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SPE 114173 Stimulating Unconventional Reservoirs: Maximizing Network Growth while Optimizing Fracture Conductivity N.R. Warpinski, SPE, M.J. Mayerhofer, SPE, Pinnacle Technologies; M.C. Vincent, SPE, Carbo Ceramics; C.L. Cipolla, SPE, and E.P. Lolon, SPE, Pinnacle Technologies Copyright 2008, Society of Petroleum Engineers This paper was prepared for presentation at the 2008 SPE Unconventional Reservoirs Conference held in Keystone, Colorado, U.S.A., 10–12 February 2008. 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 Unconventional reservoirs such as gas shales and tight gas sands require technology-based solutions for optimum development. The successful exploitation of these reservoirs has relied on some combination of horizontal drilling, multi- stage completions, innovative fracturing, and fracture mapping to engineer economic completions. However, the requirements for economic production all hinge on the matrix permeability of these reservoirs, supplemented by the conductivity that can be generated in hydraulic fractures and network fracture systems. Simulations demonstrate that ultra- low shale permeabilities require an interconnected fracture network of moderate conductivity with a relatively small spacing between fractures to obtain reasonable recovery factors. Microseismic mapping demonstrates that such networks are achievable and the subsequent production from these reservoirs support both the modeling and the mapping. Tight gas sands, having orders of magnitude greater permeability than the gas shales, may be successfully depleted without inducing complex fracture networks, but other issues of damage and zonal coverage complicate recovery in these reservoirs. As with the shales, mapping has proved itself to be valuable in assessing the fracturing results. Introduction Unconventional reservoirs provide a significant fraction of gas production in North America and increasing amounts in some other regions of the world. Such reservoirs include tight gas sands, coalbed methane (CBM), and gas shales; in 2006 these reservoirs provided 43% of the US production of natural gas (Kuuskra 1 ). Because of their limited permeability, which is foremost among many other complexities, some type of stimulation process (and/or dewatering in the case of CBM) is required to engender economic recovery from wells drilled into these formations. The focus of this paper is on gas shales, with particular emphasis on how these reservoirs perform relative to tight gas sands. The important role of natural fractures in both the stimulation and production processes, the importance of conductivity in the developed fracture or fracture system, and the critical influence of the matrix permeability are investigated using both mapping and modeling results. Gas shales, such as the Barnett, Fayettville, and Woodford in North America, are relatively recent plays, but gas production from shales has occurred since the early 1900’s from the Devonian shales of eastern North America and more recently from the Antrim shale and others. These shales 2 typically contain a relatively high total organic content (e.g., the Barnett has a total organic content of 4-5%) and are apparently the source rock as well as the reservoir. The gas is stored in the limited pore space of these rocks (a few per cent, including both matrix and natural fractures) and a sizable fraction of the gas in place may be adsorbed on the organic material. Matrix permeabilities of these shales are extremely difficult to measure because they are so low, but various approaches to determine their value have yielded permeabilities on the order of 1-100 nanodarcies. Clearly, economic production cannot be achieved without an enormous conductive surface area in contact with this matrix, either through existing natural fractures or the development of a fracture “network” during stimulation. Economic production would then also rely on the existence or development of sufficient conductivity within this network. Tight gas sands, and particularly lenticular deposits typically developed in the western US basins, have somewhat higher permeabilities relative to the shales. While conventional core analyses of these types of rocks generally yield permeabilities on the order of tens of microdarcies, detailed special core analyses funded by DOE and GRI in the 1980’s showed that the in situ permeabilities for gas flow were much lower. 3 The combined effects of confining stress and water saturation typically caused about a two order of magnitude reduction in gas permeability from the conventionally measured value, resulting in

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Page 1: [Society of Petroleum Engineers SPE Unconventional Reservoirs Conference - Keystone, Colorado, USA (2008-02-10)] SPE Unconventional Reservoirs Conference - Stimulating Unconventional

SPE 114173

Stimulating Unconventional Reservoirs: Maximizing Network Growth while Optimizing Fracture Conductivity N.R. Warpinski, SPE, M.J. Mayerhofer, SPE, Pinnacle Technologies; M.C. Vincent, SPE, Carbo Ceramics; C.L. Cipolla, SPE, and E.P. Lolon, SPE, Pinnacle Technologies

