04 Refracturing Works

8/12/2019 04 Refracturing Works

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38 Oilfield Review

Refracturing Works

George DozierHouston, Texas, USA

Jack Elbel

Consultant

Dallas, Texas

Eugene Fielder

Devon Energy

Oklahoma City, Oklahoma, USA

Ren Hoover

Fort Worth, Texas

Stephen LempCalgary, Alberta, Canada

Scott Reeves

Advanced Resources International

Houston, Texas

Eduard Siebrits

Sugar Land, Texas

Del Wisler

Kerr-McGee Corporation

Houston, Texas

Steve WolhartPinnacle Technologies

Houston, Texas

For help in preparation of this article, thanks to Curtis Boney,Leo Burdylo, Chris Hopkins and Lee Ramsey, Sugar Land,Texas, USA; Phil Duda, Midland, Texas; Chad Gutor, formerlywith Enerplus, Calgary, Alberta, Canada; Stephen Holditchand Valerie Jochen, College Station, Texas; and Jim Troyer,Enerplus, Calgary, Canada.

CoilFRAC, DSI (Dipole Shear Sonic Imager), FMI (FullboreFormation MicroImager), FracCADE, InterACT, MovingDomain, NODAL, ProCADE and StimMAP are marks ofSchlumberger.

Applicable in gas or oil wells, fracture restimulations bypass near-wellbore damage, reestablish good

connectivity with the reservoir and tap areas with higher pore pressure. An initial period of production

also can alter formation stresses, resulting in better vertical containment and more lateral extension

during hydraulic fracturing, and may even allow the new fracture to reorient along a different azimuth.

As a result, refracturing often restores well productivity to near original or even higher rates.

The potential benefits of refracturing haveintrigued oil and gas operators for more than

50 years. Most intriguing is that, under certain

conditions, this technique restores or increases

we ll pr oduc tivi ty, of ten yiel di ng ad di tion al

reserves by improving hydrocarbon recovery. The

approximately 70,000 new wells that are drilled

annually represent only about 7 to 8% of the

total number of producing wells worldwide.1

Therefore, getting the most output from the

more than 830,000 previously completed wells is

essential for field development, production

enhancement and reservoir management. Even

modest production increases from a portion ofthe vast number of existing wells represent signif-

icant incremental reserve volumes. Refracturing

is one means of accomplishing this objective.

More than 30% of fracturing treatments are

performed on older wells. Many are completions

of new intervals; others represent treatments on

producing zones that were not fractured initially

or a combination of new intervals and previously

understimulated or unstimulated zones. An

increasing number of jobs, however, involve

refracturing previously stimulated intervals after

an initial period of production, reservoir-pressure

drawdown and partial depletion. These types ofrestimulations are effective in low-permeability,

naturally fractured, laminated and hetero-

geneous formations, especially gas reservoirs.

If an original fracturing treatment was inade-quate or an existing proppant pack becomes

damaged or deteriorates over time, fracturing

the well again reestablishes linear flow into the

wellbore. Refracturing can generate higher con-

ductivity propped fractures that may penetrate

deeper into a formation than the initial treat-

ment. But not all restimulations are remedial

treatments to restore productivity; some wells

that produce at relatively high rates also may be

good candidates for refracturing. In fact, the

better wells in a field often have the highest

restimulation potential.2

Wells with an effective initial treatment alsocan be retreated to create a new fracture that

propagates along a different azimuth than the

original fracture. In formations with lower

permeability in a direction perpendicular to the

original fracture, a reoriented fracture exposes

more of the higher matrix permeability. In these

cases, refracturing significantly improves well

production, and supplements infill drilling.

For this reason, operators should consider

restimulation during the field-development

planning process.

Many companies, however, are reluctant to

retreat wells that produce at reasonably eco-nomic rates. The tendency is not to refracture

any wells, or to restimulate only poorly perform-

ing wells. This lack of confidence and the negative


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Autumn 2003 39

preconceptions about refracturing are changing

because of a better understanding of refracturing

mechanics and the favorable results reported by

companies that apply this technique regularly.

To be successful, refracturing treatments

must create a longer or more conductive

propped fracture, or expose more net pay to the

wellbore compared with existing well conditions

prior to restimulation. Accomplishing these

objectives requires knowledge of reservoir and

well conditions to understand why rest imula-tions succeed and to improve future treatments

based on experience. Quantifying average reser-

voir pressure, permeabili ty-thickness product,

and effective fracture length and conductivity

both before and after refracturing allows engi-

neers to determine the reasons for poor well

performance before new treatments and the

causes of restimulation success or failure.

Improved diagnostic techniques, such as

short shut-in time well tests, help determine the

current stimulation condition of a well and

ve ri fy re fr ac tu ri ng po te nt ia l. Ad va nc es in

fracture modeling, design and analysis software

also have contributed significantly to restimula-

tion success during the past ten years, as have

better candidate selection, innovative stimula-

tion fluids, improved proppants and proppant

flowback control.

This article presents results from a two-year ref racturing study and subs equent fie ld

trials. We also discuss reasons for restimulation

success, including candidate-selection methods

and criteria, causes of underperformance in

fracture-stimulated wells, formation-stress reori-

entation and treatment-design considerations.

Recent examples from the USA and Canada

demonstrate refracturing implementation and

productivity improvement.

1. International Outlook: World Trends, World Oil224,no. 8 (August 2003): 2325.

2. Niemeyer BL and Reinart MR: Hydraulic Fracturing of aModerate Permeability Reservoir, Kuparuk River Unit,paper SPE 15507, presented at the SPE Annual TechnicalConference and Exhibition, New Orleans, Louisiana, USAOctober 58, 1986.

Pearson CM, Bond AJ, Eck ME and Lynch KW: OptimalFracture Stimulation of a Moderate PermeabilityReservoir, Kuparuk River Unit, Alaska, paper SPE 20707,presented at the SPE Annual Technical Conferenceand Exhibition, New Orleans, Louisiana, USA,September 2326, 1990.

Reimers DR and Clausen RA: High-PermeabilityFracturing at Prudhoe Bay, Alaska, paper SPE 22835,presented at the SPE Annual Technical Conference andExhibition, Dallas, Texas, USA, October 69, 1991.

2003

1993


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A Multiple-Basin Evaluation

Some operators report disappointing results

when refracturing previously stimulated wells,

despite documented successes in individual

we ll s an d se ve ra l fi el d- wi de re st im ul at io n

efforts.3 However, recent research, subsequent

field trials and the ongoing refracturing

programs of a few operators still attract

considerable interest and attention within the

oil and gas industry.

In 1996, the Gas Research Institute (GRI),

now Gas Technology Institute (GTI), began

investigating fracture restimulation as a low-cost

means of enhancing gas production and adding

recoverable reserves. This preliminary evalua-

tion identified significant onshore gas

potentialconservatively more than 10 Tcf

[286.4 billion m3] of incremental reservesin

the USA, excluding Alaska (below).

These additional gas reserves are located in

the Rocky Mountain, Midcontinent, East Texas

and South Texas regions, primary in low-

permeability, or tight-gas, sandstones (TGS)and in other unconventional reservoirs that

include gas shales (GS) and coalbed methane

(CBM) deposits (see Producing Natural Gas

from Coal,page 8). Other areas of the USA with

refracturing potential include unconventional

reservoirs in the Michigan and Appalachian

regions as well as conventional sandstone (CS)

and conventional carbonate (CC) formations

in the San Juan basin and areas of the mid-

continent and Texas.

The 1996 GTI work concluded that docu-

mented refracturing treatments had yielded

incremental reserves at about $0.10/Mcf to

$0.20/Mcf, much less than the average costs for

acquiring or for finding and developing gas

reserves of $0.54/Mcf and $0.75/Mcf, respec-

tively. Despite the potential economic benefits,

operators remained reluctant to refracture

wells. Poor candidate selections appeared to be

the main reason for lack of restimulation

success and acceptance among operators.

In response, GTI funded another project in

1998 to develop specialized restimulation tech-

nology and analysis techniques. The need for

this project was underscored by anecdotal obser-

vations from the 1996 investigation that 85% of

refracturing potential in a given field exists in

about 15% of the wells. Identifying these topcandidates is crucial to restimulation success.

However, operators often perceive comprehen-

sive field-wide studies to be too costly in terms

of money and manpower for companies operat-

ing unconventional reservoirs, especially when

gas prices are low.

40 Oilfield Review

3. Parrot DI and Long MG: A Case History of MassiveHydraulic Refracturing in the Tight Muddy JFormation, paper SPE 7936, presented at the SPESymposium on Low-Permeability Gas Reservoirs,Denver, Colorado, USA, May 2022, 1979.

Conway MW, McMechan DE, McGowen JM,Brown D, Chisholm PT and Venditto JJ: ExpandingRecoverable Reserves Through Refracturing, paperSPE 14376, presented at the SPE Annual TechnicalConference and Exhibition, Las Vegas, Nevada, USA,September 2225, 1985.

Hunter JC: A Case History of Refracs in the Oak Hill(Cotton Valley) Field, paper SPE 14655, presented at the

SPE East Texas Regional Meeting, Tyler, Texas, USA,April 2122, 1986.

