SPE 114172
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`Stimulating Unconventional Reservoirs: Lessons Learned, Successful
`Practices, Areas for Improvement
`David D.Cramer, ConocoPhillips
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`Copyright 2008, Society of Petroleum Engineers
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`This paper was prepared for presentation at the 2008 SPE Unconventional Reservoirs Conference held in Keystone, Colorado, U.S.A., 10–12 February 2008.
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`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
`The term “unconventional reservoir” has different meanings to different people. Certain reservoirs termed unconventional
`have a rock matrix consisting of inter-particle pore networks with very small pore connections imparting very poor fluid-flow
`characteristics. Abundant volumes of oil or gas can be stored in these rocks, and often the rock is high in organic content and
`the source of the hydrocarbon. Yet because of marginal rock matrix quality, these reservoirs generally require both natural
`and induced fracture networks to enable economic recovery of the hydrocarbon. Rock types in this class include shale and
`coalbed methane (CBM.) The term shale is a catchall for any rock consisting of extremely small framework particles with
`minute pores charged with hydrocarbon and includes carbonate and quartz-rich rocks. Another type of unconventional
`reservoir is stacked pay units exhibiting somewhat better pore characteristics than in the case outlined above but with the
`individual units tending to be lenticular in shape and having an extremely small size or volume. These two classes of
`unconventional reservoirs are amenable to well stimulation and will be the focus of this paper.
`
`The above rock types when commercially exploited are known as resource plays. Once a low-priority, the depletion of
`conventional reservoirs and improving price for oil and gas has driven unconventional reservoirs to an important place in the
`oil and gas industry. In some regions (i.e., Rocky Mountain province), unconventional reservoirs represent the primary target
`of current activity and remaining hydrocarbon development. Given their unique petrophysical properties, each type of
`unconventional reservoir requires a unique approach to well stimulation, with often differing objectives than exist with
`conventional reservoir types. This paper reviews the characteristics of the basic unconventional reservoir types, lessons
`learned and successful stimulation practices developed in completing these reservoirs, and areas for improvement in
`treatment and reservoir characterization and treatment design.
`
`Introduction
`Unconventional reservoirs amenable to hydraulic fracturing are generally hydrocarbon-rich rocks with poor matrix
`characteristics. By matrix is meant the inter-particle pore network of the rock mass, with pore connections determining the
`rate of fluid flow from pore to pore or from pore to large flow channel (i.e., solution mold, fracture, or wellbore.) In
`unconventional reservoirs, pore interconnections are extremely small, significantly reduced in aperture by the liquid wetting-
`phase, and consequently fluid flow is extremely low. In the case of oil or gas-condensate reservoirs, low mobility of the
`viscous liquid phase and multi-phase flow worsens the situation. Sometimes, a change in reservoir fluid mobility within the
`accumulation causes a loss of commerciality and bounds the limits of the pay within the field. This is the case in the in the
`Codell sandstone (Wattenberg field, DJ Basin, northeast Colorado) as the thermally-influenced in-situ hydrocarbon phase
`changes from gas to oil along the boundaries of the field. A dense network of natural fractures or a combination of fractures
`and solution channels with adequate apertures are generally needed to enable flow of hydrocarbons at commercial rates, and
`drainage of the reservoir to a significant degree. Even with an improved pricing environment, the marginal flow properties
`and recovery factors of most unconventional reservoirs make necessary a continuous effort to reduce costs and improve
`efficiencies in all aspects of drilling, completing and producing these wells. Many of the recent improvements and
`innovations in well completions and hydraulic fracturing have been focused as much on the cost aspect as with improving
`well productivity.
`
`Othar Kiel was one of the first to recognize that unconventional reservoirs may require unconventional fracture stimulation
`methods.1 He patented the technology of using shut in, flow back, bridging/ spalling steps in massive stimulation treatments
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`to widen the zone of stimulation beyond a simple, single-plane trajectory. He proposed using very fine mesh sand (100 mesh
`sand) and trying to design for “partial monolayer” proppant placement/ distribution where open gaps exist between proppant/
`formation-spall grains or clusters. Versions of his visionary concepts are being applied today.
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`In unconventional reservoirs, there is an experimental, empirical quality to fracture design selection and optimization. It is
`very difficult to model or simulate the permeable flow network and fracture propagation patterns with naturally fractured
`reservoirs, especially with the popular horizontal completion method. This difficulty has helped popularize the use of
`fracture mapping services such as surface and downhole tilt and downhole microseismic measurement and interpretation.
