—.
`
`SPE 39941
`
`Society
`
`of Petroleum
`
`Engineers
`
`.-.
`..-— .
`
`,..
`
`9
`
`.
`
`.
`
`:4m*’
`
`.—..-
`A Case Histo~: Completion and Stimulation of Horizontal Wells with Multiple
`Transverse Hydraulic Fractures in the Lost Hills Diatomite
`MA. Emanuele,
`Chevron U.S.A. Production Company, W.A. Minner and L. Weijers, Pinnacle Technologies,
`Broussard and D, M. Blevens, Chevron U.S.A. Production Company
`and B. T. Taylor, Dowell Schlumberger
`T
`
`E. J.
`
`-cfht
`
`1998. SWiefy of Petroleum Engineers,
`
`Inc.
`
`prepe~
`pepsr %3
`~ls
`Conference. Oenver. U.S.A.,
`
`for presentation
`i 998.
`
`al
`
`the 1998 SPE Rocky Mountain Regional
`
`pa~r wss selected for presentation by an SPE Program Committee following review of
`~is
`information contairsti
`in sn abstre~
`subfnlffed by the author(s). Contents of the psper, ss
`presenfed, hsve not ~
`reviev,wd by the Sociefy of P~troleum Engineers end are sub~t
`fo
`comr~on
`by Ihe author(s). me material, as presented,
`does not necasserily
`refIecf any
`-Ion
`of the society of Petroleum Engineers,
`Ifs officers, or rnem~rs.
`P~rs
`presented a!
`SPE meetings are sub~
`to pubficetion review by Ediloriel Committees of the ~tety
`of
`Petroleum Engineers. Permission to copy Is restrlcf@ 10 an ebstracf of not more than 300
`mrd.s.
`Illusfrafions may
`not be
`ccpled.
`The
`sbsfract
`should
`contain
`conspicuous
`adm~-enf
`of Akre
`and by Worn the paper wes presenfed Write Librarien, SPE, P,O.
`S0s 833S36, Richardson,~
`750S3-3336, U=,
`fars01-972-9S2.9435.
`
`Abstract
`
`.—
`
`~
`
`been
`traditionally
`has
`Field Diatomite
`The Lost Hills
`completed
`with multiple
`vertical wells
`developed
`using
`fracture
`treatment
`stages.
`As
`the main
`propped
`hydraulic
`portioti-of
`the field is nearing full development
`at 2Yz-acres per
`producer,
`the setich
`for additional
`reserves has moved out
`to
`the flanh
`of the field’s anticlinal
`structure. Due to limited pay
`thickness, ”these
`flank portions
`of
`the field will not support
`economic WrticaI welI deve~opment.
`The use of horizontal
`wells was determined
`to have the best chance to economically
`deveIop_thgse areas of the _field. To evaluate this development
`concept,
`three horizontal wells were drilled
`and completed
`over the time period from November
`1996 to December
`1997.
`To assist with the horizontal well design and evaluation,
`several vertical data wells were drilled offset and parallel
`to
`the intended well path of each horizontal well. Additionally,
`two verticaI core weIIs werg-drilled
`in line with the toe and
`heel of
`the horizontal well paths.
`These
`data wells were
`utilized to e~fimate properties
`such as in-situ stress profiles,
`pore pm~~-
`gradients,
`ro;k properties
`and fluid saturations,
`and to determine
`horizontal well vertical
`depth placement.
`The horizontal welk were
`then ‘drilled
`in the direction. of
`minimum horizontal
`stress
`(transverse
`to
`the
`preferred
`hydraulic
`fracture
`orientation)
`and completed with multiple-
`staged propped hydraulic
`fracture treatments.
`horizontal welIs,.
`During
`the
`completion
`of
`the
`three
`hydraulic
`fracture
`growth
`behavior was characterized
`using
`surface
`tiltmeter
`fracture mapping
`and
`real-time
`fracture
`pressure
`analysis.
`In the
`third horizontal well, downhole
`
`-
`
`of
`fracture mapping was also used. This combination
`tiltmeter
`fracture diagnostics provided significant
`insights into hydraulic
`ficture
`behavior,
`allowing
`diagnosis
`of anomalous
`‘fracture
`growth
`behavior
`and evaluation
`of
`remediation measures.
`Fracture diagnostics
`during the first horizontal well
`revealed
`an unexpectedly
`complex
`near- wellbore
`fracture geometry, ”a
`result of fracture initiation problems.
`These problems
`slowed
`the completion
`process and severely harmed the effectiveness
`of
`the fracture-to-wellbore
`connection.
`In the subsequent’
`horizontal wells, a number of design and execution
`:haages
`were made which resulted
`in simpler
`near-wellbore
`fracture
`geometry and a greatly improved production
`response.
`and
`The paper provides
`an overview of
`the completion
`stimulation
`of all
`three horizontal wells, describes
`the” lessons.
`learned
`along the way,
`and discusses
`the implications
`for
`future Lost Hills horizontal well devcl”bpment.
`
`““,,
`
`Lost Hills Field Setting
`
`and Horizontal Well Rationale
`
`Field Description.
