SPE 159085
`
`Optimizing Perforating Charge Design for Stimulation
`Clinton C. Quattlebaum, Ken Borgen, and Zhenyu Xue, SPE, Halliburton; Pete Wilkinson, SPE, Piedra Operating
`
`Copyright 2012, Society of Petroleum Engineers
`
`This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in San Antonio, Texas, USA, 8-10 October 2012.
`
`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
`Hydraulic stimulation technologies, which are vital in maximizing the production of unconventional reservoirs, have
`typically focused on pumping capacities and rates, hydraulic fluid viscosities, and proppant materials. A technology that
`historically has been overlooked, but is critical to an efficient hydraulic stimulation, is the actual perforations through which
`the treatment is pumped.
`Fundamental rock and fracture mechanics demonstrate that perforation shot density, phasing, and hole size affect
`breakdown and treating pressures and injection rates, and can be a cause of early screenout. Although some of these
`perforation parameters are considered in the best practices, perforation hole size is often misunderstood.
`Complex computer fracture models, used to plan stimulation and completion programs, often incorporate average hole­
`diameter values with little consideration of the actual hole sizes or the variance from shot to shot. New research documents
`how this inconsistency can be considerable when using standard shaped-charge perforators. Nevertheless, perforating charges
`designed for natural completions, which focus primarily on the depth of penetration, are continuously used before hydraulic
`stimulation, ignoring the importance of consistent hole size. Advanced simulations using finite element analysis (FEA) have
`confirmed that fracture placement in a reservoir requiring stimulation would benefit significantly from maintaining
`consistency in the size of the perforation exit-hole.
`This work reviews the analysis performed and the subsequent successful field results for a new class of shaped-charge.
`The new fracture charge is engineered to maximize hole-diameter while maintaining a consistent exit-hole diameter
`independent of well profile and/or gun eccentricity. Designed for perforating before a hydraulic stimulation, a fracture charge
`has been shown to optimize fracturing efficiency and placement by ensuring that each perforation tunnel contributes equally
`during the fracture treatment, which contributes to providing cost effective hydraulic stimulation and maximizing subsequent
`asset value.
`
`Introduction
`Before any stimulation of a cased well completion, a conductive path must be established from the wellbore into the target
`reservoir rock. Several technologies currently exist, such as sliding sleeves, to create this conduit; however, the most popular
`technology is perforating because of its overall efficiency, reliability, and historically successful track record. Perforating oil
`and gas wells using specially designed shaped charge jet perforators has been used extensively since its introduction in the
`late 1940s. Broad improvements have been applied in the design and materials used since this process was first introduced as
`the physics have become better understood and testing techniques have advanced and evolved. Shaped charges can now be
`designed and manufactured for specific applications and conditions, enabling deeper penetration, maximum or minimum
`casing-hole diameter, and/or the ability to penetrate through only selected tubing or casing strings without penetrating the
`outer string. However, with all of the advances in perforator design and technology, no shaped charge had been developed to
`minimize the variation in perforated casing-hole size until now. In addition, stimulation treatment designs have not
`considered that variation does exist and that it is typically dependent upon gun-to-casing clearance.
`Fracture stimulation has demonstrated great success in conventional reservoirs where it was common to focus solely on
`completing a single zone for production. However, with the industry continuing to trend toward unconventional and resource
`type plays, which have much lower permeability and larger gross intervals than traditional conventional reservoirs, the focus
`has shifted to completion methods that can effectively implement multiple stimulation treatments conducted consecutively to
`maximize efficiency and minimize time to production.
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`It has been shown that, in horizontal wells drilled in unconventional reservoirs, the degree of stimulated reservoir volume
`(SRV) is directly proportional to the resulting production (Mayerhofer et al. 2008). It has been shown that SRV can be
`improved by increasing the number of stimulation points along the horizontal wellbore. This concept can also be applied to
`vertical wells that are drilled through long intervals of potentially productive stacked sands, silt, shale, and carbonates.
