SPE
`
`SociatuofPatrcIietmEriyteer-3
`
`SPE 19090
`
`Production and Stimulation Anaiysis- of Multiple
`Hydraulic Fracturing of a 2,000-ft Horizontal Well
`by A.B. Yost ii, U.S. DOEIMETC, and W.K. Overbey Jr.. BDM Engineering Services Co.
`SPE Members
`
`This paper was prepared for presentation at the SPE Gas Technology Symposium held In Dallas. Texas, June 7-9. 1989.
`
`This paper was selected ior presentation by an SPE Program Committee following review cl Information contained in an abstract submitted by the nuthor(a). contents oi the paper.
`as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(e). The material, as presented. does not necessarily reflect
`are subject to publication review by Editorial Committees oi the Society
`. any position or the Society oi Petroleum Engineers. its oiiicers, or members. Papers presented at SPE meetings
`is restricted to an abstract oi not more than 300 words. illustrations may
`not be copied. The abstract should contain conspicuous acknowledgment
`oi Petroleum Engineers. Permission to copy
`at where and by whom the paper is presented. Write Publications Manager. SPE. P.O. Box 833836. Richardson. TX 75083-3836. Telex. 730989 SPEDAL.
`
`
`
`
`
`
`and again in 1976.!“
`of iiest Virginia in 1972(3)
`These wells obtained inclinations of 43°
`and
`52°
`respectively.
`but
`production
`results were mixed
`and
`not
`convincing
`of
`the
`potential
`for
`the
`
`technique.
`
`
`
`
`
`
`The stimulation aspects of horizontal drilling
`represent a technical challenge in tight formations
`where the horizontal wellbore may not always provide
`adequate economic production. Little or no published
`literature exists
`on
`the mechanics of hydraulic
`fracturing of horizontal wells.
`Typically,
`long
`horizonta wells are completed with preperforated
`liners to preserve hole integrity.
`The disadvantage
`of this type of completion is the associated risk
`of pulling the liner at a later stage of production
`history and re-running and cementing a casing string
`such
`that
`selective
`placement of
`fracturing of
`fluids can be accomplished.
`
`
`zone
`isolation
`is
`approach
`alternative
`An
`accomplished by the installation of external casing
`packers
`and port collars
`as
`an
`integral part of
`a casing string in the horizontal
`section.
`Such
`a
`completion
`arrangement
`provided
`stimulation
`intervals with ready-made perforations for injecting
`fracturing
`fluids
`in
`an
`open
`hole
`fracturing‘
`condition behind pipe.
`This was
`the method of
`completion used in this 2000 foot horizontal well
`- to avoid the problems of formation damage associated
`with
`cementing
`and
`to
`eliminate
`the
`need
`for
`tubing-conveyed perforating of
`numerous
`treatment
`intervals.
`
`ABSTRACT
`
`
`
`
`
`
`The performance of multiple hydraulic fracturing
`treatments along a 2000-foot horizontal wellbore was
`completed in a gas bearing, naturally-fractured shale
`gas
`reservoir
`in Wayne County. West Virginia. Pre-
`frac flow and pressure data, hydraulic fracturing
`treatments. and post-stimulation flow and pressure
`data
`form the
`basis
`from which
`a
`comprehensive
`analysis was
`performed.
`Average
`field production
`from 72 wells was used as baseline data for
`the
`analysis.
`Such data was used to show the significance
`of
`enhanced production from a horizontal well
`in
`a field that was partially depleted.
`
`
`
`
`The post-frac stabilized flow rate was 95.000
`feet
`per
`day
`(mcf/d)
`from 2000
`feet of
`cubic
`horizontal borehole. Under current reservoir pressure
`conditions.
`the horizontal well produced at a rate
`7
`times greater
`than the field current average of
`13 mcfd for stimulated vertical wells. This increase
`in gas production suggests
`that horizontal wells.
`in strategically placed locations within partially
`depleted
`fields,
`could
`significantly
`increase
`reserves.
`
`
`
`to
`stimulations were designed
`series of
`A
`open and propagate the many known natural fractures
`that existed along the 2000 foot length of horizontal
`wellbore.
`The
`stimulations were
`also
`designed
`to induce
`fractures
`in the formation as well
`as
`propagate natural fractures by manipulating pressure
`and injection rates.
`T
`—T
`T
`T
`T_
`T
`T
`9
`
`
`
`
`BACKGROUND
`
`
`investigating
`been
`The Federal Government has
`the application of high angle and horizontal drilling
`in tight
`formations
`for more
`than 20 years.
`The
`value of high angle drilling and multiple hydraulic
`fracturing from an
`inclined or horizontal borehgle
`for maximizing production was
`recognized in 1969.
`The first test of the concept was performed by Mobil
`Oil Corporation in the Austin chalk in which a well
`inclined to 6 °
`through the pay zone was stimulated
`three
`times. 2)
`The U.S.
`Bureau
`of Mines.
`in
`cooperation with Columbia Gas and consolidated Natural
`Gas. drilled inclined wells
`in the Devonian shales
`
`RC_RAP00004061
`Exhibit 2026
`
`IPR2016-01517
`1 of 14
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`

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`
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`PRODUCTION AND STIMULATION ANALYSIS OF
`MULTIPLE HYDRAULIC FRACTURING OF A 2000-FOOT HORIZONTAL HELL
`
`SPE 19090
`
`INTRODUCTION
`
`The U.S. Department _of Energy's Morgantown
`Energy Technology Center contracted with the
`BDM
`Corporation to select
`a site. drill.