`The Lost Hills Field is an asymmetric
`anticline, approximately
`one mile wide and twelve miles long,
`located in Kern County, California,
`approximately
`45 miles
`(see Figure
`1). The anticline
`northwest of Bakersfield
`trends
`NW-SE, nearly parallel
`to the San Andreas Fault. The main
`reservoir
`is approximately
`1000 ft thick, occurring
`at “depths
`ranging from 1000 to 3000 ft.
`diatomite, which
`The main reservoir
`rock is the Belridge
`a primary
`constituent
`of
`siliceous
`shells
`that
`are ,the
`has
`remains
`of
`single-celled,
`algae-like
`plants
`called
`diatom;.
`These
`diatoms
`were
`plentiful
`in
`the
`shallow marine
`environment
`during the late ‘Miocene (5- 10 million_years
`ago),
`in what
`is now California’s San Joaquin Valley;
`Dui
`the,
`10
`open structure and round shape of the small
`(50 pm-diameter)
`is
`diatoms, porosity can be as high as 65%, while permeability
`typically much less than 1 mD (see Table
`1). With such high
`porosity,
`Iithostatic
`(overburden)
`gradients
`are relatively
`low
`at 0.79-0.82
`psi/ft.
`of
`The thickness
`1200 ft. Throughout
`at a depth varying
`
`600 and,
`between
`ranges
`the reservoir
`change
`the field, key reservoir properties
`between
`1900 and 2700
`ft, where
`the
`
`335
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`2
`
`-.
`
`. .
`
`.
`
`M.A. WUELE,
`
`W.A. MINNER, L. WEIJERS, E.J. BROussARD, D.M. BLEVENs, AND B.T. TAYLOR
`
`S~E 39941
`
`Development History.
`at Lost Hills
`characteristics
`Reservoir
`result
`in generally
`decreasing
`reservoir
`quality with depth,
`which is reflected in the development
`history.
`In the early part
`of this century, wells were drilled only to the upper parts of the
`reservoir,
`and the flowing wells were completed with slotted
`By mid-century, wells were generally
`limited to the
`liners.
`upper half of the reservoir
`and slotted liners were the norm.
`Production
`rates in these wells were greatly diminished
`from
`earlier wells due to partial
`reservoir depletion and the general
`decrease
`in reservoir
`quality with depth.
`Since
`the mid-
`1970’s, wells have commonly targeted the entire Belridge
`and
`deeper
`intervals with the development
`of hydraulic
`fracture
`stimulation technology.
`routinely
`is
`stimulation
`fracture
`Today,
`hydraulic
`from the
`scale
`to enable
`production
`performed
`on a large
`and low
`diatomite
`formations, However,
`the low permeability
`Young’s modulus of the rock make achievable
`fracture lengths
`quite short. Thus, well drainage radius is small,
`leading to the
`current primary development
`at 21/2 acre well spacing while
`areas under waterflood
`are at 1-1/4 acre spacing (one injector
`per 2% acre pattern).
`Further
`infill drilling to spacing as small
`Such tight
`as 5/16 acre
`is under
`evaluation
`and testing.
`spacing may be necessary
`to effectively
`produce
`the mobile
`fraction of the estimated 2 billion barrels of oil-in-place
`in the
`Lost Hills Field.
`
`fractured
`Multi-stage
`Justification.
`Well
`Horizontal
`horizontal wells are being tested as a way to develop reserves
`in the relatively thin pay interval along the flanks of the Lost
`Hills Field. As shown in Figure
`2, vertical wells with multiple
`stacked fracture stages are advantageous where the gross pay
`is thick and multiple reservoirs
`are targeted. However,
`as the
`diatomite
`pay thins
`toward
`the flanks of
`the anticline,
`the
`number
`of stages becomes
`very limited
`and verticaI weI1s
`become
`less economic.
`In these areas, horizontal wells with
`multi-stage,
`transverse,
`propped fractures
`targeting a selected
`
`Diatomite
`Producer
`
`I
`
`Sw
`
`Commingled Muld-fracHorizontal
`Producer
`Producer
`
`I
`
`I
`
`I
`
`NE
`
`;i::.
`>..
`
`?,.
`:33
`
`k ‘
`
`r3
`Horiz.THoriz. Wel #3%
`
`7
`
`Horiz. Well #1
`
`1.Horizontal WeUs
`
`I
`I Evaluation Wells
`
`—13
`
`k:.
`
`I
`
`I
`
`1: Location of the three horizontal wells and the
`Figure
`‘horizontal
`analog”
`vertical wells in the Lost Hills Field im
`the San Joaquin VaIley
`in California.
`
`-
`
`changes
`(Opal A)
`silica
`am-orphous
`deposited
`origimdly
`structure
`crystalline
`into a tetragonaI
`or hexagonal
`@ualIy
`(OpaI CT). With the biogenic
`silica
`phase change, porosity
`and permeability
`decrease
`variably,
`depending
`on the total
`rock constituent
`Young’s modulus
`also varies with these
`changes.
