Water Frac Application

7/25/2019 Water Frac Application

1/16

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,

419


2/16

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.

420


3/16

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.

421


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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

422


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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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6/16

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.

424


7/16

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,:


8/16

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

426


9/16

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


10/16

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


11/16

.

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


12/16

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


13/16

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


14/16

u

Net Pressure (psi)

200

100 2 2000

_

-

aad

I

I

L...

NET PRESSURE P-PC

(PO


15/16

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


16/16

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

Documents

Water Frac Application