`core.
`log.
`complete,
`test
`and stimulate a horizontal well
`in
`the Devonian
`shales.
`The
`area
`selected for
`the
`site was
`in Lincoln District. Wayne County, Nest
`Virginia;
`as
`shown
`in Figure
`1.
`Upon
`completion
`of drilling operations which were conducted between
`October
`and December.
`1986.
`the RET
`#1 well was
`completed.
`as
`shown’
`in Figure +2.
`by
`installing 8
`external casing packers
`(ECPs) as
`an integral part
`of the 4-1/2 inch casing string along with 14 sliding
`sleeve ported collars which were used to provide
`access
`to the formation in lieu of perforations.
`The casing string was not cemented in place. but
`anchored by one external casing packer located inside
`the 8-5/8 inch casing.
`A cement packer was
`included
`in the string as a backup system in case the ECPs
`failed to inflate; however, 7 of the 8 ECPs pressure
`tested okay.
`and
`thus
`7
`separate open hole zones
`were available for testing.
`
`conducted in
`test was
`frac
`One 4-stage data
`Zone 6 to obtain data on breakdown pressure. closure
`pressure,
`fracture gradient
`and
`stress
`ratio for
`use in designing the primary stimulation test series
`for
`the well.
`Three
`stimulations were
`conducted
`in Zone
`1
`to determine the nwst suitable fluid and
`injection rate;
`this
`informatigg was
`reported in
`SPE Papers
`17759 5
`and
`18249
`3.
`Evaluation of
`the
`first
`three
`fractures
`pointed the direction
`for
`design
`and
`implementation .of
`the
`final
`two
`stimulations
`conducted
`on
`the well.
`The
`results
`of
`these
`stimulations
`and
`the performance of
`the
`well
`upon
`completion of all
`stimulations
`is
`the
`subject of this paper.
`
`Pre- and Post—Frac Hell Testing and Analysis
`
`initiated
`testing phase was
`initial well
`The
`with a 640-hour pressure build-up test of the entire
`2160
`feet
`(excluding ECPs) of open-hole behind 14
`port collars opposite
`7
`isolated zones.
`Surface
`wellhead
`gauge
`pressure
`and orifice meter
`run
`pressures were used to establish reservoir, permea-
`bility.
`
`are
`techniques
`analysis
`transient
`Classical
`not strictly applicable to the horizontal wellbore
`geometry, but was used to obtain initial estimates
`of
`reservoir properties
`to be used as
`a starting
`point for the simulation analysis.
`
`rock pressure
`initial/estimated reservoir
`The
`was 192 psia from extrapolation of the Horner plot.
`It
`is important
`to note that
`the average reservoir
`pressure
`in
`the
`surrounding wells was determined
`to be between 188-200 psia based on a 7-day pressure
`build-up test.
`The value of Kh was calculated from
`the following equation:
`
`m
`
`where:
`
`= slope = 15863.2
`m
`qavg = average gas production rate. mscfpd
`= formation permeability. md .
`7
`_
`= qas viscositv. CD evaluated at initial
`
`21
`
`T
`h
`
`- gas-low deviation factor evaluate
`@ initial pressure
`= formation temperature, degrees R.
`= formation thickness. ft.
`
`24
`(h -
`interval
`shale
`the whole
`Assuming
`ft) to be productive and with a formation temperatui
`of 93°F. stabilized gas production rate of 35 mcfpc
`and
`the
`slope
`from the Horner plot of
`15863.
`psia‘/cycle;
`therefore formation permeability (1
`is calculated as follows:
`
`K ,
`
`1537
`
`0.980
`34 0.0107
`(1s3s3.2)(247)
`
`553
`
`, 0_o82 ma (2,
`
`for permeabilii
`value
`estimated
`above
`The
`is similar
`to those of a conventional well
`in
`low permeability
`reservoir with
`a
`very
`larg
`fracture.
`As discussed previously.
`these analyse
`are
`not
`strictly applicable
`to
`the
`horizonti
`wellbore geometry. but one may assume a horizonta
`wellbore to represent a vertical well with a long
`finite conductivity fracture.
`
`I
`for RET #1.
`Following the build-up test
`attempt was made
`to isolate and individually te:
`each of the seven zones representing a total interva
`of
`2211
`feet
`(3803-6014
`feet).
`A
`combinatic
`straddle tool was designed to facilitate the openir
`and closing of port collars
`in seven individua
`zones.
`
`te:
`build-up
`pressure
`hour
`twenty-four
`A
`followed by a 24-hour drawdown
`for each zone he
`performed using the combination straddle tool.
`1
`order
`to estimate permeability for
`each isolate
`zone.
`a
`three-dimensional.
`dual porosity,
`singl
`phase gas
`simulator
`reservoir model was used 1
`determine permeability values
`shown
`in Table
`1
`The average pre-stimulation permeability was 0.06!
`md.