Olson KE: A Case Study of Hydraulically RefracturedWells in the Devonian Formation, Crane County, Texas,paper SPE 22834, presented at the SPE Annual TechnicalConference and Exhibition, Dallas, Texas, USA,October 69, 1991.

Fleming ME: Successful Refracturing in the NorthWestbrook Unit, paper SPE 24011, presented at theSPE Permian Basin Oil and Gas Recovery Conference,Midland, Texas, USA, March 1820, 1992.

Hejl KA: High-Rate Refracturing: Optimization andPerformance in a CO2 Flood, paper SPE 24346, presentedat the SPE Rocky Mountain Regional Meeting, Casper,Wyoming, USA, May 1821, 1992.

Pospisil G, Lynch KW, Pearson CM and Rugen JA:Results of a Large-Scale Refracture StimulationProgram, Kuparuk River Unit, Alaska, paper SPE 24857,

presented at the SPE Annual Technical Conference andExhibition, Washington, DC, USA, October 47, 1992.

Hunter JL, Leonard RS, Andrus DG, Tschirhart LR andDaigle JA: Cotton Valley Production Enhancement TeamPoints Way to Full Gas Production Potential, paperSPE 24887, presented at the SPE Annual TechnicalConference and Exhibition, Washington, DC, USA,October 47, 1992.

Reese JL, Britt LK and Jones JR: Selecting EconomicRefracturing Candidates, paper SPE 28490, presented at

the SPE Annual Technical Conference and Exhibition,New Orleans, Louisiana, USA, September 2528, 1994.

Fengjiang W, Yunhong D and Yong L: A Study ofRefracturing in Low Permeability Reservoirs, paperSPE 50912, presented at the SPE International Oil &Gas Conference and Exhibition, Beijing, China,November 26, 1998.

4. Type curves help interpret transient-pressure buildup

tests that differ from conventional semilog, or Horner,analysis radial-flow behavior. Type curves are groups ofpaired pressure changes and their derivatives generatedfrom analytical solutions of the diffusion equation withstrategically defined boundary conditions. Near-wellboundary conditions include constant or variable well-bore storage, partial reservoir penetration, compositeradial damage or altered permeability, and proppedhydraulic fractures. Borehole trajectory can be vertical,angled, or horizontal. Distant boundary conditions includesealing or partially sealing faults, intersecting faults andsealing or constant-pressure rectangular boundaries.The diffusion equation can be adjusted to accommodatereservoir heterogeneity, such as dual porosity or layer-ing. Commercial software generates type-curve families

that account for superposition in time due to flow-ratevariations before and even during transient-pressuredata acquisition. Automated regression analysis canmatch acquired data with a specific type curve.

5. Reeves SR, Hill DG, Tiner RL, Bastian PA, Conway MWand Mohaghegh S: Restimulation of Tight Gas SandWells in the Rocky Mountain Region, paper SPE 55627,presented at the SPE Rocky Mountain Regional Meeting,Gillette, Wyoming, USA, May 1518, 1999.

Reeves SR, Hill DG, Hopkins CW, Conway MW, Tiner RLand Mohaghegh S: Restimulation Technology for TightGas Sand Wells, paper SPE 56482, presented at the SPEAnnual Technical Conference and Exhibition, Houston,Texas, USA, October 36, 1999.

Green River

USAPiceance

TGS

TGS

CC

CC CC

TGS

TGS

GS

GS

TGSGS

CBM

CSTGS

CSTGS

CS, TGS, CBMSan Juan

Hugoton

Denver-Julesburg

Conventional sands (CS)

Conventional carbonates (CC)

Tight-gas sands (TGS)

Coalbed methane (CBM)

Gas shales (GS)

Anadarko

Delaware

PermianBarnett Shale

Val Verde

TGS

South Texas

East Texas

Black Warrior

Michigan

Appalachian

N

0

0 400 800 1200 1600 km

250 500 750 1000 miles

> Areas with refracturing potential in the USA. The 1996 Gas Technology Institute (GTI) restimulationinvestigation evaluated a wide range of gas reservoirs, including conventional sandstone and carbon-ate formations, tight-gas sands, gas shales and coalbed methane deposits. This evaluation focusedon conventional gas-producing provinces with cumulative production greater than 5 Tcf [143.2 billionm3] for further evaluation. Higher production implied high numbers of older wells and more refractur-ing opportunities. The study also identified tight-gas sand areas with an estimated ultimate recovery(EUR) greater than 1 Tcf [28.6 billion m3] and the largest gas shale and coalbed methane develop-ments, but did not include offshore developments with limited production and recovery information.


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Autumn 2003 41

Project participants, including Advanced

Resources International, Schlumberger,

Intelligent Solutions, Ely and Associates,

Stim-Lab and Pinnacle Technologies, believed

that developing an effective methodology to

identify wells with restimulation potential was

one way to expand refracturing applications.

There were three other objectives: demonstrate

productivity enhancement and recovery

improvement from refracturing, identify reasons

for underperformance in previously fractured

wells, and evaluate new fracturing techniques

and technology.

The 1998 GTI study evaluated three methods

for identifying refracturing potential that were

then tested in different types of reservoirs.

These candidate-selection methods included

production statistics, pattern-recognition tech-

nologyspecifically neural networks, virtual

intelligence and fuzzy logicand production

type curves (right).4

All three methods were used to select restim-

ulation candidates at field locations with at least200 to 300 wells.5 Three sites in the USAGreen

River basin, Wyoming, USA; East Texas basin,

Texas; and Piceance basin, Colorado, USA

were chosen and actively evaluated (below): A

fourth site in South Texas was identified, but not

pursued during the GTI project. Subsequent

reservoir studies, however, have generated

recent refracturing activity in this area (see

Production-Enhancement Evaluation,page 52).

Of the nine wells eventually treated at the

three active project sites, eight were refracturing

treatments and one was an attempted damage

removal treatment. As the projec

progressed, treatment designs trended away

from high-viscosity polymer-base systems to

fracturing fluids with lower and lower gel con

centrations, or slick water. Most treatment

Inte

rpretationrequirements

Data requirements

Type curves

Production statistics

Virtual intelligence

Timea

ndcos

tincre

ase

HighLow

Low

High

> Candidate-selection methods. The GTI project developed a methodology foridentifying wells with restimulation potential that used production statistics,virtual intelligence and production type curves. By design, these techniquesprogressed from a simple, nonanalytical statistical approach with minimaldata requirements to detailed engineering analyses requiring increasinglycomprehensive data.

Green River basin GTI site

Operator:

Enron Oil and Gas, now EOG resources.

Formation:Upper Cretaceous Frontier.

Location:Big Piney/LaBarge complex, northern Moxa Arch area,southwestern Wyoming, USA.

Deposition:

Marine sandstones, primarily rivers and streams, orfluvial and distal shore zones.

Reservoir:

Tight-gas sands with permeability of 0.0005 to 0.1 mDin up to four productive horizons, consisting of as manyas eight separate intervals, or benches.

Initial completions:One to three stages of a crosslinked guar fluid andnitrogen foam with 100,000 to 500,000 lbm [45,359 to226,796 kg] of proppant sand.

GTI restimulations:

Three refracturing treatments and one gel-cleanuptreatment.

Piceance basin GTI site

Operator:

Barrett Resources, now Williams Company.

Formation:Mesaverde group, Upper Cretaceous Williams Fork.

Location:Parachute and Grand Valley fields near Rulison,Garfield County, Colorado, USA.

Deposition:

Marine sandstones, primarily fluvial and marsh,or paludal.

Reservoir:

Compartmentalized tight-gas sands with permeabilityof 0.1 to 2 mD. Because of natural fractures, effectivepermeability is 10 to 50 mD.

Initial completions:Two to five stages with proppant volumes of 50,000to 650,000 lbm [22,680 to 294,835 kg] per stage.

GTI restimulations:

Two refracturing treatments.

East Texas basin GTI site

Operator:

Union Pacific Resources Company (UPRC), nowAnadarko Petroleum Corporation.

Formation:Cotton Valley.

Location:Carthage Gas Unit (CGU) field nearCarthage, Panola County, Texas, USA.

Deposition:

Complex marine sandstones, primarily barrier reef andtidal zone.

Reservoir:

Heterogeneous, highly laminated and compartmentalizedtight-gas sands with permeability of 0.05 to 0.2 mD.

Initial completions:Three to four stages of a crosslinked fluid and proppantvolumes of 1 to 4 million lbm [453,592 to 1,814,370 kg]for an entire well; 1996 to present, UPR and Anadarkoused slick-water fluids with less than 250,000 lbm[113,398 kg] of proppant.

GTI restimulations:

Three refracturing treatments.

> The 1998 GTI restimulation study to evaluate refracturing candidate-selection methods at three USA test sites.


