DOE/MC/25115--3115
`
`DE92 012458
`
`Stimulation,
`Drilling, Completion,
`and Testing of Hardy HW#1 Weil,
`Putnam County, West Virginia
`
`Final Report
`
`William K. Overbey, Jr.
`Richard S. Carden
`C. David Locke
`S. Phillip Salamy
`
`Work Performed Under Contract No.: DE-AC21-89MC25115
`
`For
`of Energy
`U.S. Department
`Office of Fossil Energy
`Morgantown Energy Technology Center
`P.O. Box 880
`Morgantown, West Virginia 26507-0880
`
`By
`BDM Engineering Services Company
`7915 Jones Branch Drive
`McLean, Virginia 22102
`
`March 1992
`
`Weatherford International LLC et al.
`Exhibit 1036
`Weatherford International LLC et al. v. Packers Plus Energy Services, Inc.
`IPR2016-01517
`Page 1 of 231
`
`

`

`ABSTRACT
`
`the detailed
`logging,
`in drilling,
`operations
`field
`discusses
`report
`This
`located
`casing,
`completing,
`stimulating
`and testing the Hardy HW#1 well
`in Union District, Putnam County, West Virginia.
`The project was designed
`and managed by BDM in cooperation with Cabot Oil and Gas Corporation.
`The well was spudded on November 29, 1989 and was completed at a total
`measured
`depth of 6406 feet on December 29, 1989.
`The well was drilled
`on
`an
`average
`azimuth
`of
`335
`degrees
`with
`a total
`horizontal
`displacement
`of 2618 feet.
`Approximately
`1035 feet of
`the well had an
`inclination
`higher
`than 86 degrees, while 2212
`feet of
`the well had an
`inclination
`greater
`than 62 degrees.
`The well was partitioned
`into five
`zones for stimulation
`purposes.
`Four zones were stimulated
`during three
`stimulation
`operations
`(Zones 3 and 4 were stimulated
`together).
`Zone 1
`foam frac while the stimulations
`stimulation was a successful
`on Zones
`rates were 4.5
`2, 3-4 were partially
`successful.
`Initial gas production
`times greater
`than the natural
`production
`rate. After
`21 months,
`gas
`produced from the BDM/Cabot well has declined at a rate about one-half
`that of a conventional
`vertical well
`in the area.
`This horizontal well
`is
`projected to produce 475 million cubic feet of gas over a 30-year period.
`
`Weatherford International LLC et al.
`Exhibit 1036
`Weatherford International LLC et al. v. Packers Plus Energy Services, Inc.
`IPR2016-01517
`Page 2 of 231
`
`

`

`TABLE OF CONTENTS
`
`1.0
`
`EXECUTIVESUMMARY
`
`2.0
`
`INTRODUCTION
`
`3.0
`
`LEASE ACQUISITION AND LOCATION DEVELOPMENT
`
`4.0
`
`DRILLING PLAN SUMMARY
`
`5.0
`
`DRILLING OPERATIONS
`
`5.1
`5.2
`5.3
`5.4
`
`Introduction
`Vertical Hole
`Build Section
`Horizontal
`Section
`
`6.0
`
`LOGGINGOPERATIONS
`
`Introduction
`6.1
`6.2 Mud Logging
`6.3
`Shallow Hole and Free Fall Logging
`6.4
`Horizontal Section Logging
`
`7.0 MOTOR PERFORMANCEAND BOTTOM HOLEASSEMBUES
`
`7.1
`7.2
`7.3
`
`Introduction
`Motor Performance and BHA's for Angle Building
`Rotary Directional Drilling Assemblies
`for
`Horizontal
`Section
`
`iii
`
`Paae--
`
`1
`
`3
`
`3
`
`4
`
`7
`
`7
`9
`11
`14
`
`21
`
`21
`21
`21
`22
`
`23
`
`23
`23
`28
`
`Weatherford International LLC et al.
`Exhibit 1036
`Weatherford International LLC et al. v. Packers Plus Energy Services, Inc.
`IPR2016-01517
`Page 3 of 231
`
`

