WEATHERFORD INTERNATIONAL, LLC, et al.
`
`EXHIBIT 1002
`
`
`
`WEATHERFORD INTERNATIONAL, LLC, et al.
`'
`'
`V.
`
`PACKERS PLUS ENERGY SERVICES, INC.
`
`SPE
`
`Society of‘ Petroleum Engineers
`
`SPE 19090
`
`A
`
`‘
`
`Production and Stimulation Analysis of Multiple
`Hydraulic Fracturing of a 2,000-ft Horizontal Well
`by A.B. Yost ll, U.S. DOE/METC, and W.K. Overbey Jr., BDM Engineering Services Co.
`SPE Membem
`
`This paper was prepared lor presentation at the SPE Gas Technology Symposium held in Dallas, Texas, June 7-9, 1989.
`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,
`as presented. have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented. does not necessarily reflect
`any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society
`of Petroleum Engineers. Permission to copy is restricted to an abstract of not more than 300 words. illustrations may not be copied. The abstract should contain conspicuous acknowledgment
`of where and by whom the paper is presented. Write Publications Manager, SPE, P.O. Box 833836. Richardson, TX 75083-3836. Telex, 730989 SPEDAL.
`
`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,D00
`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 .
`
`BACKGROUND
`
`has
`The Federal Government
`investigating
`been
`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
`borehplg
`for maximizing production was
`recognized in 1969.
`1
`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
`
`References and illustrations at end of paper.
`
`and again in 1976.00
`of west 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
`horizontal 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.
`
`isolation
`zone
`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.
`
`to
`designed
`stimulations’ were
`of
`series
`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.
`
`oiibf 14
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`01 of 14
`
`

`
`PRODUCTION AND STIMULATION ANALYSIS OF
`MULTIPLE HYDRAULIC FRACTURING OF A 2000-FOOT HORIZONTAL WELL
`
`SPE 19090
`
`gas-low deviation factor evaluated
`@ initial pressure
`formation temperature, degrees R.
`formation thickness, ft.
`
`247
`=
`(h
`interval
`shale
`the whole
`Assuming
`ft) to be productive and with a formation temperature
`of 93°F, stabilized gas production rate of 35 mcfpd,
`and
`the
`slope
`from the Horner plot of
`15863.2
`psia?/cycle;
`therefore
`formation permeability (K)
`is calculated as follows:
`
`K =
`
`1637)(34)(0.0107)(0.980
`(15863.2)(247)
`
`553
`
`= 0.082 md (2).
`
`permeability
`for
`value
`estimated
`above
`The
`a conventional well
`in a
`similar
`to those of
`is
`low permeability
`reservoir with
`a
`very
`large
`fracture.
`As discussed previously,
`these analyses
`are
`not
`strictly applicable
`to
`the
`horizontal
`wellbore geometry, but one may assume a horizontal
`wellbore to represent
`a vertical well with a
`long,
`finite conductivity fracture.
`
`an
`RET #1.
`for
`test
`Following they build—up
`attempt was made
`to isolate and individually test
`each of the seven zones representing a total
`interval
`of
`2211
`feet
`(3803-6014
`feet).
`A
`combination
`straddle tool was designed to facilitate the opening
`and
`closing of port collars
`in
`seven
`individual
`zones.
`
`test
`pressure_ build-up
`hour
`twenty-four
`A
`_
`followed by a 24-hour drawdown
`for each zone was
`performed using the combination straddle tool.
`In
`order
`to estimate permeability for
`each isolated
`zone,
`a
`three-dimensional,
`dual
`porosity,
`single
`phase ‘gas
`simulator
`reservoir model was used to
`determine permeability values
`shown
`in Table
`1.
`The average preestimulation permeability was 0.0665
`md.
`
`pressure
`the
`of
`analysis
`stimulation
`Post
`determination
`resulted 'in
`build—up/drawdown
`data
`skin values,
`of average reservoir pressure values,
`the various
`and
`average permeability values
`for
`zones with the different stimulation jobs. Results
`of the pressure build—up analysis using the various
`techniques are summarized in Table 2.
`
`were
`techniques
`analysis
`pressure
`Various
`to
`obtain
`estimates
`of
`used
`post-stimulation
`build-up
`data
`permeability.
