Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/09HFTC/All-09HFTC/SPE-119757-MS/2707049/spe-119757-ms.pdf/1 by Robert Durham on 05 September 2023
`
`SPE 119757
`
`
`
`Method and Apparatus for Simultaneous Stimulation of Multi-Well Pads
`R.C. Tolman, SPE, and J.W. Simons, ExxonMobil Production Co., and D.H. Petrie, SPE, K.J. Nygaard, SPE,
`S.R. Clingman, SPE, and A.M. Farah, SPE, ExxonMobil Upstream Research Co.
`
`Copyright 2009, Society of Petroleum Engineers
`
`This paper was prepared for presentation at the 2009 SPE Hydraulic Fracturing Technology Conference held in The Woodlands, Texas, USA, 19–21 January 2009.
`
`This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been
`reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its
`officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to
`reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
`
`
`Abstract
`
`Progressively, the oil and gas industry is producing from unconventional reservoirs with low permeability in numerous small
`pay zones that require close well spacing and multiple stimulations in each well. To effectively produce from such reservoirs
`and reduce the surface footprint, ExxonMobil has drilled multiple wells from single pads, and new technologies have been
`developed to efficiently stimulate the multiple pay zones in each well.
`
`ExxonMobil has developed and licensed Multi-Zone Stimulation Technologies (MZST), which are designed to efficiently
`stimulate wells with multiple pays zones. The technologies have been applied in fracturing tight gas reservoirs with
`numerous lenticular sands in the Rocky Mountains. We have also developed a technology that enables the simultaneous
`stimulation of multiple wells on the same or different well pads, and while drilling additional wells. The benefits of this
`technology include reduced environmental impact, time saving, and improved production rates. Most importantly we have
`demonstrated that these simultaneous operations can be conducted in a safe and responsible manner to ensure the highest
`standards of operations integrity.
`
`This paper introduces the method and apparatus for this technology and discusses the results from several years of field
`applications, including the Piceance Basin. Some specific elements of the simultaneous operations safety plan will also be
`provided.
`
`Introduction
`
`Worldwide, substantial oil and gas resources are contained in low permeability formations. Many of these resources are
`characterized by thick intervals and/or multiple reservoir targets. In addition, matrix or fracture stimulation treatments are
`typically required to effectively and optimally produce these resources. However, the increased geologic and reservoir
`heterogeneities present in these resources can lead to substantial challenges in the stimulation treatment operations and
`effectiveness.
`
`Over the last several decades, industry has invested substantial research in attempts to develop new drilling and completion
`technologies for application in tight gas sand reservoirs. Various government and industry studies indicate a vast amount of
`tight gas resources exist within the United States alone, with similar resources located outside the U.S. Examples of such
`resources are found widely distributed in the western United States, and include the Green River, Piceance, Wind River and
`Uinta Basins.
`
`To address these challenges, ExxonMobil has focused on developing novel "Multi-Zone Stimulation Technologies" (MZST),
`consisting of hardware and procedures to substantially improve stimulation treatment placement and effectiveness in very
`thick reservoirs. MZST allows the stimulation of reservoir intervals that normally would be bypassed, thus increasing: (1)
`the production rate per well; and (2) the total hydrocarbon recovery. Additionally, resources that require numerous
`stimulations to become economic ventures can be "enabled" via the application of MZST. In the Piceance Basin, with nearly
`300,000 gross acres under lease with a potential recoverable resource of nearly 45 trillion cubic feet of gas, MZST is being
`used by ExxonMobil, in its operated acreage, to maximize recovery and per-well production rates while reducing
`
`IWS EXHIBIT 1056
`
`EX_1056_001
`
`

