EXHIBIT 28
`
`SPE
`SPE
`
`Society of Petroleum Engineers
`Society of Petroieum Engineers
`
`SPE 17759
`SPE 17759
`
`Hydraulic Fracturing of a Horizontal Well in a Naturally Fractured
`Hydraulic Fracturing of a Horizontal Well in a Naturally Fractured
`Reservoir: Gas Study for Multiple Fracture Design
`Reservoir: Gas Study for Multiple Fracture Design
`by A.B. Yost II, U.S. DOE METC; W.K. Overbey Jr., 8DM Corp.; D.A. Wilkins,
`by A.B. Yost II, U.S. DOE METC; W.K. Overbey Jr., BDM Corp.; D.A. Wilkins,
`Grace, Shursen, Moore & Assocs.; and C.D. Locke, BDM Corp.
`Grace, Shursen, Moore & Assocs.; and C.D. Locke, BDM Corp.
`
`SPE Members
`SPE Members
`
`This paper was prepared for presentation at the SPE Gas Technology Symposium, held in Dallas, TX, June 13-15, 1988.
`This paper was prepared tor presentation at the SPE Gas Technology Symposium, held in Dallas, TX, June 13-15, 1988.
`
`This paper was selected for presentation by an SPE Program Committee following review of information contained in en abstract submitted by the
`This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the
`author(s). ConterEM of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and we subject to correction by the
`author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject lo correction by the
`author(a). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers
`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 cony is
`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 no; be copied. The abstract should contain conspicuous acknOWfertgrnent of
`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 833535, Richardson, TX 75083-3836. Telex, 730989 SPEDAL
`where and by whom the paper Is presented. Write Publications Manager, SPE, P.O. Box 833838, Richardson. TX 75083.3836. Telex, 730989 SPEDAL
`
`ABSTRACT
`ABSTRACT
`
`Stimulation of a naturally-fractured, low
`Stimulation of a naturally-fractured, low
`permeability, low-pressure 2000-foot
`horizontal
`permeability, low-pressure 2000-foot horizontal
`well in a low permeability reservoir and in-situ
`well in a low permeability reservoir and in-situ
`stress environment requires careful stimulation
`stress environment requires careful stimulation
`fluid design to minimize the capillary retention
`fluid design to minimize the capillary retention
`of treatment fluids.
`Therefore, a systematic
`of treatment fluids. Therefore, a systematic
`approach to stimulation design using N2, CO2, and
`approach to stimulation design using N2, CO2, and
`N2-foam was used to select one which is most
`N2-foam was used to select one which is most
`efficient. Stimulation modeling was used to evaluate
`efficient. Stimulation modeling was used to evaluate
`fracture geometry with particular concern for the
`fracture geometry with particular concern for the
`minimum pressure rise above parting pressure required
`minimum pressure rise above parting pressure required
`for height growth during frac fluid injection.
`for height growth during frac fluid injection.
`Up to seven zones along the horizontal welibore
`Up to seven zones along the horizontal wellbore
`are available for stimulation. Each zone was ranked
`are available for stimulation. Each zone was ranked
`and
`pre-frac
`tested
`to
`establish
`pre-frac
`and pre-frac tested to establish pre-frac
`permeabilities. A N2 and N2-foam data frac was
`permeabilities. A N2 and N2-foam data frac was
`performed in one zone to establish leakoff
`performed in one zone to establish leakoff
`characteristics. Subsequently, N2, CO2, and N2-foam
`characteristics. Subsequently, N2, CO2, and N2-foam
`treatments were performed on a 400-foot zone to
`treatments were performed on a 400-foot zone to
`evaluate the effectiveness of CO2 versus N2 frac
`evaluate the effectiveness of CO2 versus N2 frac
`fluids.
