Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/09HFTC/All-09HFTC/SPE-119635-MS/2707283/spe-119635-ms.pdf/1 by Robert Durham on 12 August 2022
`
`SPE 119635
`
`Simultaneous Hydraulic Fracturing of Adjacent Horizontal Wells in the
`Woodford Shale
`George Waters, Barry Dean, and Robert Downie, Schlumberger, and Ken Kerrihard, Lance Austbo, and
`Bruce McPherson, Continental Resources
`
`Copyright 2009, Society of Petroleum Engineers
`
`This paper was prepared for presentation at the 2009 SPE Hydraulic Fracturing Technology Conference held in The Woodlands, Texas, USA, 19–21 January 2009.
`
`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
`Hydraulic fracturing of horizontal wells in shale gas reservoirs is now an established, commercially
`successful technique. The evolution of the completion technique has reached the point that numerous
`stimulation stages through multiple perforation clusters in wellbores with some form of annular isolation
`is now an accepted practice. The objective is to place multiple closely spaced hydraulic fractures. This
`has proven to be a viable development strategy for many shale reservoirs in North America.
`
`To further enhance the recovery factor in these ultra low permeability reservoirs simultaneously
`hydraulically fracturing of adjacent wellbore is increasingly being tested. Most of the time this is
`performed in horizontal wellbores paralleling each other. The goal is to create hydraulic fractures more
`closely spaced than can be achieved from a single wellbore. When real time microseismic monitoring of
`the stimulation treatments is incorporated changes can be made “On-the-Fly” to improve the effective
`stimulated reservoir volume.
`
`Continental Resources has employed simultaneous hydraulic fracturing as a development strategy for
`their Woodford Shale acreage in the Arkoma Basin of Eastern Oklahoma. To monitor the effectiveness
`of the stimulations geophones have been deployed into horizontal wellbores to record microseismic
`events when offsetting vertical wellbores are unavailable. Cased hole sonic logs have also been run to
`quantify cement bond quality, estimate stress variation along the lateral, and to pick optimum
`perforating points.
`
`This paper reviews the methodology employed in the completion design and process. The impact of the
`simultaneous stimulations and geologic structure on the fracture geometry are shown as well as the
`impact on well productivity.
`
`Woodford Geology
`The Devonian Woodford shale is a prolific gas producer in the western Arkoma Basin in Atoka, Coal,
`Hughes, and Pittsburg Counties, Oklahoma where there are over 527 Woodford completions since
`January, 2004. The majority of these wells are horizontal with multistage fracture stimulation
`treatments performed on them. In these four counties, the Woodford formation ranges in depth from
`approximately 4,000 ft to over 14,000 ft and varies in thickness from 35 ft to over 280 ft. In the area
`covered by this paper, the Woodford formation is at a depth of 6,000 ft to 7,700 ft and is 160 ft to 180 ft
`
`IWS EXHIBIT 1047
`
`EX_1047_001
`
`

`

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`
`2
`
`SPE 119635
`
`thick. The Woodford lies upon the post-Hunton unconformity and is underlain by Hunton Limestone
`with the calcareous Mayes formation overlying the Woodford.
`
`The Woodford Shale is an organic-rich, siliceous shale with 48 - 74% quartz, with an additional 3 - 10%
`feldspar, 7 - 25% illite clay, 0 - 10% pyrite, 0 - 5% carbonate, and 7 - 16% kerogen based on log and
`core analyses. The Woodford in this study area has been sub-divided into 4 units, Upper Woodford,
`Woodford A, Woodford B, and Woodford C. The Upper Woodford frequently has the highest clay
`content, while the Woodford A and C intervals have the highest silica content along with the highest
`effective porosity. The Woodford B has lower apparent porosity than the Woodford A and C (Figure 1).
`
`In this area, seismic data indicates there
`is an E-W
`trending
`fault/fracture
`network with an ENE-WSW secondary
`fault/fracture network (Figure 2). The
`horizontal wells in this area target the
`Woodford A interval and are drilled N-
`S to maximize the drainage of the
`section.