`
`pressui
`the
`of
`analysis
`stimulation
`Post
`determinatic
`resulted in
`build-up/drawdown
`data
`of average reservoir pressure values. skin value:
`and
`average permeability values
`for
`the varioi
`zones with the different stimulation jobs. Resuli
`of the pressure build-up analysis using the‘variot
`techniques are summarized in Table 2.
`
`wev
`techniques
`analysis
`pressure
`Various
`post-stimulatic
`to
`obtain
`estimates
`of
`used
`build-up
`dai
`permeability.
`Selective
`pressure
`were analyzed using type-curve matching. Horner'
`technique,
`and
`a
`newly-developed technigug know
`as the Rectangular Hyperbolic Method (RHM)
`» )-
`
`Post-stimulation analysis for Zone 6 indicate
`a post-frac permeability of 0.1835 md. but an averag
`reservoir pressure of 205 psia using history matchir
`process.
`Analysis of
`the pressure build-up dai
`using Horner's
`technique was not possible due 1
`the
`fact
`that
`the
`stabilized flow period pric
`to the build-up test was very short. hence accurai
`results
`of pressure
`and
`permeability could
`nt
`be determined.
`Instead.
`type-curve matching an
`implemented for
`the analysis and an average per
`meability value was calculated to be 0.1795 nu
`Both
`techniques
`indicated similar
`results. _hen¢
`
`RC_RAP00O04062
`Exhibit 2026
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`IPR2016-01517
`2 of 14
`
`

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`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`1 was stimulated by 3 different frac jobs
`Zone
`at various treating pressures and rates with nitrogen,
`liquid C02. and nitrogen-foam with proppants. well
`testing procedures
`and data analysis were performed
`for each job.
`In the first
`job when the well was
`stimulated with N2. pressure build-up data indicated
`a
`reservoir pressure of
`290 psia which
`is
`above
`the
`current
`average
`reservoir
`pressure
`(185-200
`psia
`as
`determined
`by
`the
`7-day
`shut-in test).
`1
`This
`is due to the fact
`that Zone
`(N2 frac) was
`still overpressured by the amount of
`inerts present
`in the gas mixture at
`the time of
`testing.
`The
`simulation of
`the pressure buildup data using G3DFR
`model
`estimated an
`average permeability equal
`to
`0.0477 md. Analysis of ‘the pressure build-up data
`following the second job ( C0
`frac)
`indicated a
`permeability value of 0.0480 and
`.0435 using Horner's
`technique and history matching.
`respectively. Using
`Horner's technique.
`reservoir pressure was estimated
`at
`182 psia. Results of build-up pressure analysis
`following
`the
`third
`job
`(N2-foam-proppant
`frac)
`indicated the presence of
`a dual porosity system
`with the middle region having a slope one-half that
`of
`the late region on
`the build-up curve which is
`characteristic of
`a
`dual
`porosity system in the
`Devonian
`shale.
`The
`average
`permeability
`was
`estimated at 0.090 md.
`and
`the
`average pressure
`was determined to be 184 psia.
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`SPE 19090
`
`Albert B. Yost II and William K. Dverbey. Jr.
`
`3
`
`.303 md. average reservoir pressure
`permeability was
`was 178 psia, and skin factor was >0.00.
`A positive
`skin
`value was
`calculated for Zones
`5
`and 8.
`indicating a
`slightly damaged well.
`A drop
`in
`the skin factor
`from -2.87 for
`the overall well
`to a more positive value for Zones
`5 and 8 could
`be attributed to:
`
`
`
`encountered
`problem that was
`sand
`the
`(a)
`during the clean-up process. hence indicating damage
`to the wellbore;
`in the analyzed horizontal
`(b)
`the decrease
`section of the wellbore from 2160 feet (all zones)
`pre—stimulation
`analysis,
`to 932
`feet
`(Zones
`5
`and 8) post-stimulation analysis.
`
`The accuracy of these results was tested using
`three different
`techniquesgv
`Estimating values of
`average reservoir pressure (P)
`using
`the
`RHM
`technique
`has
`an
`advantage over
`the conventional
`methods
`because
`knowledge
`of
`neither
`the
`well/reservoir
`configuration
`nor
`the
`boundary
`a
`condition
`is
`required
`for
`routine
`build-up
`analysis.
`However.
`conventional methods
`such
`as
`Horner's technique. when correctly used. will provide
`superior
`results of Kh
`and
`S values
`compared to
`the
`RHM technique.
`Therefore.
`values of
`K
`and
`S for Zones 5 and 8 are believed to be in the range
`of 0.300 md
`to 0.492 md
`and
`-0.881 to 1.386.
`respectively, whereas the average reservoir pressure
`_is calculated at 178 psia based on the RHM technique.
`
`well Stimulation Summary
`
`The objective of stimulation research in the
`horizontal wellbore was
`to determine the recovery
`efficiency of
`the natural
`fracture systeni and the
`effects
`expected
`from hydraulically
`fracturing
`the well whenever multiple
`fractures would
`be
`induced.
`To determine the most effective wellbore
`stimulation under these conditions, it was necessary
`to use a systematic approach to examine the effects
`of
`various
`combinations of
`four
`factors. which
`were:
`(1)
`type of fluid (e.g., gas.
`liquid.
`foam);
`(2)
`fluid injection rate;
`(3)
`volume of
`fluid
`injected;
`and
`(4)
`bottomhole
`treating pressure.
`Following each stimulation.