`The Ycrung’s modulus
`of Lost Hills Opal A
`diatom
`averages
`approximately
`100,000 psi whereas
`the
`Opal ~ modulus
`is about 500,000 psi,
`
`properties
`
`of Lost HIIIs
`
`:
`
`1: Rock mechanical
`~~le
`Diitomite
`:. --,
`Property
`Depth
`Thickness
`Young’s modulus
`Poisson’s
`ratio
`Permeability
`Porosity
`Oil Saturation
`Frac closure gradient
`
`Unit
`ft
`ft
`psi
`
`mD
`%
`%
`psilft
`
`Value
`1000-3000
`600-1200
`50,000-1,000,000
`0.25-0.35
`0.01-100
`(avg. 0.1)
`35-65
`25 – 50
`0.55-0.65
`
`r.
`
`Antelope
`
`1~
`
`—
`
`,
`‘“”f’L--
`
`-“\
`
`\
`
`\
`
`\\
`
`2000 ft
`drilling and multi-zone
`for horizontal
`Figure 2: Motivation
`completions
`at the flank
`of the Lost Hills Field.
`
`336
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`
`

`

`SPE 39941
`
`A CASE STUDY: COMPLETION AND STIMULATION OF HORIZONTAL WELLS IN THE LOST HILLS DIATOMITE
`
`3
`
`.——..=—=-
`
`and
`development
`economic
`can provide
`intervaI
`diatomite
`reserves. Horizontal wells have been
`thus, provide
`additional
`beneficial
`in
`numerous
`areass-3,
`but wellbore-to-fracture
`communication
`problems
`in other diatomite
`reservoirs
`have
`shown that successful
`completion
`of horizontal wells may be
`challenging’.
`(O.I mD average), both
`Due to the very low permeability
`in the Lost HIIIs Field
`vertical wells
`and horizontal welIs
`require
`hydraulic
`fracturing.
`Therefore,
`the
`number
`of
`hydraulic
`fractures
`required for a given reservoir volume is the
`same regardless
`of how they are connected
`to the wellbore.
`The actual
`costs
`for drilIing
`and completing
`the horizontal
`wells is about 450% that of a conventional
`vertical multi-stage
`completion
`in the heart of Lost Wills. However,
`in the flank
`areas,
`the horizontal weIls to date are only 75% of the cost
`to
`develop
`the
`same
`reservoir
`voIume
`using
`vertical wells.
`Assuming
`future
`optimization,
`horizontal
`well
`costs
`are
`expected
`to reduce
`to only 50V0
`of
`that which would be
`It
`is
`the
`ability
`to include
`required
`by vertical wells.
`numerous fracture
`stages
`in a single horizontal wellbore,
`that
`provides
`the
`cost
`advantage
`over
`vertical wells
`and the
`opportunity for reserve additions
`along the flanks of the field.
`The
`technical
`objective
`during
`this
`initial phase of
`the
`project
`has
`been
`to
`deveIop
`an
`understanding
`of
`the
`completion
`and production
`behavior of horizontal wells, using
`a combination
`of
`comprehensive
`field measurements
`and
`Measurements
`and
`diagnostic
`diagnostic
`procedures.
`techniques
`included
`special
`borehole
`imaging
`logs,
`special
`diagnostic
`fracture
`injections,
`coring
`and
`core
`anaIysis,
`and downhole
`fractm
`net
`pressure
`anaI sis%g,
`surface
`7
`5, and post-fracture
`production
`tiltmeter
`fracture mappingl”
`analysis.
`Figure 1 shows the location of the welIs that were involved
`in this pilot study.
`
`,.
`
`Horizontal Weli Design
`
`Section. With the goal of
`the Horizontal
`of
`Placement
`fractures
`(fractures
`that
`are
`transverse
`hydrauli;
`creating
`to the wellbore),
`the horizontal
`oriented roughIy perpendicular
`wells were drilled in a direction of about N 25-40° W, which
`is approximately
`orthogonal
`to the Lost Hills Field average
`fracture
`azimuth
`as determined
`by surface
`tiltmeter
`fracture
`IQI1 me Smatigraph”icpIacement
`of
`the horizontal
`mapping
`.
`sections were determined
`using stress profiles
`(micro-frac data,
`dipole sonic logs and reservoir pressure tests7’lG) and reservoir
`quality
`(core
`and Iog data)
`from offset vertical wells.
`In
`addition,
`severaI
`evaluation
`wells were
`drilled
`near
`the
`proposed
`horizontal well paths
`for data
`collection.
`These
`evaluation wells were also completed to obtain production data
`prior to drilling each horizontal welI.
`fracture modeling,
`The
`vertical
`well
`data
`improved
`geostatisfical
`simulation
`and 3D visualization
`for
`final
`target
`interval selection and horizontal wellpath definition. All of the
`
`to date have medium radius build rates and near-
`weilpaths
`lateral
`sections
`to stay within ‘a specific
`geoIogic
`horizontal
`interval. The final
`inclination of a wellbore is dependent upon
`the desire to maintain a wellpath that
`is roughly orthogonal
`to’
`anticipated fracture azimuths, constraints of existing wellbores,
`reasonable
`alignment with the vertical well development
`and
`of course,
`the structural attitude of the target zone.