`
`Understanding the Nature of Natural Fracture Networks is Critical
`Unconventional reservoirs exhibit different types of natural fracture systems. In one type, the fractures are open and
`conductive, but exist in long, narrow closely-spaced directional swarms, trending along the flanks of anticlinal or fault-
`related structural rock deformation. The Bakken formation in west central North Dakota is an example of this type of
`system.2 These relatively high conductivity fracture swarms dictate reservoir drainage area and overall flow.3 When these
`directional swarms impart high permeability anisotropy, hydraulic fracture length requirements are very minimal and long
`propped fractures are probably wasteful at best (see Figure 1.)4 Another type of system is where the rock is extensively and
`uniformly fractured, yet the fractures have very small apertures and are nearly completely mineralized (e.g., Barnett shale
`model.)5 A third system is characteristic of coalbed methane (CBM) reservoirs, in which a fracture or cleat system exists with
`continuous, often high permeability face cleats (often normal to the current minimum principal stress) and discontinuous butt
`cleats at a sharp angle to the face cleats.6,7 Each system requires a different well completion and treatment strategy.
`
`Multiple fracture propagation is a detriment to treatment results in conventional reservoirs with “single plane” geometry. It
`compromises fracture length and fosters proppant bridging at hydraulic fracture/ natural fracture nodes and loss of energy at
`the fracture tip.8,9 However, in unconventional reservoirs with poor matrix quality, multiple fracture propagation is often the
`desired outcome. A widespread zone of fracturing can enhance drainage of the reservoir by creating permeability channels at
`a wide band trending in the direction of maximum principal horizontal stress.5 The log-log plot of producing rate (or
`reciprocal productivity index) vs time often shows a long term linear trend (see Figure 2) – evidence that flow is dominated a
`anisotropic fracture-enhanced zone in the near proximity of a primary fracture trend.10 To achieve length away from the
`wellbore, a massive volume of fluid must be pumped to compensate for the low fluid efficiency of the high leakoff fluid.
`
`In the Barnett Shale model, healed fractures are believed to “reactivate” during the fracture treatment.5 These fractures are at
`nearly right angles to the current day maximum horizontal stress (hydraulic fracture) azimuth and low-viscosity slick water
`can invade and widen the zone of stimulation away from a single fracture plane, with slip or shear events occuring along
`these fracture surfaces (as evinced by reflected microseisms observed in fracture mapping operations.)11-13 The shearing
`action can result in permanent misalignment and residual permeability (see Figure 3) and is also believed to be a factor in the
`success of dynamic cavitation efforts in CBM wells.14 The physics of this model requires a small contrast in the minimum
`and maximum principal horizontal stresses and reorientation of the in-situ stress field over geologic time (from time of the
`creation of the natural fracture network to current time.) The stimulation benefit is perhaps a combination of shear enhanced
`formation permeability (along a pre-existing mostly healed natural fracture network) and a limited number of propped
`fractures acting as a trunk-line into which the shear-enhanced permeability channels feed into. So in addition to the
`conventional fracture stimulation benefit of wellbore extension (the propped fracture component), reservoir permeability (and
`thus the reservoir itself) is enhanced or created by shear displacement of fluid-invaded natural fracture systems.
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`Lessons Learned and Successful Practices
`Well Design
`In exploiting unconventional reservoirs, it is generally advantageous to achieve extensive wellbore exposure using the
`minimum number of wells or surface locations. With some exceptions (most notably in the Fairway area of the Fruitland
`Coal play15 in the San Juan Basin), wells completed in unconventional reservoirs are marginally productive and continuous
`improvement in drilling and completion efficiencies (to reduce the unit cost of hydrocarbon recovered) are necessary to
`expand develop in these reservoirs.
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`Horizontal wells usually offer the best way to achieve efficiency in laterally and vertically-continuous reservoirs, in which
`discreet layers are not separated by fracture height barriers (e.g., shale gas16), or in reservoirs dominated by fracture swarms
`(e.g., Bakken play in west-central North Dakota.) In these venues, much of the technological innovation and experimentation
`has been with treatment staging and diversion methods. Fracture mapping methods, such as downhole microseismic and
`surface and downhole tiltmeter, have been very useful for assessing the impact and effectiveness of the various
`methodologies. Generally, drilling in the direction normal to maximum principal stress maximizes access to fracture
`networks directly or when transverse-trending hydraulic fractures intersect and penetrate a cross-cutting set of sealed
`fractures (e.g., Barnett Shale model.) In cases in which the natural fracture network is deemed of secondary importance to
`productivity (for example, the middle Bakken play in the Elm Coulee field, Richland County, MT), drilling the well in the
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`direction of maximum principle stress may be preferred in order to favor the creation of longitudinally-trending hydraulic
`fractures. Longitudinal fractures reduce radial convergence by maximizing exposure of the wellbore to the hydraulically-
`created fracture and usually eliminate the need for high-conductivity proppants.