`Although there are several viable completion methods applicable to stimulating long intervals in vertical wells, the
`method using limited entry perforating (LEP) (Lagrone and Rasmussen 1963) is optimal for stimulating multiple intervals
`simultaneously to achieve a high SRV in a timely and cost effective manner. The LEP stimulation design uses standard
`hydraulic equations to define the pressure decrease across the perforations and the pressure decreases that occur between the
`perforations as a function of hydrostatic and friction pressure. In addition to these pressure decreases, full consideration of the
`fracturing pressure at each perforation point must be made. The objective of these calculations is to determine the size and
`number of perforations required at each stimulation point to distribute the stimulation fluid evenly across the intended
`interval, as shown in Fig. 1.
`
`Fig. 1—LEP design concept creating eight fractures simultaneously. Post-fracture tracer profile (left) validates the design concept.
`
`In practice, one of the main obstacles to LEP design is the inherent circumferential inconsistency in the diameter of the
`perforations when using standard perforating charges without centralization. Because the stimulation fluid must divide and
`pass through several perforations and then recombine before flowing down the fracture plane, any variation in the
`circumferential perforation size can disrupt the fluid convergence, which results in greater than expected injection pressures
`and possible bridging of the propping agent. This behavior is often referred to as near-wellbore tortuosity (Romero et al.
`1995), as shown in Fig. 2
`
`Fig. 2—The concept of flow convergence between perforation tunnels and tortuosity.
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`In several ongoing multiple well resource play projects, high injection pressures and bridging of the propping agent
`frequently occurred during the stimulation. An analysis of the injection pressures led to the premise that the standard
`perforating charges were not optimal and that a high degree of tortuosity existed. Treatment fluids were believed to be
`contributing through only some of the perforations because of the known inconsistent perforation diameter circumferentially
`around the wellbore caused from variations in gun-to-casing wall clearance. This casing-hole variation was assumed to cause
`a high degree of near-wellbore tortuosity. To test this premise, an existing perforating charge with a shallower penetration
`and a more consistent hole diameter than the previous charge was used; a moderate reduction of injection pressure and a
`reduction in the frequency of bridging of the propping agent was observed. This observation led to the research, design, and
`development of a new optimized perforating shaped charge tailored for perforating before stimulation treatment begins.
`
`Fracture Physics - Casing Hole Size and Orientation
`We have developed a simplified model to preliminarily investigate the role of perforation tunnel geometry during the
`hydraulic fracturing process. In particular, because of the known effect of gun-to-casing clearance and the challenges
`observed while treating wells, the focus was placed on the consistency of the casing entrance-hole diameter in affecting
`fracture initiation. The model incorporates a finite element stress analysis with a fracture initiation criterion. The finite
`element analysis has been performed using the commercial software ABAQUS/Standard (2011) to determine the stress
`distribution around the perforating tunnel. The model developed establishes the connection between the breakdown pressure
`and the local stresses along the surface of the perforation tunnel.
`
`Fig. 3—The model geometry.
`
`As shown in Fig. 3 (only half of the model is shown), the simplified model consists of the steel casing with six holes
`over a 12-in. interval and the reservoir. Each casing-hole is treated as a cylindrical hole. Corresponding to each casing hole, a
`cylindrical perforation tunnel is created with the length of 15 in. and the same diameter as that of the casing-hole. The
`reservoir model height is equal to the perforated interval of 12 in. and a radius of 50 in. Additional study indicated that the
`reservoir in the present model is sufficiently large such that the stress distribution near the perforation tunnel and the casing
`does not depend on the reservoir boundary. Fig. 4a shows the mesh configuration of the reservoir model; Fig. 4b provides a
`close view of the region near the perforating tunnel. The mesh is refined in the region near the perforation tunnel. For
`simplification, both the reservoir rock and the steel casing are considered as linear elastic materials. A uniformly distributed
`pressure, p, (=100 MPa) is applied to both the surface of the perforating tunnel and the casing.
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`Fig. 4—Finite element mesh configurations.
