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`SPE 116124
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`Case History of Sequential and Simultaneous Fracturing of the Barnett
`Shale in Parker County
` N Mutalik, and Bob Gibson, Williams Companies, Tulsa
`
` P
`
`
`
`Copyright 2008, Society of Petroleum Engineers
`
`This paper was prepared for presentation at the 2008 SPE Annual Technical Conference and Exhibition held in Denver, Colorado, USA, 21–24 September 2008.
`
`This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been
`reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its
`officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to
`reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
`
`
`Abstract
`
`Since 2005, Williams Production Gulf Coast Company
`has drilled over 100 horizontal wells in the Barnett Shale.
`The Barnett Shale is an unconventional gas reservoir that
`encompasses a nineteen county area in the Fort Worth
`Basin. Slick-water fracturing is the primary technique
`that has been used to hydraulically fracture the wells.
`
`Recently, Williams as well as several operators have tried
`fracturing two or more adjacent wells simultaneously with
`the goal of exposing the shale to more pressure and
`produce a more complex web of fractures, thereby
`improving the initial rates and reserves. Simultaneous
`fracturing or simo-frac technique is expensive and
`requires much more planning, coordination and logistics
`as well as a larger surface location.
`
`the case history of sequential and
`this paper,
`In
`simultaneous fracturing of four similarly drilled and
`completed horizontal azimuth wells in Eastern Parker
`County, is discussed. All the four wells where stimulated
`with
`near
`identical
`fracture
`treatments.
`The
`sequentially/simultaneously fractured wells resulted in IPs
`of 3.3 MMscfd to 3.5 MMscfd with 30-day averages
`ranging from 2.1 MMscfd to 2.9 MMscfd. The 4th well
`was a single offset horizontal well drilled with effective
`lateral 2400 ft less than a quarter mile to the north but had
`significantly lower IP of 2.3 MMscfd and 30-day average
`production of 1.2 MMscfd. The initial comparative test
`results are very encouraging and indicate a more complex
`fracture network being created in the vicinity of the
`sequentially/simultaneously fractured wells, which results
`in a significantly improved well performance.
`
`the benefit of
`evaluate
`to
`continues
`Williams
`simultaneous fracturing and has done more simo-frac jobs
`in other counties with good results. As in this case
`history, due to surface and lease constraints, many of the
`simo-frac jobs are being done in wells that are drilled
`
`from the same dual pad and have well spacing of the
`order of 500 ft to 700 ft. The paper also provides an
`analysis of the simultaneous fracturing jobs done to date
`in Parker and Johnson County.
`
`Background
`
`The Barnett Shale has evolved into the pre-eminent shale-
`gas resource plays in the US and is now considered by
`many as the largest onshore natural gas field in the United
`States. The productive part of the formation is estimated
`to stretch an area covering 5000 square miles,
`encompassing 19 counties (Figure 1). According to the
`latest figures from
`the Texas Railroad Commision
`published in June 2008, there are more than 7700
`producing wells and 185 active operators in the Barnett
`Shale with permits for more than 4,500 additional wells.
`Production from Barnett Shale currently exceeds 3.7
`Bcf/d, accounting for more than 15% of Texas gas
`production, and more than 3.8 Tcf of gas has been
`produced from the Barnett Shale since 20001.
`
`Simultaneous fracturing (simo-fracs) of paired offset
`wells is one of the recent trends in Barnett fracturing and
`is being increasingly used by many operators. In this
`technique, two or more adjacent wells that are roughly
`parallel to each other, are fractured simultaneously. The
`goal is to expose the shale to more pressure and produce a
`more complex, “three-dimensional web” of fractures by
`increasing the density of the hydraulic fracture network
`and increasing the surface area created by the frac job.
`The drainage area of each of the wells is enhanced as the
`frac fluid is pushed into the space between the two wells
`that would not have been fractured if the operator had
`drilled only well 2-3.
`
`Simo-fracs are expensive and require much more co-
`ordination and logistics and a larger location. At the same
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`IWS EXHIBIT 1049
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`Successive stimulations of a multi-stage treatment often
`show a significant influence of the prior stage, including
`potential charging of the reservoir. The fluid from the
`prior stage remains at a somewhat elevated pressure,
`pushing subsequent stages away due to increased stress
`generated by the volume of pressurized fluid 4. In
`general, reactivation of existing fracture networks is
`thought to be less beneficial than creating new fracture
`networks 5. The production data from the 3 wells appears
`to indicate that simo-fracing results in more enhanced
`fracture network and production gains compared to
`sequential fracturing. This aspect needs to be further
`understood and more data is needed to validate this
`inference.
