SPE 71692
`
`Successful Hydrajet Acid Squeeze and Multifracture Acid Treatments in Horizontal
`Open Holes Using Dynamic Diversion Process and Downhole Mixing
`M.J. Rees and A. Khallad, PetroCanada Oil and Gas, A. Cheng, K.A. Rispler, J.B. Surjaatmadja, and B.W. McDaniel,
`Halliburton Energy Services, Inc.
`
`Copyright 2001, Society of Petroleum Engineers, Inc.
`
`This paper was prepared for presentation at the 2001 SPE Annual Technology Conference,
`New Orleans, September 30.
`
`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, as
`presented, have not been reviewed by the Society of Petroleum Engineers and are subject to
`correction by the 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 copy is restricted to an abstract of not more than 300
`words. Illustrations may not be copied. The abstract should contain conspicuous acknowledg-
`ment of where and by whom the paper is presented. Write Librarian, SPE, P.O. Box 833836,
`Richardson, TX 75083-3836, U.S.A, fax 01-972-952-9435.
`
`Abstract
`Effective stimulation of wells with long, openhole horizontal
`completions is generally considered a difficult task, especially in
`low-permeability carbonate reservoirs that require deep penetra-
`tion with live acid. Because the creation of multiple effective
`fractures, the opening (etching) of existing fractures, or the
`creation of extensive wormholes is generally desired, this task
`becomes even more difficult, time-consuming, and expensive if
`conventional acidizing processes are used. If the live acid is not
`channeled properly, it will be spent rapidly at unwanted loca-
`tions, often greatly enlarging the fluid-entry point. Under such
`circumstances, creating etched fractures or wormholes of any
`significant lengths can be nearly impossible.
`A relatively new hydrajet fracturing process can be used to
`solve this problem. This process can be used in two ways: (1)
`dynamic fluid energy is used to divert flow into a specific
`fracture entry point to initiate a fracture at the intended location
`with live acid directed into this fracture plane, (2) high-pressure
`downhole mixing is used to create foam for high-intensity acid
`squeezes. This technique typically uses two independent fluid
`streams, one in the treating string and another in the annulus. The
`two fluids (if dissimilar) are mixed downhole at a tremendously
`high energy to form a homogenous mixture.
`This paper discusses and compares the results of conven-
`tional acid treatments with various styles of hydrajet fracture-
`acidizing treatments performed in several openhole horizontal
`wells within two different areas of the same formation. The novel
`use of the downhole mixing feature is also discussed.
`
`Introduction
`Mineral and organic acids have been used to stimulate oil- and
`gas-producing formations for more than 100 years. In carbonate
`formations, which have high acid solubility, using acid fluids at
`fracturing pressures predates most professionals currently active
`in stimulation technology. Over the years, several effective
`acidizing formulations, chemicals, additives, and placement
`processes have been developed. During many such develop-
`ments, laboratory and field studies were combined to develop
`specific treatment fluids and processes for a particular formation
`or reservoir.
`In long, openhole completions (primarily horizontal or
`highly deviated wellbores), large exposed surfaces tend to con-
`sume acids or other chemicals prematurely or at only a few
`locations along the wellbore. Acids are likely spent at locations
`where they first contact the formation or at more highly reactive
`areas. In such cases, different delivery techniques must be used
`to place the acid at the desired destination. Ported subs and
`coiled tubing (CT) have sometimes been used successfully for
`such placements,and other more novel approaches have report-
`edly been used in openhole carbonate completions.1-2
`Successful acid treatments in wells with long openhole
`wellbores depend on the following conditions:
`•
`Live acid reaches the desired location along the wellbore.
`•
`Live acid reaches far into the formation for adequate etching
`or wormholing to achieve sufficient near-wellbore or frac-
`ture conductivity.
`BAKER HUGHES INCORPORATED
`•
`Isolating procedures are used to ensure that the acid is only
`AND BAKER HUGHES OILFIELD
`placed within the target area.
`OPERATIONS, INC.
`The hydrajet stimulation technique can be used to achieve
`Exhibit 1033
`these goals. One variation of this technique, which uses the
`BAKER HUGHES INCORPORATED
`hydrajet fracturing process,3-6 has been used in more than 400
`AND BAKER HUGHES OILFIELD
`fractures in over 40 wells (both fracture-acidizing and proppant-
`fracturing applications). This paper describes an expansion of the
`OPERATIONS, INC. v. PACKERS
`previous technology7 to use high-pressure jetting energy to per-
`PLUS ENERGY SERVICES, INC.