`

`8.0
`
`DIRECFIONALCONTROLOPERATIONS
`
`Introduction
`8.1
`Steering Tool Operations
`8.2
`8.3 MWD Tool Operations
`
`9.0
`
`ANALYSIS OF DRILLING OPERATIONS
`
`10.0 COMPLETIONOPERATIONS
`
`10.1 Introduction
`10.2 Casing Design
`10.3 Inflation of Casing Packers
`10.4 Cementing
`
`11.0 STIMULATION OPERATIONS
`
`11.1 Introduction
`11.2 Treatment of Zone 1
`11.3 Treatment of Zone :2
`11.4 Analysis of Problems in Fracing Zone 2
`11.5 Stimulation of Zones 3 and 4
`11.6 Analysis of Problems in Fracing Zone 3-4
`
`12.0 WELL TESTING OPERATIONS AN[) ANALYSIS
`
`12.1 Pressure Build-up Testing
`12o1.1 Pre-Stimulation
`Testing and An_,!ysis
`12.1.2
`Post-Stimulation
`Testing and Analysis
`12.2 Drawdown Testing
`- Post-Stimulation
`12.3 Well Test Results and Conclusions
`
`13.0 ANALYSIS OF COMPLETION, STIMULATION, TESTING AND
`PRODUCTIONOPERATIONS
`
`13.1 Completion Operations
`13.2 Stimulation Operations
`
`iv
`
`30
`
`30
`30
`33
`
`33
`
`35
`
`35
`37
`38
`39
`
`40
`
`40
`40
`43
`48
`55
`58
`
`61
`
`61
`62
`72
`77
`83
`
`87
`
`87
`88
`
`Weatherford International LLC et al.
`Exhibit 1036
`Weatherford International LLC et al. v. Packers Plus Energy Services, Inc.
`IPR2016-01517
`Page 4 of 231
`
`

`

`13.3 Well Testing Operations
`13.4 Production Operations
`
`14.0 WELL COST ANALYSIS
`
`15.0 SUMMARYAND CONCLUSIONS
`
`16.0 REFERENCES
`
`17.0 APPENDICES
`
`92
`92
`
`95
`
`101
`
`103
`
`104
`
`''l't
`
`.....
`
`p,' "
`
`lit
`
`"'
`
`iIrllr,l_llr
`
`,i,
`
`lind irllll,
`
`Weatherford International LLC et al.
`Exhibit 1036
`Weatherford International LLC et al. v. Packers Plus Energy Services, Inc.
`IPR2016-01517
`Page 5 of 231
`
`

`

`i
`
`LIST OF ILLUSTRATIONS
`
`Figure
`
`Figure 3.1
`
`Figure 3.2
`
`Relationship to the Planned Wellbore
`Trajectory to Structure on the Base of
`the Huron Shale
`Location and Trajectory of Planned Horizontal
`Well Across a 3-Lease Production Unit
`
`Figure 5.1
`
`Depth vs Days
`
`Figure 5.2
`
`Vertical View
`
`Figure 5.3
`
`Plan View
`
`Figure 6.1
`
`True Vertical Depth Presentation of Well Logs
`Through the Horizontal and High-Angle Section
`of the Hardy HW#1 Well With Gas Shows
`
`Figure 10.1
`
`Hardy #1 Well Schematic
`
`Figure 11.1
`
`Nitrogen Breakdown (Prepad) on Zone 1
`
`Figure 11.2
`
`Foam Fracturing Treatment on Zone 1,
`Hardy HW#1
`
`Figure 11.3
`
`Nitrogen Breakdown (Prepad) of Zone 2
`(First Time)
`
`Figure 11.4
`
`Second Nitrogen Breakdown (Prepad) for Zone 2
`
`Figure 11.5
`
`Pressure Response During Initial Foam Pad
`Injection
`
`vi
`
`Paae
`
`5
`
`6
`
`8
`
`19
`
`20
`
`24
`
`36
`
`42
`
`44
`
`46
`
`47
`
`49
`
`Weatherford International LLC et al.
`Exhibit 1036
`Weatherford International LLC et al. v. Packers Plus Energy Services, Inc.
`IPR2016-01517
`Page 6 of 231
`
`