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included nitrogen [N2] or carbon dioxide [CO2]

to assist in post-stimulation cleanup, single-

stage pumping schedules and ball sealers for

fluid diversion to reduce cost compared with

multistage treatments.Standard decline-curve analysis determined

estimated ultimate recovery (EUR) for each

well ; estimated treatment co st prov ided an

undiscounted cost of incremental reserve

additions. Costs for diagnostic tests conducted

for research purposes only were not included,

only actual expenses for treatment

implementation. The project team analyzed all

nine wells to better understand each candidate-

selection method.6

The team considered treatments generatingincremental reserves at a cost of less than

$0.50/Mcf as economic successes. On this basis,

six of the nine wells restimulated at the three

sites were successful (above). All nine wells

combined added 2.9 Bcf [83 million m3] of incre-

mental reserves at a total cost of $734,000, or an

average reserve cost of $0.26/Mcf.

Excluding the damage-removal treatment

and the poorly designed treatment that did not

flow back, the six successful restimulations and

one uneconomic treatment added incremental

reserves at about $0.20/Mcf. This cost is closer to

the $0.10 to 0.20/Mcf range of past restimula-

tions, even though post-treatment evaluations

indicated that a few pay zones in some of the

wells were not stimulated effectively. Even when

the three unsuccessful treatments are included,

this field trial was highly successful, yielding

additional reserves of 300 MMcf/well [8.6 million

m3/well] at an average cost of $81,600 per well.

There are about 200,000 unconventional gas

we ll s in lo w- pe rm ea bi li ty sa nd s, co al be d

methane deposits and gas shales in the 48 con-

tiguous states of the USA. At least 20%, or about

40,000 wells, could be potential restimulation

candidates. Extrapolating GTI results using the

average incremental recovery of 300 MMcf/well

yie lds 12 Tcf [343.6 bil lion m3] of additional

reserves from refracturing. Companies operating

in the Green River and East Texas formationscontinued to perform restimulation treatments

using knowledge gained from this study.

Candidate-Selection Methods

Overall, the GTI refracturing tests were success-

ful, but did not definitively identify a single

candidate-selection method as most effective.

Each technique tends to select different wells

for different reasons that may all be valid,

depending on specific reservoir characteristics

(next page, top). Production statistics worked

reasonably well in the Piceance basin. Virtual

intelligence and pattern recognition workedbest in the Green River basin. Type curves were

most effective in the East Texas basin. Clearly,

additional evaluations were needed to validate

the effectiveness of each technique and to

advance refracturing acceptance.

A re servoi r simula tion of a hypothet ical

tight-gas field was designed for this purpose.7

The objective of this study was to independently

test and validate candidate-selection methods

against the simulation model. Results from this

simulation confirmed that each candidate-

selection method being studied tended to yield

different candidates. And like the 1998 GTIrestimulation study, some wells were selected by

more than one of the methods. The virtual-intel-

ligence method was generally most effective,

followed closely by type curves. With less effi-

ciency than random selections, production

statistics alone were the least effective method.

42 Oilfield Review

2864 m3/d 5727 m3/d 8590 m3/d 11,455 m3/d

0

50

100

150

200

250

Post-restimulation

rate,

Mcf/D

500 150100 250200 350 400300

Pre-restimulation rate, Mcf/D

300

350

400

450

CGU 10-7

GRB 45-12

CGU 3-8RMV 55-20

CGU 15-8

NLB 57-33

WSC 20-09

GRB 27-14

Langstaff 1

Sitefield/basin Well Date

Incrementalrecovery, MMcf

Treatmentcost, $

Reservecost, $/Mcf

Success/failure

Big Piney

and LaBarge/

Green River

Rulison/

Piceance

Carthage/

East Texas

Jan. 1999

Jan. 1999

Apr. 1999

Jun. 2000

Jun. 2000

Jun. 2000

Nov. 1999

Jan. 2000Jan. 2000

GRB 45-12

GRB 27-14

NLB 57-33

WSC 20-09

Langstaff 1

RMV 55-20

CGU 15-8

CGU 10-7CGU 3-8

Total

Average

602

(186)

0

302

282

75

270

4071100

2852

317

87,000

87,000

20,000

120,000

50,000

70,000

100,000

100,000100,000

734,000

82,000

0.14

NA

NA

0.40

0.18

0.93

0.37

0.250.09

0.26

S

F

F

S

S

F

S

SS

> GTI field-test results. Two of the four wells in the Frontier formation (Green River basin), all three ofthe wells in the Cotton Valley formation (East Texas basin), and one of the two wells in the WilliamsFork formation (Piceance basin) were successful. Of the three unsuccessful treatments, one addedincremental reserves at a cost of $0.93/Mcf and two had mechanical or design problems. Of the latter

two, in one, the damage-removal treatment could not be pumped at the injection rate required to flu-idize the original proppant pack and remove suspected residual gel damage from the initial treatment;

the other failed to clean up because energized fluids were not used as recommended in the GTI design.


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Autumn 2003 43

The first stage of the 1998 GTI study and

results from this simulation provided valuable

insights into the effectiveness of each candidate

selection methodology, but each technique

needed to be tested using real field data. Rather

than establish a new database of restimulation

cases for this purpose, as was the original overal

project objective, participants in the 1998 GT

study sought a field with a history of restimula

tion activity and results. With an existing

dataset, the approach used for the simulato

study could be repeated in an actual field setting

to evaluate each candidate-selection method.

As follow-up to the reservoir simulation, GTI

selected the Wattenburg field to further evaluate

candidate selection methods using actual field

data. This tight-gas development, located north

of Denver, Colorado, on the western edge of the

Denver-Julesburg basin, was attractive because

more than 1500 area wells had been refractured

since 1977. Most of these treatments were eco

nomically successful.8

Patina Oil & Gas Corporation, a leadingoperator in this basin, had performed about

400 fracture restimulations from 1997 through

2000, and agreed to participate. This allowed a

candidate-selection algorithm developed

independently by Patina to be used in addition to

the three GTI candidate-selection methods.

The methods were evaluated without disclos

ing beforehand those wells that had actually

responded favorably to restimulation. Afterward

candidate selections were compared with actua

well performance. This approach allowed the

effectiveness of each method to be assessed

Candidate selection using actual Wattenburgfield data confirmed previous GTI study and

reservoir-simulation results.

Prioritizing refracturing candidates provides

considerable value during restimulation

programs. In the absence of prior restimulation

results, both pattern recognition and type curve

are useful for selecting restimulation candi

dates; production statistics are less effective

Vi rt ua l in te ll ig en ce an d ot he r pa tt er n

recognition techniques, which use prio

refracturing data and results to learn from

can further improve candidate selection and

restimulation success. The GTI field trialsreservoir simulation and Wattenburg field

evaluation confirmed that the performance o

each candidate-selection method appeared to be

reservoir specific (bottom left).

6. Ely JW, Tiner R, Rothenberg M, Krupa A, McDougal F,Conway M and Reeves S: Restimulation ProgramFinds Success in Enhancing Recoverable Reserves,paper SPE 63241, presented at the SPE Annual TechnicalConference and Exhibition, Dallas, Texas, USA,October 14, 2000.

7. Reeves SR, Bastian PA, Spivey JP, Flumerfelt RW,Mohaghegh S and Koperna GJ: Benchmarking ofRestimulation Candidate Selection Techniques inLayered, Tight Gas Sand Formations Using ReservoirSimulation, paper SPE 63096, presented at the SPEAnnual Technical Conference and Exhibition, Dallas,Texas, USA, October 14, 2000.

Site,field/basin

Big Piney

and LaBarge/

Green River

Rulison/

Piceance

Carthage/East Texas

WellProductionstatistics

Virtualintelligence

Top 50 candidate-well ranking

Typecurves

Success/failure

*Revised analysis

Note: Bold italic numbers indicate correct classifications (true positive or true negative)

GRB 45-12

GRB 27-14

NLB 57-33

WSC 20-09

Langstaff 1

RMV 55-20

CGU 15-8CGU 3-8

CGU 10-7

>50

>50

4

38

1

43

>50>50

4

*15

*39

*>50

*2

>50

>50

>50>50

26

>50

32

20

1

>50

17

11

7

40

S

F

F

S

S

F

SS

S

> Candidate-selection performance. Based on the economic criterion of adding incremental reservesat less than $0.5/Mcf, the GTI study evaluated the capability of each candidate-selection method tocorrectly select successful refracturing candidates or to not select unsuccessful candidates. Thisdetermination was based on whether each method ranked a well among the top 50 candidates ornot. The three methodsproduction statistics, virtual intelligence and pattern recognition, and typecurvesidentified successful refracturing candidates or noncandidates in at least four of the nine

test wells, five in the case of virtual intelligence. The three methods combined identified only two ofthe five successful treatments and none of the three unsuccessful wells.

15

89 53

9371

49

10

50

14

145103

4

12052 83

7

5

Production statistics Virtual intelligence

Type curves

< Candidate selection from the GTIreservoir-simulation study. The top18 refracturing candidates repre-sent 15% of the wells from thereservoir stimulation. Virtual intelli-gence independently selected 10of the 13 true candidate wells, themost of any method. These 10wells consisted of five that wereuniquely selected by virtual intelli-gence, one well that was alsoselected by production statistics,

two wells that were also selectedby type curves, and two wells that

were selected by all three tech-niques. The type-curve methodadded three true candidate wells

to the combined selections, mak-ing the combined number ofcorrect selections between the vir-

tual intelligence and type-curvemethods 13 out of 13. In practice,however, no one knows in advancewhich wells are true candidates.