`Selective
`pressure
`were
`analyzed using type-curve matching, Horner's
`technique,
`and
`a
`newly—developed
`technzgue
`known
`as the Rectangular Hyperbolic Method (RHM)
`:3)-
`
`indicated
`6
`Post-stimulation analysis for Zone
`a post—frac permeability of 0.1835 md, but an average
`- reservoir pressure of 205 psia using history matching
`process.
`Analysis of
`the pressure build—up data
`using Horner's
`technique was not possible due
`to
`the
`fact
`that
`the
`stabilized flow period prior
`to the build-up test was very short, hence accurate
`results
`of
`pressure
`and
`permeability could
`not
`be
`determined.
`Instead,
`type-curve matching was
`implemented
`for
`the analysis
`and an average per-
`meability value was
`calculated to be 0.1795 md.
`Both
`techniques
`indicated similar
`results,
`hence
`more
`confidence was
`generated
`in
`the
`estimated
`post—frac permeability value.
`
`
`INTRODUCTION
`
`of Energy's Morgantown
`The U.S. Department
`contracted with
`the
`BDM
`Energy Technology Center
`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, west
`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
`4—stage data
`One
`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 most suitable fluid and
`injection rate; Ehis
`informati n was
`reported in
`SPE Papers
`17759 5
`and
`18249 5).
`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
`of all
`stimulations
`is
`the
`well
`upon
`completion
`subject of this paper.
`
`Pre- and Post-Frac well 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:
`
`Kh = 1637 qavg”iZiT
`m
`
`(1)
`
`.
`slope = 15863.2
`average gas production rate, mscfpd
`formation permeability, md
`gas viscosity, Cp evaluated at initial
`pressure, P1
`
`m E
`
`where:
`
`avg "IIIIII
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`Albert B. Yost II and William K. Overbey, Jr.
`
`3
`
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`SPE 19090
`
`
`.303 md, average reservoir pressure
`permeability was
`1 was stimulated by 3 different frac jobs
`Zone
`was 178 psia, and skin factor was >D.00.
`A positive
`at various treating pressures and rates with nitrogen,
`skin
`value was
`calculated for Zones
`5
`and
`8.
`
`liquid C02,
`and nitrogen-foani with proppants. Hell
`A
`indicating a
`slightly damaged well.
`drop
`in
`testing procedures
`and data analysis were performed
`the
`skin factor
`from -2.87 for
`the overall well
`
`
`
`for each job.
`In the first job when the well was
`
`to a more positive value for Zones
`5 and 8 could
`stimulated with N2, pressure build-up data indicated
`
`be attributed to:
`
`
`a
`reservoir pressure of
`290 psia which
`is
`above
`the
`current
`average
`reservoir
`pressure
`(185-200
`
`(a)
`the
`sand
`problem that was
`encountered
`psia
`as
`determined
`by
`the
`7-day
`shut-in
`test).
`during the clean-up process, hence indicating damage
`1
`This
`is due
`to the fact
`that Zone
`(N2 frac) was
`to the wellbore;
`_
`still overpressured by the amount of
`inerts present
`(b)
`the decrease
`in the analyzed horizontal
`in the
`gas mixture at
`the time of
`testing.
`The
`section of
`the wellbore from 2160 feet (all zones)
`simulation of
`the pressure buildup data using G3DFR
`pre-stimulation
`analysis,
`to
`932
`feet
`(Zones
`5
`model
`estimated an
`average permeability equal
`to
`and 8) post-stimulation analysis.
`0.0477 md. Analysis of
`the pressure build-up data
`following the
`second job ( C02
`frac)
`indicated a
`
`
`tested using
`The accuracy of these results was
`permeability value of 0.0480 and 0.0485 using Horner's
`three different
`techniques;.
`Estimating
`values of
`technique and history matching,
`respectively.
`Using
`
`
`
`average reservoir pressure (P)
`RHM
`using
`the
`Horner's technique,
`reservoir pressure was estimated
`
`technique
`has
`an
`advantage over
`the conventional
`at 182 psia. Results of build—up pressure analysis
`
`methods
`because
`knowledge
`of
`neither
`the
`
`
`following
`the
`third
`job
`(N3-foam—proppant
`frac)
`well/reservoir
`configuration
`nor
`the
`boundary
`indicated the presence of
`a
`dual porosity system
`
`
`a
`condition
`is
`required
`for
`routine
`build-up
`with the middle region having a slope one-half that
`
`
`analysis.
