Refracturing Works

Refracturing Works

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.

George Dozier Houston, Texas, USA Jack Elbel Consultant Dallas, Texas Eugene Fielder Devon Energy Oklahoma City, Oklahoma, USA René Hoover Fort Worth, Texas Stephen Lemp Calgary, Alberta, Canada Scott Reeves Advanced Resources International Houston, Texas Eduard Siebrits Sugar Land, Texas Del Wisler Kerr-McGee Corporation Houston, Texas Steve Wolhart Pinnacle Technologies Houston, Texas

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The potential benefits of refracturing have intrigued oil and gas operators for more than 50 years. Most intriguing is that, under certain conditions, this technique restores or increases well productivity, often yielding additional 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 of the vast number of existing wells represent significant 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 of restimulations are effective in low-permeability, naturally fractured, laminated and heterogeneous formations, especially gas reservoirs.

If an original fracturing treatment was inadequate 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 conductivity propped fractures that may penetrate deeper into a formation than the initial treatment. 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 also can 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 economic rates. The tendency is not to refracture any wells, or to restimulate only poorly performing wells. This lack of confidence and the negative

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, formerly with Enerplus, Calgary, Alberta, Canada; Stephen Holditch and Valerie Jochen, College Station, Texas; and Jim Troyer, Enerplus, Calgary, Canada.

CoilFRAC, DSI (Dipole Shear Sonic Imager), FMI (Fullbore Formation MicroImager), FracCADE, InterACT, Moving Domain, NODAL, ProCADE and StimMAP are marks of Schlumberger.

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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 restimulations succeed and to improve future treatments based on experience. Quantifying average reservoir pressure, permeability-thickness product, and effective fracture length and conductivity both before and after refracturing allows engineers to determine the reasons for poor well performance before new treatments and the causes of restimulation success or failure.

Autumn 2003

Improved diagnostic techniques, such as short shut-in time well tests, help determine the current stimulation condition of a well and verify refracturing potential. Advances in fracture modeling, design and analysis software also have contributed significantly to restimulation success during the past ten years, as have better candidate selection, innovative stimulation fluids, improved proppants and proppant flowback control.

This article presents results from a twoyear refracturing study and subsequent field trials. We also discuss reasons for restimulation success, including candidate-selection methods and criteria, causes of underperformance in fracture-stimulated wells, formation-stress reorientation and treatment-design considerations.

Recent examples from the USA and Canada demonstrate refracturing implementation and productivity improvement.

1. “International Outlook: World Trends,” World Oil 224, no. 8 (August 2003): 23–25.

2. Niemeyer BL and Reinart MR: “Hydraulic Fracturing of a Moderate Permeability Reservoir, Kuparuk River Unit,” paper SPE 15507, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, USA, October 5–8, 1986.

Pearson CM, Bond AJ, Eck ME and Lynch KW: “Optimal Fracture Stimulation of a Moderate Permeability Reservoir, Kuparuk River Unit, Alaska,” paper SPE 20707, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, USA, September 23–26, 1990.

Reimers DR and Clausen RA: “High-Permeability Fracturing at Prudhoe Bay, Alaska,” paper SPE 22835, presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, USA, October 6–9, 1991.

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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 midcontinent and Texas.

The 1996 GTI work concluded that documented 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, respectively. 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 technology and analysis techniques. The need for this project was underscored by anecdotal observations from the 1996 investigation that 85% of refracturing potential in a given field exists in about 15% of the wells. Identifying these top candidates is crucial to restimulation success.

However, operators often perceive comprehensive field-wide studies to be too costly in terms of money and manpower for companies operating unconventional reservoirs, especially when gas prices are low.

A Multiple-Basin Evaluation Some operators report disappointing results when refracturing previously stimulated wells, despite documented successes in individual wells and several field-wide restimulation 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 evaluation identified significant onshore gas potential—conservatively more than 10 Tcf [286.4 billion m3] of incremental reserves—in the USA, excluding Alaska (below).

These additional gas reserves are located in the Rocky Mountain, Midcontinent, East Texas and South Texas regions, primary in lowpermeability, 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

Michigan

Green River

GS

Denver-Julesburg TGS TGS

San Juan CS, TGS, CBM

CS Hugoton TGS CC Permian Delaware

Conventional sands (CS) Conventional carbonates (CC) Tight-gas sands (TGS) Coalbed methane (CBM) Gas shales (GS)

CC

Appalachian

USA

Piceance TGS

CC

Val Verde TGS

TGS GS

Anadarko Barnett Shale GS

Black Warrior CBM

CS East Texas TGS

South Texas TGS

N

0

400

800

1200

1600 km

0

250

500

750

1000 miles

> Areas with refracturing potential in the USA. The 1996 Gas Technology Institute (GTI) restimulation investigation evaluated a wide range of gas reservoirs, including conventional sandstone and carbonate formations, tight-gas sands, gas shales and coalbed methane deposits. This evaluation focused on conventional gas-producing provinces with cumulative production greater than 5 Tcf [143.2 billion m3] for further evaluation. Higher production implied high numbers of older wells and more refracturing 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 developments, but did not include offshore developments with limited production and recovery information.

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3. Parrot DI and Long MG: “A Case History of Massive Hydraulic Refracturing in the Tight Muddy “J” Formation,” paper SPE 7936, presented at the SPE Symposium on Low-Permeability Gas Reservoirs, Denver, Colorado, USA, May 20–22, 1979.