8. Emrich C, Shaw D, Reasoner S and Ponto D: CodellRestimulations Evolve to 200% Rate of Return, paperSPE 67211, presented at the SPE Production andOperations Symposium, Oklahoma City, Oklahoma, USA,March 2427, 2001.

Shaefer MT and Lytle DM: Fracturing Fluid EvolutionPlays a Major Role in Codell Refracturing Success,paper SPE 71044, presented at the SPE Rocky MountainPetroleum Technology Conference, Keystone, Colorado,USA, May 2123, 2001.

Sencenbaugh RN, Lytle DM, Birmingham TJ,Simmons JC and Shaefer MT: Restimulating Tight GasSand: Case Study of the Codell Formation, paper SPE71045, presented at the SPE Rocky Mountain PetroleumTechnology Conference, Keystone, Colorado, USA,May 2123, 2001.


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Ana lys is of pro ductio n statis tics ten ds to

identify completions that underperform

compared with offset wells. Substandard perfor-

mance could result from a poor quality reservoir,

but this method should be valid in fields with

relatively uniform reservoir quality and fairly

stable production.

Virtual-intelligence methods tend to select

we ll s th at ha ve le ss th an op ti ma l or ig in al

completions or stimulation procedures. Pattern-

recognition technologies should be applied

when reser voir, compl et ion and sti mulation

complexity is high.

Type curves tend to identify candidate wells

based solely on incremental production poten-

tial, and therefore, weights the better producing

wells in a field more heavily. This method should

be used when production data quality is good and

petrophysical information is readily available.

The applicability of any candidate-selection

process should be assessed for each specific

area being evaluated. In effect, an ideal

methodology may combine several techniques.The three efforts to evaluate candidate-selection

methods also indicated that nonanalytical

analyses, such as evaluating current producing

rate and estimated ultimate recovery to identify

underperforming wells, could be useful for

candidate selection in the absence of

other approaches.

A Field-Wide Evaluation

Prior to 1999, refracturing by Patina Oil & Gas

Corporation in the Wattenburg field had primar-

ily targeted underperforming wells and

completions that screened out prematurely or

had mechanical failures during the initial stimu-

lation. When other operators began restimulating

their better producers with varying, but generally

encouraging results, Patina initiated a field-wide

evaluation of refracturing potential.

The Wattenburg field produces mainly from

the Codell interval. This fine-grained sandstone,

deposited in a marine-shelf environment, is a

member of the Upper Cretaceous Carlisle shale.

The Codell reservoir contains 15 to 25% clay by

volume in mixed layers of ill ite and smectite

that fill and line the pore spaces.

The pay interval is 14 to 35 ft [4.3 to 10.7 m]

thick, 6800 to 7700 ft [2073 to 2347 m] deep and

continuous across the field. Permeability is

less than 0.1 mD. Porosity from density logs is

8 to 20%. Initially, the reservoir was over-

pressured with a gradient of about 0.6 psi/ft

[13.5 kPa/m]. Bottomhole temperature is 230 to

250F [110 to 121C]. Wells are drilled on a

40-acre [162,000-m2] spacing.

During 1998, Patina compiled a database of

250 fracture restimulations on both operatedand nonoperated properties. After eliminating

wells tre ate d with bor ate cro ssl ink ed fluids,

wh ich we re 20% less productive than other

we ll s, co mp an y en gi ne er s fo cu se d on th e

remaining 200 wells. These wells had been res-

timulated with carboxymethyl hydropropyl guar

(CMHPG) or hydropropyl guar (HPG) fluids.

Further evaluation identified 35 discrete

geologic, completion and production parameters

related to well performance. Linear-regression

analysis helped determine those parameters

that correlated with peak incremental produc-

tion after refracturing. Two technical

improvements from this field-wide evaluation

provided an order-of-magnitude improvement in

restimulation results.

The first was application of carboxymethy-

late guar (CMG) fluids with lower polymer

loadings, which maintain proppant transport

and minimize residual proppant-pack damage

from unbroken and unrecovered gel. Nondamag-

ing fluids are particularly important in the

refracturing of low-permeability formations

where long-term gas saturation has been estab-

lished and reservoir pressure may be depleted.

The second improvement was a candidate-

selection method developed by Patina that uses

historical restimulation results in the basin.

Together with CMG fluids, this statistically

based algorithm achieved significant improve-

ments in selection of the best refracturing

candidates (below). Average peak incremental

production rate almost doubled from just over

1000 to about 2000 barrels of oil equivalent

(BOE)/well/month [159 to 318 m3/well/month],

which equaled about 80% of the average initialproduction rate. The associated rate-of-return

on refracturing investments increased from 66%

to more than 200% at $2.50/Mcf. Estimated

incremental recoveries increased from 25 to 38

million BOE per well [4 to 6 million m3/well].

Only about 3% of refracturing treatments

resulted in economic failures, primarily because

the propped fractures communicated with the

overlying Niobrara formation or an offset well.

This failure rate may become higher as refrac-

turing density increases. The overall success of

this program resulted from stringent

well- sel ect ion crite ria, str ict qua lit y-c ont rol

44 Oilfield Review

2500

2000

1500

1000

Peakpro

duction,

BOE/well/month

Development and application of geneticalgorithm for candidate selection

CMG fluids

1997 1998 1999 2000

500

0

Patina

Others

> Historical refracturing performance in the Wattenburg field, Colorado. The combined applications of CMG stimulation fluids andthe candidate-selection algorithm developed by Patina Oil & Gas significantly improved restimulation results in Patina-operated wells.


8/16

Autumn 2003 45

guidelines for treatment fluids and effective

operational practices in the field.

Other area operators have reported similar

improvements in productivity, economic results

and recovery from refracturing.9 Based on these

results, more than 4000 other wells in the

Piceance basin may be candidates for restimula-tion. Patina engineers continue to expand their

already extensive refracturing database and fine-

tune the candidate-selection algorithm. In some

wells, Patina and other area operators are now

successfully fracturing wells for a third time.

Candidate-Selection Criteria

The Patina Oil & Gas linear-regression analysis

identified five statistically significant variables

that were incorporated into the Wattenburg field

candidate-selection algorithm (above). Although

statistically less significant, a sixth variable

maximum differential recovery in BOE, wasadded to help predict restimulation results for

economic evaluation purposes.

Hydrocarbon pore volume, or porosity-feet,

the most statistically significant parameter, is

incorporated in the cumulative and ultimate

recovery factors. Gas/oil ratio, which varies

from about 5000 to 35,000 scf/bbl [900 to

6304 m3/m3], correlates to higher recovery wells

from original and refractured completions

primarily in and around central areas of the

field. This is indicative of greater relative perme-

ability to gas because formation thickness andreservoir permeability are relatively uniform

across the field.

Well compl etions tha t use d lim ite d-ent ry

perforating across both the Codell and Niobrara

formations resulted in shorter effective fracture

lengths in the Codell than those completed only

in the Codell. Cumulative and ultimate recovery

factors determined from individual well and

reservoir parameters coupled with decline-curve

analysis indirectly represented the extent of

depletion and the capability of the reservoir to

flow back and clean up treatment fluids. These

factors also provided an indication of whethernew hydraulic fractures might reorient with

respect to the original propped fracture (see

Fracture Reorientation,page 47).

The maximum differential BOE is the differ-

ence in ultimate recovery between the subject

well and the best well within 1 mile [1.6 km]

This parameter gives an indication of upside

reserve potential in the immediate vicinity of a

subject well. Engineers eliminated some vari

ables, such as faulting, treatment size and

perforated interval, which were statistically

insignificant. Well location is not significant in

this field because of the relatively uniform

reservoir quality.

Post-refracturing performance continues to

support added reserves above baseline projec

tions for the original completions because the

initial completion in most of the wells was not

effectively draining the 40 acres allotted to each

well in the development pattern. A reevaluation

of 1000 refracturing treatments indicated good

correlation with the best fit of actual results. To

some extent, these variables can be quantified

for individual wells by analyzing actual produc

tion in terms of long-term pressure drawdown

using production type-curve analysis techniques

Production type-curve analysis requires more

analysis time, but effectively forecasts restimulation results with a higher degree of accuracy

than do other statistical techniques.

Variations still existed, but overall the Patina

algorithm successfully ranked restimulation

potential on a field-wide basis. The variability in

refractured well performance appears to resul

from an inability of statistical methods to

differentiate between actual drainage areas

differences in matrix permeability, effective

fracture lengths from the original stimulation

and the impact of liquid condensate loading, or

banking, around these wellbores using only

production and completion parameters.10The fundamental objective of refracturing is

to enhance well productivity. However, restimu

lation is viable only if wells are underperforming

because of completion-related problems, no

because of poor reservoir quality. Neither frac

turing nor refracturing can turn margina

producers in poor reservoirs into good wells. To

prioritize and select refracturing candidates

engineers must understand the reasons for poor

performance in previously fractured wells.