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`Horizontal wells are completed with various degrees of annular isolation. Uncemented annulus or open-hole completions
`offer open access to fracture swarms, which may be plugged off and inaccessible if annulus is cemented. In the uncemented
`case, the most productive part of interval has a better chance to be stimulated or at least be open to production. Also,
`uncemented completions avoid perforation-related stress cages and restricted flow along the cement/ annulus perimeter until
`the fracture plane is encountered. This extraneous source of treating pressure drop can be very excessive, especially when
`large horizontal stress anisotropy exists. The source of the excess treating pressure was evaluated by Warpinski in fracture-
`injection experiments at the Nevada test site to evaluate the effectiveness of shaped-charge perforations.17-18 Excess pressure
`drop was not observed in open-hole horizontal wells, and various degrees of drop were observed in the cased and cemented
`horizontal wells. Using more powerful shaped perforation charges resulted in higher treatment pressure. Mining back along
`the perforations showed that fractures (traced by dye) avoided the perforation tunnels entirely due to the altered, compressed
`rock created by the punching action of the high velocity jet charges.
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`Cased and cemented horizontal well completions offer greater control over fracture treatment placement and can be
`appropriate when dealing with relatively uniform rock in which localized natural fractures minimally enhance reservoir flow
`capacity. Another advantageous case may be the Barnett Shale model, in which the natural fracture system is at a high angle
`to the preferred fracture azimuth (i.e., maximum horizontal stress) and transverse-oriented hydraulic fractures readily connect
`into the natural fracture network. In horizontal wells in which cemented completions are warranted or desired, sand jet
`perforating is sometimes preferred. It removes formation material and thus avoids creating or worsening the stress cage
`around the perforation tunnel and wellbore. Placing acid soluble cement in the annulus adjacent to the perforation interval
`and then subsequently dissolving it with hydrochloric acid has also been effective at mitigating near-wellbore restriction in
`cemented horizontal wells.19
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`Discontinuous, multilayer intervals such as stacked, fluvial-dominated sandstones are best completed with vertical wells
`(through the pay section) in multistage treatments. The individual lenticular reservoirs have drainage areas sometimes
`averaging 10 acres or less, and high well density is needed to effectively exploit the resource. Pad locations, in which
`multiple S-shaped wells (sometimes as many as 32 per site) are drilled in simultaneous drilling, completing and producing
`operations (Simops), serve to minimize surface disruption and maximize efficiency in frac-factory type operations.
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`Treatment Staging and Diversion Methods
`Much of the intellectual focus and innovation in unconventional reservoir exploitation has been applied in developing
`techniques and equipment to maximize treatment coverage with minimal downhole intervention. Some methods and tools
`are specific to horizontal wells or vertical wells and some apply to both. Some have been used for over 40 years and others
`are relatively new.
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`Primary Application: Vertical Wells
`Introduced in 1961, limited entry perforating and mechanical-plug treatment diversion and stage isolation is a time-honored
`method20 and well suited for multi-zone vertical well completions. Using the choke-like characteristics of shaped-charge or
`bullet created perforations, treatment injection rate is adjusted to build a desired level of excess pressure in the casing,
`enabling diversion from lower-stressed to higher-stressed zones.21 Over the years, the physics of limited entry treatments
`have been studied (e.g., perforation erosion22) and various guidelines have been developed, regarding parameters such as
`minimum perforation friction, maximum gross interval length per treatment and the like, for improving stimulation coverage
`of multiple zones. Perforation breakdown may be the most important determinant of limited entry treatment success. Figure
`4 shows the results of tracer surveys comparing near-wellbore proppant placement of various treatment stages in a well in the
`Williams Fork formation, Piceance Basin.23 Less than 2/3 of the perforated intervals were treated in Stage 1, in which
`perforation breakdown methods were not used. In Stage 3, a pre-frac ball-out treatment improved zonal coverage but the
`lowest two intervals were left untreated. In Stage 2, all zones were propped as each interval was separately isolated and
`broken down. Fracturing and breaking down each zone is not practical in everyday operations, so alternate breakdown
`methods are used. In one method, the lowest zone is selectively perforated and broken down with borehole fluid, usually
`water. Then, the remaining intervals are perforated, the perforating gun is removed from the well and 250 to 1000 gallons of
`hydrochloric acid are spearheaded as the first stage of the fracturing treatment. Injection invariably occurs in the broken-
`down perforation set, allowing the acid to wash across, penetrate and break down the uphole perforations. This method is
`effective without ball sealers, but dissolvable ball sealers have been developed to assist in formation breakdown in lieu of or
`to augment this technique.24 Flow-through composite bridge plugs have also served to advance the limited entry process.25
`These plugs are used to isolate treatment stages and enable continuous load fluid recovery from all previously-treated
`intervals during any flowback and pre-cleanout production period.