` This
`orientation
`also
`approaches
`the
`azimuth
`of
`the
`minimum horizontal stress ((cid:86)h) which
`results in hydraulic fractures that are
`perpendicular to the wellbore. This
`stress orientation has been identified by
`induced fractures on image logs (Figure
`3) and confirmed by microseismic
`imaging of hydraulic fractures.
`
`Hydraulic Fracturing of Shales
`low
`Hydraulic
`fracturing of ultra
`permeability reservoirs is required to
`establish
`commercial
`productivity.
`Commercial
`shale
`reservoir
`permeabilities are in the range of 200
`nd, or 0.0002 md. With formation
`permeabilities of this magnitude the
`pressure drop in the system occurs
`primarily in the reservoir near the
`fracture face. Analytical techniques
`support this conclusion even assuming
`no fracture face damage1. Figure 4
`shows the source of pressure losses
`versus time in a low permeability shale
`reservoir assuming no fracture face
`skin.
`
`Reservoir simulations have also shown
`that this is the case for many years after
`production commences (Figure 5)2,3.
`As Figure 5 indicates, large sections of
`the reservoir are at initial reservoir
`
`Ga.no•• Ray (I
`
`150 (~I ) 300
`Ga.M•• Ray (3
`
`300 (gAPI) ...
`
`GR(1~300)
`
`GR(X0-450)
`
`Gllm•• Ray (4
`
`450 (~I) «II)
`
`GR ( -
`
`BltSlz::•
`
`Cln)
`
`,.
`
`,, ...... ,
`0 C,_.,,11 , ..
`
`GR(().15<1t
`
`Mudcal!.•
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`RSOZ
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`
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`RSOZ - - - - - - - -
`(•V)
`16 0.2 {ohe.m~
`-85
`OSOZ
`GR
`ATiO
`o.~in> o eioo c:1, n.o 0.2 c:;;y-WO r-~,..,="~,<~u~,- .
`r:O~ 750 c:11 $00 o~co;;:-~ ,..---..,~,-:~~~~,:~:;-,--, ------i-
`
`TOC(ELA~
`
`-~=~• TOC-TeuM♦t:
`
`0
`
`(lbf.i1bt) 0.25
`
`.,.,, . ,
`""
`
`Kgos
`(mD)
`
`Sgos
`(lt3,lt3)
`
`fOC..&hmQqf
`
`0
`
`(Mltll) O.~
`
`' ' 000
`
`, .......
`() , ..
`...
`
`GIP(BCF{mi2
`
`MtGIP(BCF
`
`CI
`GIP(BCF/m;2)
`II
`
`
`
`MayesMayes
`
`
`
`Upper WoodfordUpper Woodford
`
`
`
`Woodford AWoodford A
`
`
`
`Woodford BWoodford B
`
`
`
`Woodford CWoodford C
`
`6750
`
`Figure 1 – Woodford Shale Type Log with sub-divisions
`noted. Log does not penetrate all of Woodford
`
`IWS EXHIBIT 1047
`
`EX_1047_002
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`
`3
`
`SPE 119635
`
`pressure after 10 years of production,
`when hydraulic fractures are spaced
`1,000 ft apart in a 400 nd shale gas
`reservoir. Even after 60 years of
`production the reservoir pressure still
`approaches 50% of its initial value for
`this fracture spacing. The recovery
`factor is increased dramatically when
`the hydraulic fractures are spaced closer
`together. As indicated by Figure 6 a
`250 ft hydraulic fracture spacing drains
`as much of the reservoir in 10 years as
`the 1,000 ft spacing does in 60 years.
`With
`this spacing
`the reservoir
`is
`largely depleted between the fractures
`after 60 years of production.
`
`Recovery can be accelerated further by
`even closer
`spacing of hydraulic
`fractures, or in reservoirs where dense
`natural fractures
`that remain open
`during
`production
`are
`present.
`Ultimately the optimum spacing of
`hydraulic fractures is driven by two
`parameters:
`(cid:120) The incremental cost associated
`with creating an ever denser
`fracture
`system versus
`the
`productivity improvement from
`the denser fracture network.
`ability
`to
`physically,
`(cid:120) The
`continually propagate hydraulic
`fractures in close proximity to
`one another.