`flow rate and buildup
`test
`data
`were
`used
`to
`determine
`permeability-thickness
`product
`and
`flow
`rate
`improvement ratio.
`Key stimulation issues identified
`were:
`
`fractures
`during a
`
`be
`could
`that
`single hydraulic
`
`number of
`the
`(1)
`propagated
`and
`opened
`fracture pumping event;
`(2) whether proppant would screen out easier
`in a horizontal well;
`(3)
`understanding what determines which natural
`’fractures are propagated;
`fracture diagnostic
`(4)
`determining the best
`system to use in a horizontal well;
`(5)
`understanding
`how
`to
`and the volumes required;
`need or value of
`(6)
`understanding the
`volumes when
`treating multiple
`fractures at
`same time.
`
`place
`
`proppants
`
`pad
`the
`
`The overall
`
`technical approach was to:
`
`‘g
`
`(1)_ induce
`
`_multiple__ hydraulic
`
`fractures.
`
`
`
`
`
`
`
`using
`stimulated
`were
`4
`and
`2-3
`Zones
`period,
`cleanup
`Following
`the
`Ng—foam/proppant.
`Zones 2-3 and 4 produced at
`a rate of 62 mcfd for
`a period of
`35 days.
`Pressure build-up analysis
`using Horner's
`technique
`indicated
`an
`average
`reservoir permeability of 0.1505 mo and an‘ average
`pressure of 182 psia.
`
`stimulated using N2—foam/
`and 8 were
`5
`Zones
`proppant. Analysis‘ of pressure build-up data has
`indicated an average reservoir pressure of 178 psia
`and an average permeability of 0.310 md.
`
`
`
`
`
`
`
`
`
`
`
`
`5 and 8 were
`Pressure build-up data from Zones
`analyzed
`using
`type-curve
`matching.
`Horner's
`technique.
`and
`the Rectangular Hyperbolic Method
`(RHM).
`Values
`of
`average
`reservoir
`pressure,
`formation
`flow capacity.
`and
`skin
`factor were
`estimated.
`
`
`
`
`
`
`
`
`
`to the complexity of production from the
`Due
`Devonian shale and the existence of a dual porosity
`system.
`a
`log-log plot of AP?
`(P2wsPwf). and d(AP2)
`(derivative
`of
`delta
`pressure
`squared)
`versus
`Effective Time
`(Ate) was generated; where Ate
`t/(1+ At/tp). At
`=
`shut-in time
`(days).
`and to
`flowing time, 20 days.
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`instead of
`approach
`use of pressure-squared
`The
`reservoir analysis
`is
`the pseudo pressure for gas
`proven
`to be valid for
`reservoir pressures
`less
`than 2000 psia.
`A Flopetrol Johnson/Schlumberger-type
`curve was used for
`infinite acting reservoir, with
`' double
`porosity
`behavior
`(pseudo
`steady
`state
`interporosity flow). wellbore
`storage.
`and
`skin.
`The permeability was calculated from match points
`at
`.492 md and skin factor was calculated at 1.386.
`Using
`the Horner
`technique,
`the permeability was
`.327 md, average reservoir pressure was
`177 psia.
`and skin factor was
`-0.881;. The Rectangular Hyper-
`bolic Method
`(RHM) was —also utilized; to estimate
`
`
`
`
`
`
`
`
`
`
`
`
`
`RC_RAPO00O4063
`Exhibit 2026
`
`IPR2016-01517
`3 of 14
`
`

`
`
`
`PRODUCTION AND STIMULATION ANALYSIS OF
`MULTIPLE HYDRAULIC FRACTURING OF A 2000-FOOT HORIZONTAL WELL
`
`SPE 190
`
`how many
`determine
`(2)
`were induced in the borehole;
`fracture
`(3)
`evaluate
`hydraulic
`a horizontal well
`in shale formation;
`(4)
`establish need or lack of need for proppant
`in low stress ratio (minimum horizontal
`to vertical)
`areas.
`
`design
`
`for
`
`and where
`
`fractures
`
`
`
`m
`80
`flow rate of
`open
`Initial
`wellbore.
`the well was making
`declined rapidly so that
`baseline rate after 20 days.
`
`stimulation was
`full—scale
`second
`The
`conducted in Zone 1 since it was felt that a be
`comparison of
`fluids would be more
`realistic
`meaningful
`if all
`tests were conducted in the
`zone.
`The
`second fluid was
`liquid C02. which
`a cryogenic fluid. pumped at 0°F. and at press
`about
`200
`psi
`above
`closure
`pressure.
`pm
`stimulation was
`conducted
`in two
`stages.
`at two different rates, with considerable differ
`in the results in terms of the number of fract
`inflated.
`More
`fractures were
`inflated at
`higher injection rates.
`In addition,
`the produc
`improvement ratio was higher with C0 when comp
`to nitrogen gas and nitrogen foam as f uids.
`Ini
`production was more than 250 mcfpd, however, a
`more
`than 50
`days of production.
`the
`rate
`declined again to the original
`rate of 2.2 me
`One plausible explanation is that without propp
`the
`fractures
`opened
`up
`and
`simply closed I
`time.