`form some or all of the following tasks simultaneously: perfora-
`tion, fluid delivery, fracture initiation, fracture extension, tortuos-
`IPR2016-00596
`ity reduction, chemical mixing, and regional isolation.
`
`References at the end of the paper.
`
`Page 1 of 13
`
`

`

`SPE 71692
`
`Successful Hydrajet Acid Squeeze and Multifracture Acid Treatments in Horizontal
`Open Holes Using Dynamic Diversion Process and Downhole Mixing
`M.J. Rees and A. Khallad, PetroCanada Oil and Gas, A. Cheng, K.A. Rispler, J.B. Surjaatmadja, and B.W. McDaniel,
`Halliburton Energy Services, Inc.
`
`Copyright 2001, Society of Petroleum Engineers, Inc.
`
`This paper was prepared for presentation at the 2001 SPE Annual Technology Conference,
`New Orleans, September 30.
`
`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, as
`presented, have not been reviewed by the Society of Petroleum Engineers and are subject to
`correction by the 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 copy is restricted to an abstract of not more than 300
`words. Illustrations may not be copied. The abstract should contain conspicuous acknowledg-
`ment of where and by whom the paper is presented. Write Librarian, SPE, P.O. Box 833836,
`Richardson, TX 75083-3836, U.S.A, fax 01-972-952-9435.
`
`Abstract
`Effective stimulation of wells with long, openhole horizontal
`completions is generally considered a difficult task, especially in
`low-permeability carbonate reservoirs that require deep penetra-
`tion with live acid. Because the creation of multiple effective
`fractures, the opening (etching) of existing fractures, or the
`creation of extensive wormholes is generally desired, this task
`becomes even more difficult, time-consuming, and expensive if
`conventional acidizing processes are used. If the live acid is not
`channeled properly, it will be spent rapidly at unwanted loca-
`tions, often greatly enlarging the fluid-entry point. Under such
`circumstances, creating etched fractures or wormholes of any
`significant lengths can be nearly impossible.
`A relatively new hydrajet fracturing process can be used to
`solve this problem. This process can be used in two ways: (1)
`dynamic fluid energy is used to divert flow into a specific
`fracture entry point to initiate a fracture at the intended location
`with live acid directed into this fracture plane, (2) high-pressure
`downhole mixing is used to create foam for high-intensity acid
`squeezes. This technique typically uses two independent fluid
`streams, one in the treating string and another in the annulus. The
`two fluids (if dissimilar) are mixed downhole at a tremendously
`high energy to form a homogenous mixture.
`This paper discusses and compares the results of conven-
`tional acid treatments with various styles of hydrajet fracture-
`acidizing treatments performed in several openhole horizontal
`wells within two different areas of the same formation. The novel
`use of the downhole mixing feature is also discussed.
`
`Introduction
`Mineral and organic acids have been used to stimulate oil- and
`gas-producing formations for more than 100 years. In carbonate
`formations, which have high acid solubility, using acid fluids at
`fracturing pressures predates most professionals currently active
`in stimulation technology. Over the years, several effective
`acidizing formulations, chemicals, additives, and placement
`processes have been developed. During many such develop-
`ments, laboratory and field studies were combined to develop
`specific treatment fluids and processes for a particular formation
`or reservoir.
`In long, openhole completions (primarily horizontal or
`highly deviated wellbores), large exposed surfaces tend to con-
`sume acids or other chemicals prematurely or at only a few
`locations along the wellbore. Acids are likely spent at locations
`where they first contact the formation or at more highly reactive
`areas. In such cases, different delivery techniques must be used
`to place the acid at the desired destination. Ported subs and
`coiled tubing (CT) have sometimes been used successfully for
`such placements,and other more novel approaches have report-
`edly been used in openhole carbonate completions.1-2
`Successful acid treatments in wells with long openhole
`wellbores depend on the following conditions:
`•
`Live acid reaches the desired location along the wellbore.
`•
`Live acid reaches far into the formation for adequate etching
`or wormholing to achieve sufficient near-wellbore or frac-
`ture conductivity.
`Isolating procedures are used to ensure that the acid is only
`placed within the target area.