`
`theoretical
`of
`investigation
`An
`hydraulic fracture spacing provides a
`lower bound for their proximity. As a
`first pass one can use Hooke’s Law to
`determine realistic minimum hydraulic
`fracture spacing. For this application
`Hooke’s Law takes the form shown in
`Equation 1:
`
`N
`
`E
`
`– Woodford
`2
`Figure
`structure showing an E-W
`fault/fracture network and a
`secondary NE-SW system.
`Wellbores are oriented N-S
`for
`most
`effective
`development. Blue squares
`denote 1 mile section lines.
`
`Figure 3 – Woodford FMI
`Log showing E-W Induced
`Fractures, the azimuth of
`the maximum horizontal
`stress ((cid:86)H(cid:12)(cid:3)and of hydraulic
`fractures.
`
`(
`)/
`bwE(cid:32)(cid:39)(cid:86)
`
` . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . (1)
`
`where E = horizontal Young’s Modulus, w = hydraulic fracture width,
`and b = hydraulic fracture spacing. Figure 7 portrays this stress increase
`as a function of fracture spacing and Young’s Modulus.
`
`IWS EXHIBIT 1047
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`EX_1047_003
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`4
`
`SPE 119635
`
`Linear Flow Transient Pressure Loss
`
` % Loss Reservoir
` % Loss Damaged Zone
` % Loss Fracture
`
`0
`
`500
`
`1,000
`
`1,500
`
`2,000
`Time, days
`
`2,500
`
`3,000
`
`3,500
`
`4,000
`
`
`5 Year 5 Year
`
`Pressure Pressure
`
`TransientTransient
`
`
`10 Year 10 Year
`
`Pressure Pressure
`
`TransientTransient
`
`
`60 Year 60 Year
`
`Pressure Pressure
`
`TransientTransient
`
`Figure 5 – Pressure
`Transient in a 400 nd
`shale gas reservoir with
`an
`initial
`reservoir
`pressure of 3,000 psi
`and
`500
`ft
`long
`hydraulic
`fractures
`spaced at 1,000
`ft
`intervals.
`
`100%
`
`80%
`
`60%
`
`40%
`
`20%
`
`0%
`
`Pressure Loss
`
`Figure 4 – Sources of pressure loss
`in a hydraulically fractured shale
`reservoir showing the majority of
`the system pressure loss is in the
`formation, near the fracture face.
`
`Assumptions:
`Fracture Length = 1,000 ft
`Fracture Conductivity = 8.3 md-ft
`Formation Perm = 200 nd
`Fluid Viscosity = 0.02 cp
`Porosity = 7%
`Fluid Compressibility = 0.0001 psi-1
`No Fracture Face Skin
`
`Figure 6 – Pressure
`Transient in a 400 nd
`shale gas reservoir with
`an
`initial
`reservoir
`pressure of 3,000 psi and
`500 ft
`long hydraulic
`fractures spaced at 250 ft
`intervals.
`
`
`5 Year 5 Year
`
`Pressure Pressure
`
`TransientTransient
`
`
`10 Year 10 Year
`
`Pressure Pressure
`
`TransientTransient
`
`
`60 Year 60 Year
`
`Pressure Pressure
`
`TransientTransient
`
`IWS EXHIBIT 1047
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`EX_1047_004
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`
`Stress Change versus Hydraulic Fracture Spacing
`(assumes fracture width = 0.05 in)
`
`Modulus = 1,000,000 psi
`Modulus = 2,000,000 psi
`Modulus = 3,000,000 psi
`Modulus = 5,000,000 psi
`
`10
`
`20
`
`30
`
`60
`50
`40
`Hydraulic Fracture Spacing (ft)
`
`70
`
`80
`
`90
`
`100
`
`5
`
`Figure 7 – Stress
`increase
`versus
`hydraulic
`fracture
`spacing for various
`Young’s Moduli.
`The
`higher
`the
`Modulus the greater
`the stress increase.
`At
`very
`close
`fracture spacing the
`stress
`increases
`dramatically.
` A
`hydraulic
`fracture
`width of 0.05 inches
`is assumed.