Copyright 2008, Society of Petroleum Engineers This paper was prepared for presentation at the 2008 SPE Unconventional Reservoirs Conference held in Keystone, Colorado, U.S.A., 10–12 February 2008. 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 Unconventional reservoirs such as gas shales and tight gas sands require technology-based solutions for optimum development. The successful exploitation of these reservoirs has relied on some combination of horizontal drilling, multi-stage completions, innovative fracturing, and fracture mapping to engineer economic completions. However, the requirements for economic production all hinge on the matrix permeability of these reservoirs, supplemented by the conductivity that can be generated in hydraulic fractures and network fracture systems. Simulations demonstrate that ultra-low shale permeabilities require an interconnected fracture network of moderate conductivity with a relatively small spacing between fractures to obtain reasonable recovery factors. Microseismic mapping demonstrates that such networks are achievable and the subsequent production from these reservoirs support both the modeling and the mapping. Tight gas sands, having orders of magnitude greater permeability than the gas shales, may be successfully depleted without inducing complex fracture networks, but other issues of damage and zonal coverage complicate recovery in these reservoirs. As with the shales, mapping has proved itself to be valuable in assessing the fracturing results.

Introduction Unconventional reservoirs provide a significant fraction of gas production in North America and increasing amounts in some other regions of the world. Such reservoirs include tight gas sands, coalbed methane (CBM), and gas shales; in 2006 these reservoirs provided 43% of the US production of natural gas (Kuuskra1). Because of their limited permeability, which is foremost among many other complexities, some type of stimulation process (and/or dewatering in the case of CBM) is required to engender economic recovery from wells drilled into these formations.

The focus of this paper is on gas shales, with particular emphasis on how these reservoirs perform relative to tight gas sands. The important role of natural fractures in both the stimulation and production processes, the importance of conductivity in the developed fracture or fracture system, and the critical influence of the matrix permeability are investigated using both mapping and modeling results.

Gas shales, such as the Barnett, Fayettville, and Woodford in North America, are relatively recent plays, but gas production from shales has occurred since the early 1900’s from the Devonian shales of eastern North America and more recently from the Antrim shale and others. These shales2 typically contain a relatively high total organic content (e.g., the Barnett has a total organic content of 4-5%) and are apparently the source rock as well as the reservoir. The gas is stored in the limited pore space of these rocks (a few per cent, including both matrix and natural fractures) and a sizable fraction of the gas in place may be adsorbed on the organic material. Matrix permeabilities of these shales are extremely difficult to measure because they are so low, but various approaches to determine their value have yielded permeabilities on the order of 1-100 nanodarcies. Clearly, economic production cannot be achieved without an enormous conductive surface area in contact with this matrix, either through existing natural fractures or the development of a fracture “network” during stimulation. Economic production would then also rely on the existence or development of sufficient conductivity within this network.

Tight gas sands, and particularly lenticular deposits typically developed in the western US basins, have somewhat higher permeabilities relative to the shales. While conventional core analyses of these types of rocks generally yield permeabilities on the order of tens of microdarcies, detailed special core analyses funded by DOE and GRI in the 1980’s showed that the in situ permeabilities for gas flow were much lower.3 The combined effects of confining stress and water saturation typically caused about a two order of magnitude reduction in gas permeability from the conventionally measured value, resulting in

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effective gas-flow permeabilities of 0.1 to 1.0 microdarcies in most of these reservoirs. However, most of the producing reservoirs are at least marginally naturally fractured and the natural fractures appear to be an important factor for economic gas production, although they provide complications for the stimulation. In such a reservoir, a large, single-plane fracture with sufficient conductivity can effectively drain the reservoir, particularly if the well spacing is correctly planned based on fracture lengths, drainage widths, and reservoir compartmentalization.