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`Introduced in 1965, the ball and baffle-ring diversion method is still widely applied.20 It is based on dropping a drillable ball
`at the end of a treatment stage. The ball seats in a baffle ring which is inserted in a casing collar above the active
`perforations, isolating the hole from that point downward. Holding pressure on the well to keep the ball in place, perforations
`are shot in uphole interval(s), which are then treated. This process is limited to about 4 treatment stages because of the need
`for progressive changes in the ball and baffle-ring sizes.
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`Stress-induced diversion uses the increased compressive in-situ stress imparted by residual hydraulic fracture aperture of a
`previously-treated interval to divert a new treatment to an interval sufficiently spaced away from the stress window.
`Mechanical isolation plugs are not used. The physics of this process was described by Warpinski and Branagan.26 This was a
`common technique in many tight gas vertical well completions27 and has been used lately as a component in horizontal well
`completions.
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` novel staging method applied recently in multi-zone completions is Just In Time Perforating (JITP.) In this process, a
`wireline–conveyed perforating gun remains in the well during fracture stimulation to sequentially perforate individual zones.
`Buoyant ball sealers are dropped at the end of treatment stages to isolate (ball off) treatment zones. As the ball sealers bridge
`on the active perforations, new perforations are fired in an adjacent uphole zone, into which the subsequent treatment is
`immediately performed. This sequence is repeated until the capacity of the perforating gun (which is limited by the height of
`the gun lubricator) has been reached.28 With JITP, up to 11 zones have been treated per gun run, up to 22 individual frac jobs
`have been done in a day, and over 50 treatments have been done per well. This process is very amenable to multiple-well pad
`locations, in which activity can switch from well to well after a gun run is complete, improving efficiency. Figures 5-7 show
`data from a JITP project in the Mesaverde formation, Piceance Basin, Colorado. Five wells were treated from the same
`location in 253 separate treatment stages over a 17-day period.29 JITP offers the potential to select-treat individual zones
`rapidly and economically. To date, it has been performed on over 80 wells in more than 2700 separate treatment stages.
`
`Another recently applied method for selective multiple-zone stimulation is annular coiled tubing (ACT) fracturing. Sand-jet
`perforating is performed via a coiled tubing string, and the fracturing treatments are conducted down the casing/ coiled tubing
`annulus. Sand plugs are normally used for stage isolation (mechanical plugs have been used but this process is restricted due
`to patent protection.)30 ACT has been applied in many CBM reservoirs and the unconventional diatomite oil play in
`California, in which it outperformed limited entry and mechanical plug methods.31 In that application, up to 18 separate ACT
`fracturing stages were done per well, covering over 1000 feet of net pay.
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`Casing conveyed perforating has been used with isolation valves in cemented horizontal and vertical wells to enable
`continuous operation in multiple treatment stage applications.32 Guns and sliding sleeve-operated flapper valves are
`hydraulically actuated on commend from the surface in this patented process. It has been used most recently in non core-area
`Barnett Shale horizontal well applications in which lower injection rate treatments were designed to avoid fracture growth
`into the water-productive Ellenberger formation. Up to 28 individual treatment stages per well have been done using this
`method.
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` related technology for cemented wells is a casing-conveyed system featuring a dart-actuated sliding-sleeve mechanism to
`gain access to multiple pay intervals in continuous treatment operations.33 The opened sleeve exposes ports to the cement
`sheath, yet in the lab and field, formation breakdown has been shown to occur at minimal pressure without the need to
`perforate. The number of treatments stages is limited only by component cost and post-treatment cleanout considerations and
`has currently been limited to vertical well applications.