`To date,
`the target zone for the horizontal wells is within
`transition
`zone
`from Opal A to Opal
`~
`diato-mite.
`the
`Reservoir
`characterization
`consistently
`indicates
`that
`this
`interval offers the best combination
`of oil saturation,
`porosity
`and permeability.
`Shallower, Opal A zones, which have
`somewhat
`higher permeability
`(1 mD),
`exhibit
`reduced” oil
`This
`likely reflects
`the
`saturation
`and reservoir
`pressure.
`of
`influences
`of
`the
`long
`history
`up-dip,
`vertical weIl
`development.
`Below the transition
`zone
`in the Opar ~,
`matrix permeability
`is extremely
`low (< 0.1 mD) and nattiral
`These
`fractures may allow the
`fractures
`are more prevalent.
`secondary hydrocarbon migration vertically into the transition
`zone where natural
`fracture
`counts
`are reduced
`and effective
`porosity and permeability
`has not been reduced by the silica’
`phase transition.
`the transition
`By targeting
`fractures
`effectively
`extend
`relatively
`high oil saturation
`extremes
`intersect
`the natural
`Opal CT.
`
`the horizontal well
`interval,
`the wellbore
`into
`zones with
`and porosity while their Tower
`fractures
`that are prevalent
`in the
`—
`
`...,
`
`The mechanical
`Casing Design.
`two
`first
`the
`of
`detail
`string of 9-3R”
`horizontal wells consisted
`of an intermediate
`casing cemented at the end of the build section (see Figure 3).
`At
`inclinations
`of no more than 95°,
`the lateral
`sections of
`1350’ and 2000’ were drilled for wells #1 and #2 “respec~?ve~y.
`from ~
`to
`5Yz” casing
`The horizontal
`sections
`received
`approximately
`80° inclination, where it was then crossed over
`to a T’ casing string to surface.
`The 5W cas~g was then
`
`9 5/S” Intermediatecasing
`cemt’d@ 90 degrees
`
`7“ casing
`
`to sutiace
`
`.
`
`.
`
`..—.=..=
`
`.-
`
`I 5 1/2”x T cming
`
`II
`
`5 1/2’ casing
`
`cmt’d
`
`I
`
`Figure 3: Horizonbl
`well #1 and #2.
`
`wellbore mechanical
`
`diagram for
`
`337
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`

`>.
`
`<S-PE39941
`
`4
`
`M.A. EWUELE,
`
`W.A. MINNER, L. WEIJERS, E.J. BROUSSARD, D.M. BLEVENS, AND B.T. TAYLOR
`
`cement
`
`top several
`
`in place, with a programmed
`cemented
`hundred feet above the 5%’x 7“ crossover.
`The partird string of 7“ casing was installed in the first two
`horizontal
`wells
`to
`accommodate
`larger
`artificial
`lift
`equipment.
`Soon after
`the initial production
`of wells 1 and 2,
`it became
`apparent
`that
`the wells
`did not
`require
`larger
`artificial
`Iift equipment,
`thus the change
`to 5~z” casing from
`TD to surface
`in welI #3. Additionally,
`the 5W’ x 7“ casing
`crossovm” a@ as a receptacle
`for wellbore debris (proppant).
`The debris
`caught
`in the crossover
`caused
`severe plugging
`problems
`during fracture
`initiation
`on well #1 (the problems
`associated with Wls plugging
`on fracture
`geometry
`and net
`preswe
`resporIsewill
`be addressed later in the paper). At the
`outset
`however,
`it was unknown what was
`causing
`these
`initiation pIugging probIems.
`After encountering
`several
`frac
`stages- ~h
`IittIe to no fluid infectivity,
`the source
`of
`the
`pIugging problem was finally identified
`as debris
`left
`in the
`Insufficient
`circulating
`velocities
`(<300
`ftimin)
`tissova.
`during wellbore
`cleanouts
`between frac stages in well #1 was
`determined
`to be the primary
`cause
`for debris
`collection.
`Modifications
`to the circuiting
`rates
`and procedures were
`implemented
`in an attempt
`to achieve satisfactory
`cleaning of
`both the horizontal
`section and crossover.
`to
`adequate
`were
`The
`changes
`in cleanout
`procedures
`continue, but still did not entire~y solve the plugging problems
`during fracture initiation on well #1. By the time the SW’ x 7“
`casing crossover
`problem was identified,
`horizontal well #2
`had already been completed with an identical
`casing string
`design.
`Aa stated previously, weIl #3 received 5W’ casing from TD
`to surface,
`and was driIIed at a maximum inclination
`of 88°.
`Fracture
`pIugging
`problems
`associated with wells #1 were
`never. seen on wells #2 and #3, as adequate
`circulating
`and
`reverse circulating
`procedures
`had been implemented
`to cfean
`out sand from the fracture treatment.
`
`Program.
`Cementing
`Similar cement programs were utilized
`on alI three welI. The intermediate
`casing was cemented with
`a foamed Iead sIurry followed by a Class C tail slurry. The tail
`slurry was targeted to cover
`the build section, up to the initial
`kick off point. The foamed lead slurry was required to keep
`horn
`exceeding
`the
`formation
`fracture
`gradient.