`
`•
`
`The hydrajet stimulation technique can be used to achieve
`these goals. One variation of this technique, which uses the
`hydrajet fracturing process,3-6 has been used in more than 400
`fractures in over 40 wells (both fracture-acidizing and proppant-
`fracturing applications). This paper describes an expansion of the
`previous technology7 to use high-pressure jetting energy to per-
`form some or all of the following tasks simultaneously: perfora-
`tion, fluid delivery, fracture initiation, fracture extension, tortuos-
`ity reduction, chemical mixing, and regional isolation.
`
`References at the end of the paper.
`
`Page 1 of 13
`
`

`

`2
`
`SUCCESSFUL HYDRAJET ACID SQUEEZE AND MULTIFRACTURE ACID TREATMENTS
`IN HORIZONTAL OPEN HOLES USING DYNAMIC DIVERSION PROCESS AND DOWNHOLE MIXING
`
`SPE 71692
`
`Hydrajet Fracturing Technology
`Previous publications provide detailed discussions about using
`hydrajet fracturing to create substantial fractures. The use of el-
`evated annulus pressure to improve fracture extension is an impor-
`tant component of this technology and is also well known.3-5 Even
`when the annulus pressure is below the fracture-gradient pressure,
`small hydraulic fractures can be created by the elevated pressures
`resulting from stagnation pressure within the jetted-out tunnel or
`notch in the formation rock. Let us consider the jet and wellbore wall
`shown in Fig. 1. In this figure, high-pressure fluid inside the tool (T)
`accelerates through the jet (J), as shown in Equation 1:
`V
`Cp
`2
`+
`=
`..........................................(1)
`ρ2
`
`where
`V = fluid velocity
`P = pressure
`ρ = mass density
`
`Depending on the fluid’s viscosity, the velocity of the fluid
`exiting the jet (at a 5,000-psi pressure differential) can be
`approximately 430 to 650 ft/sec. When this jet is at a distance of
`d [or d+Dd, including the notch (Fig. 1)], “flaring” of the jet and
`enlargement of the notch reduce the effective stagnation pres-
`sure. However, as we reduce the distance to a value near zero, the
`stagnation pressure will be similar to the original jet pressure
`(minus some inefficiencies). At any time during jetting, the
`highest pressures anywhere within the entire openhole section
`will be inside the notch or cavity that is currently being jetted.
`
`High-Energy Downhole Mixing
`Through the use of the annulus between the coiled tubing and the
`production tubulars, hydrajet stimulation technology can deliver
`two independent fluid streams downhole. The composition of
`the annular fluid can vary depending on the type of stimulation
`desired. In the case of hydrajet fracture stimulation, the annular
`fluid is generally used to control annular pressure and aid in the
`creation of the fracture. In the case of hydrajet squeeze stimula-
`tion, the fluid is used to create a high-quality downhole foam that
`assists in effective mechanical diversion. The fluid used for
`hydrajet squeeze stimulation is generally a gas, whereas hydrajet
`fracture stimulation has used a variety of fluids, including clean
`fracturing fluids, liquids that chemically control clay stability,
`and plain, low-cost fluids (provided that they do not exhibit
`excessive fluid loss in the openhole annulus). Regardless of type,
`all annular fluids are mixed with the fracturing fluid, and part of
`this mixture is flowed into the fracture. The remainder of the
`fluid will be lost to the formation.
`Annular fluids can be engineered to perform various func-
`tions, such as modifying pH on location or creating a rapid
`reaction in the fracturing fluid. As mentioned earlier, one
`practical application of gaseous annular fluids is the creation of
`
`foams if sufficient mixing energy is available. Generally,
`foams are generated when one flow stream containing gas is
`mixed with another flow stream containing liquid. Foaming
`agents are usually mixed with liquid to promote effective
`foaming, and foam generators are used to improve the texture
`quality of the foam (Fig. 2).
`Foam generators improve foam texture by accelerating one
`of the fluids to a high velocity and injecting the fluid into a stream
`of the other fluid. In surface operations, acceleration is most
`easily accomplished with the gaseous portion. The gas accelera-
`tor can be a nozzle(s) or other pressure-reducing device, such as
`a porous material or channel. For pressure differentials in the
`range of 200 to 1,000 psi, we can achieve gas velocities of
`approximately 350 ft/sec, thus creating the high-energy shear
`necessary for foam development. With hydrajet fracturing, the
`same situation exists downhole: a high-energy jet enters the
`jetted cavity (Fig. 1), which contains compressed gas. The jet
`pressure differential is generally 5,000 psi, creating a jet velocity
`of approximately 650 ft/sec. The combination of the high-
`velocity differential and the high energy level causes effective
`foam development.