`

`Figure 11.6
`
`Aborted Attempt to Frac Zone 2 After Replacing
`Packer
`
`Figure 11.7
`
`Nitrogen Pad Injection Into Zone 2 After
`Perforating
`
`Figure 11.8
`
`Foam Frac on Zone 2
`
`Figure 11.9
`
`Foam Frac on Zone 2 Showing Screen Out
`
`Figure 11.10
`
`Difficulty Associated with Attempting to Inflate
`Closely-Spaced Natural Fractures from a
`Horizontal Wellbore
`
`Figure 11.11
`
`Initial Attempt to Frac Zone 3-4 Using
`Sand-Laden Foam
`
`Figure i1.12
`
`Attempt at
`in Zone 3-4
`
`Injecting Foam After Screen'Out
`
`Figure 11.13
`
`Nitrogen Frac of Zone 3-4 Following Sand-Foam
`Screen-Out
`
`Figure 12.1.1
`
`Analysis of Pre-Stimulation Data Using
`RHM T_chnique
`
`;
`:
`
`Figure 12.1.2
`
`Well Type Curve with Wellbore Storage
`and Skin Effect
`
`Figure 12.1.3
`
`Change in Adjusted Pressure vs Adjusted
`Effective Time, Pre-Stimulation
`
`Figure 12.1.4
`
`Pressure Build-up Analysis for Pre-Stimulation
`Data Using Horner's Technique
`
`Figure 12.1.5
`
`Type Curves for Horizontal Wells
`
`vii
`
`50
`
`51
`
`52
`
`53
`
`56
`
`57
`
`59
`
`60
`
`63
`
`66
`
`67
`
`69
`
`71
`
`Weatherford International LLC et al.
`Exhibit 1036
`Weatherford International LLC et al. v. Packers Plus Energy Services, Inc.
`IPR2016-01517
`Page 7 of 231
`
`

`

`Figure 12.1.6
`
`Pre-Stimulation Type Curve Match
`
`Figure 12.1.7
`
`Change in Adjusted Pressure vs Adjusted
`Effective Time, Post-Stimulation
`
`Figure 12.1.8
`
`Pressure Build-Up Analysis for Post-
`Stimulation Data Using Homer's Technique
`
`Figure 12.2.1
`
`Initial Production Data
`
`Figure 12.2.2
`
`Two Rate Flow Test Analysis, Post-
`Stimulation
`
`Figure 12.2.3
`
`Drawdown Pressure Type Curve Match
`
`Figure 13.1
`
`Gas Shows vs Measured Depth
`
`Figure 13.2
`
`Wellbore Configuration
`
`Figure 13.3
`
`Production Decline Analysis for Vertical and
`Horizontal Shale Wells, Putnam County, WV
`
`Figure 13.4
`
`Production Projection Using Gas Reservoir
`Simulation (G3DFR)
`
`Figure 13.5
`
`Average Daily Production Data
`
`Figure 13.6
`
`Cumulative Production Data
`
`Figure 13.7
`
`Hardy #1 Post-Stimulation Production Rate
`Match of Actual Data With Average Decline
`Curve of Wells in the Same Area
`
`73
`
`75
`
`76
`
`78
`
`80
`
`82
`
`89
`
`90
`
`93
`
`94
`
`96
`
`97
`
`99
`
`Figure 13.8
`
`Hardy #1 Project Cumulative Production Based
`on Type Curve Match of Average Well Decline
`
`100
`
`viii
`
`Weatherford International LLC et al.
`Exhibit 1036
`Weatherford International LLC et al. v. Packers Plus Energy Services, Inc.
`IPR2016-01517
`Page 8 of 231
`
`

`

`LIST OF TABLES
`
`Table 5.1
`
`Multishot Survey at Total Depth
`
`Table 7.1
`
`Comparison of Rates of Penetration of Motors
`During Angle Building Drilling
`
`Table 11.1
`
`Summary
`
`of Frac Treatments for Hardy HW#1
`
`Table 11.2
`
`Flowback Summary
`
`for Frac Job on Zone 1
`
`Table 12.1.1
`
`Basic Reservoir and Well Data
`
`Table 12.3.1
`
`Pre-Stimulation Well Test Analysis Results
`
`Table 12.3.2
`
`Post-Stimulation Well Test Analysis Results
`
`Table 12.3.3
`
`Estimates of Kv and KH Values Based on
`Horizontal Well Type Curve Analysis
`
`Table 12.1
`
`Cost Data BDM/Cabot Horizontal Well
`
`17
`
`29
`
`41
`
`41
`
`64
`
`84
`
`85
`
`86
`
`98
`
`ix
`
`Weatherford International LLC et al.
`Exhibit 1036
`Weatherford International LLC et al. v. Packers Plus Energy Services, Inc.
`IPR2016-01517
`Page 9 of 231
`
`