`
`the
`the IPs of
`Table 1 shows a comparison of
`simo/sequentially fraced wells versus the stand-alone well
`D. A comparison of average IP based on first 30-day
`production of the wells shows a four fold improvement
`due to sequential and simo-fracing (Table 1). Based on
`IP/linear ft of lateral drilled, the simo-fraced wells
`showed a five fold improvement.
`
`Well
`
`Actual
`Lateral
`ft
`
`30 Day
`Avg Act.
`Mcfd
`
`IP/Lateral
`Length
`Mcfd/ft
`
`Current
`Rate
`Mcfd
`
`Well A
`(Sequential Frac)
`Well B
`(Simo Frac)
`Well C
`(Simo Frac-infill well)
`Average
`
`2,195
`
`1,955
`
`1,889
`
`2,013
`
`2,576
`
`2,864
`
`2,097
`
`2,512
`
`1.17
`
`1.46
`
`1.11
`
`1.25
`
`885
`
`890
`
`655
`
`810
`
`2,413
`
`615
`
`0.25
`
`467
`
`
`
`Well D
`(Stand-alone well)
`Table 1 : Summary of IP Comparison
`
`Table 2 shows a summary of the EUR and recovery factor
`calculations. The EUR estimates were based on decline
`curve analysis and
`the gas-in-place was estimated
`assuming a drainage radius of 500 ft from the horizontal
`wells and from the toe and the heel of the horizontal
`wells. The combined drainage area for the 3 wells (A, B,
`and, C) was calculated to be 130 acres and the calculated
`drainage area was 85 acres for well D. Based on a gross
`reservoir thickness of 335 ft, a reservoir porosity of 3%,
`the calculated corresponding GIP was 21.1 Bcf and 13.8
`Bcf, respectively. The adsorbed gas GIP was based on a
`gas content of 96 scf/ton.
`
`Well
`
`Actual
`Lateral
`ft
`
`EUR
`Bcf
`
`Well A
`(Sequential Frac)
`Well B
`(Simo Frac)
`Well C
`(Simo Frac-infill well)
`Average
`
`2,195
`
`1,955
`
`1,889
`
`2,013
`
`2.06
`
`2.22
`
`1.18
`
`5.46
`
`Recovery
`Factor
`
`EUR/
`Lateral
`Length
`MMcf/ft
`0.94
`
`1.14
`
`0.62
`
`0.90
`
`25.9%
`
`Well D
`
`(Stand-alone well)
`Table 2: EUR and Recovery Factor Calculation Summary
`
`2,413
`
`0.89
`
`0.37
`
`6.4%
`
`time, they are cost-effective as the frac equipment is being
`utilized more efficiently and
`two wells are being
`completed in one week instead of two weeks.
`
`Initially, when it first started, simultaneous fracturing in
`Barnett primarily involved dual fracs, involving two
`horizontal wells in close proximity to each other. Today,
`operators are now experimenting with
`triple fracs
`(‘trifectas’) or even quad-fracs in some cases.
`
`Case History
`
`Since 2005, Williams Production Gulf Coast Company
`has drilled over 100 horizontal wells in the Barnett Shale.
`In
`this paper,
`the case history of sequential and
`simultaneous fracturing of three horizontal wells in
`eastern Parker County, is discussed. Figure 2 shows the
`well layout of the wells. Well A, a 2200 ft long lateral,
`was drilled from a separate pad, and two wells, well B,
`and, well C, of lateral lengths 1900 ft to 2000 ft, were
`drilled from a single pad. Wells A and C are spaced 900
`ft apart at the heel and the minimum well spacing is
`approximately 500 ft at the toe of the wells. A 4th stand-
`alone horizontal well, well D, with an effective lateral
`2400 ft, was drilled less than half mile to the north. Due to
`lease constraints, only one well could be drilled on the
`well D pad.
`
`The hydraulic fracturing of wells A, B, and C involved
`both sequential and simultaneous fracturing. Hydraulic
`fracturing of well A was completed over 5 stages in the
`first week. This was followed by simultaneous fracturing
`of wells B and C in the following week.