Rank Parameter DescriptionStatistical

significance

1

2

3

4

5

6

Hydrocarbon volume,porosity-feet

Cumulativerecovery factor

Initial completion

Estimated ultimaterecovery (EUR) factor

Gas/oil ratio

Maximum differentialrecovery, million BOE

Net pay for Codell above a10% density porosity cutoff

Cumulative gas recovered dividedby original gas in place (OGIP) for40-acre drainage area

Peak rate premium assignedif well was originally completedlimited entry in Codell-Niobrara

EUR divided by OGIP for 40-acredrainage area

Projected ultimate gas/oil ratio

EUR difference between subjectwell and best offset well withinone mile of subject well

38%

17%

9%

11%

20%

5%

> Patina Oil & Gas statistical algorithm. Of the five statistically significantvariables of the candidate-selection algorithm for Wattenburg field, hydro-carbon volume in porosity-feet represents reservoir quality, initialcompletion represents the initial completion, and the other threecumula-

tive recovery factor, estimated ultimate recovery factor and gas/oilratiorepresent well performance. Well location is not significant becauseof the relatively uniform reservoir quality. However, higher, and therefore bet-

ter, gas/oil ratios do tend to occur in the center of the field. The sixth variablemaximum differential recovery in BOE helps predict restimulation potentialfor economic evaluations.

9. Shaefer and Lytle, reference 8.

Sencenbaugh et al, reference 8.10. Barnum RS, Brinkman FP, Richardson TW and

Spillette AG: Gas Condensate Reservoir Behaviour:Productivity and Recovery Reduction Due toCondensation, paper SPE 30767, presented at the SPEAnnual Technical Conference and Exhibition, Dallas,Texas, USA, October 2225, 1995.


9/16

Completion-Related Underperformance

To aid in problem diagnosis, the 1998 GTI

project established a framework to classify

well-performance problems (above). For tight-

gas wells, three specific problems, ranked in

order of highest perceived restimulation poten-

tial were identified:

Unstimulated or bypassed pay

Insufficient fracture conductivity

Insufficient fracture length.

Ineffective or problematic initial comple-

tions are the most common type of problem.

Examples include lack of quality control duringinitial fracture treatments, residual polymer

damage from stimulation fluids, inappropriate

proppant selection, premature screenout, under-

designed fracturing treatments, incompatible

fluids and single-stage treatments that leave

some pay intervals unstimulated.

Hydraulic fractures can lose effectiveness in

the years after an initial stimulation treatment

because of gradual damage that occurs over the

life of a well. Examples include loss of fracture

conductivity from proppant crushing or embed-

ding in the formation and plugging of the pack

by formation fines or scale deposition. Proppantflowback from the near-well area can allow the

hydraulic fractures to close. Typically, little

information is available to identify these

specific mechanisms.

Wells with these types of problems have the

greatest potential for remediation by refractur-

ing. In older wells that have a higher occurrence

of these problems, reservoir pressure must be

sufficient to justify refracturing, both in terms of

remaining reserves and adequate flowback of

treatment fluids. Well age may be the best indi-

cator of gradual damage and the possibility of

applying new stimulation technology.

Diagnosing production damage, a second

major category of problems, often is difficult.

Proppant flowback, fluid damage and high skin

factors, frequent remedial workovers, and fines

or scale deposits during the onset of multiphase

flow or water breakthrough are manifestations

of problems that develop over time. Any

combination of these may indicate that well pro-

ductivity has deteriorated over time.A third category, advances in completion and

stimulation technology, also provides opportuni-

ties to restimulate wells originally completed

using older technology. New treatment designs,

advanced computer models, less damaging

fracturing fluids, improved fluid additives and

proppants help create longer, wider, more

conductive fractures. In some sense, this

category is a subset of the previous two because

older technology often is synonymous with less

effective initial completions where more gradual

damage has occurred.

It is important to determine what types ofproductivity problems correlate with the best

refracturing candidates in a field, area or basin.

Engineers can gain information about specific

well-completion problems and how to remediate

them by reviewing individual well records.

Unstimulated zones typically result from

using limited-entry diversion or from fracturing

multiple pay horizons in a single-stage treat-

ment. This well-completion problem may

represent the greatest restimulation potential for

two reasons. First, tight-gas wells are frequently

multiple-zone completions. The tendency is to

treat multiple intervals in fewer stages to reduce

treatment cost. Second, enhanced well produc-

tivity from stimulation of new zones almost

always represents an incremental reserve addi-

tion, not just an increase in production rate and

accelerated reserve recovery.

A lo w ratio of frac ture -tre atment stag es

and proppant volume to the number and distri-

bution of net-pay intervals is an indicator of

potentially understimulated or unstimulated

zones. Radioactive tracer surveys, well tests,

production-decline curves and production logs

also help diagnose unstimulated or poorly

performing intervals.

Insufficient conductivity of an initial

propped fracture probably represents the next

highest restimulation potential. However, the

distinction between rate acceleration and true

incremental reserve addition from increased

conductivity after refracturing is often blurred.Examples include insufficient proppant strength

for the fracture-closure pressure at reservoir

depth, proppant settling, low proppant concen-

trations and damage to proppant packs by

partially broken and unbroken gel.

Capturing incremental reserves at the outer

margin of a drainage area by increasing fracture

length is difficult. A relatively small treatment

compared with the higher net-pay thickness is

generally indicative of limited fracture length.

Generating longer hydraulic fractures can be

expensive unless the initial treatment was

extremely small. However, if restimulationachieves additional fracture length and expands

the drainage area of a well, incremental produc-

tion should represent a true reserve addition.

A review of the initial fracturing treatment

and flowback helps identify possible limited

fracture conductivity and length. Well-test

and production-decline analyses also help diag-

nose these conditions. A short period of linear

flow followed by radial flow after fracturing

indicates insufficient fracture conductivity or

inadequate length.

Refracturing opportunities also exist as a

result of field development and well productionprovided wells have enough pressure to flow

back and produce, even if energized treatment

fluids or artificial lift is required. In addition to

lower pore pressure, pressure depletion also

implies higher effective stress, which results in

less hydraulic fracture width and longer lateral

extension for the same volumes of treatment

fluid and proppant.

46 Oilfield Review

Wellunderperformance

Ineffective or problematicinitial completions.Unstimulated horizons. Low fracture conductivity. Short fracture length. High skin, or damage

Technology evolution. Advanced stimulation technology. New completion techniques.Well age

Gradual formation damageduring production. Scale and fines.Workover frequency.Well age

> Potential causes of underperformance in previously stimulated wells. TheGTI restimulation project team established a classification framework to helpdiagnose problems in hydraulically fractured wells that perform below operatorexpectations. At the highest level, there are three broad categories: ineffectiveor problematic initial completions, gradual production damage and advancesin technology or evolving techniques compared with past practices.


10/16

Autumn 2003 47

In addition, depletion of pay intervals

increases the stress contrast between pay inter-

va ls an d bo un di ng sh al es , wh ic h im pr ov es

vert ical containment and al lows generation

of longer fractures. Alteration of horizontal

in-situ stress around a wellbore and an existing

fracture also may contribute to fracture reorien-

tation during restimulation.

Fracture Reorientation

Historically, refracturing has been a remedial

measure performed on poorly producing wells

with short or low-conductivity initial fractures.

However, there are numerous examples of

successful restimulations on previously frac-

tured wells, especially tight-gas wells, that still

exhibit linear flowa negative 0.5 slope on

log-log production-rate plots indicative of deeply

penetrating, highly conductive fractures. Pro-

duction tests and history matching using a

numerical simulator that accommodated orthog-

onal fractures and horizontal permeability

anisotropy indicate a strong probability ofrefracture reorientation in many of these wells.

This concept of fracture reorientation is not

new and has been modeled in full-scale

laboratory experiments. In addition, fracture

reorientation has been observed in soft, shallow

formations.11 After an initial period of produc-

tion, stress changes around existing wells with

effective initial fracture treatments may allow

new fractures to reorient and contact areas of

higher pore pressure.

Laboratory tests have also shown that matrix

pore-pressure changes influence hydraulic frac-

ture orientation in the reservoir volume betweeninjectors and producers in a waterflood.12 The

fractures orient normal, or perpendicular, to the

higher stress gradient. Fractures initiated from

producing wells orient towards and intersect

the injection well if the stress gradient is

high enough and the in-situ stress anisotropy is

not dominant.

Pressure changes around a deeply penetrat-

ing, highly conductive fracture also create high

stress gradients normal to the initial fracture

that may cause fracture reorientation during

restimulation treatments. Stress changes reach

a maximum and then diminish with furtherdepletion. An optimal window of time during

which to perform refracturing treatments can be

determined.13 Horizontal permeability anisotropy

further increases these stress changes. Similarly,

a separate study showed that initial fracture

orientation is influenced by production in

unfractured formations that have large horizon-

tal permeability anisotropy.14

GTI provided funding for Schlumberger to

investigate these concepts in greater detail.15

Numerical simulations during this investigation

provided evidence that new fractures can form

at angles up to 90 from the initial propped

fracture azimuth (below). Fracture reorienta-

tion bypasses damage caused by drilling and

completion activities, and avoids zones of

reduced permeability caused by compaction and

other flow restrictions, including hydrocarbon

liquid dropout, or condensate banking, around

a well.