`

`Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/09HFTC/All-09HFTC/SPE-119757-MS/2707049/spe-119757-ms.pdf/1 by Robert Durham on 05 September 2023
`
`2
`
`
`
`SPE 119757
`
`development costs and the environmental footprint. This largely undeveloped tight gas resource has been known to industry
`for well over 50 years and presents a challenging test for any fracture stimulation technology. The formation is characterized
`by a thick reservoir section (up to 5,000 feet) that is comprised of numerous vertically stacked lenticular sands with effective
`permeabilities as low as approximately 1 micro-Darcy. Figure 1 shows the location of the Piceance Basin, an outcrop of the
`lenticular sand bodies, and a typical grain cross section. Figure 2 shows the conceptual approach for MZST.
`
`The two MZST methods are referred to as "Just-in-Time Perforating" (JITP) and "Annular Coiled Tubing Fracturing" (ACT-
`Frac). These technologies enable: (1) the delivery of a large number of stimulation treatments (e.g., 40+ treatments) in a
`single well over an extended reservoir interval and in a timely manner; (2) effective diversion between treatments to improve
`placement of treatments specifically designed for each target zone; and (3) the ability to pump treatments at high flow rates to
`ensure efficient and effective stimulation1. This paper will focus on the JITP technology and associated technology
`advancements.
`
`To establish further synergies, ExxonMobil has also developed a technology that enables the simultaneous stimulation of
`wells on the same or different well pads with or without the drilling rig continuing operations2. This technology: (1)
`minimizes the surface footprint; (2) results in time and cost savings compared to sequential well stimulation operations; and
`(3) realizes earlier production in the wellbore manufacturing life cycle. We have successfully applied this type of
`simultaneous operation by means of highly trained and motivated personnel, rigorous completions and operational
`procedures, and implementation of a well established, structured, safety, health, and environmental management system.
`
`JITP Stimulation Method
`
` well is stimulated using the JITP method by sequentially treating individual zones via the combination of selectively
`perforating single intervals and promoting the isolation of these intervals through the deployment of ball sealers. A single
`continuous pumping operation allows uninterrupted operations as well as positive pressure on the ball sealers to facilitate and
`maintain effective fluid diversion.
`
`Several technical areas needed to be addressed and refined during the course of the JITP technology development and field
`deployment: (1) ball sealers must reliably flow past the BHA during pumping operations; (2) the BHA must not become
`differentially "stuck" to the perforations while a treatment is being pumped (caused by the radial pressure gradient that drives
`the treating fluid into the perforations); (3) balls must tightly seat against perforations to mitigate leakage and ball sealer
`erosion; (4) if a pumping operation is interrupted, balls should be capable of re-seating when pumping is re-initiated; (5) the
`perforating operation must be properly timed to ensure that the balls have passed the BHA before the next gun is fired; and
`(6) if the stimulation treatment fluids are staged (e.g., varying fluids and/or proppant concentration), then proper arrival of the
`ball sealers is important.
`
`Figure 3 is a schematic of the JITP bottom hole assembly (BHA). It is designed to include decentralization, allowing the ball
`sealers to reliably flow past the BHA during pumping operations. Decentralization maximizes the unrestricted cross-
`sectional area available in the wellbore to facilitate unhindered ball sealer passage. The diameter of the gun barrels are also
`sized to maximize the available unrestricted cross-sectional area while still providing a sufficient perforation charge to ensure
`reliable and effective communication with the formation.
`
`Stand-offs are included in the JITP BHA as a means of mitigating differential sticking issues for zero phased guns that can
`arise from firing perforating guns in over-balanced and continuous pumping conditions. Note that phased perforating (our
`current best practice for Piceance Basin) does not require offset rings. The radial gap provided by the stand-offs prevents the
`guns from covering the perforations and provides a flow path for treatment fluids to enter the perforations, thus minimizing
`the "sticking" effect and allowing the gun assembly to be pulled up-hole. Of course this standoff, and the associated
`restriction in the wellbore flow passage, has to be balanced with the first requirement of reliable ball sealer passage.
`
`Figure 4 illustrates the JITP stimulation process. If zones have already been stimulated, the gun assembly is run with a
`bridge/frac plug and setting tool, and the plug is set below the first zone to be stimulated. After setting the plug, the gun
`assembly is positioned at the first zone and the first gun is fired. The gun assembly is then raised to the next zone of interest
`and the first treatment is pumped. At the tail-end of the treatment, ball sealers are added to the flow, with at least one ball
`sealer for each perforation. When the ball sealers arrive downhole and seal the perforations, as evidenced by a sharp rise in
`wellbore pressure, the next gun is fired and the second treatment is initiated without ever shutting down the pumps. This
`process is repeated for as many zones as there are individual guns on the deployed assembly. Once all the target zones have
`been stimulated, the gun assembly is retrieved. This process, or JITP event, is then repeated until the entire well has been
`completed.
`
`
` A
`
`IWS EXHIBIT 1056
`
`EX_1056_002
`
`