Conway MW, McMechan DE, McGowen JM, Brown D, Chisholm PT and Venditto JJ: “Expanding Recoverable Reserves Through Refracturing,” paper SPE 14376, presented at the SPE Annual Technical Conference and Exhibition, Las Vegas, Nevada, USA, September 22–25, 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 21–22, 1986.

Olson KE: “A Case Study of Hydraulically Refractured Wells in the Devonian Formation, Crane County, Texas,” paper SPE 22834, presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, USA, October 6–9, 1991.

Fleming ME: “Successful Refracturing in the North Westbrook Unit,” paper SPE 24011, presented at the SPE Permian Basin Oil and Gas Recovery Conference, Midland, Texas, USA, March 18–20, 1992.

Hejl KA: “High-Rate Refracturing: Optimization and Performance in a CO2 Flood,” paper SPE 24346, presented at the SPE Rocky Mountain Regional Meeting, Casper, Wyoming, USA, May 18–21, 1992.

Pospisil G, Lynch KW, Pearson CM and Rugen JA: “Results of a Large-Scale Refracture Stimulation Program, Kuparuk River Unit, Alaska,” paper SPE 24857, presented at the SPE Annual Technical Conference and Exhibition, Washington, DC, USA, October 4–7, 1992.

Hunter JL, Leonard RS, Andrus DG, Tschirhart LR and Daigle JA: “Cotton Valley Production Enhancement Team Points Way to Full Gas Production Potential,” paper SPE 24887, presented at the SPE Annual Technical Conference and Exhibition, Washington, DC, USA, October 4–7, 1992.

Reese JL, Britt LK and Jones JR: “Selecting Economic Refracturing Candidates,” paper SPE 28490, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, USA, September 25–28, 1994.

Fengjiang W, Yunhong D and Yong L: “A Study of Refracturing in Low Permeability Reservoirs,” paper SPE 50912, presented at the SPE International Oil & Gas Conference and Exhibition, Beijing, China, November 2–6, 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 of paired pressure changes and their derivatives generated from analytical solutions of the diffusion equation with strategically defined boundary conditions. Near-well boundary conditions include constant or variable wellbore storage, partial reservoir penetration, composite radial damage or altered permeability, and propped hydraulic fractures. Borehole trajectory can be vertical, angled, or horizontal. Distant boundary conditions include sealing or partially sealing faults, intersecting faults and sealing or constant-pressure rectangular boundaries.

The diffusion equation can be adjusted to accommodate reservoir heterogeneity, such as dual porosity or layering. Commercial software generates type-curve families that account for superposition in time due to flow-rate variations before and even during transient-pressure data acquisition. Automated regression analysis can match acquired data with a specific type curve.

5. Reeves SR, Hill DG, Tiner RL, Bastian PA, Conway MW and Mohaghegh S: “Restimulation of Tight Gas Sand Wells in the Rocky Mountain Region,” paper SPE 55627, presented at the SPE Rocky Mountain Regional Meeting, Gillette, Wyoming, USA, May 15–18, 1999.

Reeves SR, Hill DG, Hopkins CW, Conway MW, Tiner RL and Mohaghegh S: “Restimulation Technology for Tight Gas Sand Wells,” paper SPE 56482, presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, USA, October 3–6, 1999.

Oilfield Review

High Type curves Interpretation requirements

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 technology—specifically neural networks, virtual intelligence and fuzzy logic—and production type curves (right).4 All three methods were used to select restimulation candidates at field locations with at least 200 to 300 wells.5 Three sites in the USA—Green 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

e Tim

and

t cos

se

rea

inc

Virtual intelligence Production statistics

Low Low

Data requirements

High

> Candidate-selection methods. The GTI project developed a methodology for identifying wells with restimulation potential that used production statistics, virtual intelligence and production type curves. By design, these techniques progressed from a simple, nonanalytical statistical approach with minimal data requirements to detailed engineering analyses requiring increasingly comprehensive data.

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 damageremoval treatment. As the project progressed, treatment designs trended away from high-viscosity polymer-base systems to fracturing fluids with lower and lower gel concentrations, or “slick water.” Most treatments

Green River basin GTI site—

East Texas basin GTI site—

Piceance basin GTI site—

Operator: Enron Oil and Gas, now EOG resources.

Operator: Union Pacific Resources Company (UPRC), now Anadarko Petroleum Corporation.

Operator: Barrett Resources, now Williams Company.

Formation: Upper Cretaceous Frontier.

Formation: Cotton Valley.

Formation: Mesaverde group, Upper Cretaceous Williams Fork.

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

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

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

Deposition: Marine sandstones, primarily rivers and streams, or fluvial and distal shore zones.

Deposition: Complex marine sandstones, primarily barrier reef and tidal zone.

Deposition: Marine sandstones, primarily fluvial and marsh, or paludal.

Reservoir: Tight-gas sands with permeability of 0.0005 to 0.1 mD in up to four productive horizons, consisting of as many as eight separate intervals, or benches.

Reservoir: Heterogeneous, highly laminated and compartmentalized tight-gas sands with permeability of 0.05 to 0.2 mD.

Reservoir: Compartmentalized tight-gas sands with permeability of 0.1 to 2 mD. Because of natural fractures, effective permeability is 10 to 50 mD.

Initial completions: One to three stages of a crosslinked guar fluid and nitrogen foam with 100,000 to 500,000 lbm [45,359 to 226,796 kg] of proppant sand.

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

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

GTI restimulations: Three refracturing treatments and one gel-cleanup treatment.

GTI restimulations: Three refracturing treatments.

GTI restimulations: Two refracturing treatments.