`Both the data frac and subsequent
`fluids. Both the data frac and subsequent
`stimulations were evaluated in the two least
`stimulations were evaluated in the two least
`productive intervals in order to use the preferred
`productive intervals in order to use the preferred
`fluids in the best zones in the reservoir. The
`fluids in the best zones in the reservoir. The
`post-treatment decline curves for N2 and CO2 indicate
`post-treatment decline curves for N2 and CO2 indicate
`a CO2-based fluid treatment should be performed
`a CO2-based fluid treatment should be performed
`in the most productive interval to achieve maximum
`in the most productive interval to achieve maximum
`success.
`Results of the stimulation conducted
`success. Results of the stimulation conducted
`are presented along with discussion of improvement
`are presented along with discussion of improvement
`ratios and potential utility to other horizontal
`ratios and potential utility to other horizontal
`drilling projects.
`drilling projects.
`
`BACKGROUND
`BACKGROUND
`
`Tie stimulation aspects of horizontal drilling
`Ttle stimulation aspects of horizontal drilling
`represent a technical challenge in tight formations
`represent a technical challenge in tight formations
`where the horizontal placement of a horizontal
`where the horizontal placement of a horizontal
`wellbore may not always provide adequate economic
`wellbore may not always provide adequate economic
`
`References and illustrations at end of paper.
`References and illustrations at end of paper.
`
`Little or no published literature
`production.
`production. Little or no published literature
`exists on the mechanics of hydraulic fracturing
`exists on the mechanics of hydraulic fracturing
`of horizontal wells. Typically, long horizontal
`of horizontal wells. Typically, long horizontal
`wells are completed with preperforated liners
`wells are completed with preperforated liners
`The disadvantage
`to preserve hole integrity.
`to preserve hole integrity. The disadvantage
`of this type of completion is the associated risk
`of this type of completion is the associated risk
`q f pulling the liner at a later stage of production
`of pulling the liner at a later stage of production
`history and re-running and cementing a casing
`history and re-running and cementing a casing
`string such that selective placement of fracturing
`string such that selective placement of fracturing
`of fluids can be accomplished. An alternative
`of fluids can be accomplished. An alternative
`approach is zone isolation accomplished by the
`approach is zone isolation accomplished by the
`installation of external casing packers and port
`installation of external casing packers and port
`collars as an integral part of a casing string
`collars as an integral part of a casing string
`run along the horizontal section. Such a completion
`run along the horizontal section. Such a completion
`intervals with
`arrangement provided stimulation
`arrangement provided stimulation intervals with
`ready-made perforations injecting fracturing fluids
`ready-made perforations injecting fracturing fluids
`fracturing condition behind
`into an open hole
`into an open hole fracturing condition behind
`the method of completion used
`This was
`pipe.
`pipe. This was the method of completion used
`in this 2000 foot horizontal well to avoid the
`in this 2000 foot horizontal well to avoid the
`damage associated with
`problems of
`formation
`problems of formation damage associated with
`for
`need
`the
`cementing
`and
`to eliminate
`cementing and to eliminate the need for
`treatment
`tubing-conveyed perforating of numerous
`tubing-conveyed perforating of numerous treatment
`intervals.
`intervals.
`
`The V.S. Department of Energy's Morgantown
`The U.S. Department of Energy's Morgantown
`Energy Technology Center has been investigating
`Energy Technology Center has been investigating
`the merits of drilling high angle wells for more
`the merits of drilling high angle wells for more
`than 20 years. Two high angle wells were completed
`than 20 years. Two high angle wells were completed
`in the Devonian Shale at 43 and 52' from vertical.
`in the Devonian Shale at 43 and 52' from vertical.