`
`SPE 119635
`
`100,000
`
`10,000
`
`1,000
`
`100
`
`Stress Change (psi)
`
`10
`
`0
`
`Two conclusions are apparent:
`In order for hydraulic fractures to be very close together very high stresses are required. A
`(cid:120)
`fracture spacing of 1 ft requires stresses in excess of 4,000 psi for all listed moduli. This is
`unrealistic and will certainly lead to the truncation of most fractures and the creation of a
`dominant, single fracture at this spacing.
`(cid:120) The rock stiffness greatly influences the achievable fracture spacing. For example, at a fracture
`spacing of 25 ft the increase in stress is >800 psi for a rock with a Young’s Modulus of 5x106
`psi. Yet the stress increase is only 170 psi for a rock with a Young’s Modulus of only 1x106 psi.
`
`Fortunately organic-rich shales normally have relatively low Young’s Modulus compared to
`conventional low permeability reservoirs that are candidates for hydraulic fracturing. Therefore, it is
`easier to place fractures closer together in these very low permeability rocks than in tight sands or
`carbonates where the Young’s Modulus is frequently in excess of 6x106 psi. This example is a gross
`simplification yet it does provide a measure of scale of hydraulic fracture spacing.
`
`Warpinski and Branagan4 reviewed the stress alteration associated with hydraulic fracturing, comparing
`it to field results recorded in the U.S. DOE’s Multiwell Experiment Site5. This paper focused on the
`rotation of minimum horizontal stress ((cid:86)h) due to the stress perturbation created from a pre-existing
`fracture from an offset well. The analytical technique used in this paper6,7 assumes an infinitely long
`planar fracture in a homogeneous, elastic and isotropic body. While these simplifying assumptions may
`be idealistic the method does provide some insight into the potential complexities associated with
`hydraulic fractures propagating in close proximity to each other. The reader is referred to Reference 4
`for the pertinent equations.
`
`Hydraulic fracture rotation is unlikely if there is a large difference in the horizontal stresses, a moderate
`Net Pressure build, and/or a relatively small fracture height. But this does not mean that the fracture
`geometry is not impacted by the adjacent fractures. The degree of stress increase associated with a
`hydraulic fracture varies vertically through the fracture with the highest stress increase occurring at the
`center of the fracture were the hydraulic fracture width is assumed to be the maximum. From the center
`
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`6
`
`SPE 119635
`
`of the fracture to the vertical fracture tips and beyond the stress declines, eventually decreasing to below
`the initial, undisturbed value of (cid:86)h because of the tensile forces at the fracture tip (Figure 8). Thus a
`scenario exists where adjacent fractures may be drawn towards each other at their perimeters yet
`repelled near the fracture centers where the width is assumed to be the greatest. There is a large increase
`in shear stress near the fracture tips that will likely preclude the fractures from connecting to form a
`single fracture (Figure 9). Instead the fractures will likely rotate towards each other and truncate if they
`are very close to each other.
`Change in Minimum Horizontal Stress
`Mid-Fracture Height
`Mid-Point from Frac Center to Tip
`Near Fracture Tip
`Just Beyond Fracture Tip
`Fracture Tip + 50% of Frac Height
`
`1.00
`
`0.75
`
`Figure 8 – Change in (cid:86)h due to the
`presence of a hydraulic fracture.
`The stress increase is the highest
`at the center of the fracture and
`decays as the distance from the
`fracture increases (Blue Curve).
`Near the fracture tip the stress
`actually decreases as the stress in
`this region
`is
`tensile versus
`compressive
`(Red & Brown
`Curves).
`
`1.5
`1.0
`0.5
`Distance Normal to Frac / Frac Half-Height
`
`2.0
`
`0.50
`
`0.25
`
`0.00
`
`-0.25
`
`Stress Change / Net Pressure
`
`-0.50
`
`0.0
`
`Change in Shear Stress
`Mid-Fracture Height
`Mid-Point from Frac Center to Tip
`Near Fracture Tip
`Just Beyond Fracture Tip
`Fracture Tip + 50% of Frac Height
`
`1.00
`
`0.75
`
`0.50
`
`0.25
`
`Stress Change / Net Pressure
`
`Figure 9 – Change in shear stress
`due
`to
`the presence of a
`hydraulic fracture. The high
`shear stress near the fracture tip
`(Red & Brown Curves) will likely
`cause the fractures to rotate and
`truncate
`if they are
`in close
`proximity to each other.