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

Autumn 2003

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Site field/basin

Well

Date

Incremental recovery, MMcf

Treatment cost, $

Reserve cost, $/Mcf

Success/ failure

Big Piney and LaBarge/ Green River

GRB 45-12 GRB 27-14 NLB 57-33 WSC 20-09

Jan. 1999 Jan. 1999 Apr. 1999 Jun. 2000

602 (186) 0 302

87,000 87,000 20,000 120,000

0.14 NA NA 0.40

S F F S

Rulison/ Piceance

Langstaff 1 RMV 55-20

Jun. 2000 Jun. 2000

282 75

50,000 70,000

0.18 0.93

S F

Carthage/ East Texas

CGU 15-8 CGU 10-7 CGU 3-8

Nov. 1999 Jan. 2000 Jan. 2000

270 407 1100

100,000 100,000 100,000

0.37 0.25 0.09

S S S

Total

2852

734,000

Average

317

82,000

2864 m3/d

5727 m3/d

0.26 8590 m3/d

11,455 m3/d

450 CGU 3-8 RMV 55-20

Post-restimulation rate, Mcf/D

400

CGU 10-7

CGU 15-8

350 GRB 45-12 300 250 Langstaff 1

200

WSC 20-09 NLB 57-33

150 100 50

GRB 27-14 0 0

50

100

150

200

250

300

350

400

Pre-restimulation rate, Mcf/D

> GTI field-test results. Two of the four wells in the Frontier formation (Green River basin), all three of the wells in the Cotton Valley formation (East Texas basin), and one of the two wells in the Williams Fork formation (Piceance basin) were successful. Of the three unsuccessful treatments, one added incremental 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 fluidize 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.

included nitrogen [N2] or carbon dioxide [CO2] to assist in post-stimulation cleanup, singlestage 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 cost provided an undiscounted cost of incremental reserve additions. Costs for diagnostic tests conducted for research purposes only were not included,

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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 restimulations, 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 wells in low-permeability sands, coalbed methane deposits and gas shales in the 48 contiguous 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 yields 12 Tcf [343.6 billion m 3] of additional reserves from refracturing. Companies operating in the Green River and East Texas formations continued to perform restimulation treatments using knowledge gained from this study.

only actual expenses for treatment implementation. The project team analyzed all nine wells to better understand each candidateselection method.6 The team considered treatments generating incremental 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 incremental reserves at a total cost of $734,000, or an average reserve cost of $0.26/Mcf.

Candidate-Selection Methods Overall, the GTI refracturing tests were successful, 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 worked best 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 reservoir simulation of a hypothetical 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 candidateselection method being studied tended to yield different candidates. And like the 1998 GTI restimulation study, some wells were selected by more than one of the methods. The virtual-intelligence method was generally most effective, followed closely by type curves. With less efficiency than random selections, production statistics alone were the least effective method.

Oilfield Review

Site, field/basin

Top 50 candidate-well ranking Production Virtual statistics intelligence

Success/ failure

Well

Type curves

Big Piney and LaBarge/ Green River

GRB 45-12 GRB 27-14 NLB 57-33 WSC 20-09

S F F S

>50 >50 4 38

*15 *39 *>50 *2

>50 32 20 1

Rulison/ Piceance

Langstaff 1 RMV 55-20

S F

1 43

>50 >50

>50 17

Carthage/ East Texas

CGU 15-8 CGU 3-8 CGU 10-7

S S S

>50 >50 4

>50 >50 26

11 7 40

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

> Candidate-selection performance. Based on the economic criterion of adding incremental reserves at less than $0.5/Mcf, the GTI study evaluated the capability of each candidate-selection method to correctly select successful refracturing candidates or to not select unsuccessful candidates. This determination was based on whether each method ranked a well among the top 50 candidates or not. The three methods—production statistics, virtual intelligence and pattern recognition, and type curves—identified 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 of the five successful treatments and none of the three unsuccessful wells.

Production statistics

Virtual intelligence

14 15 7

50 10

5 103 89

1

45

53

49 4 93 71

52

120

83

Type curves

6. Ely JW, Tiner R, Rothenberg M, Krupa A, McDougal F, Conway M and Reeves S: “Restimulation Program Finds Success in Enhancing Recoverable Reserves,” paper SPE 63241, presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, USA, October 1–4, 2000.

7. Reeves SR, Bastian PA, Spivey JP, Flumerfelt RW, Mohaghegh S and Koperna GJ: “Benchmarking of Restimulation Candidate Selection Techniques in Layered, Tight Gas Sand Formations Using Reservoir Simulation,” paper SPE 63096, presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, USA, October 1–4, 2000.

Autumn 2003

< Candidate selection from the GTI reservoir-simulation study. The top 18 refracturing candidates represent 15% of the wells from the reservoir stimulation. Virtual intelligence independently selected 10 of the 13 true candidate wells, the most of any method. These 10 wells consisted of five that were uniquely selected by virtual intelligence, one well that was also selected by production statistics, two wells that were also selected by type curves, and two wells that were selected by all three techniques. The type-curve method added three true candidate wells to the combined selections, making the combined number of correct selections between the virtual intelligence and type-curve methods 13 out of 13. In practice, however, no one knows in advance which wells are true candidates.

8. Emrich C, Shaw D, Reasoner S and Ponto D: “Codell Restimulations Evolve to 200% Rate of Return,” paper SPE 67211, presented at the SPE Production and Operations Symposium, Oklahoma City, Oklahoma, USA, March 24–27, 2001.