`Recent emphasis has been on the use of horizontal
`Recent emphasis has been on the use of horizontal
`wellbores to enhance gas recovery efficiency in
`wellbores to enhance gas recovery efficiency in
`tight formations.1 Initial study of horizontal
`tight formations.' Initial study of horizontal
`drilling in fractured Devonian Shale in the
`drilling in fractured Devonian Shale in the
`Appalachian Basin involved selection of a geographic
`Appalachian Basin involved selection of a geographic
`area followed by full-field reservoir simulation
`area followed by full-field reservoir simulation
`and initial well design.2 Once the site was
`and initial well design.2 Once the site was
`selected, computer software was used to examine
`selected, computer software was used to examine
`drill string loads, design bottomhole assemblies,
`drill string loads, design bottomhole assemblies,
`track well trajectory, and tq
`provide daily
`track well trajectory, and to provide daily
`reporting during drilling.3 Finally, the 2000
`reporting during drilling.3 Finally, the 2000
`foot long horizontal well discussed in this paper
`foot long horizontal well discussed in this paper
`was air-drilled to a measured depth of 6020 feet
`was air-drilled to a measured depth of 6020 feet
`and a true vertical depth of 3403 feet.4 A video
`and a true vertical depth of 3403 feet.4 A video
`
`451
`451
`
`1 of 10
`
`RWCT-Prod-0000267_0001
`Ex. 2075
`IPR2016-01496
`
`RWCT-Prod-0000267_0001
`
`EXHIBIT 28
`
`

`

`2
`2
`
`Hydraulic Fracturing of a Horizontal Well in a Naturally
`Hydraulic Fracturing of a Horizontal Well in a Naturally
`Fractured Reservoir: Case Study for Multiple Fracture DesignFractured Reservoir: Case Study for Multiple Fracture Design
`
`
`
`
`SPE 17759 SPE 17759
`
`camera survey and analysis was used along with
`camera survey and analysis was used along with
`geophysical well logs to determine fracture spacing
`geophysical well logs to determine fracture spacing
`and to locate the position of external casing packers
`and to locate the position of external casing packers
`for completion and stimulation operations.5 A
`for completion and stimulation operations.5 A
`follow-on study using reservoir data from the
`follow-on study using reservoir data from the
`drilling, coring, logging and well testing operations
`drilling, coring, logging and well testing operations
`was used to examine the effects of in-field drilling
`was used to examine the effects of in-field drilling
`with horizontal wells as a field development strategy
`with horizontal wells as a field development strategy
`
`in fractured Devonian Shale.6 in fractured Devonian Shale.6
`
`
`
`INTRODUCTION INTRODUCTION
`
`The objective of stimulation research in this
`The objective of stimulation research in this
`horizontal wellbore, located in Wayne County, West
`horizontal wellbore, located in Wayne County, West
`Virginia, was to determine the recovery efficiency
`Virginia, was to determine the recovery efficiency
`of the natural fracture system and the effects
`of the natural fracture system and the effects
`expected from hydraulically fracturing the well
`expected from hydraulically fracturing the well
`whenever multiple fractures would be induced.
`whenever multiple fractures would be induced.
`To determine the most effective wellbore stimulation
`To determine the most effective wellbore stimulation
`under these conditions, it was necessary to use
`under these conditions, it was necessary to use
`a systematic approach to examine the effects of
`a systematic approach to examine the effects of
`various combinations of four factors, which were:
`various combinations of four factors, which were:
`(1) type of fluid (e.g., gas, liquid, foam); (2) (1) type of fluid (e.g., gas, liquid, foam); (2)
`
`fluid injection rate; (3) volume of fluid injected;
`fluid injection rate; (3) volume of fluid injected;
`Following and (4) bottomhole treating pressure. and (4) bottomhole treating pressure. Following
`
`
`each stimulation, flow rate and build-up test data each stimulation, flow rate and build-up test data
`
`were used to determine permeability-thickness product
`were used to determine permeability-thickness product
`and flow rate improvement ratio. Key stimulation and flow rate improvement ratio. Key stimulation
`
`issues of concern were:
`issues of concern were:
`
`o number of fractures that can be opened
`o number of fractures that can be opened
`
`and propagated during a single pumping and propagated during a single pumping
`event;
`event;
`
`o whether proppant would screen out easier o whether proppant would screen out easier
`in a horizontal well;
`in a horizontal well;
`
`o understanding what determines which natural o understanding what determines which natural
`fractures are propagated;
`fractures are propagated;
`
`o determining the best fracture diagnostic o determining the best fracture diagnostic
`
`system to use in a horizontal well. system to use in a horizontal well.