`
`0.00
`0.00
`
`0.50
`0.25
`Distance Normal to Frac / Frac Half-Height
`Most horizontal wells in low permeability shales are drilled in the direction of (cid:86)h at deviations slightly
`greater than 90 degrees. With this orientation it will not be possible to take advantage of the tensile
`region near the hydraulic fracture perimeter to place fractures closely together within the same wellbore
`
`0.75
`
`1.00
`
`IWS EXHIBIT 1047
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`SPE 119635
`
`7
`
`because the fracture widths will be largest at the wellbore where the fractures are initiated (Dark Blue
`Curve in Figure 8). Hence the stress will be higher near the perforation clusters within a horizontal
`wellbore making hydraulic fracture initiation more difficult if the perforations are spaced closely
`together.
`
`One method to achieve a dense hydraulic fracture system is to drill hydraulically fractured vertical wells
`on a dense well spacing. To achieve the required dense fracture network requires multiple vertical wells
`with a well spacing of approximately 15 acres (Figure 10). This is not cost effective as a new vertical
`borehole is needed for each stimulation. As previously mentioned, a commonly employed alternative is
`to drill horizontal wells in the direction of (cid:86)h and to place multiple hydraulic fractures in close proximity
`to each other. This success of this technique is well documented8. A more recent development is the
`utilization of the pressure alteration due to a stimulation treatment from a horizontal well to alter the
`hydraulic fracture geometry from a concurrent stimulation treatment being performed on a closely
`spaced, parallel offset horizontal well.
`
`Pr (psi)
`
`
`450045004500
`
`2286 ft
`
`
`
`B8 : 1 1B8 : 1 1
`
`
`
`B4 : 1 1B4 : 1 1
`
`
`
`B6 : 1 1B6 : 1 1
`
`
`
`B3 : 1 1B3 : 1 1
`
`
`
`B1 : 1 1B1 : 1 1
`
`
`
`B5 : 1 1B5 : 1 1
`
`
`
`B2 : 1 1B2 : 1 1
`
`
`
`B7 : 1 1B7 : 1 1
`
`457 ft
`
`
`
`
`
`400040004000
`
`
`
`
`
`350035003500
`
`
`
`
`
`300030003000
`
`
`
`
`
`250025002500
`
`
`
`
`
`200020002000
`
`
`
`
`
`150015001500
`
`Figure 10 – Reservoir
`depletion pattern after
`30 years in a 200 nd
`permeability shale gas
`reservoir
`with
`hydraulically fractured
`vertical wellbores on 15
`acre spacing.
`
`
`
`
`
`100010001000
`
`
`
`
`
`500500500
`
`Hydraulic Fracture Complexity due to Simultaneous Fracturing
`The “Simul-Frac” technique is a method in which adjacent sections of a reservoir are hydraulically
`fractured from at least two wellbores at the same time. Most of the time the wells are horizontal with
`the laterals drilled in the direction of (cid:86)h and landed at similar, although not always, the same depth. In
`such wells the toe sections of the laterals will be stimulated at the same time. Subsequent stages are
`performed concurrently working from the toe back to the heel of the lateral. The objective is to place
`hydraulic fractures in close proximity to one another by taking advantage of the tensile stress region near
`the fracture perimeters.
`
`A number of variations to the technique are commonly employed:
`(cid:120) The depth of the adjacent laterals may vary. Such vertical staggering can take advantage of the
`tensile region around the top and bottom of the fractures (Figure 8 Red & Brown Curves), not
`just at the fracture tip, to allow close spacing of fractures.
`(cid:120) More than two laterals can be stimulated at the same time. In some cases up to four parallel
`laterals have been stimulated at the same time.
`
`IWS EXHIBIT 1047
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`8
`
`SPE 119635
`
`(cid:120)
`
`(cid:120)
`
`In ultra-low permeability reservoirs such as shales the stimulations do not necessarily have to
`occur concurrently. Since there is little to no fluid leakoff into the rock matrix the fracture
`systems will remain pressurized until flown back. This pressurized system can provide the
`diversion desired when the adjacent lateral is stimulated subsequent to the initial stimulation.