The overriding importance of the matrix permeability in development of these reservoirs can be demonstrated with a reservoir simulator. Although these simulations include many simplifying assumptions (homogeneous reservoirs without lenticular discontinuity, planar fractures of constant width, symmetric networks, uniform vertical properties, etc.), they can effectively describe the impact of reservoir permeability upon depletion. Three cases, including one tight sandstone and two horizontal-well shale environments, were modeled. The sandstone simulation assumes a permeability of 1.0 μd, a spacing between hydraulic fractures of 300 ft (either from fractures in separate vertical wells or in multi-stage horizontal wells), and a relatively high hydraulic-fracture conductivity (50 md-ft). The two shale cases assume matrix permeabilities of 0.1 and 0.01 μd, network fracture spacings of 300 ft (an orthogonal fracture system), and a moderate fracture conductivity (5 md-ft) throughout the network. Figure 1 shows a comparison of the pressure depletion that would occur after three months from each of these systems, and the geometric configuration for each of the cases. In a microdarcy tight sandstone reservoir, closely-spaced planar fractures would provide efficient drainage of the reservoir. After three months, a 1000-psi drawdown occurs approximately 50 ft into the reservoir. However, the lower permeability shale reservoir shows limited depletion of the matrix, even with a fully interconnected fracture network. Here, a 1000-psi drawdown only extends 20 and 5 ft, respectively. Figure 2 illustrates the gas recovery factor obtained with long-term production of these reservoirs. In 15 years, the recovery factors could reach 80-90% in the tight gas reservoir, if it were developed with closely spaced fractures and if there is no compartmentalization. For the tighter shales, only 25-50% recovery could be expected, even with the development of a complex network.

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Figure 1 Example calculations of shale versus tight gas reservoir performance after 3 months of production.

Shale Gas

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Figure 2 Gas recovery factors for example shale and tight gas reservoir performance.

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Simple calculations such as these demonstrate the importance of developing a conductive fracture network that fits the

requirements of the particular reservoir. For gas shales in particular, the integration of fracture network size and spacing, fracture conductivity and continuity, and matrix permeability should be primary design concern for optimization. Other factors such as height growth, nearby wet zones, horizontal versus vertical wells, types of completions, damage and cleanup are obviously important and should not be minimized. These reservoirs have a well-deserved reputation for being “technology plays”, that is, those fields that cannot be developed without new or creative drilling, completion, and stimulation technology.

Fracturing Behavior As typical of most technology plays, the development of reservoirs such as the Barnett shale and lenticular tight gas sands has benefited tremendously from hydraulic fracture mapping results4-10 that provide definitive information regarding the created hydraulic fracture. It is worthwhile to begin by reviewing what we know about fracturing these reservoirs based on published mapping results.

Gas Shale Fracturing

Although little mapping information has been published from recent gas shale plays other than the Barnett, fracturing results in shales are believed to comprise the full spectrum from a network fairway to a fairly simple fracture typically envisioned in some sandstone reservoirs. Based on mapping results, the Barnett shale should be a good proxy for the end case of a complex network fracture. Current exploitation practices in this shale include multiple-stage light-sand fracture treatments11 in horizontal wells to stimulate and access large volumes of the reservoir. These fractures treatments often overlap and interact – frequently by design – and develop quite complicated fracture networks.

Evaluation of network behavior is somewhat simpler to decipher from the earlier waterfracs in vertical wells, avoiding any complications of multiple fracture initiation and interaction from a horizontal well, cement quality, or completion tools. Figure 3 shows two examples from Fisher et al4 of microseismic maps of vertical well stimulations conducted in the Barnett shale using ~20,000 bbl light-sand fracture treatments (waterfracs). These examples show the wide swath of microseismic activity that is generated by a waterfrac in these reservoirs. Fractures created in the Barnett with waterfracs are complex, often-anisotropic, show many cross-cutting linear features, and often show activity as much as 1,000 ft laterally from the predominant N45°E fracture azimuth in the Wise county region.

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Figure 3 Example microseismic maps of Barnett fractures in vertical wells (from Fisher at al6).

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Figure 4 shows the results from the same well as the left-hand map in Figure 3, but it is split into two time periods to help distinguish the aligned features that commonly develop. The early time plot on the left shows how northwestward development starts early in the treatment, but further growth becomes more northeasterly. The aligned features are often easy to discern early in time before the huge numbers of microseisms begin to obscure any details. Typically, both northeast and northwest features are observed, and it is believed that these features are related to the hydraulic fractures (NE) and opening of natural fractures (NW and NE).

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Figure 4 Development of aligned microseismic features that are indicative of possible activated natural fractures.