`However,
`conventional methods
`such
`as
`of
`the late region on
`the build-up curve which is
`
`Horner's technique, when correctly used, will provide
`characteristic of
`a
`dual
`porosity system in
`the
`superior
`results of
`Kh
`and
`S values
`compared to
`Devonian
`shale.
`The
`average
`permeability
`was
`estimated at
`0.090 md,
`and
`the
`average pressure
`the
`RHM technique.
`Therefore,
`values
`of
`K
`and
`S for Zones
`5 and 8 are believed to be in the range
`was determined to be 184 psia.
`
`of 0.300 md
`to 0.492 md
`and
`-0.881
`to
`1.386,
`
`were
`stimulated
`using
`4
`and
`2-3
`Zones
`respectively, whereas the average reservoir pressure
`is calculated at 178 psia based on the RHM technique.
`period,
`Following
`the
`cleanup
`N2-foam/proppant.
`
`a
`rate of 62 mcfd for
`Zones 2-3 and 4 produced at
`well Stimulation Summary
`a period of
`35 days.
`Pressure build-up analysis
`using Horner's
`technique
`indicated
`an
`average
`reservoir permeability of 0.1505 md
`and an average
`pressure of 182 psia.
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`stimulated using Ng-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.
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`The objective of stimulation research in the
`horizontal wellbore was
`to determine the recovery
`efficiency of
`the natural
`fracture systenl 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
`WEN-.‘:I
`
`
`
`to the complexity of production from the
`Due
`Devonian shale and the existence of'a dual porosity
`system,
`a
`log—log plot of AP2
`(P2wsPwf), and d(AP2)
`be
`could
`that
`fractures
`number of
`the
`(1)
`(derivative
`of
`delta
`pressure
`squared)
`versus
`Effective
`Time
`(Ate) was generated; where -Ate
`opened
`and propagated during
`a
`single
`hydraulic
`
`fracture pumping event;
`t/(1+ At/tp), At
`=
`shut-in time
`(days),
`and tp
`
`
`(2) whether proppant would screen out easier
`flowing time, 20 days.
`in a horizontal well;
`
`(3) understanding what determines which natural
`of pressure-squared
`approach
`instead of
`The
`use
`fractures are propagated;
`the
`pseudo pressure for gas
`reservoir analysis. is
`fracture diagnostic
`(4)
`determining the best
`proven
`to
`be valid for
`reservoir pressures
`less
`system to use in a horizontal well;
`than 2000 psia.
`A Flopetrol Johnson/Schlumberger-type
`(5)
`understanding
`how
`to
`curve was
`used for
`infinite acting reservoir with
`
`and the volumes required;
`double
`porosity
`behavior
`(pseudo
`steady
`state
`
`pad
`need or value of
`(6)
`understanding the
`interporosity flow), wellbore
`storage,
`and
`skin.
`
`
`the
`volumes when
`treating multiple
`fractures
`at
`The permeability was calculated from match points
`
`
`same time.
`at
`.492 md and skin factor was calculated at 1.386.
`
`Using
`the Horner
`technique,
`the
`permeability was
`The overall
`technical approach was to:
`.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
`the
`various
`reservoir
`properties.
`The
`computed
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`place
`
`proppants
`
`
`
`
`
`
`
`
`
`
`
` (1)
`induce multiple
`hydraulic
`fractures,
`
`
`both controlled and uncontrolled;
`
`
`
`03‘2t"3f 14
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`03 of 14
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`

`
`PRODUCTION AND STIMULATION ANALYSIS OF
`SPE 19090
`MULTIPLE HYDRAULIC FRACTURING OF A 2000-FOOT HORIZONTAL WELL
`
`
`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
`
`open
`Initial
`wellbore.
`declined rapidly so that
`baseline rate after 20 days.
`
`80 mcfpd
`of
`flow rate
`the well was making the
`
`also
`stimulation was
`full-scale
`second
`The
`conducted in Zone 1 since it was felt that a better
`comparison of
`fluids would
`be more
`realistic and
`meaningful
`if all
`tests were conducted in the same
`zone.