`The
`horizontal
`section was aIso cemented with a Class C base
`SIUXTY with several additives.
`The main requirements
`for this
`slurry were 1) light weight, 2) excellent
`rheologic
`properties,
`3) no free water, and 4) low fluid loss.
`on the horizontal
`Cement bond evaluation was attempted
`section of weIl #1. The resuIts were inconclusive.
`Therefore,
`attempts
`to evaluate
`the cement bond on the remaining wells
`was not
`implemented.
`It
`is possible
`that
`inadequate
`cement
`bond may have played a role in the abnormal
`initiation,
`and
`growth ofiacture;seen-in.
`bo[h wells #1 and #3.
`
`and Isolation.
`Stage Spacing
`Perforating,
`the
`To minimize
`creation
`of muItiple
`fractures
`upon initiation,
`point
`source
`——
`
`Each stage was perforated with 12
`perforating was utilized.
`(W’) jet holes over one foot. The perforating
`charges were
`phased at 30°.
`Perforating
`guns were conveyed
`via coiled
`tubing and fired utilizing a pressure actuated firing head.
`Stage spacing was determined
`from a number of factors.
`In well #1, frac stages were spaced approximately
`130_ft apart,
`due to the lower average permeability
`in this part of the field
`and due to limitations
`imposed
`by offset vertical wells.
`In
`wells
`#2
`and
`#3,
`the
`frac
`spacing
`was
`increased
`to
`approximately
`170 ft
`as
`a
`result
`of
`existing wells
`and
`budgetary constraints.
`stages was achieved with & use of
`Isolation
`between
`bridge
`plugs.
`other methods,
`-of stage
`drillable
`composite
`isolation were considered
`(i.e. a multi-set
`retrievable
`bridge
`plug,
`stacking several
`retrievable
`bridge plugs,
`etc.] but all
`were deemed to have greater
`risk than the operating company
`was willing to accept.
`—.
`
`Completion Operations.
`All operations were planned to be
`rigless, performed
`only with the use of a 2“ coil
`tu_@ unit.
`operations
`such as perforating,
`and setting bridge plugs, were
`performed
`routinely
`and without
`incident.
`As ~reviously
`mentioned, debris collection in the casing crossover
`c~uld not
`be removed by the maximum circulating
`rates ac~jeved with
`the coil tubing. Modifications
`to the cleanout procedures were
`made which
`included
`reverse
`circulations
`via
`coil
`tubing
`between stages,
`conventional
`circulations
`during drill-out
`of
`composite
`bridge plugs,
`along with occasional
`viscous
`pill
`sweeps during both operations.
`bridge plugs with a progressive
`Drilling of the composite
`the most
`difficult
`portion
`of
`cavity motor
`proved
`to be
`completion.
`Initial attempts
`to drill
`the composite bridge plugs
`met with limited success
`as insufficient
`circulating
`rates
`in
`combination with fluid loss to the hydraulic
`fractures
`severely
`limited cuttings
`transport
`to surface. A rig had to be utilized
`for
`this portion
`of
`the completion
`for
`the first
`two wells,
`However
`in well #3,
`the installation
`of 5 Y2° casing to surface
`allowed
`the coil
`tubing unit
`to successfully
`drill out all 11
`composite bridge plugs.
`
`Hydraulic Fracture Design and Evaluation
`
`Approach.
`Real-Data
`Over the course of the three_horizontal
`wells, real-data feedback was utilized to the maximum extent
`possible
`for completion
`and fracture design,
`evaluation,
`and
`Implicit
`in this approach
`is the recognition
`that
`refinements’g.
`hydraulic
`fracture behavior
`is complex and variable,
`severely
`limiting the usefulness of traditional
`predictive mode or “one
`size fits all” approaches.
`of
`stimulation
`fracture
`Key issues for successful hydraulic
`a horizontal well are:
`(1)
`to assure
`that
`fractures
`effectively
`cover
`the intended pay interval height; and,
`(2) to assure that
`the connection
`between the wellbore
`and the far-field fracture
`considering
`both
`proppant
`placement
`during
`is adequate4,
`
`338
`
`4 of 13
`
`Ex. 2066
`IPR2016-01496
`
`

`

`SPE 39941
`
`A CASE STUDY: ~oMPLETION
`
`AND STIMULATION OF HORIZONTAL WELLS IN THE LOST HILLS DIATOMITE
`
`,5
`
`-,
`
`.
`
`.
`
`.
`
`treatment execution and post-frac production response,
`Based on information
`obtained
`from vertical “data wells”
`the horizontal
`wellpaths,
`and
`conventional
`located
`along
`vertical weII
`fracturing
`experience,
`initial
`fracture
`designs
`were developed
`for each of the horizontal wells. A fracture
`closure stress profile was developed
`using micro-frac
`and pore
`pressure measurements,
`combined
`with
`sonic
`log results.
`Using
`~his closure
`stress
`profile
`and an estimate
`of net
`pressure,
`‘a
`-3-D fracture
`growth
`simulator was
`used
`to
`determine
`the horizontal wel[ vertical depth location,
`and to
`decide initiaI fracture treatment
`size.