`

`Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/09HFTC/All-09HFTC/SPE-119757-MS/2707049/spe-119757-ms.pdf/1 by Robert Durham on 05 September 2023
`
`SPE 119757
`
`
`
`3
`
`To promote effective fluid diversion and robust response during upset conditions, the ball sealers used for JITP are made of
`rubber-coated syntactic foam and are uniquely designed to maintain buoyancy under high pressure/high temperature
`conditions. Buoyancy is necessary to ensure that balls migrate uphole during temporary interruptions to pumping operations
`(upset conditions) thus enabling balls to re-seat once pumping operations are re-initiated.
`
`Approximaely five zones are stimulated during a single pumping operation as determined by the ball-out pressure response,
`and in some instances as many as 12 zones have been stimulated in a single operation. Bridge or frac plugs are deployed
`between pumping events to isolate the previously placed set of treatments. After all the desired zones in a well have been
`treated, the plugs are drilled out and the well is placed on commingled production.
`
`Simultaneous Operations
`
`Simultaneous operations technology has enabled ExxonMobil to gain full benefit from efficiencies in the JITP operations. In
`the Piceance Basin, as shown in Figures 5 and 6, up to nine wells, with surface locations spaced about 15 ft apart are drilled
`from a single pad. The advantage is that the drilling rig, and later the fracturing equipment, can move easily from one well to
`the next without having to travel and set up at a new location. More specifically, the technology enables sequential pumping
`operations on multiple wells without suspending fracturing operations while waiting for non-pumping events (such as
`wireline rig up and running, setting frac plugs, etc.). In this manner, crews are more effectively utilized and the overall
`completions time greatly reduced. Of significant benefit is the reduced working footprint and reduced environmental impact
`from repeated equipment mob/demob operations.
`
`The major components in the simultaneous operations are a stimulation fluid storage system, a stimulation fluid pumping
`system, a manifold system to enable stimulation fluids to be directed to any of the wells on the pad, flowline manifolds, two
`cranes, two wireline units, JITP tools, and a coiled tubing unit. Figure 7 shows a typical wellhead and piping layout for
`simultaneous operations. Multiple wellheads are connected together from the high pressure pumps through a single
`manifold. By configuring the valves prior to pumping fluids and proppant, the stimulation operator can choose which well
`will be treated and avoid the potential hazards and time delays associated with rig up and rig down of high pressure lines
`multiple times over the course of many days. In order to accommodate this treatment schedule, wireline trucks and
`associated support equipment are placed at each wellhead to support the stimulation operations (setting plugs, perforating,
`etc.). Individual choke manifolds are installed on each well to accommodate flow back and recovery of fluids used to
`transport the proppant through the well bore
`
`Since the simultaneous operations technology was first applied, there have been considerable advances in the fracturing
`operations resulting in additional cost and time savings. For example, cross-linked gel fluids were initially used; however, as
`experience grew, there was a transition to slick water fracturing. For five-stage JITP hydraulic fracture treatments on wells
`that are approximately 12,000 ft deep, pumping is performed at an average rate of about 30 barrels per minute. As a result
`the pumping time for a five-stage treatment is about 2 hours. Wireline is run down the wellbore at approximately 150 ft/min.
`As a result, the time to deploy the JITP tool at the desired location in the wellbore and to set the frac plug beneath the desired
`five-stage treatment is also about 2 hours. Thus, the efficiencies for the 12,000 ft well depth are realized. The JITP fracture
`treatment requires approximately the same amount of time as running the JITP tools on wireline in a second well.
`
`Table 1 illustrates the simultaneous operations for a set of well sequences. Prior to simultaneous operations, it is assumed
`that each well had been drilled, cased hole logged and was ready for completion, but were at different points of the overall
`JITP process. The “JITP assembly” refers to the wireline-deployed JITP perforating gun and frac plug setting system having
`a composite frac plug. This example clearly shows that three fracture treatments can be conducted sequentially in one
`working day or in many cases as little as seven hours. Crews are efficiently utilized with minimal waiting on non-pumping
`operations. The wells are allowed to flow back to unload the treatment fluids and to allow recycling of fluids. At the end of
`the last treatment, a coiled tubing rig is brought in to drill out the plugs, and a completion rig is used to run tubing into the
`wells to enable commingled production testing. One of the major benefits of the simultaneous operations is the ability to
`accelerate the application of learnings from one well to the next. For example, results from flowback operations can quickly
`be applied in the design and application of a fracture treatment in another well, almost on a real time basis.
`
`Referring again to Table 1 and Sequence 1, it should be noted that running (or deploying) a JITP assembly in Well 2 while
`pumping a five-stage fracture treatment in Well 1 has become an established practice. Should an upset occur during pumping
`in Well 1 for any reason, pumping can quickly be initiated in Well 2 with a 15 minute turn around time. Pumping in Well 2
`will usually be under way while wireline is being removed from Well 1. Once the wireline is removed from Well 1, it can be
`redressed for a new deployment and returned to Well 1, if needed, or Well 3 as denoted in Table 1, depending on that day’s
`strategy for sequential fracturing operations.
`
`
`IWS EXHIBIT 1056
`
`EX_1056_003
`
`