Shaefer MT and Lytle DM: “Fracturing Fluid Evolution Plays a Major Role in Codell Refracturing Success,” paper SPE 71044, presented at the SPE Rocky Mountain Petroleum Technology Conference, Keystone, Colorado, USA, May 21–23, 2001.

Sencenbaugh RN, Lytle DM, Birmingham TJ, Simmons JC and Shaefer MT: “Restimulating Tight Gas Sand: Case Study of the Codell Formation,” paper SPE 71045, presented at the SPE Rocky Mountain Petroleum Technology Conference, Keystone, Colorado, USA, May 21–23, 2001.

The first stage of the 1998 GTI study and results from this simulation provided valuable insights into the effectiveness of each candidateselection 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 overall project objective, participants in the 1998 GTI study sought a field with a history of restimulation activity and results. With an existing dataset, the approach used for the simulator 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 economically successful.8 Patina Oil & Gas Corporation, a leading operator 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 disclosing beforehand those wells that had actually responded favorably to restimulation. Afterward, candidate selections were compared with actual well performance. This approach allowed the effectiveness of each method to be assessed.

Candidate selection using actual Wattenburg field 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 curves are useful for selecting restimulation candidates; production statistics are less effective.

Virtual intelligence and other patternrecognition techniques, which use prior refracturing data and results to “learn” from, can further improve candidate selection and restimulation success. The GTI field trials, reservoir simulation and Wattenburg field evaluation confirmed that the performance of each candidate-selection method appeared to be reservoir specific (bottom left).

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Analysis of production statistics tends to identify completions that underperform compared with offset wells. Substandard performance 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 wells that have less than optimal original completions or stimulation procedures. Patternrecognition technologies should be applied when reservoir, completion and stimulation complexity is high.

Type curves tend to identify candidate wells based solely on incremental production potential, 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 primarily targeted underperforming wells and completions that screened out prematurely or

had mechanical failures during the initial stimulation. 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 illite 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 overpressured with a gradient of about 0.6 psi/ft [13.5 kPa/m]. Bottomhole temperature is 230 to 250°F [110 to 121°C]. Wells are drilled on a 40-acre [162,000-m2] spacing.

During 1998, Patina compiled a database of 250 fracture restimulations on both operated and nonoperated properties. After eliminating wells treated with borate crosslinked fluids, which were 20% less productive than other wells, company engineers focused on the remaining 200 wells. These wells had been restimulated 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 production after refracturing. Two technical

improvements from this field-wide evaluation provided an order-of-magnitude improvement in restimulation results.

The first was application of carboxymethylate guar (CMG) fluids with lower polymer loadings, which maintain proppant transport and minimize residual proppant-pack damage from unbroken and unrecovered gel. Nondamaging fluids are particularly important in the refracturing of low-permeability formations where long-term gas saturation has been established and reservoir pressure may be depleted.

The second improvement was a candidateselection method developed by Patina that uses historical restimulation results in the basin.

Together with CMG fluids, this statistically based algorithm achieved significant improvements 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 initial production 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 refracturing density increases. The overall success of this program resulted from stringent well-selection criteria, strict quality-control

2500

Peak production, BOE/well/month

Development and application of genetic algorithm for candidate selection 2000

1500

1000 Patina 500 Others CMG fluids 0 1997

1998

1999

2000

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

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Oilfield Review

Description

Statistical significance

Rank

Parameter

1

Hydrocarbon volume, porosity-feet

Net pay for Codell above a 10% density porosity cutoff

38%

2

Cumulative recovery factor

Cumulative gas recovered divided by original gas in place (OGIP) for 40-acre drainage area

17%

3

Initial completion

Peak rate premium assigned if well was originally completed limited entry in Codell-Niobrara

9%

4

Estimated ultimate recovery (EUR) factor

EUR divided by OGIP for 40-acre drainage area

11%

5

Gas/oil ratio

Projected ultimate gas/oil ratio

20%

6

Maximum differential recovery, million BOE

EUR difference between subject well and best offset well within one mile of subject well

5%

> Patina Oil & Gas statistical algorithm. Of the five statistically significant variables of the candidate-selection algorithm for Wattenburg field, “hydrocarbon volume” in porosity-feet represents reservoir quality, “initial completion” represents the initial completion, and the other three—“cumulative recovery factor,” “estimated ultimate recovery factor” and “gas/oil ratio”—represent well performance. Well location is not significant because of the relatively uniform reservoir quality. However, higher, and therefore better, gas/oil ratios do tend to occur in the center of the field. The sixth variable “maximum differential recovery” in BOE helps predict restimulation potential for economic evaluations.

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 restimulation. Patina engineers continue to expand their already extensive refracturing database and finetune 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,” was added 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

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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 permeability to gas because formation thickness and reservoir permeability are relatively uniform across the field.

Well completions that used limited-entry 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 whether new hydraulic fractures might reorient with respect to the original propped fracture (see “Fracture Reorientation,” page 47).

The maximum differential BOE is the difference 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 variables, 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 projections 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 production 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 result 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.10 The fundamental objective of refracturing is to enhance well productivity. However, restimulation is viable only if wells are underperforming because of completion-related problems, not because of poor reservoir quality. Neither fracturing nor refracturing can turn marginal 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.

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 to Condensation,” paper SPE 30767, presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, USA, October 22–25, 1995.

45

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

Gradual formation damage during production . Scale and fines . Workover frequency . Well age

Well underperformance

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

> Potential causes of underperformance in previously stimulated wells. The GTI restimulation project team established a classification framework to help diagnose problems in hydraulically fractured wells that perform below operator expectations. At the highest level, there are three broad categories: ineffective or problematic initial completions, gradual production damage and advances in technology or evolving techniques compared with past practices.