`
`
`
`The overall technical approach was to: The overall technical approach was to:
`
`
`o induce multiple hydraulic fractures; o induce multiple hydraulic fractures;
`
`o determine how many and where fractures o determine how many and where fractures
`
`were induced in the borehole; were induced in the borehole;
`o evaluate hydraulic fracture design for
`o evaluate hydraulic fracture design for
`horizontal well in shale formation; horizontal well in shale formation;
`
`o establish need or lack of need for proppant
`o establish need or lack of need for proppant
`
`in low stress ratio (minimum horizontal in low stress ratio (minimum horizontal
`
`to vertical) areas. to vertical) areas.
`
`
`Conceptual hydraulic fracture design had to Conceptual hydraulic fracture design had to
`
`consider the strong interaction between the natural consider the strong interaction between the natural
`
`fracture orientation of N37°E and N67°E and the fracture orientation of N37°E and N67°E and the
`predicted induced fracture trend of N52°E as shown
`predicted induced fracture trend of N52°E as shown
`
`in Figure 1. In addition, the consideration of in Figure 1. In addition, the consideration of
`other
`joint
`system
`having
`nearly
`parallel
`other joint system having nearly parallel
`orientations which would either act as leakoff
`orientations which would either act as leakoff
`
`areas or actually accept fracture fluid under areas or actually accept fracture fluid under
`propagating conditions. Each zone available for
`propagating conditions. Each zone available for
`
`fracturing had numerous natural fractures which fracturing had numerous natural fractures which
`Therefore, the
`
`would accept fracturing fluid. would accept fracturing fluid. Therefore, the
`need for acquiring injectivity information was need for acquiring injectivity information was
`
`
`warranted to observe whether multiple hydraulic warranted to observe whether multiple hydraulic
`
`fractures were propagated during a single pumping fractures were propagated during a single pumping
`
`event as postulated in Figure 2. event as postulated in Figure 2.
`
`Pre-Stimulation Input Data
`Pre-Stimulation Input Data
`
`In order to fully evaluate the effects of
`In order to fully evaluate the effects of
`propagating natural fractures, detailed evalution
`propagating natural fractures, detailed evalution
`of mud log shows and natural fractures observed
`of mud log shows and natural fractures observed
`from a drill-pipe conveyed video camera were made.
`from a drill-pipe conveyed video camera were made.
`In addition, eight zones were originally isolated
`In addition, eight zones were originally isolated
`
`with external casing packers (ECPs) and port collars with external casing packers (ECPs) and port collars
`
`Following inflation of as shown in Figure 3. as shown in Figure 3. Following inflation of
`
`
`ECPs, only seven zones were available for pre-frac ECPs, only seven zones were available for pre-frac
`well testing due to one ECP failure between Zones well testing due to one ECP failure between Zones
`
`2 and 3. A combination tool was used to open
`2 and 3. A combination tool was used to open
`
`and close port collars as well as provide pack-off and close port collars as well as provide pack-off
`for zone isolation during
`pre-frac testing.
`for zone isolation during pre-frac testing.
`Pre-frac flow rates from individual zones varied
`Pre-frac flow rates from individual zones varied
`from 2 to 17 thousand cubic feet of gas per day
`from 2 to 17 thousand cubic feet of gas per day
`(mcfd).
`In addition, pressure build-up tests
`(mcfd). In addition, pressure build-up tests
`were conducted on all seven zones with
`conducted
`on
`all
`zones
`with
`were
`seven
`.098
`permeabilities
`ranging
`from
`.031
`to
`permeabilities ranging from .031 to .098
`(md). (cid:9)
`The (cid:9)
`initial (cid:9)
`design
`(md).