`
`losing production bec
`This experience of
`of closing fractures led us to conclude that prop
`was a necessary ingredient in the stimulation des
`The
`third stimulation was
`a
`small volume nitr
`foam stimulation pumped
`in two
`stages
`(#1
`#2 proppant), but at the same rate of 10 bbls/min
`Two different
`radioactive
`tracers were
`used
`determine where
`fractures were
`being
`propag
`along the wellbore.
`Forty-six (46)
`fractures ‘
`opened and propagated. After cleanup. the produc
`was sustained due to the use of proppant.
`
`fourth stimulation was conducted in
`The
`4
`combined. After
`the
`results of
`2-3 and
`#3,
`it was felt
`that we needed to see if a l
`volume
`fracture
`over
`about
`the
`same
`length
`wellbore would
`give
`a proportionate
`increase
`production rate.
`The large volume fracture consi
`of 4500 gallons of
`liquid C03 as a prepad. 44
`gallons of pad.
`and 90.000 gallons of 80-qua
`foam containing 250,000 pounds of sand (2.5 lbs]
`all
`pumped at 50 gallons per minute downhole
`rate.
`There were
`some difficult
`sand
`cle
`problems
`after
`this
`frac
`job.
`The
`improve
`ratio of stimulated production to natural produc
`was 3.1 to 1.
`Zone
`4 was
`the zone with a
`natural
`show of 2.16 million scf of gas per
`and was a major fault and fracture zone.
`A sum
`of
`the
`stimulation treatment
`schedule for No
`is
`shown
`in Table
`3
`and
`the production his
`after stimulation is shown in Figure 3.
`
`fracture was a scaled-
`The fifth and final
`The final
`treatment cov
`version of Frac No. 4.
`almost
`twice as much borehole (930 feet)
`in Z
`5 and 8 versus 590 feet
`in Zones 2-3 and 4 du
`Frac
`#4,
`but
`pumpeds only
`105,000
`gallons
`85—quality foam and 150.000 pounds of
`sand a1
`barrels per minute
`rate.
`Sand cleanout prob
`were
`not
`as
`severe
`this
`time.
`Gas
`produc
`improvement
`ratio for
`the combined zones was
`to 1. which was
`an
`improvement over Frac #1
`Zones 2-3 and 4. but not
`in the same class as
`#3 with its 15.5 to 1 improvement ratio.
`
`to
`had
`design
`fracture
`hydraulic
`Conceptual
`consider
`the strong interaction between the natural
`fracture orientation of N37°E
`and N67°E
`and
`the
`predicted
`induced _fracture
`trend
`of N52°E.
`In
`addition,
`the consideration of other
`joint
`systems
`having
`nearly
`parallel
`orientations which would
`either
`act
`as
`leakoff
`areas or actually accept
`fra;:ure fluid under propagating conditions.
`Each
`zone available for stimulation had numerous natural
`fractures which would
`accept
`fracturing
`fluid.
`An open hole type completion technique using external
`casing packers and port collars was used to isolate
`zones with different stimulation potential.
`
`fracturing fluids.
`handling of
`The mechanical
`proppants.
`and
`tracer materials along a
`2000
`foot
`horizontal wellbore offers
`a
`technical
`challenge
`relative
`to
`developing
`a
`systematic
`approach
`to
`conducting fracturing experiments
`in selected zones
`without causing any permanent damage to the wellbore
`that
`would
`prevent
`execution
`of
`remaining
`stimulations.
`The
`rationale
`used was
`to
`select
`the lowest productive zone(s)
`to conduct experiments
`in and
`subsequently reserve
`the better
`zones
`for
`full-scale stimulation.
`Zones 6 and 1 were selected
`for
`testing.
`Zone
`6
`had very few fractures
`and
`was
`selected for
`the mini
`frac tests. while Zone
`1 had many fractures and was selected for frac fluid
`testing.
`The overall
`stimulation rationale focused
`on the following considerations:
`
`to propagate natural
`(1) Primary design was
`fractures with a slight difference in orientation
`from principal stress orientation.
`allows
`2)
`Injection at
`low rates
`fluid to
`select
`pre-existing
`natural
`fractures
`to
`be
`propa ated.
`(3)
`Injection
`at pressures which will
`keep
`the fracture(s) from growing out of zone.
`(4)
`By
`starting off at
`low injection rates
`and not exceeding 200 psi
`above closure pressure
`with
`average
`BHTP.
`natural
`fractures would
`be
`propa ated.
`(5)
`By
`increasing injection rates. additional
`fractures would be induced which would likely create
`network
`of
`interconnected
`fractures
`with
`a
`orientations of N37°E, N52°E, and N67°E.
`
`6 using a
`fracs were conducted on Zone
`Data
`From this
`computerized
`data
`acquisition system.
`(or
`parting
`series
`of
`tests.
`closure
`pressure
`pressure) was determined to be 850 and 1050 psi.
`The
`lower pressure is postulated'to be the closure
`pressure
`for
`a natural
`fracture,
`and
`the higher
`pressure
`for
`an
`induced
`fracture.
`The
`fracture
`gradient was calculated to be 0.25 psi/ft of depth
`for Zone 6.
`The ratio of minimum horizontal stress
`to vertical stress was calculated to be 0.22.
`
`on
`five full-scale stimulations
`first of
`The
`the horizontal well was‘ conducted on Zone
`1 with
`_ nitrogen ‘gas —fluid..