`

`1.0 EXECUTIVESUMMARY
`
`The Cabot Oil & Gas Hardy HW#1 well was spudded on November 29,
`1989, and drilling was completed at a total measured depth of 6,399 feet
`on December 29, 1989. The well was drilled on an average azimuth of
`335°, with a total horizontal displacement of 2618 feet.
`Approximately
`1035 feet of
`the well had an inclination higher
`than 86"
`(horizontal),
`while 2212 feet of the well had an inclination greater
`than 62 degrees.
`The well was turned to a 90 degree inclination over a measured course
`length of 1346 feet which is a true vertical depth (radius) of 829 feet.
`
`The inclined well encountered 59 shows of gas with a calculated
`volume of more than 2 mcfpd. Twelve gas shows had calculated volumes
`greater than 50 mcfpd, the largest of which was 178 mcfpd.
`
`required only 35
`it
`reaching the kick-off point at 3253 feet,
`After
`hours of drilling time to turn the well
`to a 90 degree
`inclination
`(horizontal at an average penetration rate of 41.0 feet per hour).
`The
`Ilorizontal
`section was drilled with conventional
`rotary tools with a 7-
`7/8" bit and the rate of penetration was 46.5 feet per hour.
`During
`drilling of
`the shallow vertical section of
`the hole,
`the average rate of
`penetration was 26.6 feet per hour for drilling both the 17 1/2" and 12
`1/4" hole down to the KOP. When a strong flow of water was encountered
`in the Big lnjun Sand and the well was mudded up, penetration rate
`dropped to 12.2 feet per hour.
`
`Steering tool operations were the most costly and time consuming
`during drilling.
`Seven steering tool
`failures were encountered which
`resulted in delays of four days in the drilling operations.
`
`Logging operations were beset with operational problems which
`provided an incomplete video survey of
`the borehole (to a depth of only
`4550 feet) and successful geophysical
`logs going into the hole only. The
`available logs along with the mud logs were used to select
`tl_e locations
`of
`the five external casing packers and the four ported collars in the
`casing string.
`
`Weatherford International LLC et al.
`Exhibit 1036
`Weatherford International LLC et al. v. Packers Plus Energy Services, Inc.
`IPR2016-01517
`Page 10 of 231
`
`

`

`The improvements in downhole motors have increased penetration
`rates to the point where they are nearly equal
`to those of vertical air-
`drilling rates. The Hardy HW#1 well was drilled in twenty-eight days less
`time than the first air-drilled horizontal well which was drilled
`in 1986
`(BET#l).
`
`The well was completed with five (5) casing packers and five (5)
`port collars included in the string of J-55, 10.5 Ib/ft 4.5 inch casing.
`A
`section of the casing in the inclined portion of the wetlbore was cemented
`with 130 sacks of class A cement
`between 4057' and 3500' as a
`permanent barrier
`to water. Thus the wellbore was configured into four
`separate zones for stimulation purposes.
`
`the port collars did not
`function as
`During stimulation activities,
`advertised by the vendor, and their opening and closing tools had to be
`modified in the field to make them work. This made stimulation and clean-
`up operations much more difficult and costly than anticipated.
`
`Zone one (1) was broken down with nitrogen and fraced with 80
`Quality
`foam and sand. Although the actual
`volumes
`injected were
`somewhat
`less than planned,
`the first
`stimulation was accomplished
`too many problems. Zone two
`(2) was a different story. Two
`without
`attempts were made before the well was partially fraced with foam at a
`much lower injection rate than originally planned. Zones 3 and 4 could be
`pumped into with nitrogen, but
`they would not accept
`foam, even at very
`low injection rates and without sand. These two zones were finally
`pumping straight nitrogen into the zones at
`stimulated by
`the highest
`rate possible without exceeding the established pressure limit.
`
`The well was cleaned-up after stimulation, and
`pressure build-up
`tests were conducted
`and drawdown
`to determine the success of
`ratio of 4.5 times
`natural
`stimulation
`operations.
`An improvement
`production rate was determined as a result of
`the well
`testing activities.
`
`is expected to produce 475 million cubic feet of gas over
`The well
`the next 30 years. Ultimate production before abandonment could well be
`double that amount. Production records examined for the first 21 months
`
`Weatherford International LLC et al.
`Exhibit 1036
`Weatherford International LLC et al. v. Packers Plus Energy Services, Inc.
`IPR2016-01517
`Page 11 of 231
`
`