Completion-Related Underperformance To aid in problem diagnosis, the 1998 GTI project established a framework to classify well-performance problems (above). For tightgas wells, three specific problems, ranked in order of highest perceived restimulation potential were identified: • Unstimulated or bypassed pay • Insufficient fracture conductivity • Insufficient fracture length.

Ineffective or problematic initial completions are the most common type of problem.

Examples include lack of quality control during initial fracture treatments, residual polymer damage from stimulation fluids, inappropriate proppant selection, premature screenout, underdesigned 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 embedding in the formation and plugging of the pack by formation fines or scale deposition. Proppant flowback 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 refracturing. In older wells that have a higher occurrence of these problems, reservoir pressure must be sufficient to justify refracturing, both in terms of

46

remaining reserves and adequate flowback of treatment fluids. Well age may be the best indicator 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 productivity has deteriorated over time.

A third category, advances in completion and stimulation technology, also provides opportunities 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 of productivity 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 treatment. 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 productivity from stimulation of new zones almost always represents an incremental reserve addition, not just an increase in production rate and accelerated reserve recovery.

A low ratio of fracture-treatment stages and proppant volume to the number and distribution 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 concentrations 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 restimulation achieves additional fracture length and expands the drainage area of a well, incremental production 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 diagnose 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 production provided 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.

Oilfield Review

In addition, depletion of pay intervals increases the stress contrast between pay intervals and bounding shales, which improves vertical containment and allows generation of longer fractures. Alteration of horizontal in-situ stress around a wellbore and an existing fracture also may contribute to fracture reorientation 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 fractured wells, especially tight-gas wells, that still exhibit linear flow—a negative 0.5 slope on log-log production-rate plots indicative of deeply penetrating, highly conductive fractures. Production tests and history matching using a numerical simulator that accommodated orthogonal fractures and horizontal permeability anisotropy indicate a strong probability of refracture 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 production, 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 fracture orientation in the reservoir volume between injectors 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 penetrating, 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 further depletion. 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 horizontal permeability anisotropy.14

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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 reorientation 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 component. If these induced stress changes overcome the original stress differential, then a new fracture will initiate and propagate along a different

azimuthal plane than the initial fracture until it reaches the boundary of the elliptical stressreversal region. The fracture may continue along the new azimuth for some distance beyond this point, depending on formation toughness.

Many factors contribute to the location of the stress-reversal boundary, including production history, reservoir permeability, fracture dimensions, pay-zone height, elastic properties of the pay and bounding barrier zones, and the initial horizontal stress contrast. These parameters 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 initial fractures in low-permeability formations have a longer time window. Production shut-in periods

y New fracture Isotropic point Stress-reversal region Maximum horizontal stress

Wellbore x

Initial fracture Isotropic point

New fracture

Minimum horizontal stress

> Stress reorientation and orthogonal fracture extension. This horizontal section through a vertical wellbore depicts an original hydraulic fracture in the “x” direction and a second reoriented fracture in the “y” direction. Fluid production after placement of the initial fracture can cause a local redistribution of pore pressure in an expanding elliptical region around the wellbore and initial fracture. The stress-reversal boundary is defined by isotropic points of equal primary horizontal stresses. Stress reorientation and fracture extension in a direction away from the initial propped fracture help explain pressure responses during refracturing treatments and unanticipated production increases from refractured wells known to have effective initial fractures.

11. Wright CA, Stewart DW, Emanuel MA and Wright WW: “Reorientation of Propped Refracture Treatments in the Lost Hills Field,” paper SPE 27896, presented at the SPE Western Regional Meeting, Long Beach, California, USA, March 23–25, 1994.

Wright CA, Conant RA, Stewart DW and Byerly PM: “Reorientation of Propped Refracture Treatments,” paper SPE 28078, presented at the SPE/ISRM Rock Mechanics in Petroleum Engineering Conference, Delft, The Netherlands, August 29–31, 1994.

Wright CA and Conant RA: “Hydraulic Fracture Reorientation in Primary and Secondary Recovery from Low-Permeability Reservoirs,” paper SPE 30484, presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, USA, October 22–25, 1995.

12. Bruno MS and Nakagawa FM: “Pore Pressure Influence on Tensile Propagation in Sedimentary Rock,” International Journal of Rock Mechanics and Mining Sciences and Geomechanics Abstracts 28, no. 4 (July 1991): 261–273.

13. Elbel JL and Mack MG: “Refracturing: Observations and Theories,” paper SPE 25464, presented at the SPE Production Operations Symposium, Oklahoma City, Oklahoma, USA, March 21–23, 1993.

14. Hidayati DT, Chen H-Y and Teufel LW: “Flow-Induced Stress Reorientation in a Multiple-Well Reservoir,” paper SPE 71091, presented at the SPE Rocky Mountain Petroleum Technology Conference, Keystone, Colorado, USA, May 21–23, 2001.

15. Siebrits E, Elbel JL, Detournay F, Detournay-Piette C, Christianson M, Robinson BM and Diyashev IR: “Parameters Affecting Azimuth and Length of a Secondary Fracture During a Refracture Treatment,” paper SPE 48928, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, USA, September 27–30, 1998.

47

should be minimized to maintain a high porepressure gradient normal to the initial fracture.

Aside from this, standard fracture design considerations should be used.

Fracture restimulations in the naturally fractured 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 fracture 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 concentrations in treatment fluids—currently only surfactant-base friction-reducing agents are used—and 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 stimulation 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 thousands of wells.