`
`In this study, the entrance-hole diameters of the six perforation tunnels were varied, but the influence of the tunnel length
`and irregularities of the geometry of the real perforation tunnel has not been explored. Three cases are considered: (1) an
`ideal case in which all six tunnels have the same entrance-hole diameter; (2) a specific case in which the entrance-hole
`diameters vary from 0.36 to 0.48 in., as a representative having less variation in the perforation entrance-hole diameters
`(EHD) created by a specially designed shaped charge; (3) a specific case in which the entrance-hole diameters vary from 0.25
`to 0.55 in., as a representative having larger variation in the perforation EHD created by a conventional deep penetration
`shaped charge. As testing has confirmed and will be presented later in this work, the perforation EHD varies relative to the
`clearance between the perforating gun and the casing wall.
`Fig. 5 shows the numerically predicted distribution of the local maximum principal stress (MPS) on the surfaces of the
`perforation tunnels and the wellbore. In the figures, red indicates a large magnitude of the stress, and blue indicates a
`relatively small magnitude. For all three cases, the local maximum principal stress (MPS) is always on the top surface of the
`perforation tunnel near the base of the perforation and near the wellbore surface. This outcome is consistent with the previous
`work completed by Behrman and Elbel (1991). The entrance-hole diameter greatly contributes to fracture initiation, whereas
`the tunnel length has a much smaller effect on the initial perforation breakdown.
`
`TABLE 1—SUMMARY OF FEA RESULTS COMPARING EHD TO MPS
`
`Scenario
`
`Case 1
`Case 2
`Case 3
`
`Entrance-Hole Diameter
`Maximum
`Minimum
`
`0.43 in.
`
`0.36 in.
`0.25 in.
`
`0.48 in.
`0.55 in.
`
`Maximum Principal Stress
`Maximum
`Minimum
`152.7 MPa
`157.2 MPa
`149.9 MPa
`144.8 MPa
`
`162.5 MPa
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`Case I: (Ideal Case) All six
`tunnels have the same entrance
`hole diameter.
`
`MPS =152.7 MPa, D = 0.43”
`
`Case II: The entrance hole
`diameters vary from 0.36
`inches to 0.48 inches.
`
`MPS =152.1 MPa, D = 0.40”
`M PS =157.2 M Pa, D = 0.48’
`MPS =155.9 MPa, 0 = 0.46’
`MPS =149.9 MPa, 0=0.36”
`M PS =155.9 M Pa, D = 0.46”
`MPS =157.2 MPa, 0 = 0.48’
`
`Case III: The entrance hole
`diameters vary from 0.25
`inches to 0.55 inches.
`
`MPS =160.7 MPa, 0 = 0.53’
`MPS =147.1 MPa, 0 = 0.30’
`MPS =144.8 MPa, 0 = 0.25’
`MPS =147.1 MPa, 0 = 0.30’
`MPS =160.7 MPa, 0= 0.53’
`MPS =162.5 MPa, 0 = 0.55”
`
`Fig. 5—Contour plots of the local maximum principal stress (MPS) on the surfaces of the perforation tunnel and the wellbore. The
`local maximum principal stress (MPS) is always on the surface of the perforation tunnel near the entrance, so the entrance-hole
`diameter greatly contributes to fracture initiation.
`
`To derive a fracture initiation criterion, we will consider the following hydraulic fracturing process. As the fluid is
`injecting into the well, a very high pressure will build up on the casing surface and the perforation tunnel surface, resulting in
`locally elevated stresses in the reservoir rock near the perforation tunnel. In general, the fracture will initiate when the
`maximum principal stress,^ of the rock reaches the tensile failure strength of the rock,Tfail which can be written as:
`
`Furthermore, based on the present finite element analysis, the hydraulic pressure generated by the injection fluid is
`linearly proportional to the calculated local max principal stress, such that
`
`O'! — Tfail-
`
`(1)
`
`<7i = Kp
`
`(2)
`
`Where K is the coefficient, which is a function of reservoir rock properties, as well as the geometry of the perforation tunnel.