`

`1.0 EXECUTIVESUMMARY
`
`The Cabot Oil & Gas Hardy HW#1 well was spudded on November 29,
`1989, and drilling was completed at a total measured depth of 6,399 feet
`on December 29, 1989. The well was drilled on an average azimuth of
`335°, with a total horizontal displacement of 2618 feet.
`Approximately
`1035 feet of
`the well had an inclination higher
`than 86° (horizontal),
`while 2212 feet of
`the well had an inclination greater
`than 62 degrees.
`The well was turned to a 90 degree inclination over a measured course
`length of 1346 feet which is a true vertical depth (radius) of 829 feet.
`
`The inclined well encountered 59 shows of gas with a calculated
`volume of more that1 2 mcfpd. Twelve gas shows had calculated volumes
`greater than 50 mcfpd, the largest of which was 178 mcfpd.
`
`it required only 35
`reaching the kick-off point at 3253 feet,
`After
`hours of drilling time to turn the well
`to a 90 degree
`inclination
`(horizontal at an average penetration rate of 41.0 feet per hour).
`The
`horizontal section was drilled with conventional
`rotary tools with a 7-
`7/8" bit and the rate of penetration was 46.5 feet per hour.
`During
`drilling of
`the shallow vertical section of
`the hole,
`the average rate of
`penetration was 26,6 feet per hour for drilling both the 17 1/2" and 12
`1/4" hole down to the KOP. When a strong flow of water was encountered
`in the Big Injun Sand and the well was mudded up, penetration rate
`dropped to 12.2 feet per hour.
`
`Steering tool operations were the most costly and time consuming
`during drilling.
`Seven steering tool
`failures were encountered which
`resulted in delays of four days in the drilling operations.
`
`problems which
`Logging operations were beset with operational
`provided an incomplete video survey of the borehole (to a depth of only
`4550 feet) and successful geophysical
`logs going into the hole only. The
`available logs along with the mud logs were used to select
`the locations
`of
`the five external casing packers and the four ported collars in the
`casing string.
`
`Weatherford International LLC et al.
`Exhibit 1036
`Weatherford International LLC et al. v. Packers Plus Energy Services, Inc.
`IPR2016-01517
`Page 12 of 231
`
`

`

`The improvements in downhole motors have increased penetration
`rates to the point where they are nearly equal
`to those of vertical air=
`drilling rates. The Hardy HW#1 well was drilled in twenty-eight clays less
`time than the first air-drilled horizontal well which was drilled
`in 1986
`(RET#1).
`
`The well was completed with five (5) casing packers and five (5)
`port collars included in the string of J-.55, 10.5 Ib/ft 4,5 inch casing.
`A
`section of the casing in the inclined portion of the wellbore was cemented
`with 130 sacks of class A cement
`between 40574 and 3500' as a
`permanent barrier
`to water. Thus the wellbore was configured into four
`separate zones for' stimulation purposes.
`
`the port collars did not
`function as
`During stimulation activities,
`advertised by the vendor, and their opening and closing tools had to be
`modified in the field to make them work. This made stimulation and clean-
`and costly than anticipated.
`up operations much more difficult
`
`Zone one (1) was broken down with nitrogen and fraced with 80
`Quality
`fo_m and sand. Although the actual volumes
`injected were
`the first stimulation was accomplished
`somewhat
`less than planned,
`too many problems. Zone two
`(2) was a different
`without
`story. Two
`attempts were made before the well was partially fraced with foam at a
`much lower injection rate than originally planned. Zones 3 and 4 could be
`foam, even at very
`pumped into with nitrogen, but they would not accept
`sand. These two zones were finally
`low injection rates and without
`pumping straight nitrogen into the zones at
`stimulated by
`the highest
`rate possible without exceeding the established pressure limit.
`
`pressure build-up
`The well was cleaned-up after stirnt:_ation, and
`and drawdown
`tests were conducted
`t,) determine the success of
`stimulation operations. An improvement
`ratio of 4.5 times natural
`production rate was determined as a result of the well testing activities.
`
`is expected to produce 475 million cubic feet of gas over
`The well
`the next 30 years. Ultimate production before abandonment could well be
`double that amount. Production records examined for th_ first 21 months
`
`Weatherford International LLC et al.
`Exhibit 1036
`Weatherford International LLC et al. v. Packers Plus Energy Services, Inc.
`IPR2016-01517
`Page 13 of 231
`
`

