24
27
38
91 40-60 12.0 ppg CaBr/2 ppa
100 40-60 12.0 ppg CaBr/2 ppa
53 40-60 12.6 ppg CaBr/2 ppa
75 4040 12.6 ppg CaBr/2 ppa
73 4040
12.6 ppg CaBr/2 ppa
100 40-60
12.3 ppg CaBr/2 ppa
50 40-60 12.3 ppg CaBr/2 ppa
100 40+0 12.3 ppg CaBr/ 2,4,6 ppa
71 40-60
3% NH4CL/2 ppa
75 20-40 3% NH4CL/2 p~
30 40-60
13.9 ppg CaBr/2 ppa
48 40-60 13.9 ppg CaBr/2 ppa
36 3040 11 ppg CaBr/2 ppa
68 30-40
11ppg CaBr/2 ppa
45 20-40 13.6 ppg CaBr/2 ppa
31 20-40 13.6 ppg CaBr/2 ppa
50 30-40 13.4 ppg CaBr/2 ppa
26 3040
13.5 ppg CaBr/2 ppa
66 30-40 12.2 ppg CaBr/ 1.5 ppa
54 30-40 11,9 ppg CaBr/ 1.5 ppa
36 3040 11,9 ppg CaBr/ 1.5ppa
32 30-40 10.6 ppg CaC1/ 1.5ppa
29 30-40 10.6 ppg CaC1/ 1.5ppa
26 30-40 11,7 ppg CaBr/ 1,5 ppa
52 30-40 11.6 ppg CaBr/ 1,5 ppa
27 30-40 11,6 ppg CaBr/ 1.5 ppa
26 3040 11.9 ppg CaBr/1.5 ppa
43 30+0 11.9 ppg CaBr/1.5 ppa
19 30-40 12.6 ppg CaBr/1.5 ppa
24 30-40 10.5 ppg CaC1/1.5 ppa
27 30-40 12,2 ppg CaBr/ 1,5 ppa
38 30-40 12.3 ppg CaBr/ 1,5 ppa
165 16 11.1
255 7 3.2
39 15 28.8
118
96
200 25 5.5
130
230 3 9.6
250 5 2.0
30 1 3.3
85
45
240
20
83
7 12.4
101
157
25
160
46
172
763
20
430
42
74
265
57
234
11
648
33
1312 39345
156 7820
1098 111996
1206 25335
349 17460
18 495
57 2459
430 20222
2.8
4.1
2.6
2.2
5.5
39.6
13.5
6.1
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TABLE 2: Log
Quality vs Fluid Leak-off Coefllcient
WELL
BIIL
B4D
Bll
B5Z
B12L
B8L
15L
15D
14D
10
SAND
Pb5B
PL1-5A
PLI-5A
PL1-5A
PL1-5A
PL1-6
PL15AL
PL1-5A Upr
PL1-4M3
PLI-7B
LOG
QUALITY
4
8
8
7
5
6
4
9
6
1
PROG CT DESIGN CT
(tT/MmJ.)
(FVMIN.n)
.024
.06
.005 .035
.026 .06
.03 .06-.16
.022
,06
.09
POST
EVAL
.035
.100
.1O-.I6
.13
.06
.06
.026
.46
.04
.0125
TABLE 3:
Comparison of Upper & Lower Zone Water Packs wf Suspect Communication
WELLS
B-13,135
B-ll,l ID
B.7,7S
B-6,6S
B-5,5D
B-14,14D
LOWER INTERVAL
L13+TTPROP:
763
160
240
85
250
264
UPPER INTERVAL
LB/IT PROP
20
46
20
45
30
54
INTERVAL
SEPARATION
30
10-15
10
10
10-12
25
Eff. .tOf Pract. r. L.n Bthnn W.ll?. rl. rm . . . . lor Hlnh. P.rm. .bllbty F orm. ti. n
190
ma orm
.tl. .
3 AFIO II
E
C,, .4.