`The gas was
`injected at
`slow ’
`
`RC_RAPO00O4064
`Exhibit 2026
`
`IPR2016-01517
`4 of 14
`
`

`
`
`
`SPE 19090
`
`Albert B. Yost II and William K. Overbey. Jr.
`
`5
`
`A summary of the stimulation treatment schedule
`for No. 5 is shown in Table 4 and the post-stimulation
`production is shown in Figure 4.
`A summary of all
`stimulation treatment
`fluids.
`rates.
`volumes.
`and
`diagnostics is shown in Table 5.
`
`Productivity Improvement
`
`in the
`frac jobs
`the different
`a result of
`As
`enhanced in all
`zones.
`the production was
`various
`This
`improvement
`in production is reflected
`zones.
`increase in flow rates and
`a decrease
`in
`in the
`skin factor values.
`Following stimulation No.
`5.
`frac sand and plugs were
`removed from the entire
`2000
`foot
`section
`and
`the well was
`placed
`on
`production at
`155 mcfd.
`Both reservoir simulation
`and
`average current day production from 72 wells
`in the field indicate that stimulated vertical wells
`are currently averaging 13 mcfd. Pre-frac stabilized
`flow rate from the horizontal well was
`35 mcfd.
`A
`summary
`of
`individual
`stimulation
`improvement
`ratios for
`frac No.
`1
`and 2 went
`to zero beyond
`40 days of
`flow due to the lack of proppant
`in the
`treatment.
`Overall,
`the productivity
`improvement
`ratio ranged from 2.9 to 11.8 based on 40 days of
`production.
`
`in skin value is a qualitative
`improvement
`The
`measurement of
`the productivity improvement.
`In
`addition.
`this
`improvement
`is
`indicative of
`the
`conditions around the wellbore which is translated
`into an
`increase in the surface area contributing
`to production due
`to the stimulation process.
`A
`negative skin indicates a stimulated wellbore; hence.
`a successful stimulation.
`
`the pre-stimulation
`horizontal well.
`the
`In
`skin value was estimated at -2.87 due to the geometry
`of
`the wellbore (horizontal well). since horizontal
`wellbores are equivalent
`to astimulated reservoirs.
`The
`skin values
`showed
`an
`improvement
`for Zones
`1. 2-3. and 4. whereas a decrease in skin from -2.87
`to -0.881 was detected in Zones 5 and 8.
`This could
`be
`due
`to presence of
`sand
`in the wellbore or
`formation damage as a result of the frac job.
`
`An additional method of analyzing stimulation
`effectiveness
`is
`the
`examination of permeability
`improvements. Table 7 provided data on the post-frac
`permeability compared to the pre-frac permeability.
`Improvements
`ranged from 1.79 to 4.4 with an average
`ratio of 3.2.
`
`The production decline curve for the horizontal
`is
`shown
`in Figure
`5.
`The stabilized flo
`well
`rate was 95 mcfd representing a 2.7 fold increase
`as a result of hydraulic fracturing.
`The horizontal
`well
`is- currently producing 7
`times more
`than a
`vertical well
`based on simulation and the 72-well
`average flow rate for the field.
`
`to predict/projec
`used
`G3DFR model was
`The
`a 20-year history of production based on estimated
`_values of
`reservoir pressure.
`formation thickness,
`and
`average
`permeability.
`The
`average
`reservoi
`pressure and formation thickness were kept
`constan
`at 182 psia and 247 feet,
`respectively. due to th:
`fact
`that
`geologic
`and
`engineering
`data werz
`sufficient
`to
`accurately
`estimate
`these
`values.
`L- n nan ._,n
`Post-stimulation
`permeability
`was
`calculated
`at:
`
`a permeability value of
`is believed that
`It
`is
`representative
`of
`the
`formation's
`md
`0.2
`permeability.
`when
`permeability
`anisotropy
`(R)
`equals 1:1,
`the
`first year's
`average production
`rate was projected at 83 mcfd. when R = 1.2 (Kx:Ky).
`the first year's average production rate is projected
`at 97 mcfd.
`Plots of cumulative production versus
`time
`for different
`anisotropy
`ratios
`are
`shown
`in Figure 6.
`In addition,
`a plot of
`the 20-year
`projected
`production
`rate
`versus
`time
`is
`shown
`in Figure 7.
`
`the
`to evaluate
`used
`G3DFR model was
`The
`to
`location prior
`production from the
`potential
`drilling the Recovery Efficiency Test No.
`1 well
`and was
`also used to predict production of
`the
`well after drilling and stimulation was completed.
`Figure
`8 projects
`20 year
`cumulative production
`for
`the RET #1 well utilizing developed parameters
`from well
`testing of
`180 psia pressure.
`Using
`the
`full
`reservoir
`thickness
`of
`247
`feet
`as
`productive reservoir, we found that we had to reduce
`the permeability to an average of 0.09 md to match
`the
`current
`rate of production.
`This
`indicates
`that
`there are most
`likely heterogeneities in the
`fracture system and
`that
`the
`flow path to the
`wellbore
`is not consistent.
`It
`is
`likely that
`the
`fracture
`permeability changes with
`time
`as
`fractures
`slowly close as pressure declines with
`production.
`This would
`seem to be one argument
`in favor of holding a back pressure on the formation
`during production.