`in each horizontal
`stages
`During
`the course
`of
`fracture
`fracture diagnostic
`well, a combination
`of direct and indirect
`techniques were utilized to provide
`feedback for fracture and
`Surface
`tiltmeter
`fracture
`completion
`design
`refinement.
`mapping*0”13 and real-time
`fracture
`pressure
`analysiss’g were
`performed
`to: (a) estimate
`fracture dimensions;
`(b) determine
`approximate
`fracture location with respect
`to the perforations;
`and,
`(c) eva~ua~=the
`wellbore-to-fracture
`connectioniin
`‘ad&ltlon, fracture height was directly measured
`during
`four
`stages
`in we~ #3 using
`a wireline-deployed
`downhole
`tiltmeter array located in a nearby vertical we11]4’ls.
`Three
`diagnostic
`fracture
`injections
`were
`generally
`performed prior
`to each propped fracture stage,
`including two
`water” (K~
`substitute)
`injections
`and
`a
`crosslinked
`gel
`injection.
`~~njections
`was to: (a) provide
`such as” fracture
`closure
`pressure,
`analysis
`‘iZn=OIntS-
`Ieakoff behavior,
`and net pressure
`trends
`for net pressure
`history matchingg;
`and,
`(b)
`characterize
`the wellbore-to-
`fracture
`connection,
`using a combination
`of
`rate
`stepdown
`testss and proppant
`slugs17”18.
`the
`determining
`involves
`Net pressure
`histgr~ matching
`_——
`actual or. “observed” _net pressure within the fracture, and then
`adjusting
`simulator
`input
`parameters
`to match
`theoretical
`“model” net pressure with the observed net pressure response.
`While net pressure history matching does not assure that
`the
`correct
`frac-.
`geometry
`is modeled,
`it at
`least provides
`a
`framework
`for
`analysis
`and
`stage-by-stage
`consistent
`comparison,
`and the
`solutions
`are
`firmly
`linked
`to actual
`treatment behavior.
`
`injection(s)
`
`using
`
`KC1
`
`is higher) Borate
`(higher geI loading when tortuosity Ievcl
`crosslinked
`gel fluid system, at rates of 45-50 BP,M, with
`20/40 Ottawa sand proppant.
`Proppant
`concentration
`“was
`ramped quickly to a maximum of 12 PPG. The last 75%
`of the sand contained a fibrous proppant
`flowback control
`additive;
`bridge plug via coiled tubing half
`Set a composite
`distance between last perfs and next stage perfs;
`Clean the remaining proppant
`from wellbore using coiled
`tubing;
`next point source (1 ft @ 12 SPU in[er~al via
`Perforate
`coiled tubing; and,
`Repeat
`for subsequent
`
`stages.
`
`the
`
`6)
`
`7)
`
`8)
`
`9)
`
`Overview of Hydraulic Fracture Completion
`Observations
`and Conclusions
`
`and concliutions -for
`the general observations
`In this section,
`summari:,ed.’
`‘“ The
`. well
`completion
`are
`each
`horizontal
`following section will
`then address
`selected issues and-results
`in a more detailed manner.
`fracture behavior was
`In general, highly variable hydraulic
`encountered,
`but
`there were consistent behavior
`trends in each
`well.
`The transition
`from the routine, manufacturing-mfide
`completion
`of conventional
`vertical Lost Hills wells
`to the
`horizontal well completions
`involved a steeper
`learning curve
`than originally
`anticipated,
`especially
`in terms of wel~ore
`cleanout
`and fracture
`initiation.
`Thus,
`there were significant
`changes in procedures
`from well to well.
`Table
`2
`completion
`in
`summarizes
`the
`differences
`procedure,
`fracture treatment behavior
`and results for aI1 tfiiee
`horizontal wells. Figure 4 summarizes
`the estimated propped
`frac vertical height coverage for all fracture stages:
`“”
`
`Well #1.
`first
`of Chevron’s
`fracture behavior
`The hydraulic
`by
`horizontal well
`in the Lost Hills Field was dominated
`problems
`resulting
`from insufficient
`wel[bore
`c~eanout
`between stages.
`from
`in the crossover
`left
`Starting with stage 3, proppant
`5-1/2” to 7“ production casing (located at the beginning of the
`horizontal
`section)
`caused
`problems with fracture
`initiation
`and breakdown.
`The initial breakdown
`injection
`tended to
`mobilize
`and transport-
`the leftover
`proppant
`to the’”perfs.
`Before any significant
`fracture width was created,
`resu?ting in
`partial or total plugging of the near-wellbore
`fracture
`region.
`The problem worsened with succeeding
`stages,, as the voIume”
`(casing
`length)
`between
`the
`crossover
`and the per~orated
`interval decreased.
`region with
`The plugging and packing of the perforation
`abnormal
`proppant
`during
`breakdown
`resulted
`in highly
`fracture behavior,
`as the preferred
`fracture
`initiation pIane(s)
`were
`screened
`out and formation
`stress
`in the perforation
`region was increased. Breakdown
`injection ISIP’S clim%ed to
`well
`above
`overburden
`stress,
`and
`net
`pressures
`were
`
`339
`
`5 of 13
`
`Ex. 2066
`IPR2016-01496
`
`Fracture Design.