`

`Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/09HFTC/All-09HFTC/SPE-119757-MS/2707049/spe-119757-ms.pdf/1 by Robert Durham on 05 September 2023
`
`4
`
`
`
`SPE 119757
`
`Cost savings realized on a non-dimensional cost per frac basis are shown in Figure 8. The cost savings over time are due to
`full implementation of the simultaneous operations technology. Additionally, fracture fluid systems have evolved from a
`cross-linked gel to the current practice of slick water fracturing. Ceramic proppants, with a loading of 5-6 ppg) were initially
`used with the cross-linked gel. Currently white sand at a much lower cost and a loading of 2-3 ppg are used in the slick water
`fracturing operations. Thus cost per fracture is now about 50% of what it was initially.
`
`
`Drilling Operations
`
`Many drilling rigs today have derricks that can “skid” in both the X and Y axis. This enables the rig to continuously drill on
`a pad for up to 22 wells in some cases without moving the supporting equipment such as generators, mud tanks and mixing
`equipment, etc. Completion of a well while drilling the next has the potential to further reduce cost and release stranded
`capital investments (cash flow) prior to complete release or FRR of the rig on that location. This technology economically
`enhances the investment while employing real time lessons learned.
`
`Cased hole logs can be run, obtaining needed information on formation and cement tops for early well completion planning.
`Early completion results may influence stimulation decisions for offset wells and zones. Everything from water avoidance to
`enhanced cement job design and practices can be measured and evaluated prior to drilling and completing many wells on the
`same pad. A real time feed-back loop of data can be established for teams managing results from actual vs. theoretical data.
`
`Operations Integrity
`
`It was recognized that additional risks and hazards can occur with multiple operations occurring simultaneously with more
`than one wellbore on the same location. For this reason a dedicated organizational structure was put in place. More
`specifically, the incremental complexities associated with the multi-well completion process were addressed with the
`establishment of a “Natural Safety Leadership Team (NSLT), formed with representatives from Health, Safety Environment
`(HSE), technical, and operations. Flawless communication systems were established for each area of operation, with overall
`coordination residing with the Person-In-Charge or PIC. The NSLT was responsible for coordinating the morning safety
`meetings with the contractor crews and also conducting a closeout review at the end of each day to assess “what went well”
`and what areas need to be strengthened.
`
` A
`
` A
`
` key element of ensuring operations integrity was a Simultaneous Operations Hazard Identification and Mitigation Matrix.
`In summary, this matrix identified potential hazards, mitigators, and actions required and more specifically identified
`activities that were restricted from occurring at the same time (i.e., CAN NOT OCCUR activities). As an example, if the
`operations on a well involved high pressure pumping or JITP ball sealing pressure events, then manipulating manifold well
`valves and wellhead trees valves on another well were not allowed to be performed concurrently. When operations on a well
`involved high pressure pumping, then operations on a second well, such as arming the perforating gun or setting tool and
`picking up or laying down the perforating tool or setting tool, required lights and audible notifications.
`
`Critical to maintaining safety, quality and schedule were proper and sufficient isolation of fracturing fluids. To accomplish
`this, a minimum of two positive stops or valves were closed during any given isolation from the other wells. The current
`configuration afforded three valves. These included a minimum of one "ground" valve and two gate valves on each injection
`head. Valves were marked in the OPEN position during all operations. The default position upstream of the wellhead was
`always the CLOSED position.
`
`Communications are essential to the safety and efficiency of the simultaneous operations. It was recognized early on that
`wireless headsets are commonly used by contractor crews during fracturing operations. When a perforating gun is armed and
`placed in the wellbore or removed from the well all radios were either stored in a central location away from wireline
`operations in the "off" position and/or each individual with a radio or cell phone was checked to ensure their device had been
`turned off. Recognizing that pumping operations would need to continue during wireline gun rig up and rig down, "hard-
`wired" radios were used. In the unlikely event of a total or partial failure of the wired radio system, back up wireless units
`were on site. Wireless radios were allowed to be used when all armed guns were at least 1,000 ft or deeper in the well, and
`only then with strobe-warning lights on the active crane. The PIC and contractor lead supervisors personally coordinated this
`activity.
`
` drawing of all piping for flow back operations was reviewed for each individual wellhead and all points where flow was
`commingled for cleanup and/or sales. This operation was expected to continue through fracturing and drill out of plugs in
`each wellbore. A flow back lead supervisor along with the PIC and field foreman reviewed and approved the drawing for
`operability. Flowback testers were equipped with portable Lower-Explosive Limit ("LEL") detectors. During the flowback
`operations, the flowback personnel continuously monitored the location for the presence of hazardous gas levels. If
`
`IWS EXHIBIT 1056
`
`EX_1056_004
`
`