`
`Figure 9 compares the final projected production
`and decline curve with the pre-drilling estimate.
`The difference
`in the projections was primarily
`the difference in pressures used.
`The pre-drilling
`model
`used 350 psi
`reservoir pressure, while the
`post-drilling projection used 180 psia. Pre—drilling
`model studies also projected a vertical well. drilled
`at
`the site where the horizontal well was drilled.
`would produce 80 mmcf
`in 20 years. This comparison
`indicates
`the horizontal well
`should produce 7.8
`times more gas
`than a vertical well drilled at
`the same location.
`
`CONCLUSIONS
`
`1.
`
`2.
`
`3.
`
`4.
`
`in fractured
`foot horizontal well
`2000
`This
`shale
`has
`successfully demonstrated
`Devonian
`folds
`of_
`increase
`in production as
`numerous
`compared to vertical wells in a pressuredeplete-
`producing field.
`
`successfully
`improvements were
`Productivity
`actual
`flow rates.
`evaluated
`by
`build-up
`analysis, and skin factor calculations.
`
`the most extensively
`represents
`This project
`documented zone-to-zone production and stimu-
`lation testing of
`a
`long horizontal well
`in
`a naturally-fractured gas reservoir.
`
`long horizontal drilling and multiple
`Both
`.stimulations
`are
`required
`to
`achieve
`high
`folds of increase in production.—
`
`
`
`HiJ3MiLi*Wl~1
`
`RC_RAPOOOO4065
`Exhibit 2026
`
`IPR2016-01517
`5 of 14
`
`

`
`
`
`Yost. A.B.
`II. N.K. Overbey, Jr., D.A. Hilki
`and C.D.
`Locke.
`"Hydraulic Fracturing of
`Horizontal
`Nell
`a Naturally-Fractu
`Reservoir:
`for Multiple Fract
`Case Study
`per
`17759, presented at
`Design".
`SPE
`Pa
`Tehcnology Symposium, June, 1988.
`
`Jr.. A.B. Yost
`D
`and
`II.
`Overbey. H.K..
`Multiple Hydraulic Fractu
`Wilkins.
`"Inducing
`from a Horizontal Hellbore".
`SPE Paper
`182
`presented at 63rd Annual Technical Conferen
`Houston. Texas. October 2-5, 1988.
`
`Hasan. A.R.
`"Pressure Bui
`and Kabir, C.$.
`A- Sim
`up Analysis:
`plified Approach".
`J
`January 1983, 178-188.
`
`Salamy, S.P.,
`J
`C.D. Locke. w.K. overbey.
`A.B. Yost II.
`"Four Pressure Build-up Analy
`lied
`Horizontal
`and Verti
`Techniques App
`Wells with Field Examples,"
`SPE #19101,
`p
`sented at
`the Gas Technology Symposium, Dall
`Texas. June 7-9, 1989.
`
`
`
`
`
`
`"Drilling
`and N.M. Ryan.
`Jr.
`Dverbey, W.K.,
`Stimulate
`a Directionally Deviated Hell
`to
`Gas Production from a Marginal Reservoir
`in
`Southern West Virginia." MERC/TPR-76/3 (1976).
`
`
`
`"Drilling
`R.N. Metzler.
`and
`McManus, G.R.
`
`Stimulate
`a Directionally Deviated ,well
`to
`
`Gas Production from a Marginal Reservoir Near
`
`cottageville. west Virginia."
`Final
`Report
`
`Under ERDA Contract E(461)-8047 with Consolidated
`Gas Supply Corporation (1979).
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`Table 1
`
`Pre-Stimulation Pressure Build-Up and Drawdown Test Resul
`Ret No. 1 - Wayne County, West Virginia
`I
`.
`
`Length
`_(iL)__
`
`~24-Hour
`Build-Up
`1.0.3131
`
`Permeabi|ity*
`__1mdL___
`
`Flow Rate“
`(mgfg)
`
`2.2
`
`4.4
`
`16.7
`
`4.4
`
`2.2
`
`0 5
`
`.2
`
`0.031
`
`0.078
`
`0.098
`
`0.073
`
`0.078
`
`0.037
`
`0.068
`
`TOTAL:
`
`35.1 mcfd
`
`404
`
`41 7
`
`1 82
`
`640
`
`1 35
`
`90
`
`292
`
`54
`
`75
`
`68
`
`73
`
`74
`
`74
`
`83
`
`.
`
`_e@
`
`1
`
`2-3
`
`4
`
`5
`
`6
`
`7
`
`8
`
`* Predicted by reservoir simulation model G3DFR
`"* 24-hour flow rate test after pressure build-up test
`
`RC_RAP00004066
`Exhibit 2026
`
`IPR2016-01517
`6 of 14
`
`
`
`PRODUCTION AND STIMULATION ANALYSIS OF
`SPE 1909
`MULTIPLE HYDRAULIC FRACTURING OF A 2000-FOOT HORIZONTAL HELL
`5
`
` REFERENCES
`"Natural
`1.
`Pasini, J. III. and H.K. Overbey, Jr.
`Their
`and
`Induced
`Fracture
`Systems
`and
`Application to Petroleum Production." SPE Paper
`2565
`presented
`at
`SPE Meeting
`in Denver.
`Colorado.
`(May. 1969).