N

Initial fracture azimuth W

E Initial injection 1st 83 minutes 2nd 83 minutes 3rd 83 minutes Final 83 minutes S

Fracture-induced surface trough

Depth

Surface tiltmeters

Fracture

Downhole tiltmeters in offset well

> Formation displacement around a vertical hydraulic fracture. Extremely sensitive tiltmeters placed in a radial pattern on the surface around a stimulation well candidate (bottom) can monitor fracture azimuth during stimulation treatments (top). Fracture geometry is inferred by measuring induced rock deformations. The deformation field, which radiates in all directions, can also be measured downhole by wireline-conveyed tiltmeter arrays in offset wells.

48

Deposited in a deep marine environment, the Barnett Shale consists of layered mudstone, siltstone 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 the original fracture plane for a short distance before taking a new direction.17 Recent microseismic surveys conducted during refracturing treatments confirm that new fractures propagate initially in the original northeast-southwest direction before diverging along a new northwest-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 creating 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 completions—primarily early termination of the initial treatment—bypassed or unstimulated zones and gradual production damage in this naturally 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 temperature—about 200°F [93°C]. Some of the initial

Oilfield Review

Microseism

Receivers

Reservoir Fracture Wellbore

Offset wellbore

> Microseismic fracture mapping. Microseismic imaging relies on detection of microearthquakes or acoustic emissions associated with hydraulic fracturing or induced movement of preexisting fractures. This technique uses three-component sensors, typically 5 to 12 geophones or accelerometers, in an offset observation well to detect these extremely small events, or microseisms. Normally, perforating operations in the well being monitored are used to calibrate and orient the sensors. As a treatment proceeds, the microseisms generated 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 classical description of a hydraulic fracture is a single, biwing, planar crack with the wellbore at the center of the two wings (top). In some formations, however, complex (middle) and very complex (bottom) hydraulic fractures may also develop, as appears to be the case in the naturally fractured Barnett Shale.

16. Siebrits E, Elbel JL, Hoover RS, Diyashev IR, Griffin LG, Demetrius SL, Wright CA, Davidson BM, Steinsberger NP and Hill DG: “Refracture Reorientation Enhances Gas Production in Barnett Shale Tight Gas Wells,” paper SPE 63030, presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, USA, October 1–4, 2000.

Fisher MK, Wright CA, Davidson BM, Goodwin AK, Fielder EO, Buckler WS and Steinsberger NP: “Integrated Fracture Mapping Technologies to Optimize Stimulations in the Barnett Shale,” paper SPE 77441, presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, September 29–October 2, 2002.

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Maxwell SC, Urbancic TI, Steinsberger N and Zinno R: “Microseismic Imaging of Hydraulic Fracture Complexity in the Barnett Shale,” paper SPE 77440, presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, September 29–October 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 and Queen J: “Optimization of Fracture Cleanup Using Flowback Analysis,” paper SPE 39920, presented at the SPE Rocky Mountain Regional/Low-Permeability Reservoirs Symposium and Exhibition, Denver, Colorado, USA, April 5–8, 1998.

treatments also included CO 2 or N 2 . Initial post-treatment production increases were encouraging, but short-lived. These practices 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 as 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 of the Barnett remained untreated or understimulated and provided little or no gas production after initial fracturing treatments.

Gradual completion damage and productivity degradation potentially result from insufficient initial fracture length, incomplete treatmentfluid cleanup and relative-permeability restrictions caused by water influx from lower formations. In some wells, there is evidence of 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 methods help increase gas output.

After 1990, operators began reducing polymer concentrations, using N 2 for flowback assistance, increasing overall fluid and proppant volumes, and pumping maximum sand concentrations of three pounds of proppant added (ppa) per 1000 gal [360 kg of proppant added (kgpa) per m3]. These changes were in response to earlier limited well productivity and disappointing stimulation results. Engineers increased the use of external breaker systems, eventually eliminating N 2 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 optimization, which culminated in the advent of slick-water treatments in 1997.

Operators also began to focus on improving post-treatment cleanup. Previous procedures were conservative, with limited flowback rates and treatment cleanup periods that lasted 7 to 10 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 significantly enhanced gas production from the

49

100,000

Typical Barnett Shale restimulation results Gas rate, Mcf/month

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 elimination of solids in fracturing fluids generate better production results in tight-gas formations. Slickwater treatments are currently the accepted practice for completing new wells and refracturing existing completions in the Barnett Shale. The reasons for success of this method are not fully understood and are still under study. One possibility 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 conjunction with standard well-logging suites provide more detailed formation evaluation and reservoir characterization. Stress profiles from sonic logs assist in design and implementation of multistage treatments to ensure complete zonal stimulation coverage. The higher level of detail resulted in additional improvement in Barnett Shale completions, including more accurate perforation placement across intervals with identified open natural fractures.

10,000 Refractured

1000

100 1990

1991

1992

1993

1994

1995

1996 1997 Year

50

1999

2000

2001

2002

2003

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

R14

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 of 2002. 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 formations 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 perforations. To select restimulation candidates, engineers sought a relationship between initialfracture effectiveness and current production.

1998

R13W4

50.8

223.9

137.3

T20

397.4

570.0

743.1

310.4 483.5 656.6 Cumulative gas, MMscf

916.2

829.6

T20

T19

T19

T18

T18

R14

R13W4

> Shallow-gas restimulation criteria. Because pressure-transient testing and analysis were too expensive and not economically practical for this project, Enerplus Resources Fund chose production data as the best relative indicator of gradual damage, connectivity and initial stimulation effectiveness. Cumulative gas production data were contoured and color-coded using gas-mapping software. This allowed engineers to easily identify and select refracturing candidates in areas with lower recovery factors (blue).