`the
`of
`consisted
`frac design
`The basic
`fluid injections were ended with a rate
`all
`following
`(Note:
`stepdown
`testG to assist with evaluating
`the near-wellbore
`wellbore-to-fr~ture
`connection]:
`I)
`perform
`diagnostic
`water
`substitute;
`(a) proppant
`containing
`,minifrac
`a crosslinked
`2) Conduct
`the perforations
`using linear gel;
`slug(s), overflushed
`past
`3) Tailor
`the pad volume with respect
`to the observed leakoff
`rate,
`to shorten
`closure
`time
`and thus
`lessen proppant
`redistribution
`during fracture closure;
`4) Adjust
`fracture
`treatment
`size (within practical
`achieve desired geometry);
`Pump
`propped
`fracture
`
`5)
`
`treatment
`
`using
`
`a 25-35 PPT
`
`limits)
`
`to
`
`

`

`6
`
`ti.A. EWUELE,
`
`W.A, MINNER, L. WEIJERS, E.J. BROUSSARD, D.M. BLEVENS, AND B.T. TAYLOR
`
`.4
`
`Table 2: Cornpa~son
`
`of f;acture
`
`treatment
`
`bebavior
`
`in the three horizontal weils.
`
`Sti-tiit
`. ... -. .-. .
`
`..
`
`‘“
`.
`
`.
`
`.
`
`.
`
`.
`
`.
`
`.
`
`,.
`
`,.’
`
`-----
`
`. . . .
`
`. ..
`
`. ___
`~Well
`__
`Number of stages
`Horizontal section len~th (ft)
`Horizontal section.TVD DepthfRl_
`Overall fracture behavior summary
`
`Fracture inltlatlon procedure
`
`...
`
`#l
`
`7
`1350
`2250’
`Near-wellbore & far-field
`fracture complexity,
`abnormally high net pressure,
`dominant upward growth
`Water (KCI substitute),
`low flow rate,
`conventional oerforatina
`
`stage 3, 4, 5, 6, 7
`stage 7
`250,000
`0.51-0.71
`470
`
`105-680
`365
`-6
`
`60-143
`100
`118-277
`190
`N43”E - N56”E
`Within 6° from vertical
`8%
`
`stages 4 and 5
`stage 6 and 7
`
`(% of total
`
`Well #-
`10
`2000
`2000’
`Nomal net pressure, frac
`height growth centered at
`wellbore, good wellbore-
`fracture connection
`Avoid pert in high natural frac
`intensity, 60# HEC viscous
`Dill, high flow rate,
`overbala~ce perforating,
`none
`none
`300,000
`0.55-0.61
`540
`
`90-175
`140
`-3
`
`76-105
`95
`165-226
`200
`N39”E - N50°E
`Within 5° from vertical
`17%
`
`none
`none
`
`-440
`100
`
`Weii #3
`12
`2400
`2000’
`Dominant upward growth into
`low stress interval, low net
`pressure, fractures offset from
`perf interval
`60# HEC viscous pill,
`extreme overbalance
`perforating,
`tigh flow rate
`Stage 3
`
`260,000
`0.53-0.64
`440
`
`20-310
`75
`-3
`
`114-167
`130
`165 —41O*
`205
`N38”E - N51 “E
`Within 8“ from vetical
`25%
`
`None
`stage 1, 2, 3, 5, 7, 8, 10
`
`~
`
`-250
`not available
`
`Fracture initiation perf plugging problems
`~
`Average proppant per stage (Ibs.)
`Closure stress gradient (psi/ft)
`Average near-wellbore fracture tortuosity during
`~
`End propped frac net pressure range (psi)
`Average end propped frac net pressure (psi)
`Average number of “equivalent” far-field fractures
`to explain prop frac observed net pressure
`Propped fracture half-length range (ft)
`Average propped half-length (ft)
`Propped fracture height range (ft)
`~d
`height (ft)
`Primary fracture azimuth
`Fracture dip
`Average horizontal fracture component
`frac volume)
`Substantial
`longitudinal vertical fractures
`Main frac offset from Perforation interval
`(displaced along well~re)
`All stages
`Dominant upward fracture height qrowth
`-140
`Initial production (BOPD)
`10
`Production @ 6 months (BOPD)
`* Height growth cfifictly measured utifrzing downhole tiltmeter fracture mapping in stages 7-10
`
`tiltmeter
`surface
`two stages,
`During
`elevated.
`abnorrnafly
`fricture mapping
`identified
`a significant
`(15-30% of fracture
`volume)
`Iongifudinal Vertical
`fracture
`component,
`separate
`from the main transverse
`vertical
`fracture
`component.
`Two
`other stages- showed significant
`fracture offset
`(50 ,to 125 ~)
`alo’ng the wellbore
`from the perforation
`interval.