`The
`initial
`design
`millidarcies (cid:9)
`millidarcies
`considerations were premised on the fact that considerations were premised on the fact that
`
`
`mud log shows would' be the best indication of mud log shows would' be the best indication of
`
`where frac fluid would first be accepted during where frac fluid would first be accepted during
`A summary of all pre-stimulation stimulation. stimulation. A summary of all pre-stimulation
`
`
`input data and reservoir characteristics is provided
`input data and reservoir characteristics is provided
`in Table 1 and Table 2 respectively.
`in Table 1 and Table 2 respectively.
`
`Stimulation Rationale
`Stimulation Rationale
`
`The mechanical handling of fracturing fluids,
`The mechanical handling of fracturing fluids,
`proppants, and tracer materials along a 2000 foot
`proppants, and tracer materials along a 2000 foot
`
`horizontal wellbore offers a technical challenge horizontal wellbore offers a technical challenge
`
`relative to developing a systematic approach - to relative to developing a systematic approach - to
`
`conducting fracturing experiments in selected conducting fracturing experiments in selected
`
`zones without causing any permanent damage to zones without causing any permanent damage to
`the wellbore that would prevent execution of
`the wellbore that would prevent execution of
`
`remaining stimulations. The rationale used was remaining stimulations. The rationale used was
`to select the lowest productive zone(s) to conduct
`to select the lowest productive zone(s) to conduct
`
`experiments in and subsequently, reserve the better experiments in and subsequently, reserve the better
`zones for full-scale stimulation. In Figure 3,
`zones for full-scale stimulation. In Figure 3,
`
`both Zone 6 and 1 were used for all frac fluid both Zone 6 and 1 were used for all frac fluid
`testing which will be the focus of this paper.
`testing which will be the focus of this paper.
`
`The overall stimulation rationale focused on the The overall stimulation rationale focused on the
`following considerations:
`following considerations:
`
`
`1) Primary design was to propagate natural 1) Primary design was to propagate natural
`fractures with a slight difference in orientation fractures with a slight difference in orientation
`
`
`from principal stress orientation. from principal stress orientation.
`
`2) Injection at low rates allows fluid to select 2) Injection at low rates allows fluid to select
`pre-existing natural fractures to be propagated. pre-existing natural fractures to be propagated.
`
`
`3) Injection at pressures which will keep the 3) Injection at pressures which will keep the
`
`fracture(s) from growing out of zone. fracture(s) from growing out of zone.
`4) By starting off at low rates and not exceeding
`4) By starting off at low rates and not exceeding
`
`200 psi above closure pressure with average BHTP 200 psi above closure pressure with average BHTP
`natural fractures would be propagated.
`natural fractures would be propagated.
`
`5) By increasing injection rates additional 5) By increasing injection rates additional
`fractures would be induced which would likely
`fractures would be induced which would likely
`create a network of interconnected fractures with
`create a network of interconnected fractures with
`
`orientations of N37°E, N52°E, and N67°E. orientations of N37°E, N52°E, and N67°E.
`
`
`The initial frac design sequence was premised The initial frac design sequence was premised
`
`on treatment of Zone #6 with both N2 and foam on treatment of Zone #6 with both N2 and foam
`injection
`tests
`to
`injection tests to verify fluid leakoff
`verify
`fluid
`leakoff
`
`characteristics for low and high viscosity fluids. characteristics for low and high viscosity fluids.
`The initial flow diagram was developed to conduct
`The initial flow diagram was developed to conduct
`
`pre-frac tests on Zone #6 followed by hydraulic pre-frac tests on Zone #6 followed by hydraulic
`fracturing experiments using straight N2 and CO2
`fracturing experiments using straight N2 and CO2
`
`on Zone #1 followed by N2-foam without proppant on Zone #1 followed by N2-foam without proppant
`on Zone #2-3 and #5 as shown in Figure 4.
`on Zone #2-3 and #5 as shown in Figure 4.