`
`Figure 3 shows the production performance of the 4 wells
`over the first 6 months of their production life. The three
`simo/sequentially fraced wells had IPs of 3.3 MMscfd to
`3.5 MMscfd and the first month averages ranged from 2.1
`MMscfd to 2.9 MMscfd. The stand-alone well D well to
`the north had significantly lower IP of 2.3 MMscfd and
`the first month average production was also lower at 1.2
`MMscfd. The initial results for the simo/sequentially
`fraced wells are very encouraging and indicate a more
`complex fracture network being created in the vicinity of
`the simultaneously fractured wells, contributing to a
`significantly improved well performance.
`
`The graph shows that the average 5 month production of
`the 3 sequentially-fraced/simo-fraced wells was almost
`double the stand-alone D well, which was completed and
`had first sales about a month later than the 3 sequentially-
`fraced/simo-fraced wells. Well B well has the best
`production among the three wells, and is possibly
`draining a larger area to the east. The well A fracture
`network was likely enhanced due the the subsequent
`simo-fracing of wells B and C, resulting in enhanced
`production. Well C well has the lowest production among
`the three wells which may be attributed to interference
`effects from the two offset wells.
`
`
`IWS EXHIBIT 1049
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`EX_1049_002
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`

`

`SPE 116124
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`
`
`
`The % fluid recovery also appears to correlate with the
`well production performance. It has been suggested that
`rapid fluid cleanup with a high percentage of load
`recovery (> 50%) may actually be an indication that
`significant fracture network was not generated and only a
`simple fracture was created that acts like a “balloon” and
`quickly deflates back into the wellbore 6. The data below
`are not consistent with the above observation and further
`analysis is needed in this regard. In the first 100 hours of
`flowback, wells A and B had higher fluid recoveries
`ranging from 20.8% to 10.5%, respectively, whereas the
`other two wells had fluid recoveries ranging from 3 to
`4%. However, well C despite being a better well
`compared to the stand-alone well D, had relatively poorer
`fluid recovery. It is likely that due to the simo-frac and the
`higher fracture network created in the vicinity of the well,
`part of the flowback fluid was recovered in the offset
`wells, A and B, both of which had high recoveries.
`
`
`Well A
`(Sequential Frac)
`Well B
`(Simo Frac)
`Well C
`Max
`(Simo Frac-infill well)
`bbls
`Well D
`Max
`(Stand-alone well)
`bbls
`Table 3 : Summary of Net Pressures and Frac Job Fluid
`Recoveries
`
`Parker County Simo Frac Study
`
`the benefit from simultaneous
`To further quantify
`fracturing, a comprehensive study was undertaken to
`evaluate the data of simo-fraced wells in Parker County
`based on public information.
`
`1,955 1500 to 1600 psi
`
`4,749
`
`10.5% 11,197
`
`24.7%
`
`1,889 400 to 900 psi
`
`1,421
`
`3.0%
`
`1,457
`
`2,413 200 to 300 psi
`
`3,073
`
`4.0%
`
`6,359
`
` A
`
` total of 29 groups of simo-fraced wells were identified
`based on first date of production being in the same month
`or within one month of each other. The production
`performance of these wells was then compared with that
`of stand-alone wells drilled within a distance of
`approximately 1 to 1.5 miles from the simo-fraced wells.
`Thus, each group of wells consisted of a total 3 wells, the
`two simo-fraced wells and the stand-alone well. For
`approximately 75% of the cases, the simo-fraced wells
`and the stand alone wells were drilled by the same
`operator.
` The analysis
`is based on production
`performance alone and provides general guidelines and
`does not consider the influence of other parameters, such
`as, local geology, frac design, frac injection rates, number
`of stages, etc. which can all impact the production
`performance.
`
`Figure 6 provides a distribution of the simo-fraced wells
`by well spacing and quadrant. Of the 29 groups,
`approximately 55 % (16 groups) had wells drilled on
`1000 ft+ spacing and the rest were approximately 500 ft
`
`Well
`
`Net
`Lateral
`Pressure
`Length
`psi
`ft
`2,195 1000 to 1400 psi
`
`Fluid Recovery
`100 hrs
`300 hrs
`bbls
`bbl
`%
`10,738
`20.8% 22,292
`
`%
`43.3%
`
`
`The analysis indicates a four-fold increase in recovery
`factor from 6.4% for the stand-alone well D to a recovery
`factor of approximately 26% for the simo-fraced wells.