The horizontal stress component parallel to

an initial fracture is reduced more quickly as a

function of time than the perpendicular compo-

nent. If these induced stress changes overcome

the original stress differential, then a new frac-

ture will initiate and propagate along a different

azimuthal plane than the initial fracture until i

reaches the boundary of the elliptical stress

reversal region. The fracture may continue along

the new azimuth for some distance beyond thi

point, depending on formation toughness.

Many factors contribute to the location o

the stress-reversal boundary, including produc

tion history, reservoir permeability, fracture

dimensions, pay-zone height, elastic properties

of the pay and bounding barrier zones, and the

initial horizontal stress contrast. These parame

ters can be modeled and should be considered

when selecting refracturing candidates.

Computer simulations can determine the

optimal time window for refracturing and

fracture reorientation. Wells with long initia

fractures in low-permeability formations have a

longer time window. Production shut-in periods

11. Wright CA, Stewart DW, Emanuel MA and Wright WW:Reorientation of Propped Refracture Treatments in theLost Hills Field, paper SPE 27896, presented at the SPEWestern Regional Meeting, Long Beach, California, USA,

March 2325, 1994.Wright CA, Conant RA, Stewart DW and Byerly PM:Reorientation of Propped Refracture Treatments,paper SPE 28078, presented at the SPE/ISRM RockMechanics in Petroleum Engineering Conference,Delft, The Netherlands, August 2931, 1994.

Wright CA and Conant RA: Hydraulic FractureReorientation in Primary and Secondary Recovery fromLow-Permeability Reservoirs, paper SPE 30484, pre-sented at the SPE Annual Technical Conference andExhibition, Dallas, Texas, USA, October 2225, 1995.

12. Bruno MS and Nakagawa FM: Pore PressureInfluence on Tensile Propagation in Sedimentary Rock,International Journal of Rock Mechanics and MiningSciences and Geomechanics Abstracts 28, no. 4(July 1991): 261273.

New fracture

New fracture

Isotropic point

Wellbore

Isotropic point

x

Maximumhorizontalstress

Minimumhorizontalstress

Initial fracture

Stress-reversalregion

y

> Stress reorientation and orthogonal fracture extension. This horizontal sec-tion through a vertical wellbore depicts an original hydraulic fracture in thex direction and a second reoriented fracture in the y direction. Fluid pro-duction after placement of the initial fracture can cause a local redistributionof pore pressure in an expanding elliptical region around the wellbore andinitial fracture. The stress-reversal boundary is defined by isotropic points ofequal primary horizontal stresses. Stress reorientation and fracture extensionin a direction away from the initial propped fracture help explain pressureresponses during refracturing treatments and unanticipated productionincreases from refractured wells known to have effective initial fractures.

13. Elbel JL and Mack MG: Refracturing: Observationsand Theories, paper SPE 25464, presented at the SPEProduction Operations Symposium, Oklahoma City,Oklahoma, USA, March 2123, 1993.

14. Hidayati DT, Chen H-Y and Teufel LW: Flow-InducedStress Reorientation in a Multiple-Well Reservoir,paper SPE 71091, presented at the SPE Rocky MountainPetroleum Technology Conference, Keystone, Colorado,USA, May 2123, 2001.

15. Siebrits E, Elbel JL, Detournay F, Detournay-Piette C,Christianson M, Robinson BM and Diyashev IR:Parameters Affecting Azimuth and Length of aSecondary Fracture During a Refracture Treatment,paper SPE 48928, presented at the SPE Annual TechnicaConference and Exhibition, New Orleans, Louisiana,USA, September 2730, 1998.


11/16

should be minimized to maintain a high pore-

pressure gradient normal to the initial fracture.

Aside from this, standard fracture design consid-

erations should be used.

Fracture restimulations in the naturally frac-

tured Barnett Shale, north of Fort Worth, Texas,

USA, are an example of fracture reorientation.

These treatments were monitored with an

array of surface and subsurface tiltmeters

(below).16 The results suggested significant frac-

ture reorientation in one well and oblique

reorientation in the other well. Post-treatment

production increased substantially in both wells.

Other refractured wells in the area had similar

increases. Reservoir depletion combined with

natural fractures can cause complex fracture

networks to develop during initial treatments

and restimulations.

A Gas-Shale Restimulation Program

In 1997, Mitchell Energy, now Devon Energy,

began using greatly reduced polymer concentra-

tions in treatment fluidscurrently only

surfactant-base friction-reducing agents are

usedand much lower volumes of proppant in

the Barnett Shale formation. These slick-water

fracturing treatments have been extremely

successful and are similar to designs used by

operators for Cotton Valley sandstone stimula-

tion treatments in the nearby East Texas basin.

Additional gas-shale development efforts are

currently under way in other areas of North and

West Texas. The Barnett Shale, for example, is

present in wells from the Fort Worth basin to

the Permian Basin of West Texas, so lessons

learned in North Texas can be applied in thou-

sands of wells.

Deposited in a deep marine environment, the

Barnett Shale consists of layered mudstone, silt-

stone and some interbedded limestone with

open and calcite-filled natural fractures. Matrix

permeability in this rich organic, fine-grained,

Mississippian-age shale formation is extremely

low, about 0.0001 to 0.001 mD. Estimated

ultimate recovery for a typical Barnett Shale

well is 0.5 to 1 Bcf [14.3 to 28.6 million m3]. This

represents a calculated recovery of 8 to 10 % of

the gas in place. Achieving economic production

requires large fracturing treatments.

The Barnett Shale typically lies between the

upper Marble Falls limestone and the lower Viola

limestone. In some areas, the Viola formation is

replaced by the Ellenburger dolomite, which is

not as competent as the Viola for confining

hydraulic fractures. The Barnett Shale is 200 to

1000 ft [61 to 305 m] thick, averaging about

500 ft [152 m] in the main area of the field.

In 1999, analysis of near- and far-stress fields

in the Barnett determined that new fractures

created during restimulation followed theoriginal fracture plane for a short distance

before taking a new direction.17 Recent micro-

seismic surveys conducted during refracturing

treatments confirm that new fractures propa-

gate initially in the original northeast-southwest

direction before diverging along a new north-

west -southeast azimuth (next page, top).18 In

addition to fracture reorientation, microseismic

mapping, such as StimMAP hydraulic fracture

stimulation diagnostics, also provide evidence of

complex fractures that contribute further to

increased well productivity from the Barnett

Shale (next page, bottom).Infill wells drilled on a spacing as close as

27 acres [109,300 m2] indicated long elliptical

drainage patterns. Refracturing, therefore,

offers significant potential for increased well

productivity and improved gas recovery by creat-

ing new fractures that contact other areas of the

reservoir as a result of fracture reorientation

and creation of complex hydraulic fracture

networks. Restimulations also address

underperformance caused by ineffective well

completionsprimarily early termination of the

initial treatmentbypassed or unstimulated

zones and gradual production damage in thisnaturally fractured formation.

Barnett Shale completions date back to the

1980s, when acid breakdown and fracturing

treatments used high polymer concentrations,

crosslinked-gel fluids and moderate proppant

concentrations with minimal external gel

breaker because of high formation tempera-

tureabout 200F [93C]. Some of the initial

48 Oilfield Review

N

S

EW

Initial fracture azimuth

Initial injection

1st 83 minutes

2nd 83 minutes

3rd 83 minutes

Final 83 minutes

Fracture-induced

surface trough

Fracture

Depth

Surface tiltmeters

Downholetiltmeters inoffset well

> Formation displacement around a vertical hydraulic fracture. Extremelysensitive tiltmeters placed in a radial pattern on the surface around a stimu-lation well candidate (bottom) can monitor fracture azimuth during stimulation

treatments (top). Fracture geometry is inferred by measuring induced rockdeformations. The deformation field, which radiates in all directions, can alsobe measured downhole by wireline-conveyed tiltmeter arrays in offset wells.


12/16

Autumn 2003 49

treatments also included CO2 or N2. Initia

post-treatment production increases were

encouraging, but short-lived. These practice

continued through 1990.

Early treatments yielded poor fracture

conductivity because of damage caused by

incomplete treatment-fluid cleanup and polymer

degradation, and by the fine silica flour used a

a fluid-loss additive, which remained in the

proppant pack. Shorter fracture length resulted

from small treatment volumes. Data from

production logs indicated that some sections o

the Barnett remained untreated or understimu

lated and provided little or no gas production

after initial fracturing treatments.

Gradual completion damage and productivity

degradation potentially result from insufficien

initial fracture length, incomplete treatment

fluid cleanup and relative-permeability

restrictions caused by water influx from lowe

formations. In some wells, there is evidence o

scale deposition when water from incompatible

sources is used in stimulation treatments. Productivity degradation also occurs as reservoir

energy decreases. NODAL production system

analysis indicates that below about 400 Mcf/D

[11,455 m3/d], high fluid levels in the wellbore

restrict gas production. Artificial-lift method

help increase gas output.