`
`452
`452
`
`2 of 10
`
`RWCT-Prod-0000267_0002
`Ex. 2075
`IPR2016-01496
`
`RWCT-Prod-0000267_0002
`
`(cid:9)
`(cid:9)
`

`

`SPE 17759
`SPE 17759 (cid:9)
`
`A.B. Yost II, W.K. Overbey, Jr., D.A. Wilkins, & C.D. Locke
`A.B. Yost II, W.K. Overbey, Jr., D.A. Wilkins, & C.D. Locke (cid:9)
`
`3
`3
`
`DATA FRAC DESIGN, EXECUTION AND EVALUATION
`DATA FRAC DESIGN, EXECUTION AND EVALUATION
`
`As previously discussed, Zone #6 was selected
`As previously discussed, Zone #6 was selected
`for data frac experiments to determine leakoff
`for data frac experiments to determine leakoff
`characteristics.
`computer-controlled
`data
`A
`characteristics. (cid:9)
`computer-controlled (cid:9)
`A (cid:9)
`data
`acquisition system was used to perform fluid
`acquisition system was used to perform fluid
`injection tests. The data frac treatment procedure
`injection tests. The data frac treatment procedure
`is described as follows:
`is described as follows:
`
`1. Pump straight N2 down hole to load hole at
`1. Pump straight N2 down hole to load hole at
`5 bbl/min (2500 scfm) tq fill welibore. (Wellbore
`5 bbl/min (2500 scfm) to fill weilbore. (cid:9)
`(Wellbore
`storage calculated at 51,000 at 1600 psi.) Estimated
`storage calculated at 51,000 at 1600 psi.) Estimated
`time: 20.4 minutes.
`time: 20.4 minutes.
`
`2. Pump
`Test #1 at 5 bbl/min rate for 15 minutes.
`2. Pump
`Test #1 at 5 bbl/min rate for 15 minutes.
`(2500 scf
`x 15 minutes = 37,500 scf N2)
`(2500 scf
`x 15 minutes = 37,500 scf N2)
`
`in for 37.5 minutes and watch leakoff. 3. Shut
`
`
`in for 37.5 minutes and watch leakoff. 3. Shut
`
`4. Pump
`Test #2 at 15 bbl/min rate for 15 minutes.
`4. Pump
`Test #2 at 15 bbl/min rate for 15 minutes.
`
`N2 x 15 minutes = 112,500 scf N2) (7500 scf
`(7500 scf
`N2 x 15 minutes = 112,500 scf N2)
`
`5. Shut
`in for 37.5 minutes and watch leakoff.
`5. Shut
`in for 37.5 minutes and watch leakoff.
`
`80 quality foam at 5 bbl/min for 20 minutes 6. Pump
`
`
`80 quality foam at 5 bbl/min for 20 minutes 6. Pump
`(tag with
`radioactive iodine). (40,000 scf N2)
`(tag with
`radioactive iodine). (40,000 scf N2)
`
`7. Shut
`in for 50 minutes to watch leakoff.
`7. Shut
`in for 50 minutes to watch leakoff.
`Note ISIP
`calculated closure pressure.
`Note ISIP
`calculated closure pressure.
`
`8. Pump
`8. Pump
`minutes.
`minutes.
`scf N2)
`scf N2)
`
`80 quality foam at 15 bbl/min for 20
`80 quality foam at 15 bbl/min for 20
`(Tag with second RA liquid.) (120,000
`(Tag with second RA liquid.) (120,000
`
`9. Shut
`in for 50 minutes to watch leakoff.
`9. Shut
`in for 50 minutes to watch leakoff.
`Note ISIP
`and calculated closure pressure.
`Note ISIP
`and calculated closure pressure.
`
`10. Within 2.5 hours, replumb well for flow back.
`10. Within 2.5 hours, replumb well for flow back.
`
`Approximately 25,000 scf of N2 was used to
`Approximately 25,000 scf of N2 was used to
`load the hole to start the data frac activities
`load the hole to start the data frac activities
`in Zone #6.
`in Zone #6.