We also know that fracture treatments in these wells will load up nearby producing wells (lateral distances of 500-1000 ft)

with the fracturing fluid (Fisher et al4), so the microseismic activity is indicative of actual fluid movement and not just stress effects. The distance that fluid can move in a fracture in a given treatment time can be estimated12 from

μϕtPky Δ= 2 ,

where k is the permeability of the fracture while pumping, ΔP is the treatment pressure minus the reservoir pressure, t is the treatment time, ϕ is the fracture porosity, and μ is the fluid viscosity. Figure 5 shows the estimated distance of water movement as a function of permeability for several treatment times and a pressure differential of 2,000 psi. The obvious conclusion is that the lateral permeability of the network (orthogonal to the maximum stress azimuth) must be on the order of tens to hundreds of darcies while pumping in order to have fracture fluid intercept offset wells at the observed lateral distances. These high permeabilities are only realistic if the lateral fractures are dilating, that is, behaving like hydraulic fractures during the treatment. Such behavior also implies that the stress bias – the difference between the maximum and minimum horizontal stresses – is very low.

Figure 5 Calculation of lateral fluid movement as a function of time and fracture permeability.

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SPE 114173 5

The actual opening of the lateral fractures is also supported by tiltmeter data (Fisher et al4). Tiltmeter measurements of surface deformation induced by these fracture system frequently show a 60%-40% split in volume between the major fracture orientation (NE, for the Wise county area of the Barnett) and the conjugate orientation (NW). This split is also reflected in the shape of the surface deformation, which instead of being a trough with two adjacent humps, can approach a bowl shape that reflects the dual fracture orientations.

Since vertical or horizontal wells drilled into the Barnett shale do not produce any significant gas prior to stimulation, it is evident that the waterfracs generate or activate the network fracture system to induce an economically viable effective permeability. Most cores and imaging logs have also indicated that natural fractures in the Barnett are mostly healed when the wells are drilled. Mapping results have shown that a much more limited network is obtained using cross-linked gel systems13, so clearly the waterfracs are an important element of the process. It is envisioned that the low viscosity fluid in a waterfrac can penetrate into the natural fractures (assuming some residual permeability) and begin dilating them. The increased dilation results in more permeability and greater penetration into the natural fracture. At some point, there is sufficient pressure in the natural fractures to begin “jacking” them open, which also requires a low stress bias. Once opened, they continue to propagate as orthogonal hydraulic fractures as long as the fluid supply supports them. Multiple natural fractures can be opened in this way, thus creating the fracture network. Microseismic events, which are shear events, are a natural result of having various interconnecting fracturing planes with different pressures, since this configuration generates large amounts of shear transmitted through the matrix blocks. The brittleness of the shales is also regarded as an important factor for developing a large fracture network that maintains conductivity upon production drawdown. Softer shales are likely to be more challenging when trying to achieve large conductive networks.

The process described above produces an interconnected fracture network that has very high permeability at the time of fracturing. However, all of the fractures will close after pumping stops unless supported by proppant or by shear offset. Shear offset is a natural part of this process and the microseismic activity usually found in Barnett stimulations suggest that considerable large scale movement occurs, but it is not well known how much permeability/conductivity can be generated by shear offset alone. Proppant transport into the network is more complicated and will be discussed in a later section.

Tight Gas Fracturing

Hydraulic fractures performed in tight gas sands are generally thought to be near the other end of the fracturing spectrum, representing relatively simple, planar features. Most published results of fractures in tight sands7-10, 14-19 tend to support this assumption, as shown for example in data from a Piceance basin test (Wolhart et al10) in Figure 6. Nevertheless, there is a wide variation in microseismic behavior observed in such tests. Some tests have been published that show faults inducing some geometric complexities (Wolhart et al16), while a stimulation experiment at M-Site (Warpinski et al19) showed interesting fracturing behavior that indicated activation of some natural fractures fairly early in the fracture treatment, as shown in Figure 7. Additionally, some of the mapping tests showed fairly wide microseismic zones (Cipolla et al14 and Shemeta et al18) that might also be indicative of fluid movement into natural fractures in some zones, although much of the

width may also be due to uncertainty in event locations since fracturing tests in these reservoirs often generate smaller microseisms that cannot be detected as clearly. In general, however, the relatively high length-to-width ratio of the microseismic cloud dimensions would suggest more planar fracturing in these reservoirs with some likely fissure opening in specific situations.

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Figure 6 Example fracturing results in lenticular tight gas sands at Grand Valley, CO (Wolhart et al16). Figure 7 M-Site example showing activation of fracture planes

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Figure 8 shows a schematic of the types of fractures that can be envisioned in these types of reservoirs (adapted and modified from Fisher et al.4). It is highly unlikely that the simple planar fracture ever is achieved in geologic materials, but some level of planarity does appear to occur in many reservoirs, albeit with roughness, waviness, corners and stranding.7,8,12 Fissure opening is probably common, but may be difficult to recognize in microseismic maps because the open length orthogonally may not be much greater than the normal width of a microseismic cloud. It is expected that the “normal” width of a microseismic cloud is due to a combination of the accuracy of the microseisms (tens of feet) and the distance at which stress effects from the hydraulic fracture are large enough to induce shear slippage (approximately equal to the height of the fracture). Network fractures can often be distinguished (particularly in the Barnett shale) because of the aligned microseismic events over very wide areas, but also because of the fluid loading of offset wells.