`
`
`and Glenn. E.E.,
`Strubhar, M.K., Fitch, J.L.,
`
`
`
`
`Jr.
`"Multiple. Vertical
`Fractures
`from an
`
`
`Inclined wellbore -- a Field Experiment," Paper
`
`
`SPE
`5115
`presented
`at
`SPE-AIME
`49th Annual
`
`
`F311 Meeting, Houston, Texas, October
`6-9,
`
`4.
`
`
`
`5.
`
`
`
`
`
`
`
`
`
`
`

`
`
`
`Comparison of Pre- and Post-Frac Testing Results
`
`Table 2
`
`Frac
`Number
`
`Zonom
`
`M
`(24 hr)
`Build-up
`(pm)
`
`Post-Fm:
`Pro-Fmc
`Rourvolr
`Pennnbllny Prueure
`K (md)
`(pull)
`
`Pos1~FrIc
`Ponnublmy
`K (ma)
`
`Post-Frac
`Skin
`Value
`
`Pro-Frac
`Flow Rate
`(mclpd)
`
`Post-Frac
`Flow Rate
`(rndlpd)
`
`0
`1
`2 (N2)
`3 (C02)
`4 (N2 Foam)
`5
`
`6
`
`All
`6
`1
`1
`1
`‘
`i'3
`5
`8
`
`1 19'
`74
`54
`54
`54
`Q:
`73
`83
`
`0082'“
`0.0792
`0.0306
`0.0306
`0.0306
`o.oe4"
`__
`
`0.071
`
`NA
`- NA
`NA
`182
`184
`132
`
`0.20““
`0.1835
`0.0477
`0.0430
`0.0900
`0.1505
`
`-----
`-----
`----
`
`-3.212
`4.220
`
`178
`
`0.3270
`
`-0.881
`
`34.0
`2.2
`2.2
`2.2
`2.2
`21.1
`
`9.6
`
`155.0
`009.0
`01 1.0
`055.0
`034.0
`'oe2.o
`
`050.0
`
`mm
`69
`‘ D
`rgctgrggég 1333113“!p1I‘gl—‘£1gI up1i°b'§§1J1‘o n)
`" Weighted average of Individual tests
`1" Homer p1o1ca1eu1a11on
`
`
`
`‘Mall 3. Treatment Schedule to: 5t.i.nu1|ti.en No. 4
`
`Sea a
`
`1
`
`Rate
`
`15
`
`50
`
`"'
`
`' ""'cu-«man
`Volume
`Volume
`bbl
`11011:
`
`sand
`Volume
`lbs
`
`119 (00,)
`
`1,140
`
`5,000
`
`40,000
`
`0
`
`0
`
`Puuun
`:1
`
`200
`
`1,350
`
`'
`Pump Time
`minutes
`
`B
`
`22
`
`1
`
`2
`
`3
`
`I
`
`5
`
`6
`
`7
`
`8
`
`40
`
`(0
`
`40
`
`40
`
`30
`
`30
`
`119
`
`119
`
`119
`
`230
`
`230
`
`53,000
`
`53,000
`
`63,000
`
`73,000
`
`83, 000
`
`2,500
`
`5,000
`
`7,500
`
`20,000
`
`25, 000
`
`1.310
`
`138, 000
`
`165,000
`
`1,300
`
`1,350
`
`1,370
`
`1, 390 '
`
`1, 150
`
`1,200
`
`3
`
`3
`
`3
`
`G
`
`B
`
`«H
`
`
`
`a 29 11. man “I '1 9 4
`
`
`
`
`
`
`
`
`
`RC_RAP00O04067
`Exhibit 2026
`
`IPR2016-01517
`7 of 14
`
`

`
`
`
`‘man! 4.
`
`‘treatment Schedule for Sttaulation He. 5
`
`
`001512151-.i.ve
`Send
`Volume
`voluno
`Gallons
`lb:
`
`8:: o
`
`Rate
`b
`
`Volume
`bbl
`
`Pgouuu
`:1
`
`Pup The
`lttauten
`
`1
`
`2
`
`3
`
`I
`
`5
`
`6
`
`7
`
`B
`
`12
`
`25
`
`5_0
`
`50
`
`so
`
`50
`
`S0
`
`50
`
`233 (C0,)
`
`1, 140
`
`119
`
`119
`
`119
`
`238
`
`238
`
`10,000
`
`22, 333
`
`29,000
`
`42, 333
`
`55, 566
`
`69, 000
`
`86,012
`
`1,310
`
`105,000
`
`0
`
`0
`
`3,300
`
`13,400
`
`20, ooo
`
`26, 600
`
`36,700
`
`50,000
`
`200
`
`1, 100
`
`1,300
`
`1,350
`
`1, 310
`
`1, 500
`
`1, 550
`
`1,550
`
`22
`
`24
`
`3
`
`3
`
`7
`
`7
`
`8
`
`10
`
`9
`1o
`40 :1, nun
`4
`
`
`Summary of Stimulation Test Series Conducted on Fist #1 Well
`
`Table 5
`
`Test No.
`
`Zone
`
`Fluid
`
`Rate
`
`Volume
`
`Diagnostics
`
`Fro
`
`1
`2
`3
`4
`5
`6
`7
`8
`9
`
`10
`11
`
`12
`13
`
`6
`6
`6
`6
`1
`1
`