`
`Pump test #1 was pumped for 15 minutes at
`Pump test #1 was pumped for 15 minutes at
`an average rate of 2500 scfm of N2, then shut-in
`an average rate of 2500 scfm of N2, then shut-in
`for 15 minutes to watch leakoff rate.
`Leakoff
`for 15 minutes to watch leakoff rate. Leakoff
`rate was 6.6 psi per minute. A total of 37,500
`rate was 6.6 psi per minute. A total of 37,500
`scf N2 was pumped into the formation.
`scf N2 was pumped into the formation.
`
`Pump test #2 was pumped for 15 minutes at
`Pump test #2 was pumped for 15 minutes at
`a programmed rate of 7500 scfm of N2, however,
`a programmed rate of 7500 scfm of N2, however,
`the rate meter was in error and injection rate
`the rate meter was in error and injection rate
`is projected to be 10,000 scfm since the unit was
`is projected to be 10,000 scfm since the unit was
`running wide open. A total of 150,000 scf of N2
`running wide open. A total of 150,000 scf of N2
`was pumped into the formation. Leakoff rate was
`was pumped into the formation. Leakoff rate was
`8.4 psi per minute.
`8.4 psi per minute.
`
`Pump test #3 was pumped for 20 minutes at
`Pump test #3 was pumped for 20 minutes at
`5 bbl/min of 80 quality foam. Leakoff rate was
`5 bbl/min of 80 quality foam. Leakoff rate was
`4.15 psi per minute after Test #3; 33,000 scf of
`4.15 psi per minute after Test #3; 33,000 scf of
`Radioactive
`N2 was pumped during this stage.
`N2 was pumped during this stage. Radioactive
`scandium was injected as a tracer for this test.
`scandium was injected as a tracer for this test.
`A total of 100 bbls (4200 gallons) of foam was
`A total of 100 bbls (4200 gallons) of foam was
`injected in the formation.
`injected in the formation.
`
`Test #4 was pumped for 16 minutes at 12 bbl/min
`Test #4 was pumped for 16 minutes at 12 bbl/min
`of 80 quality foam. Leakoff rate was 4.7 psi per
`of 80 quality foam. Leakoff rate was 4.7 psi per
`minute for the final stage; 69,200 scf of N2 was
`minute for the final stage; 69,200 scf of N2 was
`pumped during this stage. Radioactive iodine was
`pumped during this stage. Radioactive iodine was
`injected with the foam as a tracer for the final
`injected with the foam as a tracer for the final
`test. A total of 200 bbls of foam (8400 gallons)
`test. A total of 200 bbls of foam (8400 gallons)
`was injected in the formation. A pressure versus
`was injected in the formation. A pressure versus
`time plot is provided in Figure 5.
`time plot is provided in Figure 5.
`
`Results from the data fracs as shown in Table
`Results from the data fracs as shown in Table
`3 indicate the following: (1) two different closure
`3 indicate the following: (1) two different closure
`pressures (850 and 1050 psi) were observed from
`pressures (850 and 1050 psi) were observed from
`the N2 and N2foam injection test. One possible
`the N2 and N2foam injection test. One possible
`explanation was that different fractures were
`explanation was that different fractures were
`induced having near-adjacent angles in Zone #6;
`induced having near-adjacent angles in Zone #6;
`(2) calculated fluid loss coefficients varied
`(2) calculated fluid loss coefficients varied
`from 2.75 x 10-4 to 1.38 x 10-3 ft/ min between
`from 2.75 x 10-4 to 1.38 x 10-3 ft/ min between
`N2-foam; (3) frac gradients ranged from .25 to
`N2-foam; (3) frac gradients ranged from .25 to
`.31 psi/ft; low frac gradients provide a formation
`.31 psi/ft; low frac gradients provide a formation
`stress environment where proppants may not be
`stress environment where proppants may not be
`necessary; (4) fracture diagnostics indicate that
`necessary; (4) fracture diagnostics indicate that
`the differences in foam injection was not enough
`the differences in foam injection was not enough
`to alter the preferential fluid acceptance paths
`to alter the preferential fluid acceptance paths
`established by an initial injection rate of 5
`established by an initial injection rate of 5
`barrels per minute, and (5) fracture diagnostics
`barrels per minute, and (5) fracture diagnostics
`showed four of six natural fractures were opened
`showed four of six natural fractures were opened
`and propagated, plus 9 additional fractures were
`and propagated, plus 9 additional fractures were
`generated which interconnected with Zone #5.