`The
`second fluid was
`liquid C02, which is
`a cryogenic fluid, pumped at 0°F,
`and at pressures
`about
`200
`psi
`above
`closure
`pressure.
`The
`stimulation was
`conducted
`in
`two
`stages,
`pumped
`at
`two different rates, with considerable difference
`in the results in terms of the number of fractures
`inflated.
`More
`fractures were
`inflated at
`the
`higher injection rates.
`In addition,
`the production
`improvement ratio was higher with C03 when compared
`to nitrogen gas and nitrogen foam as fluids.
`Initial
`production was more than 250 mcfpd, however, after
`more
`than
`50
`days
`of production,
`the
`rate
`had
`declined again to the original
`rate of 2.2 mcfpd.
`One plausible explanation is that without proppant,
`the
`fractures
`opened
`up
`and
`simply
`closed with
`time.
`
`losing production because
`experience of
`This
`of closing fractures led us to conclude that proppant
`was a necessary ingredient in the stimulation design.
`The
`third stimulation was
`a
`small
`volume nitrogen
`foam stimulation pumped
`in
`two
`stages
`(#1
`pad;
`#2 proppant), but at the same rate of 10 bbls/minute.
`Two different
`radioactive
`tracers were
`used
`to
`determine where
`fractures were
`being
`propagated
`along the wellbore.
`Forty—six (46)
`fractures were
`opened and propagated.
`After cleanup,
`the production I
`was sustained due to the use of proppant.
`
`conducted in Zone
`fourth stimulation was
`The
`results of Frac
`4
`combined. After
`the
`and
`2-3
`it was felt
`that we needed to see if a
`large
`#3,
`volume
`fracture
`over
`about
`the
`same
`length of
`wellbore would give
`a proportionate
`increase
`in
`production rate, The large volume fracture consisted
`of 4500 gallons of
`liquid C02 as
`a prepad, 44,000
`gallons of pad,
`and 90,000 gallons of 80-quality
`foam containing 250,000 pounds of sand (2.5 lbs/gal)
`all
`pumped at 50 gallons per minute downhole foam
`rate.
`There were
`some difficult
`sand
`cleanup
`problems
`after
`this
`frac
`job.
`The
`improvement
`ratio of stimulated production to natural production
`was 3.1 to 1.
`Zone
`4 was
`the zone with a high
`natural
`show of 2.16 million scf of gas per day
`and was a major fault and fracture zone.
`A summary
`of
`the
`stimulation treatment
`schedule
`for No.
`4
`is
`shown
`in Table
`3
`and
`the production history
`after stimulation is shown in Figure 3.
`
`a scaled—down
`fracture was
`The fifth and final
`The final
`treatment covered
`version of Frac No. 4.
`almost
`twice as much borehole (930 feet)
`in Zones
`5 and 8 versus 590 feet
`in Zones 2-3 and 4 during
`Frac
`#4,
`but
`pumped
`only
`105,000
`gallons
`of
`85-quality foam and 150,000 pounds of
`sand at
`50
`barrels per minute
`rate.
`Sand cleanout problems
`were
`not
`as
`severe
`this
`time.
`Gas
`production
`improvements ratio for
`the combined zones was 6.1
`to 1, which was
`an
`improvement over Frac
`#4
`in
`Zones 2-3 and 4, but not
`in the same class as Frac
`#3 with its 15.5 to 1
`improvement ratio.
`
`to
`had
`design
`fracture
`hydraulic
`Conceptual
`interaction between the natural
`the strong
`consider
`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
`fracture 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.
`
`The mechanical
`fracturing fluids,
`handling of
`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:
`
`propagate natural
`to
`Primary design was
`(1)
`in orientation
`fractures with a
`slight difference
`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
`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
`propagated.
`increasing injection rates, additional
`(5)
`By
`fractures would be induced which would likely create
`a
`network
`of
`interconnected
`fractures
`with
`orientations of N37°E, N52°E, and N67°E.
`
`keep
`
`6 using a
`conducted on Zone
`fracs were
`Data
`From this
`computerized‘ data
`acquisition
`system.
`(or
`parting
`series
`of
`tests,
`closure
`pressure
`and
`1050 psi.
`pressure) was determined to be 850
`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
`rates
`to
`inflate
`the
`natural
`fractures
`in
`the
`
`04 olE‘14
`
`04 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
`the different frac jobs
`result of
`a
`As
`zones,
`the production was
`enhanced in all
`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.