HOI. Gr, v,l P,00 1000 1500 2000 2S00 1000 ISDO 4000 ,S00 $000
Pr. d.ctl*m*t. (m O PO)
Fig.
1- Well production in high permeability formations does not require long fractures
428
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.
um.
i?
aeaa.
a6-.
ii44a4D.
: a.a6
F.
:3766.51
I
m
639
w
,/,
L.-A
r
C9a .
00 -
/
9a
/
00
/
/-
m
)
m
Fig. 2- Field
evidence illustrates hydraulic fracture creation using brine
lDamaged ~.
1
= Gravel Pack
Screen
~\
Fracture
Fig. 3-
Typical geometry for a Water Frac (WF) bypassing well damage
Gam ma Ray
Fig. 4- Self diverting process of the Multi-Stage Water Frac (MS-WF) in the multiple sub-zones of a
completion interval
429
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gamma my
b
.
r
4
I
I
I
5100
5200
5300
5400
5500
damn induction
Fig. 5- Measured depth log section of example Well 4 D showing two sub-zones within the interval
24mm
3e0c.000
24mom
3200000
3amm
2800920
Zecmm
-4mn
-Z.om O.mca 2,cmo 4SC0 em mm ~oOw t2 000 14000 low
* Rat. ( BPMI
Fig. 6-
Step
Rate
Test for interval
in Well
4 D indicating minimum fracture propagation pressure of
approximately 3160 psi.
430
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N--h Plei - OKYX 1410H 51AMD A- f7Q WfU S 4 D AU INTD OK FRAC
I
I
I
~
1
n.
;g
---_
-
t-
-
i :
s
z
ii
iii:
W 20
m 200
Pump Tim* (rein)
Dulal CawMNll?.TXr
Fig. 7-Attempted history match of Well 4 D data assuming single frac illustrating poor results.
locdm
bmow
mm
2
h
aonm
mooo
ODOOO
-Zoo Doo
1
I
1
1
T
1
T
,
.
1
1
I
1
1 1
1 1
143S,COD 144DWD lU5~ 14S3000 14S5000 1~.000 1465000 4470000 147SCGtI 1460000 14.95CO0
Ckck Tkm MhwtDs)
Fig 8-Net pressure for Well 4-D indicating Stage ArnvaUTSO indications for three stages as 1452/14S4,
1461/1463, and 1475/1476+ minutes.
431
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u
Net Pressure (psi)
200
100 2 2000
_
-
aad
I
I
L...
NET PRESSURE P-PC
(PO
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R
[ HIGH lSL/
] Os+re, , psi) 3
T
:
L..
L
L
.
) A-
TvD
379
WELL B 4 D 1 ST STAGE INTO ZONE
A l S ,hut -t n
All Froc Hdight is Fluid Loss Height Layer 1
4870
4880
4890
I
)
L
I
,,., ,
10
20
Froclure Penelral on 11
ON
1
Fig.
11- Resultant cross
section
of stage 1
into sukone 1
NcJle-Smith Plot ORYK HIGH ISLAND A-379 WELL B 4 D 2 ND STAGE INTO ZONE 2
I
I
I
I
I i
I
I
0
a
I
1
z
10
20
Pump Time (rein)
Ooto 0B4FKNT3 TxT
Fig.
12 History match for Well 4 D indicating stage 2 into sub-zone 2
433
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L*akoff Co@ fflclcnlva, Log Quality
9.s
0.4s
8.4
9,3s
0,3
B.ls
a.2
O.ts
0.3
8, s
e
Fig. 13 Plot of Log Quality vs C t hkdfCoef)
z
40
35
30
25
I
0
b=
v
FRAcWcxs
I-f20
RAas
Xmflwww
20000 4ooal mom smoo
120000
~WATION KH
(md-ft)
Figure 14: Plot of Offset Data from
Vermilion 331 Frac Pack Wells vs HI 379-B Gel
and Water packs