`generated which interconnected with Zone #5.
`
`Following the four data frac experiments
`Following the four data frac experiments
`on Zone #6, a spectral gamma ray, casing collar,
`on Zone #6, a spectral gamma ray, casing collar,
`and temperature log was run into the well on coiled
`and temperature log was run into the well on coiled
`tubing through Zone #6. Evaluation q f the tracer
`tubing through Zone #6. Evaluation of the tracer
`log indicates that the majority of the tracer
`log indicates that the majority of the tracer
`material was located in the vicinity of the only
`material was located in the vicinity of the only
`mud log gas show in Zone #6. However, up to 13
`mud log gas show in Zone #6. However, up to 13
`fluid entry points were observed in Zone #6 on
`fluid entry points were observed in Zone #6 on
`the tracer log as compared to 6 natural fractures
`the tracer log as compared to 6 natural fractures
`observed on the downhole camera.
`observed on the downhole camera.
`
`Following well logging, Zone #6 was produced
`Following well logging, Zone #6 was produced
`and cleaned up over a 7-day flow period and a
`and cleaned up over a 7-day flow period and a
`75 psi back pressure was applied to simulate flowing
`75 psi back pressure was applied to simulate flowing
`conditions. After 10 days of flowing, Zone #6
`conditions. After 10 days of flowing, Zone #6
`was flowing 14 thousand cubic feet of gas per
`was flowing 14 thousand cubic feet of gas per
`day (mcfd) as compared to a pre-frac rate of 2
`day (mcfd) as compared to a pre-frac rate of 2
`mcfd. After 3 days of simulated back pressure,
`mcfd. After 3 days of simulated back pressure,
`the well's flow rate suddenly dropped to 9 mcfd
`the well's flow rate suddenly dropped to 9 mcfd
`as shown in Figure 6. A plausible explanation
`as shown in Figure 6. A plausible explanation
`for this drop in rate was some of the induced
`for this drop in rate was some of the induced
`fractures were closing off. Subsequently, 4 days
`fractures were closing off. Subsequently, 4 days
`later Zone #6 was q pened to atmospheric conditions
`later Zone #6 was opened to atmospheric conditions
`and production rate dropped to 3 mcfd; however,
`and production rate dropped to 3 mcfd; however,
`when the 75 psi back pressure was reestablished,
`when the 75 psi back pressure was reestablished,
`Zone #6 began producing 9 mcfd, a 4.5-fold increase
`Zone #6 began producing 9 mcfd, a 4.5-fold increase
`over baseline conditions. A plausible explanation
`over baseline conditions. A plausible explanation
`for this type of flow behavior is that the natural
`for this type of flow behavior is that the natural
`gas liquids, observed in the fracture by the
`gas liquids, observed in the fracture by the
`downhole video camera, restrict the gas flow under
`downhole video camera, restrict the gas flow under
`open flow conditions. Subsequently, the addition
`open flow conditions. Subsequently, the addition
`of back pressure improves the relative flow
`of back pressure improves the relative flow
`potential.
`potential.
`
`After flow rate testing, a 14-day build-up
`After flow rate testing, a 14-day build-up
`test was performed on Zone #6. Both the pre-frac
`test was performed on Zone #6. Both the pre-frac
`and post-treatment build-up test for Zone #6 are
`and post-treatment build-up test for Zone #6 are
`in Figure 7. Results of the build-up test
`shown
`shown in Figure 7. Results of the build-up test
`increase
`from
`analysis
`indicate a permeability
`analysis indicate a permeabilit