` This “Zipper-Frac” method provides some significant operational efficiencies:
`o When two wells drilled from the same pad are being stimulated only one stimulation
`crew and perforating crew is required. While the fracturing crew is stimulating one well,
`the perforating crew is setting the frac plug and perforating the adjacent wellbore. The
`two crews continue to work back and forth between the two wells to efficiently complete
`them in a timely manner.
`o If more than two wells are being stimulated at the same time then a completion sequence
`can be developed to most effectively create a dense fracture network throughout the
`acreage. For example, if four laterals are being stimulated with two crews the outer wells
`can be stimulated first, followed by the inner wells where a more dense fracture pattern
`can be created. The treatment sizes can be adjusted based on the order in which the wells
`are stimulated. The completion sequence utilized will be a function of the well spacing,
`the structural geology, surface logistics, and the desire for hydraulic fracture density
`versus fracture length.
`(cid:120) A third technique is to completely stimulate one lateral. Then, before fracturing fluid flowback
`is commenced, completely stimulate the adjacent lateral(s) taking advantage of the pressurized
`system from the first lateral stimulated. This method has the same operational efficiencies as the
`Zipper-Frac technique but can be employed when the wellheads are separated requiring
`movement of the frac crews.
`
`Simultaneous Fracturing Examples in the Woodford Shale of the Arkoma Basin
`All discussed wells are operated by Continental Resources, Inc. of Enid Oklahoma and are in Hughes
`County, Oklahoma, in the western part of the Arkoma Basin. All wells are similarly drilled and
`completed. All wells are cased and cemented using 5.5 in, 17 lb/ft, P110 casing in 8.5 in hole. Wells
`are fracture stimulated in multiple stages, each stage stimulating 400 to 500 ft of lateral through 4 to 6
`sets of perforations spaced 70 to 125 ft apart. Cement bond logs were run in all wells except in wells
`where cased hole dipole sonic logs were run to quantify cement bond quality and to estimate (cid:86)h along
`the lateral. The bond logs were used to place perforation clusters in intervals with similar bond quality
`and to insure that annular isolation between stages was attained. When practical, perforation clusters
`were placed in sections with poor cement bond quality to minimize near-wellbore fracture complexity
`issues due to solids plugging the annulus. When stress profiles were available along the lateral
`perforations were placed in intervals of similar stress9. Coupling these techniques with limited entry
`perforating increased the odds that all perforation clusters would be active during the stimulation
`treatments.
`
`Fracture stages contained short perforation clusters varying in length from 1.5 ft to 2.5 ft. The number
`of perforation clusters varied from 4 to 6 per frac stage. All perforating utilized 6 shots per foot, 60
`degree phasing with entry hole diameters of 0.42 in (low side) to 0.32 in (high side). The first
`stimulation stage perforations were shot via coiled tubing. Subsequent perforations were run on wireline
`with composite drillable isolation plugs using the pump-down technique in the horizontal section at low
`injection rates of 2 to 12 bpm.
`
`On all example projects treatment wells were shut-in after fracturing until coiled tubing units were
`mobilized to drill out all isolation plugs at the same time. Wells were flowed back together within 24 to
`36 hours of the end of stimulation operations. Most wells within a project were then put on production
`
`IWS EXHIBIT 1047
`
`EX_1047_008
`
`

`

`Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/09HFTC/All-09HFTC/SPE-119635-MS/2707283/spe-119635-ms.pdf/1 by Robert Durham on 12 August 2022
`
`SPE 119635
`
`9
`
`at the same time. All wells are produced up open ended 2-3/8” production tubing landed in the heel
`section of the lateral.
`
`, ..., ... :~;-::r:~u
`/~
`I/
`
`•;,.nt
`
`,
`
`i\
`
`-1000
`
`Monitoring
`Well
`-500
`
`~tlitl, ri!,.::
`
`Example 1:
`The first project area includes six
`horizontal wells drilled parallel
`to each other with laterals spaced
`approximately 1,320 ft apart.
`Four new wells were drilled
`between two existing producers.
`Figure 11 shows
`the surface
`layout of the project.
