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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.
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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.
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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.
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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.
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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.
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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.
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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).
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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.
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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.
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practices and restimulation techniques, whic