`

`Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/09HFTC/All-09HFTC/SPE-119757-MS/2707049/spe-119757-ms.pdf/1 by Robert Durham on 05 September 2023
`
`SPE 119757
`
`
`
`5
`
`hazardous gas levels were detected on location, the flowback would be suspended and appropriate corrective action taken.
`Windsocks were installed at various points and heights on the location to aid in determining wind direction.
`
`JITP Piceance Basin Field Experience
`
`JITP has been used and refined over the past eight years in the Piceance Basin in the Western United States of America
`where ExxonMobil holds a large acreage position. In the Piceance Basin, ExxonMobil will drill nine wells on a single
`surface pad of approximately six acres. These wells target gas-productive reservoir targets at approximately 20 acre spacing.
`Well depths range from 12,000 to 15,000 ft with lateral throws of 1,400 to 2,000 ft. Each well includes up to forty or more
`reservoir targets. Using simultaneous operations and the JITP fracture treatment process, at least 20 zones may be pumped
`during each work day. Forty zones can be stimulated in two to three work days. Thus, approximately one or two days
`associated with waiting on non-pumping time may be saved on each well. Extending these time savings to the full nine-well
`program is apparent.
`
`To date, over 2500 proppant fracture treatments have been successfully pumped in over 70 vertical and S-turn wells having
`4-1/2-inch or 5-1/2-inch production casing. Most all of the completions have been performed taking economic advantage of
`the simultaneous operations approach. Zones have been stimulated at depths of 14,700 ft MD, formation temperatures up to
`320ºF, and maximum surface treating pressures up to 9,500 psi in three wells at the same time.
`
`Recent field experience has demonstrated that this technology can be used to rapidly perform multiple stimulation treatments
`that result in wellbore production that generally exceeds that obtained from more traditional methods. Figure 9 shows a plot
`of cumulative production as a function of time for Piceance Basin wells that have been stimulated with JITP compared to
`nearby offset wells that have been stimulated with various conventional methods. These basins are characterized by
`substantial reservoir and geologic heterogeneities. Variables impacting reservoir performance include completion practices,
`permeability contrasts, reservoir pressure, natural fractures, and faulting. The Multi-Zone Stimulation Technology and
`Conventional Approach bounded regions labeled in the figure outline raw production data from 55 MZST-wells and 23
`conventional-wells completed in the Mesa Verde section of the Piceance basin. Compared to conventional approaches,
`MZST provides a significant improvement in the ability to quickly generate many high quality fractures.
`
`Conclusions
`
`MZST technology combined with ExxonMobil simultaneous operations technology provides an increased utilization of
`equipment and manpower previously unheard of. It has the potential to make any multiple pad well site a real time feedback
`environment allowing continuous improvement in both execution and reservoir understanding; thus enabling optimization of
`the implemented preplanned investment. Most importantly we have demonstrated that this technology can be applied in a
`safe and responsible manner following a structured operations integrity program.
`
`Acknowledgements
`
`The authors would like to recognize the integrated teamwork that was necessary for the success of the simultaneous
`operations technology. The team included members of ExxonMobil Production Company and ExxonMobil Upstream
`Research Company with both technical and operations expertise. Operations integrity is a guiding principle within
`ExxonMobil and the authors would also like to recognize the dedication of the technology team in upholding these standards
`to ensure a truly safe operation.
`
`References
`
`1. Lonnes, S.B., et al: “Advanced Multizone Stimulation Technology”, SPE 95778, 2005 SPE Annual Technical
`Conference and Exhibition, Dallas, Texas, October 2005.
`2. Tolman, R. C., et al: “Method and Apparatus Associated with Stimulation Treatment for Wells”, World Intellectual
`Property Organization WO 2207/024383 A2, International Publication Date March 1, 2007.
`
`
`
`
`IWS EXHIBIT 1056
`
`EX_1056_005
`
`