`
`
`
`
`
`
`
`
`
`
`
`
`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
`evaluate
`to
`used
`GBDFR 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
`pre-stimulation
`the
`horizontal well,
`the
`In
`skin value was estimated at -2.87 due to the geometry
`model
`used 350 psi
`reservoir pressure, while the
`of
`the wellbore (horizontal well),
`since horizontal
`post—drilling projection used 180 psia. Pre-drilling
`model studies also projected a vertical well, drilled
`wellbores
`are equivalent
`to stimulated reservoirs.
`at
`the site where the horizontal well was drilled.
`The
`skin values
`showed
`an
`improvement
`for Zones
`1, 2-3, and 4, whereas a decrease in skin from -2.87
`would produce 80 mmcf
`in 20 years.
`This comparison
`to -0.881 was detected in Zones
`5 and 8. This could
`indicates
`the horizontal well
`should produce 7.8
`times more
`gas
`than a vertical well drilled at
`be
`due
`to presence of
`sand
`in
`the wellbore or
`
`
`
`
`the same location.
`formation damage as a result of the frac job.
`
` An additional method of analyzing stimulation
`CONCLUSIONS
`
`effectiveness
`is
`the
`examination
`of permeability
`improvements.
`Table 7 provided data on the post—frac
`1.
`This
`2000
`foot horizontal well
`in fractured
`
`permeability compared to the pre-frac permeability.
`Devonian
`shale
`has
`successfully demonstrated
`
`Improvements
`ranged from 1.79 to 4.4 with an average
`numerous
`folds of
`increase
`in production as
`ratio of 3.2.
`
`
`compared to vertical wells in a pressuredepleted
`
`producing field.
`
`
`The production decline curve for the horizontal
`is
`shown
`in Figure
`5.
`The
`stabilized flow
`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.
`
`2.
`
`3.
`
`
`
`
`
`
`
`
`
`
`
`to predict/projec
`used
`GSDFR model was
`The
`a 20-year history of production based on estimated
`values of
`reservoir pressure,
`formation thickness,
`
`
`horizontal drilling and multiple
`long
`Both
`and
`average
`permeability.
`The
`average
`reservoi
`are
`required
`to
`achieve
`high
`stimulations
`pressure and formation thickness were kept
`constan
`folds of increase in production.
`at 182 psia and 247 feet,
`respectively, due to th
`
`fact
`that
`geologic
`and
`engineering
`data wer-
`sufficient
`to
`accurately
`estimate
`these
`values.
`
`Post-stimulation
`permeability
`was
`calculated
`to
`
`be 0.200 md.
`
`
`0525)f 14
`
`4.
`
`
`
`
`
`
`
`
`
`
`successfully
`were
`improvements
`Productivity
`actual
`flow rates,
`build—up
`evaluated
`by
`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.
`
`05 of 14
`
`

`
`6
`
`REFERENCES
`
`PRODUCTION AND STIMULATION ANALYSIS OF
`MULTIPLE HYDRAULIC FRACTURING OF A 2000-FOOT HORIZONTAL HELL
`
`SPE 19090
`
`1.
`
`"Natural
`Pasini, J. III, and W.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
`Fall Meeting, Houston,
`Texas, October
`6-9,
`1974.
`
`“Drilling
`and w.M.~ Ryan.
`Jr.
`Overbey, M.K.,
`Stimulate
`a Directionally Deviated well
`to
`Gas Production
`from a Marginal Reservoir
`in
`Southern Nest_Virginia,” MERC/TPR-76/3 (1976).
`
`"Drilling
`R.N. Metzler.
`and
`G.R.
`McManus,
`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).
`
`.
`
`.
`
`Yost, A.B. II, w.K. Overbey, Jr., D.A. Wilkins,
`and C.D.
`Locke.
`"Hydraulic Fracturing of
`a
`Horizontal
`Well
`in
`a
`Naturally-Fractured
`Reservoir:
`Case Study
`for Multiple Fracture
`Design".
`SPE Paper
`17759,
`presented at Gas
`Tehcnology Symposium, June, 1988.
`.
`'
`and D.A.
`II,
`Overbey, w.K., Jr., A.B. Yost
`Wilkins.