`Substituting (1) into (2), we obtain the relation between the breakdown pressure, pbd and the tensile failure strength of the
`rock,?faii as
`
`Pbd = Tfail/K (3)
`
`Eq. 3 indicates that for a given reservoir rock (i.e., Tfaii is a constant), the breakdown pressure is proportional to the
`inverse of the coefficient K. A larger value of K leads to a reduced breakdown pressure. Furthermore, according to the
`numerical results in Fig. 3, for a given pressure, the local maximum principal stress (MPS) increases as the hole diameter
`decreases. For example (i.e., in Case 3), for the smallest entrance-hole diameter (£> = 0.25 in.), the MPS equals 144.8MPa,
`whereas for the largest entrance-hole diameter (£> = 0.55 in.), the MPS is 162.5MPa. Consequently, the larger the entrance­
`hole diameter, the larger the value of the coefficient K. Finally, we can conclude that for a given reservoir rock, the
`breakdown pressure will be reduced as the perforation tunnel diameter increases. This conclusion agrees with previous work
`that documents the importance of casing hole size over penetration (Behrman and Nolte 1998).
`Although breakdown pressure can be reduced locally by a larger entrance-hole diameter, the consistency of all hole
`diameters is also critical for a successful breakdown and stimulation. An important factor affecting the efficiency of hydraulic
`stimulation process is the ability to pass fluid through all perforations, specifically those aligned with the preferred fracture
`plane, which enables each hole to contribute to a successful breakdown and stimulation. If the variation of the entrance-hole
`diameter of the neighboring perforation tunnels is too large, then the fracture will initiate at the entrance of the larger hole,
`leaving the smaller holes less effective and possibly creating a tortuous path as the fracture grows and aligns itself with the
`preferred fracture plane. This is because after the fracture occurs at a single perforation hole, the diameter of the damaged
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`hole will be further enlarged, and the required local breakdown pressure will be further reduced, thus making the fracture
`grow locally.
`
`Perforator Performance - Casing Hole Size Varies
`Jet perforator performance can vary greatly depending upon the particular materials used in the charge case and liner. In
`addition, the geometric shape and dimensions of the liner, charge case, and explosive column can also affect performance.
`For example, the two most common classes of shaped charges for the oil and gas industry are big hole (BH) and deep
`penetrating (DP) charges; BH charges typically use a parabolic shaped solid metal liner, whereas DP charges most commonly
`have a liner pressed from powdered metal particles into a convex shaped liner. As their names suggest, the performance of
`each class of charge is unique. Under a given set of conditions, a correlative tradeoff exists between the penetration of a
`charge and the casing hole size that it creates. In other words, as the penetration becomes greater, the casing hole size
`becomes smaller; conversely, as the hole size created becomes larger, the depth of penetration becomes smaller.
`Just as casing hole size and penetration can vary depending upon the particular design of a shaped charge, the
`environment in which it is detonated can have a major influence upon performance. Particularly important to this work is the
`influence the distance between the perforating gun and interior casing wall; which is known as clearance.
`
`Fig. 6—Perforating to casing wall clearance.
`
`Perforating gun systems, regardless of conveyance, will likely be against the casing wall in a decentralized position, with
`charge phasing oriented toward an unknown direction unless a specific mechanism is used to centralize or orient the gun. As
`a result, it is impossible to know the exact clearance that a shaped charge will have, but known gun diameter and casing size
`can provide an expected maximum and minimum clearance. The amount of clearance between the perforating gun and the
`casing wall significantly affects casing hole size for most BH and DP charges.
`An extensive evaluation was performed of the industry-available shaped charges often used to perforate wells before
`stimulation treatment. The most common good hole (GH) charge used throughout the North America frac market was
`evaluated and shot under quality control (QC) setup conditions, using minimum and maximum clearances. Fig. 7 provides an
`example the significant variation that can exist with a 3-1/8 in. gun assembly inside 5-1/2 in. casing and the QC setup in
`which it was tested. Table 2 presents the measurements of the casing plate coupons perforated using the minimum and
`maximum clearance in Fig. 7. Fig. 8 outlines a summary of completed test program datapoints, highlighting significant
`variance in hole diameter relative to clearance, as well as significant variance in charge performance.
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`Fig. 7—Casing coupons from QC shot of GH charge with minimum and maximum clearance and illustration of QC setup.
`
`TABLE 2—CASING COUPON HOLE SIZE COMPARISON.