`Figure 11 – Layout of the
`horizontal wells in the Example
`1 area. Geophones were run in
`the vertical section of
`the
`perimeter wells
`for
`all
`stimulation treatments and in
`the short lateral for the initial
`stimulation treatment on the
`other three horizontal wells.
`
`-1000
`
`-1500
`
`-2000
`
`Y-axis
`(ft)
`
`-2500
`
`-3000
`
`-3500
`
`-4000
`
`-4500
`
`1000
`
`K-alCiS
`(ft)
`
`2000
`
`/
`
`3000
`I
`
`_._,.J,w'
`
`--~-
`
`4000
`
`8
`
`Monitoring
`I
`Well
`r,, j:f•Nl: ~;orit(•"
`I
`-500
`\
`
`-1000
`
`Stage 1
`Stage 2
`Stage 3
`Stage 4
`Stage 5
`Stage 6
`Stage 7
`
`Treatment
`Well 2 &
`Monitoring
`Well for 1st
`two stages
`
`I
`Treatment
`Well 4
`
`Treatment
`Well 3
`
`Treatment
`Well 1
`
`-1000
`
`1000
`
`2000
`
`3000
`
`4000
`
`K-alCiS
`(ft)
`
`-1500
`
`-2000
`
`Y-axis
`(ft)
`
`-2500
`
`1
`\
`
`-3000
`
`-3500
`
`-4000
`
`-4500
`0
`
`N
`
`Example 1 project area perforation and stimulation design:
`(cid:120) Frac stages spaced every 500 ft along the lateral, with 5 to 7 stages per well
`(cid:120) Four perforation clusters per frac stage, spaced approximately 125 ft apart
`(cid:120) Fluid volumes of 10,000 bbls of Slickwater per frac stage
`100 mesh sand volume of 75,000 lbs/stage
`(cid:120)
`30/50 mesh sand volume of 200,000 lbs/stage
`(cid:120)
`Injection Rate of 80 bpm
`(cid:120)
`(cid:120) A total of 22 of the 25 stimulation stages pumped to completion
`
`In order to maximize the advantage of the simultaneous fracturing process, hydraulic fractures induced
`from individual wellbores must propagate towards each other. There were two suspected fracture
`orientations based on the strike of faults that were identified by surface seismic data. The orientation of
`the induced fractures would dictate the number of simultaneously pumped stages required. Seven
`pumping cycles would be required if the fractures were aligned east to west. Up to 13 pumping cycles
`would be required if the orientation was aligned with faults that had a strike of N56E. There was an
`additional concern that the azimuth of the induced fractures might change from stage to stage during the
`treatment because of the stress changes associated with faults.
`
`Prior to stimulation, wells were logged with a sonic tool, measuring axial, azimuthal and radial acoustic
`properties from dipole and monopole systems. The predicted direction of the maximum stress was
`between N79E and N92E, predominantly east-west, along all lateral sections measured. During
`stimulation, real-time microseismic monitoring and processing were utilized to confirm the direction of
`fracture propagation. The objectives of microseismic monitoring were:
`
`(cid:120)
`
`Identify the fracture orientation to maximize the interference between simultaneously pumped
`treatments from adjacent wellbores and adjust subsequent staging based on these results.
`
`IWS EXHIBIT 1047
`
`EX_1047_009
`
`

`

`Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/09HFTC/All-09HFTC/SPE-119635-MS/2707283/spe-119635-ms.pdf/1 by Robert Durham on 12 August 2022
`
`10
`
`SPE 119635
`
`Identify any effects of hydraulic fracture interference on fracture geometry.
`(cid:120)
`(cid:120) Better understand the role of geologic structure on the hydraulic fracture geometry.
`(cid:120) Determine the growth in fracture height.
`
`Three wells were used for microseismic monitoring during the project. Geophone arrays were placed in
`the vertical sections of existing wells located to the east and west of the four treatment wells. The
`distance from both vertical monitoring wells to the ends of the longest laterals was beyond which all but
`the very strongest microseismic events could be detected. Therefore, a third geophone array was placed
`in the horizontal section of the shortest of the four treatment well laterals and was used to monitor the
`first two treatment stages on the offset wells. The horizontal geophone array was removed following the
`second stages so that stimulation operations could begin on that well. The location of the geophone
`arrays with respect to the treatment wells is shown in (Figure11).