`The average EUR per lateral length also showed a 2.5
`fold benefit and was 0.9 MMcf per ft of lateral for the
`simo-fraced wells versus 0.37 MMcf per ft of lateral for
`the stand alone well.
`
`significant
`shows a
`The case history discussed
`enhancement in IPs, EURs, and recovery factors as a
`result of simo-fracing the wells compared to a stand-alone
`well.
`
`Production Data Analysis
`
`in
`techniques
`Conventional graphical-interpretation
`hydraulically fractured tight gas wells are typically based
`on analyis of flow-regimes, such as linear, bilinear, or
`pseudo-radial flow. For low-permeability wells such as in
`the Barnett, the time to radial flow can be impractically
`long and most of the production data in Barnett wells can
`be characterized as either bi-linear or linear flow. In bi-
`linear flow, the flow occurs both inside the fracture and
`outside the fracture perpendicular to the fracture (Figure
`4). If the fracture has low permeability, bi-linear flow
`will occur over a longer period of time. On the other
`hand, in linear flow, the flow occurs only perpendicular to
`the fracture. If the fracture has sufficient permeability, bi-
`linear flow will last for a short period of time before
`starting the linear flow.
`
`Figure 5 shows the production data of the 4 wells on a
`log-log diagnostic plot of production versus time. The
`plot indicates that well D production data is a lot closer to
`bi-linear flow (1/4 slope) compared to the other three
`wells, which can be represented by linear flow (1/2
`slope). This implies that the quality of fracture is not as
`good in well D compared to other three wells, which may
`be attributed to the type of fracture created. Since the
`three southern were simo-fraced, it is likely that better
`fractures were created for these three wells as compared
`to well D.
`
`Frac Data Analysis
`
`The frac data from the fracturing jobs was reviewed to
`evaluate possible
`reasons behind benefits
`from
`simultaneous /sequential fracturing. It has been suggested
`that interaction of the fluid from the different fractures
`might provide additional energy to enhance the intensity
`of fracturing, either through higher net pressures or forced
`diversion of the fluids at they contact other fluid-filled
`fractures4.
`
`Table 3 provides a summary of the frac fluid recoveries
`and the net pressures for the 4 wells. The results do
`indicate better production performance from wells A and
`B, which had higher net pressures in the range of 1000 to
`1600 psi, compared to the other two wells.
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`IWS EXHIBIT 1049
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`

`4
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`simo-fraced wells indicated the time-lag between 1st sales
`of simo-fraced and stand-alone wells was a key factor in
`the success of the simo-frac over stand-alone wells. The
`data suggests that wells that had less than 3 months of
`time-lag between the simo-fraced wells and the stand-
`alone wells had the best success rate to see incremental
`production and reserves due to simo-fracing.
`
`Figure 10 provides a distribution of the simo-fraced wells
`time-lag between 1st
`with
`less
`than 3 months of
`production from simo-fraced wells and stand-alone wells,
`sorted by well spacing and quadrant. A comparison of
`Figure 9 and 10 shows that only 20 to 30% of the well
`groups fell in this category, and, the majority of the simo-
`fraced wells (70 to 80%) were drilled anywhere from 4
`months to 3+ years after the stand alone well was drilled.
`A few instances were also identified where the stand-
`alone well was drilled later after the simo-fraced wells by
`a different operator on an offset lease. In such instances,
`the simo-fraced wells did better than the stand-alone well.
`
`the production
`Figure 11 provides a summary of
`enhancement of simo-fraced wells over stand alone wells
`sorted by well spacing. The comparisons were based on
`comparing peak monthly production, which for most of
`the cases, is in the first or 2nd month of well life. The
`results indicate an average enhancement of 56% in
`production of simo-fraced wells over offset non-
`simofraced wells. As expected, the greater the well
`spacing, lower are the interference and depletion effects.
`Thus, wells with 1000 ft spacing had greater incremental
`gain compared to wells with 500 ft spacing, which did
`better than the 250 ft spacing wells.
`
`If the simo-frac well was drilled beyond 3 months, the
`production performance fell significantly and the average
`IP of simo-fraced wells was less than the stand-alone well
`(85% of the stand alone well). This is attributed to
`possible interference and depletion effects, which might
`change the stress profile in the vicinity of the wellbore.
`Again, the 250 ft spacing wells were most affected by
`interference and depletion effects and had the lowest IPs
`compared to stand alone wells at 80%.