`
`Stimulation with CO2 and N2 Foams
`For more than 20 years, foamed fluids have been used during
`hydraulic fracturing, fracture acidizing, and matrix acidizing
`treatments for reducing fluid loss, carrying proppants into the
`formation, and reducing liquid loads on the formation (reducing
`formation damage). During acidizing, foamed fluids also help
`retard the reaction rate of the acid with the formation, allowing
`live acid to penetrate further into the formation matrix or frac-
`ture. Generally, slowing the reaction rate may also promote
`“wormholing,” a condition that can improve production. Finally,
`foamed fluids can be useful for cleaning the wellbore after the
`stimulation treatment.
`The creation of fractures and the transportation of proppant
`into the fracture are enhanced by the viscosity of the foamed
`fluid. Foam viscosity depends on several variables, including
`foam quality, the viscosity of the external phase, and the texture
`(or bubble-size distribution) of the foamed fluid. Foams exposed
`to shear for a sufficient time will equilibrate to a bubble-size
`distribution that is characteristic of shear rate. The texture of a
`foamed fluid is also influenced by surfactant volume and type
`(composition). Surfactant concentrations must be adequate for
`stabilizing the foam under dynamic conditions.
`Studies have shown that the texture of a foamed fluid also
`influences its diversion capabilities. Higher shear rates, spe-
`cific surfactant concentrations, and high pressures create
`finer-textured aqueous foams, which provide better diver-
`sion. The nature of the liquid phase also influences the texture
`of foamed fluids. The larger bubble sizes exhibited by hydro-
`carbon and methanol foams result in greater sensitivity to
`degradation at high shear rates.10-11
`
`Page 2 of 13
`
`

`

`SPE 71692
`
`M.J. REES, A. KHALLAD, A. CHENG, K.A. RISPLER, J.B. SURJAATMADJA, B.W. MCDANIEL
`
`3
`
`Acid Treatment Tools and Processes
`Various methods for placing acid in an openhole (horizontal)
`wellbore are described in the following paragraphs.
`
`Pumping through Casing. Pumping acid through the casing is
`possibly the easiest way to place acid downhole at high injection
`rates. However, this practice is seldom effective for wells with
`long openhole sections. In many wells, the acid will generally be
`spent at the point of entry into the open hole, often close to the
`heel section, leaving the remainder of the wellbore relatively
`untreated. This can create a large void that may later cause well
`collapse, or make it difficult to get tools downhole past this
`section at a later time.
`
`Spot Placement. Spot placement of acid through coiled tubing
`can sometimes be effective for removing near-wellbore damage.
`The acid can often be placed almost evenly along the openhole
`section. Tools are not generally required, but gravity segregation
`problems and varying acid reactivity of the formation often limit
`the effectiveness of this technique.
`
`Washing. Although acid-washing procedures are similar to
`spot-placement procedures, acid washing involves using jet
`nozzles to wash the wellbore surface. This process is usually
`more effective at removing the damage caused by procedures
`such as drilling. Figs. 3 and 4 show sample jet-nozzle assem-
`blies; however, jet positions and sizes may differ with the tool
`chosen for a particular job. When an acid wash is performed,
`differential pressures across the jets are generally low and do not
`reach levels high enough to initiate fracturing or effective shear
`for foam generation. Summers8 and Momber9 have shown that
`effective wash pressures are primarily affected by the tensile
`strength of the filter cake or the grain of the cementitious
`material. Consequently, effective wash pressures are generally
`less than 2,500 psi. Often, rotating heads running at high speeds
`are used to more effectively clean the wellbore surface.
`
`Squeezing. To achieve a squeeze condition, a method similar to
`washing is used, but the annular area between the formation and
`the treating string is pressurized or shut in, forcing some of the
`acid to penetrate the matrix. The stability of foam generated at
`surface during these squeezes is questionable at the high tem-
`peratures (250°F) exhibited by some of the case wells. Conse-
`quently, the effectiveness of the diverting properties of the
`downhole foams is questionable.