Oilfield Review

casing scraper was run on all wells to clear the wellbore of restrictions and to verify the minimum internal diameter.

Intervals targeted for restimulation were reperforated to ensure injectivity and improve treatment effectiveness. Because of a lack of upto-date logs, existing intervals were reperforated at the same depths and lengths as the initial perforations. Pretreatment well evaluations confirmed 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 producing 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 wells produced within 25% of their original 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 depletion (below).

These results are consistent with documented evaluations of other CoilFRAC treatments performed in the area since 1997. 21 Average production from wells fractured through coiled tubing was slightly higher than treatments 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 tubingconveyed fracturing costs about 10% less than snubbing-unit treatments.

Average production rate for CoilFRAC restimulations

Average production rate for snubbing-unit restimulations 140

450 psi

120

335 psi

100

Pressure depletion over 30 years

80 60 40

335 psi

20

Average production rate, Mcf/D

140

Average production rate, Mcf/D

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 stimulation effectiveness are related, so stimulation effectiveness is directly proportional to cumulative production.

Completions with lower cumulative gas production than nearby wells were identified as candidates for refracturing (previous page, bottom). Other considerations included average production in the first three months after initial completion, productive interval lengths, vertical distance between perforated intervals and current production rate. Wells producing at currently economical rates of more than 25 Mcf/D [716 m3/d] were eliminated as refracturing candidates.

Intervals greater than 7 m [23 ft] were eliminated as CoilFRAC candidates. Snubbing-unit operations 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

0

120

450 psi 335 psi

100

Pressure depletion over 30 years

80 60 40

335 psi

20 0

Well life Initial

Well life Before refracturing

After refracturing

Field production 5.0 6 new wells

4.5

Coiled tubing cleanout of new wells

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Production, MMscf/D

4.0 20. Degenhardt KF, Stevenson J, Gale B, Gonzalez D, Hall S, Marsh J and Zemlak W: “Isolate and Stimulate Individual Pay Zones,” Oilfield Review 13, no. 3 (Autumn 2001): 60–77.

21. Lemp S, Zemlak W and McCollum R: “An Economical Shallow-Gas Fracturing Technique Utilizing a Coiled Tubing Conduit,” paper SPE 46031, presented at the SPE/ICoTA Coiled Tubing Roundtable, Houston, Texas, USA, April 15–16, 1998.

Zemlak W, Lemp S and McCollum R: “Selective Hydraulic Fracturing of Multiple Perforated Intervals with a Coiled Tubing Conduit: A Case History of the Unique Process, Economic Impact and Related Production Improvements,” paper SPE 54474, presented at the SPE/ICoTA Coiled Tubing Roundtable, Houston, Texas, USA, May 25–26. 1999.

Marsh J, Zemlak WM and Pipchuk P: “Economic Fracturing of Bypassed Pay: A Direct Comparison of Conventional and Coiled Tubing Placement Techniques,” paper SPE 60313, presented at the SPE Rocky Mountain Regional/Low Permeability Reservoirs Symposium, Denver, Colorado, USA, March 12–15, 2000.

Two out of five snubbing-unit refractured wells on-line

3.5 3.0

13 new wells

2.5 2.0 Last well to be CT fractured (only 10 of 15 wells have been fractured at this point and all through CT)

1.5 1.0 Gas compressor shutdown

0.5 0.0 2001

2002

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

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52

100,000 Average during the first month for all 12 wells: 6.6 MMcf/D after refracturing Projected decline after refracturing

10,000

Total average gas rate, Mcf/D

Short Shut-In Time Well-Test Analysis Determining how a well should respond to refracturing requires knowledge about the original fracturing treatment and the current state of well stimulation—fracture length and conductivity. Another objective of the 1998 GTI restimulation project was to develop a welltesting method to verify restimulation potential in tight-gas wells.

In low-permeability reservoirs, long shut-in times—sometimes several days, weeks or even months—are required to obtain a unique reservoir and fracture characterization from 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 unacceptable. 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-permeability gas wells.22 This new technique, applicable in new or depleted reservoirs, uses early-time pressure-transient data to estimate probable ranges of reservoir permeability and fracture length.

The SSTI method is especially effective in lowpermeability formations, tight-gas reservoirs and in wells with large wellbore-storage volumes.

This approach is not a quantitative determination 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 a well 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 ineffective. 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 restimulation candidates selected by the three GTI

1000 Rate for all 12 wells: 1.5 MMcf/D before refracturing Projected decline had the wells not been refractured 100

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> Kerr-McGee South Texas refracturing results.

methods—production statistics, pattern recognition 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 gauges and 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 reservoir 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 the most impact and, in turn, help operators produce gas more economically.

The objective was to understand how geological, petrophysical and well-completion practices impact well performance. This Vicksburg study identified underperforming wells and specific technologies, such as advanced formationevaluation tools, improved well-completion

22. Bastian P: “Short Shut-in Well Test Analysis for Verifying Restimulation Potential,” presented at the GRI/Restimulation Workshop, Denver, Colorado, USA, March 15, 1999.

Huang H, Bastian PA and Hopkins CW: “A New Short Shut-In Time Testing Method for Determining Stimulation Effectiveness in Low Permeability Gas Reservoirs,” Topical Report, Contract No. 5097-210-4090, Gas Research Institute, Chicago, Illinois, USA (November 2000).