Fracturing treatments in tight gas sandstones consist of a wide range of light-sand fracs, hybrid fractures, gel fractures, and various energized treatments that are intended to create and adequately prop a single fracture plane. The primary fracture-design issues are obtaining sufficient fracture length and height in contact with reservoir rock, optimizing conductivity within the hydraulic fracture to promote fluid cleanup, minimizing damage to the hydraulic fracture and the natural fractures, determining the optimum number of stages (if it is a typical fluvial lenticular reservoir), avoiding water, and coordinating well locations for maximum drainage efficiency based on fracture azimuths and lengths. The fracturing process itself is likely to be much less complicated than in shales and the design requirements are more straightforward. The selection of fracturing treatments in tight gas sands will depend on actual permeability, pore pressure, liquid yield, temperature, and stress magnitudes.

Fracture Requirements For Shale Stimulation If it is assumed that fracturing of shales can generate anything from planar fractures to very large networks depending on the reservoir conditions and the treatment parameters, then it is imperative that reservoir conditions be adequately assessed and that treatments be designed appropriately for the given conditions. A planar fracture in a nanodarcy reservoir will only recover a small fraction of the gas in place in any reasonable time period, and even a network fracture with rather wide fracture spacing will have a poor recovery factor. In the Barnett shale, development of network fracture systems is further complicated by reservoir features such as karsts and faults that may have detrimental effects on the fracturing; 3D seismic surveys are routinely used to map out and avoid such features.

At the present time, there is no method to predict the network generation capability of a given reservoir for any treatment; instead, fracture complexity is directly observed via mapping. Even the best current mapping services provide only a general idea as to the network that has been created, such as information on the volume of reservoir rock stimulated by the treatment (the SRV or Stimulated Reservoir Volume13), the intensity of the microseismicity as a possible indicator of the degree of fracturing, and the development of clear linear trends in microseismicity which probably highlight major fluid pathways during fracturing. Unfortunately, current mapping technologies do not provide adequate resolution to precisely determine the wellbore to fracture intersection of the details of the fracture geometry on a small scale. However, all information gathered to date helps develop an understanding of the complexity of the fractures and assists in the development of models to simulate the process.

Reservoir and Fracture Influence on Production

The ultra-low permeability of the gas shale reservoirs places a stringent requirement on the fracture treatment design. Mayerhofer et al20 have conducted a series of numerical calculations to assess the effect of SRV, fracture density, network conductivity, and other factors in initial and long-term production from these reservoirs.

Figure 9 shows example calculations that illustrate the pressure depletion (left side plots) that occurs for two different fracture spacings and the significant variation in gas recovery factor (right side plot) that results, even after 15 years of production. It is evident that ultra-low permeability gas shales need to be fractured in blocks that are less than 100 ft on edge in order to recover most of the gas in place.

Figure 8 Schematic diagrams of levels of fracture complexity (adapted and modified from Fisher et al4).

Simple Fracture Complex Fracture

Complex FractureWith Fissure Opening

Complex FractureNetwork

Simple Fracture Complex Fracture

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Figure 9 Example calculations showing effect of fracture density in gas shale recovery (after Mayerhofer et al20).

Using this same approach, the effect of the size of the stimulated volume (SRV) was evaluated and is shown in Figure 10

for the case of 400-ft fracture spacing. Using a shale thickness of 300 ft, a SRV of 600x106 ft3 corresponds to an area of 2,000,000 ft2 (about 46 acres), or a network that is 1,000 ft by 2,000 ft. Doubling the size of the SRV (essentially 2,000 ft by 2,000 ft) yields an increase of 1.3 BCF of production over 15 years. Interestingly, increasing the size of the SRV again by the same amount only nets another 0.7 BCF, recoverable in 15 years, which demonstrates the effects of limited conductivity in the stimulated natural fracture system.

ΔG=1.3 BCF

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Figure 10 Effect of reservoir volume on gas recovery factor (after Mayerhofer et al20).