`
`
`the production
`Figure 12 provides a summary of
`enhancement seen sorted by quadrant for Johnson county.
`The results indicate an average enhancement of 53% in
`production of simo-fraced wells over offset non-
`simofraced wells. If the simo-frac well was drilled beyond
`3 months, the average IP of simo-fraced wells was 87% of
`the stand-alone well. Surprisingly, the lowest IPs of
`simo-fraced wells compared to stand-alone wells (70%
`factor) were in the NE quadrant in Johnson county, which
`generally has seen prolific producing wells. This may be
`due to the fact that the presence of Voila barrier in most
`of the NE quadrant has resulted in operators fracturing
`and high injection rates and there have been excellent
`stand-alone wells in the area, even without simo-fracing.
`Moreover, in some instances, the stand alone and the
`
`spacing. Most of the drilling activity in Parker county has
`been in the eastern half where the reservoir thickness is
`relatively higher. Thus, in terms of the location of the
`wells, almost 72% (21 groups) were in SE quadrant, and,
`90% (26 groups) of the well groups were in eastern half
`of Parker County.
`
`For the analysis of the Parker County production data for
`simo-fraced wells the time-lag between 1st sales of simo-
`fraced and stand-alone wells was evaluated as a possible
`factor in the success of the simo-frac over stand-alone
`wells. Figure 7 provides a distribution of simo-fraced
`well groups with less than 3 month lag between 1st sales
`of simo-fraced and stand-alone wells sorted by Well
`spacing and quadrant in Parker County. Approximately
`50% of the well groups fell in this category, with many of
`the wells drilled on 1000 ft spacing.
`
`the production
`Figure 8 provides a summary of
`enhancement seen in each of the quadrants of Parker
`county. The comparisons were based on comparing peak
`monthly production, which for most of the cases, is in the
`first or 2nd month of well life. The analysis for wells in
`SE quadrant, which accounted for more than 70% of well
`groups, suggests that wells that had less than 3 months of
`time-lag between the simo-fraced wells and the stand-
`alone wells had the best success rate to see incremental
`production and reserves due to simo-fracing. In NE
`quadrant, irrespective of when the wells were completed,
`the simo-fraced wells outperformed the stand-alone wells.
`Again, this might be attributed to factors such as
`variations in frac design, injection rates, etc. as well as
`regional geology.
`
`
`Johnson County Simo Frac Study
`
`In terms of drilling activity, Johnson county has seen a
`significant increase in recent years and some the best
`producing wells in Barnett Shale have been drilled in the
`county. For Johnson county, the number of simo-fraced
`wells to date is significantly higher compared to Parker
`county. A total of 104 groups of simo-fraced wells were
`identified in Johnson county based on first date of
`production being in the same month or within one month
`of each other.
`
`Figure 9 provides a distribution of the simo-fraced wells
`by well spacing and quadrant. Of the 104 groups,
`approximately 33 % (34 groups) of them, had wells
`drilled on 500 ft spacing. Due to thick shale resource and
`the presence of the Voila in the eastern part of Johnson
`county, some of the operators have began experimenting
`with 250 ft spacing and another 33% (34 groups) had
`wells drilled on 250 ft spacing. In terms of the well
`groups location by quadrant, approximately 40% (40
`groups) were in NE quadrant of Johnson county and
`another 33% (34 groups) were in the NW quadrant.
`
`The analysis of the Johnson County production data for
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`IWS EXHIBIT 1049
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`References
`
`
`1. Carillo, V. G. :”Barnett Shale Update”, Platts
`Shale Developer Conference,Houston TX, June
`2008.
`2. LaFollete, R. and Schein, G: “Understanding the
`Barnett Shale”, Supplement to Oil and Gas
`Investor , January 2007.
`3. Durham, L.S.: “Barnett Shale Play Can Be
`Complex
`: Their Success Doesn’t Ensure
`Yours”, AAPG Explorer Bulletin, September
`2007.
`4. Leonard, R. et al: “Barnett Shale Completions :
`A Method for Assessing New Completion
`Strategies”, SPE 110809, presented at the 2007
`SPE Annual Technical Conference
`and
`Exhibition, Anaheim, California, November
`2007.
`5. Daniels J., Waters G., LeCalvez J., Lassek J.,
`and Bentley D.: “Contacting More of the
`Barnett Shale Through an Integration of Real-
`Time-Microseismic Monitoring, Petrophysics,
`and Hydraulic-Fracture Design,” SPE 110562,
`presented at the 2007 SPE Annual Technical
`Conference and Exhibition, Anaheim, California,
`November 2007.