`0.142 in. Water Clearance
`1.910 in. Water Clearance
`Variable
`2
`Test Number
`1
`4
`5
`3
`6
`Minor EHD (in.)
`0 230
`0.240
`0.480
`0.520
`0.520
`0.230
`Major EHD (in.)
`0.530
`0.240
`0.250
`0.520
`0.540
`0.250
`Average EHD (in.)
`0.525
`0.240
`0.500
`0.530
`0.240
`0.240
`
`Casing Entrance Hole Diameter (in.)
`
`Fig. 8—Clearance sensitivity data points from commonly used non-optimized charges.
`
`Data sheets commonly referenced within the industry to identify perforator performance include API 19B Section I, or a
`less controlled and outdated method RP43. These testing methods require the detonation of a representative perforating gun
`inside an appropriate-sized segment of casing placed inside a cement target. After gun detonation, each casing hole created
`from the perforation jet is measured and documented. The average of these casing holes, regardless of clearance, is typically
`presented as the shaped charge or gun system performance. Therefore, neither the minimum or maximum hole size created is
`often understood nor the variance without looking specifically at hole size relative to clearance.
`
`Optimized Shaped Charge
`Shaped charges are fundamentally described as having three basic components: charge case, explosive load, and liner. The
`performance of a shaped charge or gun system is varied through modifying the geometry, quantity, or composition of those
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`main components. Recent studies have shown that the manufacturing process can also significantly affect performance.
`Variations of these three components, as has been demonstrated and widely accepted within the industry, can be optimized to
`tailor the performance of a charge for a given set of conditions, including optimizing hole size and hole size consistency
`relative to gun-to-casing clearance. Taking into consideration the importance of hole-size consistency, a shaped charge jet
`perforator was developed and manufactured to minimize this variation. Through minimizing hole size variation in non­
`oriented perforations, fracture efficiency would improve. This is a result of all of the perforation holes receiving injected
`treating fluids, rather than only the largest holes. As previously presented in Fig. 8, the minimal clearance generally provides
`the greatest hole size; consequently, the perforations on the low side of the casing would most likely receive the majority of
`injected treating fluids, regardless of the preferred fracture plane. Fractures that initiate from larger perforations greater than
`30 degrees from the preferred fracture plane demonstrate higher treating pressures and decreased width, a known effect of
`near-wellbore tortuosity (Abass et al. 1994).
`The newly developed 21.0 gram fracture charge was loaded into a 3-1/8 in. and 3-3/8 in. 6 spf 60 deg gun assembly and
`detonated within 4-1/2 in. and 5-1/2 in. casing, respectively, to represent the most common perforating condition in the North
`America stimulation market. This testing is commonly referred to as a barrel test; its purpose is to confirm and validate that a
`charge could be tailored to generate a more consistent hole size, regardless of clearance. Fig. 9 and Table 3 present the
`results, comparing casing hole size consistency relative to gun-to-casing clearance between the newly optimized fracture
`charge, a 21.0 gram shaped charge (Charge A) and an industry-available 19.0 gram GH shaped charge (Charge B).
`
`Fig. 9—Barrel test results from charge comparison.
`
`TABLE 3—CASING HOLE PERFORMANCE DATA.
`
`3-1/8 in. Perforating Gun in 4-1/2 in. Casing
`
`3-3/8 in. Perforating Gun in 5-1/2 in. Casing
`
`Charge
`Frac Charge
`Charge A
`Charge B
`
`Average (in.)
`0.46
`0.49
`0.50
`
`Max (in.)
`0.47
`0.52
`0.54
`
`Min (in.)
`0.42
`0.40
`0.39
`
`% Dev
`10.9
`24.7
`
`29.9
`
`Average (in.)
`0.43
`0.42
`
`0.40
`
`Max (in.)
`0.47
`0.54
`
`0.55
`
`Min (in.)