`
`Hydrajet Squeezing. Similar to conventional squeezing (de-
`scribed in the previous section), hydrajet squeezing employs
`pressurization of the annulus while the primary treating fluid
`(acid) is pumped down the CT. However, hydrajet squeezing
`takes this process one step further; CO2 or a CO2/N2 mixture is
`pumped down the annulus at a high rate, allowing downhole
`foam generation. A high-pressure drop (3,000 psi) nozzle is used
`to create the shear necessary for creating this foam.
`
`In addition to allowing acid to be pumped at extremely high
`rates, this technique allows operators to easily change the quality
`of the downhole foam by changing the rates at which the gas and
`acid are pumped. This technique simplifies the placement of
`foam plugs in the open hole and allows high volumes of acid to
`be pumped over short periods.
`
`Fracture Acidizing. Fracture acidizing involves creating hydrau-
`lically induced fractures for significant penetration into the forma-
`tion, where acid can react with the fracture face to create an uneven
`or irregular fracture surface, resulting in a conductive path between
`the fracture faces (Fig. 5). In higher-temperature reservoirs, addi-
`tives (including gases) are often used to retard the acid’s reaction,
`allowing etching to occur farther from the wellbore.
`With the hydrajet fracturing approach, a coplanar jetting
`tool (Fig. 3) is preferred. The tool shown in Fig. 3 was designed
`for creating fractures perpendicular to the wellbore; however,
`other angles are possible, including fractures that are parallel to
`the wellbore axis. The annulus is pressurized to a level close to
`the fracturing pressure, and the jetting tool is generally pressured
`at a 4,000- to 5,000-psi differential pressure. These combined
`pressures allow large hydraulic fractures to develop while the
`acid etches the fracture surface.
`A new process, used here for the first time, is a variation of
`the hydrajet fracturing technique. This process involves squeez-
`ing acid using a jetting tool (shown in Fig. 4) or a slowly rotating
`hydrablast tool (Fig. 6). During this process, the annulus is
`subjected to a pressure higher than the formation pore pressure
`(pressure gradient of approximately 0.5 psi/ft) while acid is
`jetted at a relatively high pressure. Because this annular pressure
`is well below the fracture gradient, hydraulic fractures may or
`may not be created unless the distance between the jets and the
`wellbore wall approaches zero.
`
`Treatment Success
`Successful well treatments depend on identifying the causes of
`the production deficiency for the specific well to be treated.
`Descriptions of various production deficiencies and treatment
`options follow:
`• Debris. If the production problem is caused by debris
`plugging along the wellbore, the well can be cleaned with an
`effective hydrablasting and cleaning service. This service
`addresses the problems associated with cleaning sand and
`debris from large-diameter, deviated, or horizontal wellbores.
`Using CT with standard industry practices can yield poor
`results. This service combines design software, specialized
`fluid systems, and a wash tool designed for the different
`mechanics associated with deviated and horizontal wells.
`Filter Cake and/or Near-Wellbore Damage. If near-
`wellbore damage is causing the production deficiency, an
`acid wash might be the best solution.
`
`•
`
`Page 3 of 13
`
`

`

`4
`
`SUCCESSFUL HYDRAJET ACID SQUEEZE AND MULTIFRACTURE ACID TREATMENTS
`IN HORIZONTAL OPEN HOLES USING DYNAMIC DIVERSION PROCESS AND DOWNHOLE MIXING
`
`SPE 71692
`
`• Deep Damage Close to the Wellbore. If deep damage close
`to the wellbore is decreasing production, an operator can place
`several small fractures to bypass the damage. This option may
`also be applicable for near-wellbore damage because small
`fractures increase the effective wellbore diameter.
`• Wellbore Location. If the wellbore is located in a poorly
`producing zone in the reservoir some distance from a better
`interval in the reservoir, or if a vertical permeability barrier
`exists, the operator may need to create larger fractures that
`can communicate the wellbore with more productive zones.
`Low Formation Permeability. If the average permeability
`of the formation is too low to produce at commercial levels,
`placing numerous hydraulic fractures (proppant fractures or
`fracture acidized) is the only viable method for effective
`production stimulation.
`
`•
`
`Of course, successful treatments must improve production
`at the lowest possible cost. Therefore, engineers must consider
`economics (cost/benefit ratio) when choosing a production-
`enhancement solution.