`
`Microseismic data for first two stages on the
`offset wells from the horizontal tool array is
`shown in Figure 12. The extension of the
`induced fracture networks from their respective
`perforation intervals was observed to be in an
`east to west direction. It is also possible to see
`clusters of microseismic events along a
`secondary azimuth oriented generally to the
`northeast. These events are near structural
`features identified with 3D seismic within and
`below the Woodford Shale and do not indicate
`a change in horizontal stress, but do show how
`structure can impact stimulation geometry.
`Figure 12 – Microseismic activity from the
`initial stimulation treatments in Wells 1, 3
`& 4 recorded from the horizontal geophone
`array in Well 2.
`The entire set of microseismic data acquired during the project is shown in Figure 13. There are two
`patterns of microseismic activity visible. Most of the stages produced fracture networks that were
`complex and do not have well defined azimuths. Some stages show well organized patterns of
`microseismic activity that are oriented east to west. The stages displaying this behavior originate from
`the two exterior wells and appear to indicate that asymmetric fracture extension towards the previously
`completed laterals to the east and west of the project area.
`
`The best example of interaction between simultaneously pumped fracture treatments is found during the
`sixth treatment stages. The effects of fracture interference on a fracture initiated in an exterior well,
`Treatment Well 1, and an interior well, Treatment Well 2, can be seen in Figures 14A through 14D.
`This is one of the few stages where an adequate volume of microseismic data was present to clearly
`illustrate the activity near the interior wells.
`
`The data is color-coded into four segments, which coincide with key elements of the pumping schedule.
`The first time period, the green events shown in Figure 14A, occurs while high near-wellbore pressures
`are present early in the treatment. Figure 14B additionally shows the blue events detected just prior to
`the time that the fractures appear to meet one another. Figure 14C adds the yellow events recorded up to
`the final cycle of proppant. Figure 14D adds the red events recorded through the final proppant cycle.
`
`IWS EXHIBIT 1047
`
`EX_1047_010
`
`

`

`Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/09HFTC/All-09HFTC/SPE-119635-MS/2707283/spe-119635-ms.pdf/1 by Robert Durham on 12 August 2022
`
`SPE 119635
`
`11
`
`-2000
`
`0
`
`X-axis
`
`(ft)
`2000
`
`4000
`
`400
`
`0
`
`-400
`
`-800
`
`-1200
`
`-1600
`
`-2000
`
`-2400
`
`-2800
`
`-3200
`
`-3600
`
`-4000
`
`-4400
`
`-4800
`
`.•
`
`'
`
`.· .. · , . - •· ........ , ... ..
`..
`
`! ~
`
`•
`
`I
`
`.
`
`. ...
`
`~ ..
`
`. ·=- •
`
`.i
`
`.
`
`• .. ·
`
`Stage 1
`Stage 2
`Stage 3
`Stage 4
`Stage 5
`Stage 6
`Stage 7
`
`0
`
`400
`
`0
`
`-400
`
`-800
`
`-1200
`
`-1600
`
`-2000
`
`-2400
`
`-2800
`
`-3200
`
`-3600
`
`-4000
`
`-4400
`
`Y-axis
`(ft)
`
`-4800
`
`N
`
`0
`
`Figure 13 – All of the
`Microseismic
`activity
`recorded from all 25
`stimulation treatments.
`Variations
`in
`microseismic
`activity
`are
`apparent with
`complex
`networks
`in
`common
`the
`toe
`stages and more planar
`events
`in
`the heel
`stages.
`
`Growth
`towards
`the outlying
`existing wellbores was
`frequently
`seen once
`the
`fractures
`from
`offset wells began to
`interact with one and
`other.
`
`-2000
`
`0
`
`2000
`(ft)
`
`X-axis
`
`4000
`
`The fracture network initiated from Treatment Well 1 appears to shift to the west side of the lateral,
`away from the region of interference, and extends toward the NW Monitoring Well lateral after the
`microseismic activity from Treatment Wells 1 & 2 merge. The rate of microseismic events generated
`from this