`0.36
`0.30
`
`0.25
`
`% Dev
`25.6
`57.1
`
`75.0
`
`Although the fracture charge does not have the largest hole size, it also does not have the smallest. As expected from
`initial QC shots, the optimized frac charge significantly outperformed the alternative charges in the fully loaded gun system
`test when detonated in a representative segment of casing having the tightest variation. Fig. 10 illustrates the average
`performance, which provides insight into how the casing hole variation could be a significant contributor to near-wellbore
`tortuosity. Figure 8b, in the appendix benchmarks the Frac charge performance compared to the initial clearance sensitivity
`data set of Fig 8.
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`3 % in. gun in 5 72 in. casing
`
`0.25 in.
`
`0.36 in.
`
`0.55 in.
`Charge B
`Fig. 10—Barrel test performance overview.
`
`0.40 in.
`FRAC Charge
`
`For example, if the preferred fracture plane was transverse to the horizontal wellbore, and the well was cluster perforated
`with non-optimized charges, only the perforations closest to the lowside with the significantly larger hole diameter would
`likely contribute to the treatment, making nearly half non-contributing. Alternatively, the optimized fracture charge would
`generate a perforation tunnel with a greater probability of accepting treating fluids proportionally.
`
`Field Studies
`The first phase of field trials consisted of five wells, with a total of 25 stages, to evaluate the newly designed and optimized
`fracture shaped charge. The well completions were made in the Atoka-Strawn formations for two wells and the Wolfcamp-
`Leonard (Wolfberry) for the remaining three wells. All five wells are located in the Midland basin of West Texas. These field
`trials were designed to test the effectiveness of the new charge and the premise that a smaller variance in perforated hole size
`and less emphasis on depth of penetration would improve the connectivity between the wellbore and the fractures created
`from it. This section includes examples of four of the 25 stages, showing the rate and pressure responses of treatments using
`the new charge and how these parameters compare to previous treatments.
`
`Field Trial 1. Field Trial 1 was conducted in the Atoka formation. This interval consisted of medium hard to hard limestone
`interbedded with shale of various properties and having a fracture gradient ranging from 0.85 to 0.95% of the overburden
`gradient. Area stimulation history shows that it is difficult to initiate fractures in the interval and difficult to obtain the
`designed injection rates within the pressure limits of the casing. Six individual clusters of perforations were strategically
`spaced across 300 vertical ft of Atoka formation. The perforations were shot with 60-degree phasing and with a shot density
`of 6 shots per ft, for a total of 49 perforations.
`Treatment data from a recently completed offset well was used to evaluate the performance of the new optimized fracture
`shaped charge. This well was also completed with six individual clusters of standard perforations spaced across 300 vertical
`ft of Atoka formation. These perforations were also shot with 60-degree phasing and with a shot density of 6 shots per ft, for
`a total of 49 perforations.
`On the offset well, an injection rate of 55 bpm was obtained with the injection pressure approaching 6,000 psig, near the
`casing limit, in approximately 29 minutes. The test well using the new perforating charge reached this treating pressure in
`approximately the same amount of time, but it was possible to continue to increase the rate to 70 bpm, as shown in Fig. 11.
`An increase of 15 bpm was obtained for the same pressure by using the new perforating fracture charge.
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`Fig. 11—Wellhead treating pressure comparison for Field Trial 1.
`
`Field Trial 2. Field Trial 2 was conducted in the Lower Spraberry formation. This interval consisted of medium soft to soft
`limestone muds interbedded with shale of various properties; the fracture gradient ranged from 0.60 to 0.65% of the
`overburden gradient. Area stimulation history shows the interval to be easy to initiate fractures and to obtain the designed
`injection rates within the pressure limits of the casing. Five individual clusters of perforations were strategically spaced
`across 250 vertical ft of Spraberry formation. The perforations were shot with 60-degree phasing and with a shot density of 6
`shots per ft, for a total of 48 perforations.
`Treatment data from an offset well was used to evaluate the performance of the new perforating charge. This well was
`completed with six individual clusters of standard perforations spaced across 250 vertical ft of Spraberry formation. These
`perforations were also shot with 60-degree phasing and with a shot density of 6 shots per ft for a total of 57 perforations.