`
`Case Histories
`Formation Properties. The formation properties of the wells
`stimulated in these case histories differ. The area of the forma-
`tion containing Wells C and D has higher porosity and less
`fracturing than the rest of the wells. In these wells, fracturing
`exists in a number of selectable areas of the wellbore, and,
`consequently, the hydrajet fracturing technique was used to
`concentrate on these specific areas. Wells A, B, E, F, and G are
`located in an area of the formation that has lower porosity, lower
`effective permeability, and fracturing throughout the wellbore.
`This necessitated a stimulation procedure that would not concen-
`trate on specific areas of the wellbore but would still use the
`effective downhole mixing and high-pressure jetting associated
`with the hydrajet stimulation system.
`
`General Procedures. The general procedure for stimulating
`newly completed wells in this area involves using N2, which
`lightens the hydrostatic column, to unload the drilling fluids
`from the wellbore. The well is then allowed to flow until it
`achieves a semi-stabilized, prestimulation rate and pressure.
`Next, several acid washes are performed with the hydrajet tool
`while the well is flowing to flare. This process removes excess
`filter cake or superficial drilling damage in the wellbore. The
`well is flowed again, allowing operators to determine the effec-
`tiveness of the wash. Finally, a hydrajet squeeze stimulation is
`performed over the entire openhole section. Acid containing
`inhibitors and foaming agents is pumped though the CT at high
`rates, and CO2 is pumped down the annulus. The well is then
`unloaded and allowed to flow until cleanup and an evaluation of
`the effectiveness of the stimulation treatment are completed.
`
`After the wash was performed in Well A, the operator
`decided that a squeeze was not necessary. However, Well A may
`have achieved a significantly higher production rate if it had been
`subjected to a hydrajet squeeze stimulation.
`Table 1 presents a summary of the case histories. This table
`shows the treatments and general stimulation results.
`
`Overview of Well Treatments. Conventional acid washes were
`performed in the first and second wells (Wells A and B), but the
`second well (Well B) was also squeezed with acid. Well C was
`hydrajet fracture-acidized through coiled tubing in an attempt to
`place several small fractures along the open hole. The fourth well
`was also hydrajet fracture-acidized through CT, but downhole
`mixing procedures used during this treatment provided in-situ
`generation of carbon dioxide (CO2) foam. Fewer yet larger frac-
`tures were placed in this well. A slowly rotating jetting tool was
`used to treat the fifth well, while a simple, high-pressure drop
`nozzle was used to simultaneously mix acid with CO2 and N2
`downhole in the sixth and seventh. Achieving sufficient bottomhole
`and tubing pressures may have allowed the creation of many small,
`near-wellbore fractures in these wells. (Detailed job information
`for each of these seven wells is provided later in this section).
`
`Well A. Well A, an openhole horizontal well, is the best potential
`producer well within the case-study group. It is approximately
`12,500 ft deep and includes a horizontal openhole section
`extending approximately 2,200 ft. Production from Well A
`before the stimulation treatment was 10.6 Mmscfd at a pressure
`of 2,175 psi. The reservoir pressure is approximately 4,500 psig,
`and porosity is approximately 5%.
`Before the hydrajet stimulation technique was invented,
`operators performed simple acid washes to improve production.
`The treatment consisted of 13,000 gal of 15% HCl. After three
`such treatment passes, production increased to 25 Mmcfd at a
`pressure of 2,500 psi (Fig. 7). This increase, when normalized
`with Fetkovich’s backpressure correction equation12 equates to
`an increase of 253%.
`
`Well B. Well B is also a horizontal well with a depth similar to
`that of Well A and a horizontal openhole section extending
`approximately 2,200 ft. Initial production from this well was 2.5
`Mmscfd at a pressure of 360 psi with a reservoir pressure of
`approximately 4,650 psi and a porosity of 5%.
`The operator performed a conventional acid wash/squeeze
`with two passes of an acid wash consisting of 8,300 gal of 15%
`HCl. Production increased to 3.3 Mmscfd (a 32% increase). A
`second treatment was performed with an additional 13,500 gal of
`15% HCl foamed with nitrogen and squeezed into the matrix in
`two passes. This treatment increased production an additional
`156% to 8.47 Mmscfd. However, over a 30-day period, the
`production decreased to 3.7 Mmscfd, indicating that the treat-
`ments did not reach the natural fracture network and that larger
`fractures might be necessary.