The influence of conductivity in the fracture system is evident during all phases of production, as can be seen in Figure

11, also from Mayerhofer et al20. Increased conductivity has clear benefits up to at least 20 md-ft, although it may not be possible to generate such high conductivity with waterfracs in gas shale reservoirs. Nevertheless, any incremental improvement in conductivity adds value in terms of increased production over shorter time periods.

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8 SPE 114173

Figure 11 Effect of fracture conductivity on gas recovery factor (after Mayerhofer et al20).

In their calculations, Mayerhofer et al20 also demonstrated that higher near-wellbore conductivity could add value, that

unstimulated areas would reduce production essentially equivalent to the volume missed, and that fracture skin damage was insignificant unless the damage was greater than a 95% loss in permeability. Along with modeling of a measured fracture network, they also showed how measured SRV’s correlated with early-time production.

Figure 12 shows the actual production history of a typical shale gas well on a log-log diagnostic plot, which is used to identify various producing flow regimes. Flowing pressures were fairly constant throughout most of the production period prior to liquid loading. The initial month of production is significantly influenced by fracturing fluid cleanup, followed by an almost 2-year period of bi-linear flow indicating a low conductivity fracture network as illustrated in Figure 11. The later part of the production data is strongly impacted by liquid loading effects.

Conductivity and Proppant Transport in Light Sand Fracture Treatments

Proppant transport and the resulting conductivity in light sand fracture treatments are challenging issues. Since these treatments are essentially conducted with water (often slickened with linear gel or friction reducer to reduce friction in the tubing/casing), and given that proppant concentrations are generally quite low, the settling of proppant particles are often predicted using the relatively simple Stokes’ Law’

( )μ

ρρ18

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This form of the equation has many simplifying assumptions which are violated in actual slickwater treatments. Stokes’ Law in this form predicts the terminal settling velocity of spherical particles in stagnant Newtonian liquid without wall effects, and without particle interaction. In actual treatments, realistic power-law fluids are highly turbulent near wellbore, irregularly shaped particles settle at a velocity adequate to generate wakes requiring corrections for inertia, particles agglomerate (draft) and interact (hinder), while rough and/or inclined fracture faces complicate settling. Although Stoke’s Law has been deemed to be “grossly inadequate”21 for describing proppant placement, the general relationships are valid:

• With low viscosity (μ) fluids – proppant settling will be rapid, • settling can be slowed with reduced pellet density (ρp), and most poorly recognized,

Figure 12 Log-Log diagnostic plot of actual shale gas production showing the presence of a low-conductivity fracture network.

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• when particle diameter is reduced, settling velocity reduces exponentially. Although more sophisticated mathematical treatments have been proposed to describe proppant settling,21,22 a predictive

tool is not available to provide a precise description of the created fracture geometry, and the hindrance of particle movement by rough, inclined, stair-stepping fractures. Those concerns notwithstanding, Figure 13 presents the predicted settling rate for several common proppants, corrected for proppant settling Reynold’s Number. From Figure 13, it is apparent that most proppants will settle through slickwater at 5 to 30 feet per minute. Since many frac treatments require several hours to implement, it is clear that most injected proppants will fall into a settled bank and will not remain suspended until fracture closure.

Figure 13 Reducing particle diameter and/or particle density will reduce settling rates. However, most commonly used particles settle at an adequate rate that they will likely form a settled bed unless the frac fluid is densified or viscosified (LWC = light-weight proppant; ULWP = ultra-light-weight proppant).

However, the maximum distance that particles will be transported with slickwater is not exclusively a function of

suspension time. Instead, in slickwater fractures, the main mode of lateral transport is likely to be saltation, or bed transport as proposed by Kern, Perkins, and Wyant23, Patankar24 and shown in recent laboratory videos by Stim-Lab25 and others. The observed behavior for this type of flow is shown in Figure 14. Particles with a density greater than the fracturing fluid quickly fall to the base of the created frac, but are eroded from the settled bed and progressively transported along the bed and deposited at the end – effectively achieving propped length. By this manner, laboratory observation and theoretical modeling demonstrate that even very large, dense particles may be transported to enormous lengths given adequate water velocity and time.