`On the offset well, the designed injection rate of 65 bpm was obtained with the injection pressure approaching 2,200 psig
`in approximately 3 minutes. The test well using the new perforating fracture charge reached this treating pressure in
`approximately the same amount of time, but at a lower designed rate of 60 bpm. As shown in Fig. 12, both wells were treated
`at approximately the same injection pressure of 2,200 psig, although the well with the new perforating fracture charges had
`fewer holes. The rate per perforation in the test well was 1.25 bpm vs. the offset wells 1.14 bpm. This amounts to an
`approximately 10% improvement in perforation flow area. Table 4 provides details of Field Trial 2.
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`TABLE 4—COMPARISON OF STAGE #5, FIELD TRIAL 2.
`
`Clusters
`Holes
`Time to Rate
`Rate
`Pressure
`ISIP
`
`Old Charge
`6
`57
`3
`65
`2,212
`1,004
`
`New Frac Charge
`5
`48
`3
`60
`2,175
`1,013
`
`Difference
`-1
`-9
`0
`-5
`-37
`9
`
`Field Trial 3. Field Trial 3 was conducted in the Middle Spraberry formation. This interval consisted of medium soft to soft
`limestone muds interbedded with sand and silt stones of various properties; the fracture gradient ranged from 0.50 to 0.52%
`of the overburden gradient. Area stimulation history shows the interval to be easy to initiate fractures and to obtain the
`designed injection rates within the pressure limits of the casing. Six individual clusters of perforations were strategically
`spaced across 250 vertical ft of Spraberry formation. The perforations were shot with 60 degree phasing and with a shot
`density of 6 shots per ft for a total of 52 perforations.
`Treatment data from an offset well was used to evaluate the performance of the new perforating charge. This well was
`completed with six individual clusters of standard perforations spaced across 250 vertical ft of Spraberry formation. These
`perforations were also shot with 60-degree phasing and with a shot density of 6 shots per ft for a total of 58 perforations.
`On the offset well, the designed injection rate of 65 bpm was obtained with the injection pressure approaching 1,800 psig
`in approximately 6 minutes. The test well using the new perforating charge reached this treating pressure in approximately
`the same amount of time and at the same rate of 65 bpm. As shown in Fig. 13, both wells were treated at approximately the
`same injection pressure of 1,800 psig, although the well with the new perforating charges had fewer holes. The rate per
`perforation in the test well was 1.25 bpm vs. the offset wells 1.12 bpm. This amounts to approximately an 11% improvement
`in perforation flow area. Table 5 provides details of Field Trial 3.
`
`Fig. 13—Comparison of treating pressure and rate of Field Trial 3.
`
`TABLE 5—COMPARISON OF STAGE #8, FIELD TRIAL 3.
`
`Clusters
`Holes
`Time to Rate
`Rate
`Pressure
`ISIP
`
`Old Charge
`6
`58
`4
`65
`1,812
`719
`
`New Frac Charge
`6
`52
`2
`65
`1,800
`745
`
`Difference
`0
`-6
`-2
`0
`-12
`26
`
`Field Trial 4. Field Trial 4 was conducted in the Upper Spraberry formation. This interval consisted of medium soft to soft
`limestone muds interbedded with sand and silt stones of various properties; the fracture gradient ranged from 0.50 to 0.52%
`of the overburden gradient. Area stimulation history shows the interval to be easy to initiate fractures and to obtain the
`designed injection rates within the pressure limits of the casing. Six individual clusters of perforations were strategically
`spaced across 200 vertical ft of Spraberry formation. The perforations were shot with 60 degree phasing and with a shot
`density of 6 shots per ft, for a total of 52 perforations.
`
`DynaEnergetics Europe GmbH
`Ex. 1007
`Page 11 of 13
`
`

`

`12
`
`SPE 159085
`
`Treatment data from an offset well was used to evaluate the performance of the new perforating charge. This well was
`completed with five individual clusters of standard perforations spaced across 200 vertical ft of Spraberry formation. These
`perforations were also shot with 60-degree phasing and with a shot density of 6 shots per ft for a total of 52 perforations.
`On the offset well, the designed injection rate of 60 bpm was obtained with the injection pressure approaching 2,0