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`Primary Application: Horizontal Wells
` Extensively used in horizontal wells configured with an uncemented annulus, external casing packers have been used to
`segment the well into smaller sections for selective stimulation in a continuous operation. The packers can be of various
`types, including mechanical, swellable34 and inflatable. Within the casing string and between packers, ball or dart-actuated
`sliding sleeves are inserted as dual opening and shut-off devices.35 Treatment stages are limited to about 10 by the ever
`changing ball size requirements to sequentially activate the sliding sleeves.
`
`Another widely-used technique for stimulating horizontal wells with an uncemented annulus, annular friction pressure has
`been used in combination with ball sealers and sand slugs for treatment diversion inside and outside of the treating string. Its
`effectiveness has been documented in the middle Bakken play in Richland County, Montana and is especially suited for cases
`in which the toe section of the well treats preferencially.36 The annular clearance between liner/casing and drilled hole needs
`to be minimized to take full advantage of this tactic. Figure 8 is a graph of friction pressure vs rate for various annular
`configurations showing the impact of reducing the annular clearance on pressure drop and diversion capability.
`
`Flexible sand plugs have been developed for stage diversion.37 Deformable and conventional proppants are mixed together at
`a specific ratio, added to fracturing fluid at a high concentration (14 lb/gal of fluid) and pumped at the end of a treatment
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`stage to fill across and uphole of the stimulated zone. With sufficient plug length, the flexible plug is very resistant to
`displacement, possessing a yield pressure in the range of 9000 psi. After all treatments are complete, the plugs are easily
`circulated from the well using a vortex nozzle. This application has been combined with coiled tubing deployed sand-jet
`perforating in cased and cemented horizontal well completions.
`
` method developed for multiple-stage stimulation in open-hole horizontal wells uses the Venturi effect of a high velocity
`fluid jet focused on a specific point at the wellbore to favor hydraulic fracture propagation at that point.38 The jetting fluid is
`normally conveyed by a coiled tubing string. The fracturing fluid is pumped down the open-hole/ coiled tubing annulus.
`This method is most likely to be effective when horizontal stress anisotropy is absent or very low.
`
`Other iterations and combinations of the above technologies have been used effectively. An example is pumping down
`perforating guns and bridge plugs with gelled water in multiple-stage fracture stimulation of uncemented horizontal wells.
`This technique has been used in combination with external casing packers in the Bakken play in North Dakota.
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`Fluid and Proppant Design
`Reservoir properties are important in selecting the best fracturing method. In shales, coals, and many tight gas sand intervals,
`natural fractures/ fissures/ cleats are the dominant flow conduits for liquids and gases. These rocks are characterized by very
`low leak off to the matrix. Because of the fissures, pressure dependent permeability and leak-off are often encountered
`during fracturing treatments. Fracturing fluid viscosity has a dominant influence on the leak-off to these pressure-sensitive
`fissures – low viscosity enhances and high viscosity diminishes the leak-off. Leak off enhances the potential for a wide zone
`of stimulation, including enhanced permeability due to shearing movements along the invaded fissure surfaces but increases
`the risk of proppant bridging at the fissure / hydraulic fracture nodes or intersections.8,39
`
`Water is used as a base fluid in most unconventional reservoir treatments. Water is economical and can be re-used,
`especially if chemical quality control standards are broad, as in waterfrac applications (i.e., non-gelled, non-viscosified
`water). Unconventional reservoir rock is usually chemically un-reactive to water as pore throats are too small to accept much
`fluid and the majority of flow and leak off occurs to fractures. Mobile or swelling clay minerals are not usually a component
`of fracture-fill material (or of matrix pore-wall linings.) Water becomes an issue when its physical properties, high density
`and capillary pressure gradient in small pore networks, render it immobile in low energy systems.
`
`With several notable exceptions, there has been a strong trend to using waterfrac or slick water as the primary fracturing fluid
`in treating unconventional reservoirs.40 Plain or slick water mitigates the plugging of fractures from gel residue. Water leaks
`off easily to fracture networks to widen the zone of stimulation by inducing shear fracture enhancement of marginal or
`cemented natural fracture networks. Proppant is important to stimulation results41 by extending the effective wellbore radius
`and serves this purpose by propping open at least the main part or “trunk” of the hydraulic fracture system. Proppant settles
`rapidly in waterfrac systems, forming a proppant bed along the bottom of the fracture; an equilibrium bed height is quickly
`established, then proppant is transported along the top of the bed toward its terminus. Within the bed, propped width is equal
`to the pumping width achieved during the pad stage of the treatment, resulting in a conductive multi-layer proppant pack.