`6. Warpinski, N.R.
`“Stimulating
`al:
`et
`Reservoirs: Maximizing
`Unconventional
`Network Growth while Optimizing Fracture
`Conductivity”, SPE 114173, presented at 2008
`SPE Unconventional Reservoirs Conference,
`Keystone, CO, February 2008.
`
`
`
`
`
`
`
`
`
`simo-fraced wells (which were identified from maps) may
`not have been completed by the same operator. Again, the
`contrast in results could be due to differences in frac
`design, injection rates, number of stages, completion
`design, etc.
`
`Conclusions
`
`Simultaneous fracturing is being increasingly used by
`operators in the Barnett to produce a more complex web
`of fractures, increase the surface area created by the frac
`job, thereby enhancing initial production rates and
`ultimate recovery.
`
` case history and results of simultaneous and sequential
`fracturing in south-east Parker county is presented in the
`paper, which showed an average 100% enhancement in
`rates compared to a stand-alone well producing from the
`same leasing unit. The data also appears to indicate that
`simo-fracing results in more enhanced fracture network
`and production gains compared to sequential fracturing.
`
`The analysis of the data from simo-fraced wells in Parker
`and Johnson county showed an enhancement in average
`peak IP rates of 21% to 55% over stand-alone wells, for
`wells which had less than a 3 month lag between 1st sales
`from simo-fraced wells and stand alone wells.
`
`On the other hand, if the time lag between 1st sales from
`simo-fraced wells and stand alone wells was greater than
`3 months, the simo-fraced wells showed lower average IP
`rates compared to stand-alone wells. Any material
`production from the same reservoir sink from interference
`and depletion effects, causes changes in stress profile in
`the vicinity of the wellbore, which impacts the production
`performance of the simo-fraced wells.
`
`Overall, the analysis suggests simultaneous fracturing is a
`viable technique for application in the Barnett shale
`reservoir. For the best chance of success, simultaneous
`fracturing should be planned in the initial wells that are
`drilled to develop a new lease.
`
`
`Nomenclature
`
`IP : Initial Potential
`EUR : Estimated Ultimate Recovery
`Simo-frac : Simultaneous fracturing
`
`Acknowledgements
`
`The authors would like to thank the management of
`Williams Companies for their support and permission to
`publish this study. We would also like to thank Kevin
`Mcdaniel, student at Missouri University of Science and
`Technology, for his help with compiling the data used in
`the analysis. Thanks are also due to Dr. Mohan Kelkar of
`Univeristy of Tulsa and Dr. Harun Ates for their
`insightful comments.
`
` A
`
`IWS EXHIBIT 1049
`
`EX_1049_005
`
`

`

`Downloaded from http://onepetro.org/SPEATCE/proceedings-pdf/08ATCE/All-08ATCE/SPE-116124-MS/2734784/spe-116124-ms.pdf/1 by Robert Durham on 12 August 2022
`
`6
`
`
`
`
`
`
`Figure 1 : Barnett Shale Drilling Activity1
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`Figure 2 : Well Location Map
`
`10,000
`
`1,000
`
`Gas Rate, Mcfd
`
`100
`
`1
`
`
`
`
`
`
`
`
`
`
`Figure 5: Log-log diagnostic plot of Production vs Time
`
`10
`
`100
`
`Time (Days)
`
`1,000
`
`
`
`SPE 116124
`
`Well A
`Well B