`
`Page 4 of 13
`
`

`

`SPE 71692
`
`M.J. REES, A. KHALLAD, A. CHENG, K.A. RISPLER, J.B. SURJAATMADJA, B.W. MCDANIEL
`
`5
`
`Well C. Well C is a horizontal open hole that is approximately
`11,069 ft deep. The 6.25-in. open hole extends approximately
`2,560 ft to a measured depth (MD) of 14,468 ft. The reservoir
`pressure is approximately 3,045 psi.
`Initial production from Well C was approximately 1.5
`Mmscfd. During early discussions, engineers determined that
`the well had near-wellbore damage and that no major fractures
`were necessary. A hydrajet fracturing process was performed
`through 1.75-in. CT. The tip of the CT was fitted with a 2-in. OD
`jetting tool with three 0.142-in. jets (Fig. 3).
`The treatment fluid consisted of 28% gelled HCl containing
`corrosion inhibitors, iron-control chemicals, and chemicals for
`controlling sulfide cracking. Water containing surfactants and
`friction reducers was used for the annular fluid. The treatment
`was designed to place 35 fractures at an average spacing of 15 ft
`in a concentrated area at a depth of 13,910 to 14,468 ft. The total
`volume of acid used was 49,000 gal. Fig. 8 shows a partial
`treatment chart.
`After this treatment, the well responded positively, produc-
`ing approximately 9 Mmscfd. However, soon afterwards, pro-
`duction declined rapidly until reaching the well’s original flow
`rate. Eventually, the well was shut down. This response indicates
`that the damage bypass was successful but that the treatment
`procedure was not selected correctly. Larger fractures may have
`been necessary for reaching farther into the formation.
`
`Well D. Well D, also an openhole horizontal well, was treated
`with the hydrajet fracturing process. The well is 10,850 to 13,350
`ft deep, and 3.5-in. production casing is installed to this depth. A
`6.25-in. open hole extends approximately 4,600 ft to measured
`depth of 15,450 ft. The reservoir pressure is approximately
`3,335 psi.
`Initial production from Well D was approximately 0.83
`Mmscfd. Engineers determined that a natural fracture network
`located far away from the wellbore need to be reached, necessi-
`tating major fractures. Hydrajet fracturing was performed through
`1.75-in. CT fitted with a 2-in. OD jetting tool with three 0.142-
`in. jets (Fig. 3).
`As with the previous job, the tubing fluid consisted of gelled
`28% HCl acid with corrosion inhibitors, iron-control chemicals,
`and chemicals for controlling sulfide cracking. Surfactants and
`friction reducers were also added. Unlike the previous hydrajet
`process treatments, the mixing capability of the hydrajet fractur-
`ing process was used to generate CO2 foam. Downhole foam
`generation enhanced diversion and limited fluid loss, allowing
`larger fractures to be generated. Only three fractures were placed
`(at depths of 12,598, 12,112, and 11,719 ft). Approximately
`15,300 gal of acid was used during this treatment: 5,400 gal were
`spent at the initial fracture, 6,869 gal were spent at the second
`fracture, and 3,038 gal were spent at the third fracture. The
`treatment chart is shown in Fig. 9.
`
`As shown in Fig. 9, the behaviors of the annular pressure and
`the tubing pressure were almost opposite. In each treatment stage,
`the tubing pressure decreased almost every time the annulus
`pressure increased, indicating active fracture extension. The tub-
`ing pressure increased rapidly as the annulus pressure decreased.
`Fig. 9 demonstrates that the hydrajet fracturing technique
`can be used effectively to force a tip screenout from the surface
`(annulus pressure). Fig. 10 is a dramatization of this unusual
`phenomenon. In this figure, the effects of parameters, such as
`fluid friction, pump fluctuation, and density fluctuation, have
`been ignored. When the annulus pressure is increased but the
`tubing flow rate remains constant, the tubing pressure increases
`accordingly. Immediately after the fracture initiates, the downhole
`annulus pressure drops, and increases in the annulus pressure
`(which are typically low) only combat friction losses. When this
`action is reversed, annular pressure (flow) is reversed, the
`fracture stops growing, and tubing pressure increases. Increasing
`annular flow will restart fracture