`Perhaps more importantly, a highly conductive, open channel (an unpropped wedge) can persist along the top of the settled
`bed.9,42 The waterfrac/ sand bank method is particularly effective in small drainage area fluvial reservoirs with limited
`downward fracture height growth, as exist in the Piceance Basin Williams Fork formation.
`
`In the unpropped wedge scenario, fine-mesh proppants can produce similar and sometimes better results as compared to
`commonly-used 20/40 mesh proppant since smaller proppant particles have less tendency to bridge and pack off in the
`fracture. In fact, 40/70 mesh has been a preferred proppant type in stimulating the Barnett Shale and many other
`unconventional reservoirs. The properties of an unpropped wedge are likely to be insensitive to the material characteristics of
`the proppant. Consequently, wells treated with non API-spec proppants may produce similarly to wells treated with standard
`proppants. If the unpropped wedge mechanism is validated in a particular application, formerly substandard sources of
`proppant could be approved for use, reducing demand on the limited supply of high quality 20/40 and 40/70 mesh sand.
`
`Proppant-induced pressure increases (PIPI) and total treatment screenouts are generally undesirable in unconventional
`reservoir treatments. Most PIPIs are the result of proppant bridging near the wellbore.39 When near-wellbore bridging
`happens, the ability to propagate and extend fracture growth far away from the wellbore is lost. Also, the proppant bridging
`may eliminate the potential for sustaining a high-conductivity open channel at the top of a settled proppant bed. An
`exception to this rule is the intentional use of high-concentration proppant slugs to induce diversion at the end of treatment
`stages in uncemented horizontal well treatments.
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`Although there is some concern in regard to the molecular weight characteristics of polyacrylamide (PA) friction reducers
`used in slick water applications, they are generally used at very low concentrations, sometimes as little as 0.25 gal/1000 gal
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`of water. Recently, delayed gel-breaking additives have been used that degrade PA without effecting friction reduction
`properties.
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`Over-pressured or higher-energy reservoirs usually have the potential for high sustained post-treatment flow rates. High and
`controlled flow rate facilitates fracture fluid clean-up and the use of breaker-laden high-viscosity crosslinked fluids if
`warranted.43 Under-pressured reservoirs are more prone to clean-up issues, especially with high gelant loading fracturing
`fluids, and often respond better to gas-assist, foam, slick water (low viscosity) and oil. In cases of ultra-low reservoir
`pressure, all-gas treatments have been effective, such as the CO2 dry frac process44, N2 coiled tubing fracturing treatments in
`the Horseshoe Canyon CBM45-46 and Devonian Shale plays.
`
` blend of the above methods that has been widely used is the hybrid treatment method, using a low-viscosity water pre-pad
`to create fracture area, then a viscous crosslinked gel to transport and place proppant.47 The benefits of extensive stimulation
`of fracture systems are combined with superior proppant placement, especially vertically, in the “trunk” fracture(s) exhibiting
`sufficient width to accept proppant.
`
`One-hundred mesh sand is used as a scouring agent, proppant and limiter of fluid loss to crossed fissures. Being extremely
`fine, it can abrade and enlarge narrow flow-path restrictions as exist in the annulus of the cement sheath and drilled hole, and
`may be able to penetrate fracture branches and resist fracture rehealing. As a bridging agent at hydraulic fracture/ fissure
`nodes or intersections, 100 mesh sand enables the propagation of additional primary hydraulic fracture length and minimizes
`the potential for proppant bridging at hydraulic fracture / cross-fissure nodes.48-49
`
`Ultra-lightweight proppant (ULWP) has been widely used in conjunction with waterfracs.50-51 ULWPs possess grain density
`as low as 1.05 specific gravity, providing minimal density contrast to fresh water and near-neutral buoyancy when light
`brines are used as the fracturing fluid. Because of the small density contrast between the proppant and carrying fluid, grains
`of ULWP proppant settle slowly and can be transported farther into the vertical and lateral extremities of the hydraulic
`fractures. Although relatively expensive, ULWP is usually used in low, dispersed concentrations, with the intension of
`creating partial monolayer-like proppant placement, in which open channels exist in the fracture around clusters or individual
`grains of the ULWP. ULWPs are somewhat deformable and resist embedment into the fracture faces, but are prone to
`excessive flattening at hig