`Well C
`Well D
`
`2,000
`
`1,800
`
`1,600
`
`1,400
`
`1,200
`
`1,000
`
`800
`
`600
`
`400
`
`200
`
`Gas Rate, Mcfd
`
`
`
`0
`Oct-07
`
`Dec-07
`
`Feb-08
`
`Apr-08
`
`
`
`
`Figure 3 : Production History of the Simo-
`frac/Sequentially fraced wells (wells A, B, C) versus
`stand alone well (well D)
`
` Bi-linear Flow
`
`
`
` Linear Flow
`
`
`Figure 4 : Linear and Bi-linear Flow Regimes
`
`
`
`
`
`
`
`Well A
`Well B
`Well C
`Well D
`
`IWS EXHIBIT 1049
`
`EX_1049_006
`
`

`

`SPE 116124
`
`
`
`7
`
`
`
`
`
`
`
`
`
`
`
`500 ft
`500/1000 ft
`Well Spacing, ft
`
`Figure 10 : Distribution of Simo-fraced Well Groups with
`less than 3 month lag between 1st sales of Simo-fraced
`and stand-alone wells Sorted by Well Spacing and
`Quadrant - Johnson County
`
`
`SW
`NW
`NE
`SE
`
`4
`1
`
`3
`
`1000 ft
`
`10
`
`02468
`
`Number of Simo-fracced
`
`Well Groups
`
`9
`2
`1
`
`5
`
`1
`
`4
`1
`
`3
`
`1
`
`4
`2
`1
`1
`
`250 ft
`
`214%
`
`185%
`
`87%
`
`103%
`
`83%
`
`88%
`
`120%
`
`80%
`
`250%
`
`200%
`
`150%
`
`100%
`
`50%
`
`16
`1
`4
`
`11
`
`
`
`NW
`SW
`NE
`SE
`
`13
`11
`1
`
`10
`
`1000 ft
`
`Well Spacing, ft
`
`500 ft
`
`9
`
`2
`
`2
`
`5
`
`SW
`NW
`NE
`SE
`
`5
`1
`
`4
`
`18
`16
`14
`12
`10
`
`02468
`
`10
`
`
`
`
`
`
`
`
`Number of Simo-fracced
`
`Well Groups
`
`Well Groups
`
`Downloaded from http://onepetro.org/SPEATCE/proceedings-pdf/08ATCE/All-08ATCE/SPE-116124-MS/2734784/spe-116124-ms.pdf/1 by Robert Durham on 12 August 2022
`
`
`
`
`
`0%
`
`IP_Simo/IP_standalone
`
`250 ft
`
`1000 ft
`
`500 ft
`500/1000 ft
`Lag* > 3 Months
`Lag* < 3 months
`* Time Lag Between 1st Sales of Simo-Frac and Stand-alone Wells
`Figure 11 : Average IP Enhancement of Simo-fraced
`wells over stand-alone wells sorted by Well Spacing –
`Johnson County
`
`
`154%
`
`148%
`
`154%
`
`156%
`
`105%
`
`92%
`
`83%
`
`70%
`
`180%
`160%
`140%
`120%
`100%
`80%
`60%
`40%
`20%
`0%
`
`IP_Simo/IP_standalone
`
`
`
`SE
`
`NE
`Lag* < 3 months
`
`NW
`Lag* > 3 Months
`
`SW
`
`* Time Lag Between 1st Sales of Simo-Frac and Stand-alone Wells
`Figure 12 : Average IP Enhancement of Simo-fraced
`wells over stand-alone wells sorted by Well Quadrant –
`Johnson County
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`Figure 6 : Distribution of Simo-fraced Well Groups by
`Well Spacing and Quadrant - Parker County
`
`
`
`
`
`
`
`
`
`
`
`Well Spacing, ft
`
`Figure 7 : Distribution of Simo-fraced Well Groups with
`less than 3 month lag between 1st sales of Simo-fraced
`and stand-alone wells Sorted by Well Spacing and
`Quadrant - Parker County
`
`
`02468
`
`Number of Simo-fracced
`
`1000 ft
`
`500 ft
`
`139%
`
`138%
`
`114%
`
`90%
`
`SE
`Lag* < 3 months
`
`NE
`Lag* > 3 Months
`
`160%
`140%
`120%
`100%
`80%
`60%
`40%
`20%
`0%
`
`IP_simofrac/IP_standalone
`
`Figure 8: Average IP Enhancement of Simo-fraced wells
`over stand-alone wells sorted by Well Quadrant – Parker
`County
`
`
`
`
`
`
`
`
`
`
`
`
`Figure 9 : Distribution of Simo-fraced Well Groups by
`Well Spacing and Quadrant - Johnson County
`
`7
`
`2
`500 ft
`500/1000 ft
`Well Spacing, ft
`
`SW
`NW
`NE
`SE
`16
`2
`9
`4
`1
`1000 ft
`
`40
`35
`30
`25
`20
`15
`10
`
`05
`
`Number of Simo-fracced
`
`Well Groups
`
`34
`
`9
`
`10
`
`13
`
`20
`5
`8
`
`34
`
`11
`
`7
`
`16
`
`250 ft
`
`IWS EXHIBIT 1049
`
`EX_1049_007
`
`