After 1990, operators began reducing poly

mer concentrations, using N2 for flowback

assistance, increasing overall fluid and proppan

volumes, and pumping maximum sand concen

trations of three pounds of proppant added

(ppa) per 1000 gal [360 kg of proppant added

(kgpa) per m3]. These changes were in responseto earlier limited well productivity and disap

pointing stimulation results. Engineers increased

the use of external breaker systems, eventually

eliminating N2 and solid fluid-loss additives

such as fine silica flour. Incremental production

from fracture stimulations continued to improve

as a result of these trends in treatment opti

mization, which culminated in the advent o

slick-water treatments in 1997.

Operators also began to focus on improving

post-treatment cleanup. Previous procedure

were conservative, with limited flowback rate

and treatment cleanup periods that lasted 7 to10 days. The new procedures reflected a more

aggressive attempt to force fracture closure and

recover as much treatment fluid as possible in 2

to 3 days.19

The evolution of fracturing practices from

crosslinked gels to slick water and improved

procedures for treatment-fluid recovery signifi

cantly enhanced gas production from the

16. Siebrits E, Elbel JL, Hoover RS, Diyashev IR, Griffin LG,

Demetrius SL, Wright CA, Davidson BM, Steinsberger NPand Hill DG: Refracture Reorientation EnhancesGas Production in Barnett Shale Tight Gas Wells, paperSPE 63030, presented at the SPE Annual TechnicalConference and Exhibition, Dallas, Texas, USA,October 14, 2000.

Fisher MK, Wright CA, Davidson BM, Goodwin AK,Fielder EO, Buckler WS and Steinsberger NP: Inte-grated Fracture Mapping Technologies to OptimizeStimulations in the Barnett Shale, paper SPE 77441,presented at the SPE Annual Technical Conferenceand Exhibition, San Antonio, Texas, USA,September 29October 2, 2002.

Maxwell SC, Urbancic TI, Steinsberger N and Zinno R:

Microseismic Imaging of Hydraulic Fracture Complexityin the Barnett Shale, paper SPE 77440, presented at theSPE Annual Technical Conference and Exhibition, SanAntonio, Texas, USA, September 29October 2, 2002.

17. Siebrits et al, reference 16.

18. Fisher et al, reference 16.

Maxwell et al, reference 16.

19. Willberg DM, Steinsberger N, Hoover R, Card RJ andQueen J: Optimization of Fracture Cleanup UsingFlowback Analysis, paper SPE 39920, presented at

the SPE Rocky Mountain Regional/Low-PermeabilityReservoirs Symposium and Exhibition, Denver, Colorado,USA, April 58, 1998.

Receivers

Reservoir

Offsetwellbore

Wellbore

Microseism

Fracture

> Microseismic fracture mapping. Microseismic imaging relies on detectionof microearthquakes or acoustic emissions associated with hydraulic frac-

turing or induced movement of preexisting fractures. This technique usesthree-component sensors, typically 5 to 12 geophones or accelerometers, inan offset observation well to detect these extremely small events, or micro-seisms. Normally, perforating operations in the well being monitored are used

to calibrate and orient the sensors. As a treatment proceeds, the microseismsgenerated by fracture propagation are detected, oriented and located with

the reservoir to develop a fracture map.

Simple fracture

Complex fractures

Extremely complex fractures

> Complex fracture networks. The simple classi-cal description of a hydraulic fracture is a single,biwing, planar crack with the wellbore at thecenter of the two wings (top). In some formations,however, complex (middle) and very complex(bottom) hydraulic fractures may also develop, asappears to be the case in the naturally fracturedBarnett Shale.


13/16

Barnett Shale. Refracturing with large fluid

volumes and lower volumes of proppant yielded

well productivities that, in some cases, are the

highest ever in these wells (right).

It appears that reduction and eventual elimi-

nation of solids in fracturing fluids generate better

production results in tight-gas formations. Slick-

water tre atments are currently the acc epted

practice for completing new wells and refractur-

ing existing completions in the Barnett Shale. The

reasons for success of this method are not fully

understood and are still under study. One possibil-

ity may be that fracture facies do not heal, or

close, completely once displaced or may be etched

and eroded by large stimulation treatments.

Advanced well logs from tools , such as the

FMI Fullbore Formation MicroImager and DSI

Dipole Shear Sonic Imager tools, used in con-

ju nc ti on wi th stan da rd we ll -l og gi ng su it es

provide more detailed formation evaluation and

reservoir characterization. Stress profiles from

sonic logs assist in design and implementation

of multistage treatments to ensure completezonal stimulation coverage. The higher level of

detail resulted in additional improvement in

Barnett Shale completions, including more accu-

rate perforation placement across intervals with

identified open natural fractures.

A Shallow-Gas Restimulation Program

Enerplus Resources Fund realized an average

sixfold increase in production from refracturing

shallow-gas wells in the Medicine Hat and Milk

River formations of southeastern Alberta,

Canada. These results were obtained in a 15-well

stimulation program during the second half of2002. Ten treatments were performed using the

CoilFRAC stimulation through coiled tubing

service. 20 The CoilFRAC technique utilized a

straddle isolation tool that allowed individual

perforated intervals to be selectively isolated

and stimulated. Jointed pipe and a snubbing

unit were used in place of coiled tubing (CT) on

the other five wells. These CT-conveyed and

snubbing-conveyed stimulations helped optimize

fracture treatments and facilitated completion

and stimulation of bypassed zones.

Initially completed in the 1970s, vertical

wells in the Medicine Hat and Milk River forma-tions produce from depths of 300 to 500 m [984

to 1640 ft]. Producing intervals consist of layered

sandstones with high shale content that fracture

easily. These wells were originally fractured by

pumping fluids and proppants down casing in a

single-stage operation with ball sealers to divert

the treatment across multiple sets of perfora-

tions. To select restimulation candidates,

engineers sought a relationship between initial-

fracture effectiveness and current production.

50 Oilfield Review

1001990 1991 1992 1993 1994 1995 1996

Year

1997 1998 1999 2000 2001 2002 2003

1000

10,000

Gasra

te,

Mcf/month

100,000

Typical Barnett Shalerestimulation results

Refractured

> Typical restimulation results for a Barnett Shale well. The use of substantial volumes of slick waterand low quantities of proppant sand to refracture the Barnett Shale resulted in well productivities asgood as or better than the original completion. In some cases, the well productivities after refracturingwere the highest ever recorded in this field.

T20

R14 R13W4

R14 R13W4

T19

T18

T20

T19

T18

50.8

137.3 310.4 483.5Cumulative gas, MMscf

656.6 829.6

223.9 397.4 570.0 743.1 916.2

> Shallow-gas restimulation criteria. Because pressure-transient testing andanalysis were too expensive and not economically practical for this project,Enerplus Resources Fund chose production data as the best relative indicatorof gradual damage, connectivity and initial stimulation effectiveness. Cumula-

tive gas production data were contoured and color-coded using gas-mappingsoftware. This allowed engineers to easily identify and select refracturingcandidates in areas with lower recovery factors (blue).


14/16

Autumn 2003 51

These wells were completed initially within a

two-year period, so cumulative production is

normalized over 30 years. Analysis indicated

that average production in the first three

months after initial completion was directly

proportional to the 30-year cumulative gas

production. Furthermore, gas rates and stimula-

tion effectiveness are related, so stimulation

effectiveness is directly proportional to cumula-

tive production.

Completions with lower cumulative gas pro-

duction than nearby wells were identified as

candidates for refracturing (previous page, bot-

tom). Other considerations included average

production in the first three months after initial

completion, productive interval lengths, vertical

distance between perforated intervals and cur-

rent production rate. Wells producing at

currently economical rates of more than 25

Mcf/D [716 m3/d] were eliminated as refractur-

ing candidates.

Intervals greater than 7 m [23 ft] were elimi-

nated as CoilFRAC candidates. Snubbing-unitoperations allowed longer straddle-tool isolation

lengths up to about 15 m [49 ft]. Additionally,

because of the risk of fractures growing vertically

into adjacent intervals, intervals closer together

than about 10 m [33 ft] also were eliminated.

The length of individually perforated zones

fractured with coiled tubing varied from 0.9 m to

6.1 m [3 to 20 ft] with four to seven zones

treated in each well. Zones fractured using the

snubbing technique varied from 3 m to 14 m [9.8

to 45.9 ft] in perforated length. The number of

zones treated ranged from two to four zones

per well.Because of the age of these wellbores,

precautions were taken to avoid potential

mechanical failures. Surface casing vent flows

were checked; any indication of gas migration to

surface eliminated the well as a candidate. A

casing scraper was run on all wells to clear the

wellbore of restrict ions and to verify the mini-

mum internal diameter.

Intervals targeted for restimulation were

reperforated to ensure injectivity and improve

treatment effectiveness. Because of a lack of up-

to-date logs, existing intervals were reperforated

at the same depths and lengths as the initial

perforations. Pretreatment well evaluations con-

firmed interval lengths and sand quality from

gamma ray logs. In four wells stimulated through

coiled tubing, additional net-pay intervals were

perforated based on existing logs.