`

`production indicate the rate of production decline from the horizontal
`of
`well is about half the rate exhibited by vertical wells in the area.
`
`2.0
`
`INTRODUCTION
`
`As part of an ongoing Department of Energy Program to test
`emerging technology as methods of producing additional natural gas
`resources at economic rates,rh6 Morgantown Energy Technology Center
`has for more than twenty years been exploring the concept of horizontal
`drillingas an advanced technologyconcept to improve gas and oil recovery
`efficiency.
`
`The first successful air-drilled horizontal well was designed and
`drilled by BDM Internationalfor DOE in 1986 (Reference 1)
`in Wayne
`County, West Virginia, in conjunction with a small industry partner. BDM
`Engineering Services Company (BDMESC),
`a subsidiary of BDM
`International, was awarded a
`second competitive contract
`in 1989 to
`continue to explore the economics of drilling, completing and producing
`horizontal wells in tight,
`resource rich, Devonian shales of
`the
`Appalachian basin.
`
`BDMESC proposed a cost sharing arrangementwith Cabot Oil and Gas
`Corporation whereby they provide leases for drilling, share in the well
`costs, and serve as operator for drilling and production operations.
`BDMESC conductedgeologicstudies, selected the drill sites to be approved
`by Cabot and DOE , designed the weil, and supervised drilling and
`completion operations.
`
`3.0
`
`LEASEACQUISITIONAND LOCATIONDEVELOPMENT
`
`The results of a detailed geologic study and reservoir anatysis of
`three areas in Putnam County,West Virginia, where Cabot Oil and Gas had
`40,000 acres under lease were reported in a topical report "Selection of
`Geographic Area and Specific Site for Drilling a Horizontal Well
`in
`Cooperation with Cabot Oil and Gas Company." Area 2 in Union District
`near the village of Extra was selected as the specific area. The specific
`site and orientation of the well with respect to structure on the base of
`
`3
`
`Weatherford International LLC et al.
`Exhibit 1036
`Weatherford International LLC et al. v. Packers Plus Energy Services, Inc.
`IPR2016-01517
`Page 14 of 231
`
`

`

`Location of postulated fracture
`the Huron Shale is shown in Figure 3.1.
`zones is indicated by the dashed line on Figure 3.1.
`
`The location was presented to Cabo_ Oil and Gas who then proceeded
`to develop a production unit outline and to clear
`the titles for the leases
`included for drilling operations. The proposed production unit
`is shown in
`Figure 3.2 along with the location of a postulated 300 million cubic feet
`production fairway which would be crossed by the horizontal weil.
`
`Considerable problems were encountered by Cabot
`in obtaining a
`title for the included leases as a result of _, survey problem which
`clear
`occurred thirty or more years ago.
`The lease was finally cleared after
`legal examination and resurveying
`three months of
`of
`the involved
`properties. The staked location was surveyed on the ground and a drilling
`permit obtained from the West Virginia Oil and Gas Division of
`the West
`Virginia Department of Mines and Mineral Resources.
`
`4.0 DRILLINGPLANSUMMARY_
`
`The Hardy HW#1 Well was to be drilled as a horizontal well
`in the
`Lower Huron Shale to improve productivity. The well was designed to be
`drilled vertically
`to a kick-off point 716' below the top of
`the Berea
`Formation (approximately 3236' below GL).
`A string of 13 3/8" surface
`to isolate fresh water and coal. A 9 5/8"
`casing was to be set at 655'
`through the Berea Formation to isolate
`intermediate string was to be set
`potential water and hydrocarbon bearing intervals.
`
`the inclination was to be built with a
`point,
`the kick-off
`At
`downhole motor and steering tool at a rate of 8°/100'
`to an inclination of
`Then, 2000 feet of wellbore would be drilled in the target
`interval
`870,
`with a rotary assembly. The assembly would be designed to drop angle at
`approximately 0.25°/100' causing the weilbore to drop out of
`the target
`interval at the end of the 2000 feet.
`
`the wellbore was 340o which is nearly
`The preferred azimuth of
`fractures in the area.
`Provided the well stayed
`orthogonal
`to the natural
`within the pooled acreage, direction would not be a problem.
`In relation to
`
`4
`
`t
`
`L
`
`Weatherford International LLC et al.
`Exhibit 1036
`Weatherford International LLC et al. v. Packers Plus Energy Services, Inc.
`IPR2016-01517
`Page 15 of 231
`
`

`

`--
`
`Ffc3ure 3.2-
`
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`;_elattonsni_ of *_e Plamma _l]bore
`on _e 8ase of _
`Huron Shale
`
`TrLi_
`
`_o St_'t_e
`
`Weatherford International LLC et al.
`Exhibit 1036
`Weatherford International LLC et al. v. Packers Plus Energy Services, Inc.
`IPR2016-01517
`Page 16 of 231
`
`

`

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`
`Weatherford International LLC et al.
`Exhibit 1036
`Weatherford International LLC et al. v. Packers Plus Energy Services, Inc.
`IPR2016-01517
`Page 17 of 231
`
`