`"Inducing Multiple Hydraulic Fractures
`from a Horizontal Nellbore“,
`SPE Paper 18249,
`presented at 63rd Annual Technical Conference,
`Houston, Texas, October 2-5, 1988.
`
`"Pressure Build-
`and Kabir, C.S.
`.- Hasan, A.R.
`A- Simplified Approach",
`JPT,
`up Analysis:
`January 1983, 178-188.
`
`Salamy, S.P., C.D. Locke, w.K. Overbey, Jr.,
`A.B. Yost II.
`"Four Pressure Build-up Analysis
`Techniques Applied to Horizontal
`and Vertical
`Wells with Field Examples,"
`SPE
`#19101, pre-
`sented at
`the Gas Technology Symposium, Dallas,
`Texas, June 7-9, 1989.
`
`Table 1
`
`I
`
`
`
`Pre—Stimulation Pressure Build—Up and Drawdown Test Results
`Flet N0. 1 — Wayne County, West Virginia
`
`Length
`__C_)_fi-
`
`
`
`24-Hour
`Build—Up
`3&1
`
`Permeabi|ity*
`_i_n_id)_
`
`Flow Rate”
`_imm)_
`
`404
`
`417
`
`182
`
`640
`
`135
`
`90
`
`292
`
`54
`
`75
`
`68
`
`73
`
`74
`
`74
`
`83
`
`A
`
`0.031
`
`0.078
`
`0.098
`
`0.073
`
`0.078
`
`0.037
`
`0.068
`
`2.2
`
`4.4
`
`16.7
`
`4.4
`
`2.2
`
`0
`
`5.2
`
`TOTAL:
`
`35.1 mcfd
`
`* Predicted by reservoir simulation model GSDFR
`** 24-hour flow rate test after pressure build-up test
`
`06 0312514
`
`06 of 14
`
`

`
`35 19090
`
`Comparison of Pre— and Post—Frac: Testing Results
`
`
`Table 2
`
`Pre-Frac
`Pressure)
`(24 hr)
`Eulld-Up
`(psla)
`
`Pre-Frac
`Permeablllty
`K (md)
`
`Post-Frac
`Reservolr
`Pressure
`(P518)
`
`Zone{s)
`
`Posl-Frac
`Permeability
`K (md)
`
`P091-Frac
`Skin
`Value
`
`Pre-Frat:
`Flow Rate
`(mnlpd)
`
`Post-Frac
`Flow Rate
`(mdrpd)
`
`0.20""
`0.1835
`0.0477
`0.0480
`0.0900
`
`-----
`
`-3 .21 2
`
`0.1505
`
`-4.220
`
`34.0
`2 .2
`2.2
`2.2
`2.2
`
`21 .1
`
`0.3270
`
`-0.831
`
`9.6
`
`155.0
`009.0
`011.0
`055.0
`034.0
`
`062.0
`
`050.0
`
`1 1 9‘
`74
`54
`54
`54
`
`75
`68
`
`73
`83
`
`0.082***
`0.0792
`0.0306
`0.0306
`0.0306
`
`it
`
`0.084
`
`o.o71**
`
`NA
`NA
`NA
`182
`184
`
`182
`
`178
`
`All
`
`6 1 1 1 2
`
`-3
`
`45 8
`
`Frac
`Number
`
`0
`
`1 .
`2 (N2)
`3 (C02)
`4 (N2 Foam)
`
`5
`
`' Dela from 28-day hulld-up (169 psla boltomhala rassure
`recordad: 192 psla pr
`ujacled as absolute reserv Ir pressure)
`" Weighted average at Individual iesls
`"' Homer plot calculallon
`/
`
`
`TABLE 3. Treatment Schedule for Stimulation No. 4
`
`
`Cumulative
`Sand
`Volume
`Volume _
`allons
`lbs
`
`Sta e
`
`Rate
`b m
`
`Volume
`bbl
`
`Pressure
`:5.
`
`Pump Time
`minutes
`
`a
`22
`
`1‘
`2
`
`3 .
`
`4
`
`5
`
`6
`
`7
`
`8
`
`.
`
`15
`50
`
`40
`
`40
`
`40
`
`40
`
`30
`
`30
`
`119_ (co,)
`1, 140
`
`119
`
`119