`OveralI,
`pro~ti
`ficture
`shutdown-net
`pressures were also abnormally
`suggesting
`that
`near-wellbore
`fracture
`initiation
`high,
`complexity
`also
`resulted
`in far-field
`fracture
`complexity”
`fiai[urS31s’19’20. - As a result of
`the high net
`(multiple
`presfis
`fracture height was generally smaller
`than desired.
`The we~l’s production-response
`from the seven frac stages
`.
`. .. .
`placed was disappo]nting~ with an IP of 140 BOPD and a 6-
`month rate of 10 BOPD (see Figure
`5). The primary reason
`for the pooi productivity
`~s believed to be a poor connection
`between-the
`perforations
`and the far-field fractures,
`a resu~t of
`the perforation’
`plig@ng
`~ro=m
`and consequent
`awkward
`fracture initiation.
`The !OWproductivity may also have been
`ag-d
`by post-frac
`creanout problems,
`the result of poor
`transport of compotite
`bridge plug debris during circulation up
`
`,.
`
`.-:
`
`__,
`
`the annulus.
`the circu9at~on-rate,
`increasing
`Despite pumping gels pills,
`and additional
`circr,da(ion time in the crossover
`region,
`it was
`concluded
`that
`the crossover
`could not be effective~y c~eaned
`by circulating
`up the
`annulus.
`Thus,
`reverse” circulation
`techniques were used in the following wells.
`
`—..--,.
`
`,..
`
`. :-
`
`this well also had a 7“ x 5-1/2”
`to well #1,
`Wefi #2. Similar
`at
`the beginning
`of
`the horizontal
`section. ”
`casing crossover
`breakdown
`problems
`experienced
`during
`However,
`the
`fracture stimulation
`in well #l were mostly eliminated,
`due to
`the
`combination
`of different
`clean-out
`procedure
`between
`fracture stages, and a different
`fracture initiation procedure.
`As on well #1, a “point
`source” perfora~ion “itrfiegy was
`empIoyed, with 12 large holes spaced over
`I’”foot’of interval:
`However,
`fracture
`initiation
`procedures
`dufing-’well- #2 were
`significantly
`changed, with the goals
`of
`rninirnqi~ng near-
`wellbore
`fracture
`tortuosity
`and
`reducing”
`the weI~ore
`fracturesZ1”23. The
`revised
`initiation
`initiation
`of multiple
`-..
`procedures
`consisted OE
`
`340
`
`6 of 13
`
`—.-
`
`Ex. 2066
`IPR2016-01496
`
`

`

`SPE 39941
`--. —
`.-. ——
`
`A CASE STUDY COMPLETION AND STIMULATION OF HORIZONTAL WELLS IN THE LOST HILLS DIATOMITE
`
`7
`
`-.
`
`. _.=
`
`2.
`
`3.
`
`4.
`
`15(X)
`
`! I
`
`()
`
`IX(X)
`
`Mstincc (feet)
`I(xx)
`
`51X1
`
`()
`
`15(11
`
`Slxl
`
`O&tie
`(fee;)
`I(MXI
`
`Is(x)
`
`21XX)
`
`2
`
`3
`
`4
`
`~
`
`~
`
`x
`
`7
`
`9
`
`10
`
`I
`
`17(XI
`
`t
`
`- lxx)
`
`21(XI
`
`5 }
`
`% 1’“‘ ‘ ‘:‘:‘:~~: ‘:‘1
`
`at
`
`overbalanced
`
`or
`
`extreme
`
`overbalance
`
`injection rate as fast as
`
`Perforating
`conditions;
`Initiating with a 60 PPT HEC linear gel “pill” (as opposed
`to low-viscosity KC1 substitute),
`spotted
`downhole
`via
`coiled tubing; and,
`Increasing
`the initial breakdown
`operationally
`feasible.
`Overbalanced
`perforating was used during stages 4-9 with
`the bottomhole
`pressure
`gradient
`set at 0.75 psi/ft
`(above
`fracture closure gradient but below overburden
`gradient)
`and a
`fluid-filled wellbore, Extreme overbalance
`perforating
`(with a
`nitrogen cushion and a bottomhole
`gradient of 1.4 psi/ft) was
`tested on the last stage, and yielded the lowest near-wellbore
`friction (tortuosity) of all of the stages and a low net fracturing
`pressure at the end of the treatment.
`appeared to be
`These revised fracture initiation procedures
`complexity
`and
`effective
`in reducing
`near-wellbore
`fracture
`reducing the number of far-field multiple fractures
`required to
`explain observed levels of net pressure.
`generally
`results
`Surface
`tiltmeter
`fracture mapping
`showed a simple fracture geometry in the expected transverse
`orientation, with no significant
`fracture
`center depth shift or
`offset from the perforation
`interval along the casing axis. As a
`result of the good interval height coverage
`and the favorable
`wellbore-to-frauture
`connection,
`initial production was better
`than expected at about 440 BOPD, with a 6-month production
`rate of about 100 BOPD (see Figure 5).
`
`Well #3. With the success of well #2, nearly all drilling and
`completion
`procedures were held constant
`for well #3, but
`there were several significant
`changes.
`First, well #3 was completed with 5-1/2” casing from TD
`to surface.
`This cha