`

`below the top of
`interval was 1431feet
`the target
`the top of
`TVD,
`the
`Berea and the bottom was 1610 feet below the top of
`the Berea.
`Total
`target
`thickness was 179 feet.
`
`total depth,
`the well would be logged with wireline
`reaching
`After
`free fall and drill pipe conveyed open hole logs and a video camera.
`Then 4
`1/2"
`casing would
`be run
`using external
`casing
`packers
`to
`isolate
`individual
`producing
`intervals.
`The placement
`of
`the external
`casing
`packers and port collars would be determined
`using mud log data, open
`hole geophysical well
`logs, and the video camera.
`
`5.0
`
`DRILLING OPERATIONS
`
`5.1
`
`Introduction
`
`the site between November
`Drilling operations were conducted at
`29, 1989 and January 2, 1990.
`Total days on location were 30 compared
`to the anticipated
`24 days
`(excluding
`the four
`day
`shut down
`over
`A plot of depth versus time in days can be seen in Figure 5.1
`Christmas).
`with the plot comparing actual and projected times.
`
`took
`point
`to the kick-off
`the well
`portion of
`Drilling the vertical
`than anticipated because of an excessive water
`four days longer
`flow and
`required
`stuck
`drill pipe. The angle
`build section
`eight
`days
`to drill
`compared to a planned seven days.
`Steering tool problems slowed drilling
`The horizontal _;ection was planned to be drilled
`this section of
`the hole.
`in five days which was the actual
`time required.
`Logging required four
`days of rig time compared to an estimated three days. Drilling from kick-
`off point
`to release
`of
`the rig took
`two days
`longer
`than
`had been
`anticipated.
`
`the wellbore started at a deeper TVD than
`The horizontal section of
`had been planned because of problems associated with building inclination
`rate was 8°/100 ' and the
`with the Eastman motor.
`The planned build
`Eastman motor assembly
`averaged 6.7°/100'o
`The amount
`of wellbore
`within the target
`interval was still 2020'.
`
`Weatherford International LLC et al.
`Exhibit 1036
`Weatherford International LLC et al. v. Packers Plus Energy Services, Inc.
`IPR2016-01517
`Page 18 of 231
`
`

`

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`
`Weatherford International LLC et al.
`Exhibit 1036
`Weatherford International LLC et al. v. Packers Plus Energy Services, Inc.
`IPR2016-01517
`Page 19 of 231
`
`

`

`5.2
`
`Vertical Hole To 3253'
`
`to the kick-off point was drilled on
`the well
`The vertical portion of
`a footage basis by Great Western Drilling1. The well was spud at 11:00 pm
`on November 29, 1989. The conductor hole was drilled to 32 feet below
`ground level and a 20" conductor pipe was set. A 17 1/2" surface hole was
`drilled to 696' KB through fresh water zones and coal.
`
`Sixteen joints of 13 3/8", 54.5#/ft, J-55, ST&C casing were run and
`set at 668' KB (654' GL) to isolate fresh water zones and coal sections as
`The casing tally can be found in
`required by the state of West Virginia.
`The casing was cemented to surface with 460 sacks of
`Appendix A-I.
`Class "A" cement containing 2 percent CaCI2. The cement was mixed at
`15.6 ppg with a yield of 1.18 _3/sack.
`
`The 12 1/4" intermediate hole was drilled to a depth of 1860' when
`a 3" water flow was encountered in the Maxton sand section. Water from
`the Maxton had not been expected. The fresh water in the second reserve
`pit was drained to allow room for the formation water.
`
`a large water
`flow was
`until
`using mist
`continued
`Drilling
`encountered in the Big Injun Formation (2105') where water had been
`anticipated. A third reserve pit had been constructed to accommodate the
`additional water.
`Air and mist drilling continued for
`less than one hour
`until the third reserve pit was full. The well was m_king water
`in excess
`of 300 bbls per hour. Air drilling could not continue because there was no
`place to put the formation water.
`
`the well was mudded up. A day's worth of rig time
`this point,
`At
`was used to rig up a mud pit, mud pump and shale shaker. Once circulation
`drilling continued with partial
`was established,
`returns.
`Initially,
`the
`well was losing around 40 bbls per hour and the loss slowly tapered off.
`
`feet while the rig crew worked on
`Drilling was stopped at 2301'
`transferring more water
`into the mud pit
`(to make up for partial
`lost
`
`1 Use of company names and/or trademarks are for identification
`only and do not imply endoresment of a service or product.
`9
`
`Weatherford International LLC et al.
`Exhibit 1036
`Weatherford International LLC et al. v. Packers Plus Energy Services, Inc.
`IPR2016-01517
`Page 20 of 231
`
`