23. Bradley HB: Petroleum Engineering Handbook.

Richardson, Texas, USA: Society of Petroleum Engineers (1992): 55-1–55-12.

Economides MJ and Nolte KG: Reservoir Stimulation, Third Edition, West Sussex, England: John Wiley & Sons Ltd. (2000): 5-1–5-28.

Duda JR, Boyer II CM, Delozier D, Merriam GR, Frantz Jr JH and Zuber MD: “Hydraulic Fracturing: The Forgotten Key to Natural Gas Supply,” paper SPE 75712, presented at the SPE Gas Technology Symposium, Calgary, Alberta, Canada, April 30–May 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 in Hassi Messaoud, Algeria,” paper SPE 65186, presented at the SPE European Petroleum Conference, Paris, France, October 24–25, 2000.

25. Oberwinkler C and Economides MJ: “The Definitive Identification of Candidate Wells for Refracturing,” paper SPE 84211, presented at the SPE Annual Technical Conference and Exhibition, Denver, Colorado, USA, October 5–8, 2003.

Oilfield Review

practices and restimulation techniques, which could have the most impact on well productivity.

The study team gathered and interpreted key information, including well logs and data related to fracture stimulation practices. They then combined elements of both routine and advanced proprietary processes into an integrated workflow that identified numerous refracture opportunities.

Key elements of this workflow included the Moving Domain technique for rapid assessment of producing properties, development of a specific petrophysical model to identify bypassed gas zones and techniques to assess and mitigate risk. Moving Domain analysis provides a statistically based analysis of production data to identify areas with potential for infill development, recompletion and restimulation.

As a result of the project team’s efforts, Kerr-McGee refractured 12 wells during 2002.

Initially, this refracturing campaign added 5.5 Bcf [157.5 million m3] of incremental recoverable gas reserves (previous page). This equates to $600,000 of revenue per month at $4/Mcf gas, which increased Kerr-McGee gross cash flow by an estimated $8.5 million in 2002.

To date, the program has been even more successful in 2003 with an additional 3.6 Bcf [103.1 million m3] of recoverable gas for the first four wells alone. From 2002 to 2003, development costs also were reduced by more than 40% through improved risk assessment and mitigation.

Schlumberger works with Kerr-McGee across several geographic locations to facilitate project execution. Results from the work performed on each well are published in an Informed Decision Report (IDR) that includes reservoir properties derived from the Vicksburg-specific petrophysical model, FracCADE fracturing design and analysis software, ProCADE well analysis software rate predictions and key production characteristics from the Moving Domain analysis.

These results are then posted electronically using InterACT real-time monitoring and data delivery and made available to Schlumberger and Kerr-McGee staff participating in the project.

Current teleconference capabilities and collaboration tools, such as InterACT software that allows review and evaluation of project results as they become available, facilitate this interaction and collaboration by the project team.

A Schlumberger project manager located in the Kerr-McGee office coordinates operations that range from initial diagnostic work— pressure-buildup tests and production logs—to actual refracturing designs, execution, real-time monitoring and post-treatment evaluations.

Autumn 2003

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> Refracturing economics. In shallow-gas wells like those in the Medicine Hat and Milk River formations of southeastern Alberta, Canada, restimulating existing wells costs less (left) and provides incremental production at a lower unit cost (right) than drilling and completing new wells. To some greater degree, the same holds true for currently producing wells in many other fields, especially those in deeper low-permeability reservoirs.

Recognizing the value of a collaborative relationship with Schlumberger, including an extended staff of experts for the duration of a project, Kerr-McGee recently identified other brownfield opportunities for joint evaluation.

Restimulations Work With world demand for petroleum growing daily, well restimulations are increasingly important.

High productivity improvements for a relatively low investment make hydraulic fracturing, either as initial treatments or restimulations, one of the most economically attractive production-enhancement techniques.23 Fracture stimulation during initial completion or later in the life of a well bypasses near-wellbore damage and increases connectivity with the reservoir. The practice of refracturing began soon after the introduction of hydraulic fracturing in about 1947, but early applications required considerable effort to diagnose problems and select well candidates, and yielded mixed results. From the 1996 and 1998 GTI studies and associated field trials to continuing restimulation success in North America and other areas, including China, Algeria, Brazil and Russia, it is clear that significant refracturing potential exists worldwide, even in mature oil fields.24 In many cases, refracturing is much less expensive than a new development well and can inexpensively supplement infill drilling, especially in deep, low-permeability reservoirs. This is clearly evident even in the shallow-gas wells of Canada (above). However, restimulation economics are most sensitive to proper candidate selection. Relatively minor miscalculations can

turn a potentially profitable project into an unsuccessful venture.

Basically, refracturing candidates are selected the same way as initial fracturing candidates, except there may be considerably more data to work with. Several emerging methodologies, including multidimensional crossplots and self-organizing maps, offer operators large databases that contain hundreds of different wells, input parameters and fracturing criteria.

In general, these techniques fall into the category of data mining and knowledge discovery.25 Schlumberger also continues to develop and refine methods for selecting fracturing candidates. Using Moving Domain analysis, for example, Schlumberger is evaluating ways to use offset-well production histories as a means of selecting high-potential refracturing candidates.

When applied judiciously, refracturing has proved effective for capturing incremental reserves and the financial benefits they represent, particularly in today’s challenging business climate. These types of well restimulations are a viable and economically attractive means of improving economic returns for operators willing to apply new methods and technologies related to candidate selection and treatment design.

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