`

`Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/09HFTC/All-09HFTC/SPE-119757-MS/2707049/spe-119757-ms.pdf/1 by Robert Durham on 05 September 2023
`
`6
`
`
`
`SPE 119757
`
`Sequence
`Initial
`Conditions
`
`1
`
`2
`
`3
`
`
`
`
`
`Well No. 1
`JITP assembly in place in the
`wellbore and ready for 5-
`stage
`fracture
`treatment
`(Crane 1)
`
`fracture
`five-stage
`First
`treatment conducted. JITP
`assembly removed from the
`wellbore (Crane 1). ~3 hours
`
`Flowback operations from 5-
`stage fracture treatment
`
`Well No. 2
`fracture
`treatment
`5-stage
`completed and flowed back.
`JITP assembly at surface and
`ready for deployment down
`the wellbore (Crane 2)
`Deploy JITP assembly down
`the wellbore and set frac plug
`for 5-stage fracture treatment
`(Crane 2). ~3 hours
`
`Well No. 3
`fracture
`treatment
`5-stage
`completed and JITP assembly
`out of the wellbore. Ready for
`flowback.
`
`Flowback operations from 5-
`stage fracture treatment
`
`fracture
`five-stage
`Second
`treatment conducted. JITP
`assembly removed from the
`wellbore (Crane 2). ~3 hours
`
`Deploy JITP assembly down
`the wellbore and set frac plug
`for 5-stage fracture treatment
`(Crane 1). ~3 hours
`
`Deploy JITP assembly down
`the wellbore and set frac plug
`for 5-stage fracture treatment
`(Crane 2). ~3 hours
`
`Flowback operations from 5-
`stage fracture treatment.
`
`fracture
`five-stage
`Third
`treatment conducted. JITP
`assembly removed from the
`wellbore (Crane 1). ~3 hours
`
`Table 1: Simultaneous stimulation operations sequences
`
`Sandstones
`
`Simulated
`Wellbore
`
`100’
`
`Outcrop of Lenticular Sand Bodies
`
`Grain cross section
`
`Figure 1: Tight gas opportunity
`
`Piceance Basin
`
`B
`
`P
`
`K
`
`M
`
`RMM
`
`P
`
`K
`
`0.2
`
`IWS EXHIBIT 1056
`
`EX_1056_006
`
`

`

`Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/09HFTC/All-09HFTC/SPE-119757-MS/2707049/spe-119757-ms.pdf/1 by Robert Durham on 05 September 2023
`
`SPE 119757
`
`
`
`7
`
`Wireline
`
`Perforating Guns
`
`Ball Sealers
`
`Decentralizer
`
`Frac or Bridge Plug
`
`Figure 2: Multi-Zone Stimulation Technology (MZST) concept
`
`Figure 3: JITP bottomhole assembly
`
`When ball-out
`Perforate current zone
`achieved, perforate next
`and move guns up-hole
`adjacent to next zone
`zone and repeat process
`Figure 4: JITP stimulation process
`
`Pump treatment and
`ball sealers
`
`IWS EXHIBIT 1056
`
`EX_1056_007
`
`

`

`Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/09HFTC/All-09HFTC/SPE-119757-MS/2707049/spe-119757-ms.pdf/1 by Robert Durham on 05 September 2023
`
`8
`
`
`
`SPE 119757
`
`Figure 5: Well pads in the Piceance Basin
`
`Figure 6: Well configurations from individual pads
`
`Figure 7: Multi-well simultaneous stimulation operations showing wellhead and piping layout
`
`IWS EXHIBIT 1056
`
`EX_1056_008
`
`

`

`Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/09HFTC/All-09HFTC/SPE-119757-MS/2707049/spe-119757-ms.pdf/1 by Robert Durham on 05 September 2023
`
`SPE 119757
`
`
`
`Cost per Frac
`
`
`
`9
`
`~ 50% Reduction
`
`2000
`
`Present
`
`Figure 8: Cost per frac reduction using simultaneous stimulation operations technology
`
`CUMULATIVE PRODUCTION
`(billions of cubic feet)
`1.0
`
`0.8
`
`0.6
`
`0.4
`
`0.2
`
`0
`
`0
`
`Multi-Zone Stimulation
`Technology
`
`Conventional Approach
`
`100
`
`300
`200
`(producing time in days)
`
`400
`
`500
`
`Figure 9: Piceance basin production comparison
`
`IWS EXHIBIT 1056
`
`EX_1056_009
`
`