`

`,
`
`,,
`
`IL Ii
`
`iLIJ,
`
`,,
`
`the drill pipe
`circulation). When the crew came back to continue drilling,
`was differentially stuck.
`The drill pipe was worked for several hours but
`remained stuck.
`
`To free the pipe, both aerating the mud and spotting oil were debated
`as possible solutions,
`lt was assumed that aerating the mud might tear up
`the hole, So, 80 bbis of crude oil were spotted around the drill cellars.
`Once the oil was spotted,
`the drill pipe came free in a short period of
`time.
`
`to 2657 feet which was the intermediate
`then continued
`Drilling
`The drilling plan called for setting the 9 5/8" casing fifty
`casing point.
`feet below the base of
`the Berea Formation.
`The mud logger showed the
`top of the Berea to be at 2579 feet.
`
`A string of 9 5/8", 36#/ft, J-55, ST&C casing was run and set at
`2654' KB. The 9 5/8" pipe tally can be found in Appendix A-2.
`The casing
`was cemented as follows:
`
`of Halliburton
`light
`330 sacks
`fresh water,
`15 bbls of
`Pumped
`"A" cement
`followed
`by 100 sacks of Class
`containing
`3
`cement
`The cement was displaced with
`percent CaCl2 and 1/8 pps flocele.
`204 bbls fresh water and the plug was bumped with 1200 psi.
`The
`light cement was mixed at 13.6 ppg with a yield of 1.54 ft3/sack.
`The Class "A" cement was mixed at 15.6 ppg with a yield of 1.18
`ft3/sack.
`
`run
`log was
`ray correlation
`a gamma
`on cement,
`While waiting
`the
`the Berea Formation to be at 2577 feet or about
`showing the top of
`same depth as picked by the mud logger. The kick- off point would then be
`3295 feet; 716 feet below the top of
`the Berea.
`
`the 13 3/8" casing was cut
`for 12 hours,
`on cement
`After waiting
`The mud system was
`off and welded to the 9 5/8" casing for support.
`rigged down and the air system rigged back up. The BOP's were nippled up
`and the casing drilled out with an 8 3/4" bit.
`Drilling continued,
`dusting,
`to 3253' when a survey was taken to determine inclination and well
`
`10
`
`Weatherford International LLC et al.
`Exhibit 1036
`Weatherford International LLC et al. v. Packers Plus Energy Services, Inc.
`IPR2016-01517
`Page 21 of 231
`
`

`

`direction. The survey showed an inclination of 1° and an azimuth of 279°
`at a depth of 3191 feet,
`
`5.3
`
`Build Section
`
`Based upon the Berea top, the kick-off point should have been 3295';
`however, the kick- off point was changed to 3253'
`to provide some margin
`for
`failure to build angle at
`the planned rate.
`The Eastman motor was
`picked up along with a new 8 3/4" bit. The bend in the motor was set at
`1.1° with an 8 3/8" stabilizer below the bend. An 7 7/8"
`integral blade
`stabilizer was placed above the motor.
`(See BHA data in Appendix B-I.)
`
`The motor was tested at the surface and it operated normally. Three
`16/32"
`jets were placed in the bit
`to reduce air
`flow rates past
`the
`steering tool and increase steering tool
`life.
`The jets should have
`increased the pressure above the motor by 100 psi.
`
`The motor was tripped to bottom and Smith's steering tool was run
`through a side entry sub to orient
`the motor. The first motor
`run drilled
`from 3253'
`to 3487' (234') at an average penetration rate of 47 feet per
`hour. Unfortunately,
`the build rate (not dogleg severity) experienced with
`the motor configuration was only 5.9°/100'. Build rates can be seen in the
`Build and Walk Rate Table in Appendix C. The motor was pulled from the
`hole to change the adjustable bend and lay down the top 7 7/8"
`integral
`blade stabilizer.
`
`The bend was set at the maximum angle of 1.3° which according to
`Eastman's design program should yield a dogleg severity of 9.5°/100'. The
`motor was tripped back in the hole and drilling continued to 3603 feet.
`The build rate after changing the motor configuration was still 6.3°/100'.
`lt would not have been possible to hit the target at that build rate.
`
`The motor was again pulled from the hole. This time a 1.50 bent sub
`was placed on top of the motor. No experience was available to be able to
`project build rate for this BHA, so the anticipated build rate was unknown.
`The motor was tripped back to bottom and the well drilled to 3817 feet.
`The motor was now building inclination at an average rate of 6.6°/100,
`which was still not
`fast enough to hit
`the target.
`Formation tendencies
`
`11
`
`Weatherford International LLC et al.
`Exhibit 1036
`Weatherford International LLC et al. v. Packers Plus Energy Services, Inc.
`IPR2016-01517
`Page 22 of 231
`
`

`

`were assumed to be contributing to the lower build rates.
`
`Prior to plugging back and sidetracking, one more attempt was made
`using the Eastman mot