Cumulative production and current produc-

ing rates proved effective in selecting

restimulation candidates. Refracturing resulted

in an average per-well production increase of

about six times the prestimulation rate. Six of

the 15 wells had higher average post-fracture

rates than at the time of initial completion; four

well s produced wi th in 25% of their or ig ina

three-month completion rates in the 1970s

This substantial level of productivity increase

is even more impressive when viewed in the

context of almost 30 years of production and

more than 100 psi [689 kPa] of pressure deple

tion (below).

These results are consistent with documented

evaluations of other CoilFRAC treatment

performed in the area since 1997.21 Ave rage

production from wells fractured through coiled

tubing was slightly higher than treatment

performed with a snubbing unit. This further

confirms that fracturing many small intervals

yields better production rates than fracturing a

few larger intervals. In addition, coiled tubing

conveyed fracturing costs about 10% less than

snubbing-unit treatments.

20. Degenhardt KF, Stevenson J, Gale B, Gonzalez D, Hall S,Marsh J and Zemlak W: Isolate and StimulateIndividual Pay Zones, Oilfield Review 13, no. 3(Autumn 2001): 6077.

21. Lemp S, Zemlak W and McCollum R: An EconomicalShallow-Gas Fracturing Technique Utilizing a CoiledTubing Conduit, paper SPE 46031, presented at theSPE/ICoTA Coiled Tubing Roundtable, Houston, Texas,USA, April 1516, 1998.

Zemlak W, Lemp S and McCollum R: SelectiveHydraulic Fracturing of Multiple Perforated Intervalswith a Coiled Tubing Conduit: A Case History of theUnique Process, Economic Impact and RelatedProduction Improvements, paper SPE 54474, presentedat the SPE/ICoTA Coiled Tubing Roundtable, Houston,Texas, USA, May 2526. 1999.

Marsh J, Zemlak WM and Pipchuk P: EconomicFracturing of Bypassed Pay: A Direct Comparison ofConventional and Coiled Tubing Placement Techniques,paper SPE 60313, presented at the SPE Rocky MountainRegional/Low Permeability Reservoirs Symposium,Denver, Colorado, USA, March 1215, 2000.

140

120

100

Well life

335 psi

450 psi

335 psi

Averageproductionrate,

Mcf/D

80

60

40

20

0

140

120

100

Well life

Pressure depletion over 30 years

335 psi

335 psi

450 psi

Averageproductionrate,

Mcf/D

Production,

MMscf/D

13 newwells

6 new wells Coiled tubing cleanoutof new wells

Two out of fivesnubbing-unitrefractured wellson-line

Last well to be CTfractured (only 10 of

15 wells have beenfractured at this pointand all through CT)

Gas compressorshutdown

80

60

40

20

0

5.0

4.5

4.0

3.5

3.0

2.5

2.0

1.5

1.0

0.5

0.02001 2002

Average production rate for CoilFRAC restimulations

Field production

Average production rate for snubbing-unit restimulations

Pressure depletion over 30 years

Initial Before refracturing After refracturing

> Shallow-gas restimulation results. Refracturing shallow wells in the gas-bearing Medicine Hat andMilk River formations resulted in significant production increases, even after the wells had producedfor more than 30 years. Enerplus Resources Fund used both coiled tubing and snubbing-unit tubing-conveyed stimulation techniques.


15/16

Short Shut-In Time Well-Test Analysis

Determining how a well should respond to

refracturing requires knowledge about the origi-

nal fracturing treatment and the current state of

well stimulationfracture length and conduc-

tivity. Another objective of the 1998 GTI

restimulation project was to develop a well-

testing method to verify restimulation potential

in tight-gas wells.

In low-permeability reservoirs, long shut-in

timessometimes several days, weeks or even

monthsare required to obtain a unique reser-

vo ir an d fr ac tu re ch ar ac te ri za ti on fr om a

pressure-transient well-test analysis, typically a

pressure-buildup test. Consequently, many

operators find the high costs of performing these

tests and associated production downtime unac-

ceptable. However, if the objective is only to

verify that a well requires stimulation, a unique

well-test solution may not be needed.

Schlumberger developed the short shut-in

time interpretation (SSTI) method to obtain

interpretable well-test data in low-permeabilitygas wells.22 This new technique, applicable in

new or depleted reservoirs, uses early-time pres-

sure-transient data to estimate probable ranges

of reservoir permeability and fracture length.

The SSTI method is especially effective in low-

permeability formations, tight-gas reservoirs and

in wells with large wellbore-storage volumes.

This approach is not a quantitative determi-

nation of reservoir properties and stimulation

effectiveness, but it is not entirely qualitative

either. The SSTI method defines lower and

upper values for both reservoir permeability

and fracture length at critical points during awell test. By providing a range of results rather

than multiple sets of nonunique solutions, this

quick and simple determination reduces

uncertainty and nonuniqueness compared with

conventional interpretations.

Reasonably good estimates of reservoir

properties are usually obtained in as little as a

few hours, and generally fewer than three days.

This significantly reduces well-test cost, in

terms of equipment, services and delayed

production. Identifying radial or linear flow into

a well gives a good indication of whether the

current propped fracture is effective or ineffec-tive. The SSTI approach suffers from limitations

in multilayered reservoirs, but engineers can

often use these results to determine if a well

should be restimulated.

The GTI project included a well-testing

program in the Frontier formation of the

North Labarge Unit in Sublette and Lincoln

Counties, Wyoming, USA, to validate restimula-

tion candidates selected by the three GTI

methodsproduction statistics, pattern recog-

nition and type curves. The SSTI method was

applied to determine initial hydraulic fracturing

treatment effectiveness in wells at this test site.

Successful application in several Frontier area

gas wells demonstrated the potential of the SSTI

method, but data quality and acquisition

difficulties hampered complete analysis of the

well-test data.

Interpretations using the SSTI method

require high-quality, precise data. Downhole

measurements with precise electronic gaugesand frequent data sampling help capture the

required level of detail. Downhole shut-in

devices reduce wellbore storage effects and

accelerate the onset of linear flow. Using test

times that fall between the start and end of

linear flow, the SSTI method is also applicable in

conventional well tests.

Production-Enhancement Evaluation

Kerr-McGee Corporation and Schlumberger

began working collaboratively to enhance

production from mature, or brownfield, South

Texas gas properties in March 2002. These

efforts are the result of a comprehensive reser-

voir evaluation performed by Schlumberger to

develop a better understanding of completion

and production trends in the Vicksburg basin.

Initiated in the fall of 2001, this proactive study

concentrated on areas where application of new

technologies and techniques would have themost impact and, in turn, help operators

produce gas more economically.

The objective was to understand how geologi-

cal, petrophysical and well-completion practices

impact well performance. This Vicksburg study

identified underperforming wells and specific

technologies, such as advanced formation-

evaluation tools, improved well-completion

52 Oilfield Review

22. Bastian P: Short Shut-in Well Test Analysis forVerifying Restimulation Potential, presented at theGRI/Restimulation Workshop, Denver, Colorado, USA,March 15, 1999.

Huang H, Bastian PA and Hopkins CW: A New ShortShut-In Time Testing Method for Determining StimulationEffectiveness in Low Permeability Gas Reservoirs,Topical Report, Contract No. 5097-210-4090, GasResearch Institute, Chicago, Illinois, USA(November 2000).

23. Bradley HB: Petroleum Engineering Handbook.Richardson, Texas, USA: Society of Petroleum Engineers(1992): 55-155-12.

Economides MJ and Nolte KG: Reservoir Stimulation,Third Edition, West Sussex, England: John Wiley & SonsLtd. (2000): 5-15-28.

Duda JR, Boyer II CM, Delozier D, Merriam GR,Frantz Jr JH and Zuber MD: Hydraulic Fracturing: TheForgotten Key to Natural Gas Supply, paper SPE 75712,presented at the SPE Gas Technology Symposium,

Calgary, Alberta, Canada, April 30May 2, 2002.24. Pospisil et al, reference 3.

Olson, reference 3.

Wright and Conant, reference 11.

Marquardt MB, van Batenburg D and Belhaouas R:Production Gains from Re-Fracturing Treatments inHassi Messaoud, Algeria, paper SPE 65186, presentedat the SPE European Petroleum Conference, Paris,France, October 2425, 2000.

25. Oberwinkler C and Economides MJ: The DefinitiveIdentification of Candidate Wells for Refracturing,paper SPE 84211, presented at the SPE Annual TechnicalConference and Exhibition, Denver, Colorado, USA,October 58, 2003.

100,000

10,000

10-96 -84 -72 -60 -48 -36 -24

Normalized time, months

-12 0 12 24 36 48 60

100

1000

Totalaverage

gasrate,

Mcf/D

12 wells refractured at time 0

Average during the first month for all12 wells: 6.6 MMcf/D after refracturing

Projected declineafter refracturing

Projected decline had thewells not been refractured

Rate for all 12 wells: 1.5MMcf/D before refracturing

> Kerr-McGee South Texas refracturing results.


16/16

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