Figure 14 Proppant Transport in Slickwater (from Kern, Perkins, Wyant,23 and Patankar24)

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Field validation of proppant transport is somewhat limited. With cross-linked fluids in the Bakken formation, 20/40 sand has been pumped to surface in offset wells 2200 feet away from the treatment wells26. With slickwater fluids, Leonard et al27 have reported tracer surveys indicating radioactive traced sand being identified in offset wells at distances of 500 feet with 40/70 mesh sand. In mineback observations of coalbed methane (CBM) treatments, Diamond and Oyler28 report a sand filled fracture observed 110 feet from the treatment well. The well was treated with 20/40 and 80/100 sand with water as the carrying fluid. The sand-filled frac was primarily horizontal at the top of the coal section. Other CBM treatments with 70-quality N2 foams confirmed sand was transported as far as 400 feet in vertical and complex fractures as proved by subsequent minebacks. Diamond and Oyler reported that the fracture geometry in CBM was frequently complex, with vertical, horizontal, and stair-stepping fractures. Fractures were not laterally homogeneous – fractures would vary in width, trajectory, and orientation, providing many pinch points which would restrict flow beyond what is predicted in uniform models. In 22 government sponsored minebacks in six states, it appeared that new fractures were seldom created in CBM, but rather that naturally occurring planes of weakness (cleats, joints, bed boundaries) were dilated and widened to varying degrees by the fracturing treatment. It is not clear whether lessons learned in CBM minebacks will directly translate to deeper shale reservoirs, but it does corroborate that fracture geometry and proppant transport are more complex than explained by most models.

In addition, most production models and published conductivity data presume that fractures are linear, planar, of uniform width, have smooth fracture faces and are not damaged by gel. However, more realistic testing conducted on narrower fractures subjected to realistic flowrates of liquid and gas subjected to cyclic stress and gel damage may show 50 to 100 times higher pressure losses, as reported by Palisch et al.29

Fredd et al30 tested flow capacity of fractures between split core from the Cotton Valley sandstone formation, as indicated in the diagrams and photos in Figure 15. Unpropped and partially propped fractures were compared to evaluate potential waterfrac cases.

Figure 15 Testing of flow capacity of fractures created from split core instead of standard honed core [from Fredd et al30]. As shown in Figure 16, unpropped fractures from split core retain some conductivity at low stress. However, at stresses

above 3000 psi, these fractures were observed to heal and provide essentially zero flow capacity. If fracture faces were displaced (perhaps simulating tectonic stress in the reservoir allowing shifting of the fracture faces) some degree of flow capacity was provided even with unpropped fractures. However, in all fracture conditions, adding 0.1 lb/sq ft of white frac sand increased the conductivity by 10 to 100 fold. Substituting a strong bauxite in place of frac sand increased the conductivity by another 100-fold at stresses below 4000 psi. While no operators consider bauxite at stress conditions of only 4000 psi, these results suggest that conventional proppants are not strong enough to withstand closure stress when placed in a partial monolayer, and the use of higher strength proppants should be evaluated despite conventional wisdom to the contrary. It is unclear that dense particles can be placed in a partial monolayer within an actual propped fracture. However, it appears highly likely that the proppant distribution within actual fractures is irregular, with proppant pillars adjacent to poorly propped areas, and stress concentration upon proppant is certainly greater than the ideal conditions normally evaluated within the lab and echoed by most production models.

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100x difference in flow capacity

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Figure 15 Comparison of Waterfracturing cases 1 through 4 by Fredd et al30 indicated that proppant strength is much more important in partial monolayers than in fully packed fractures.

A large concern with production models and “rules of thumb” for required conductivity is the implicit assumption that

fractures are of uniform width vertically and laterally. However, all physical evidence (minebacks, core-throughs, block studies) indicate some degree of complexity to fracture geometry and continuity. Although in the laboratory it is possible to place a uniform proppant bed, carefully leveled with a spatula, in actual wells it is highly unlikely that we are able to fill fractures many hundreds of feet vertically and laterally with uniform concentrations of proppant. More likely, there are regions of higher stress that serve as width restrictions, and areas of the fractures where proppant pillars and/or unpropped areas will provide flow restrictions.

For gas shales, a second important question relates to the conductivity of the fractures that are oriented orthogonal to the primary hydraulic fracture azimuth and whether the conductivity is generated substantially by shear offset during fracturing or by transport of proppant into these fractures. Shear offset, essentially the sliding of the two rough surfaces of a fracture over one another so that they cannot close in their original location, is a ubiquitous process that has been demonstrated in all materials with rough fracture surfaces. Although many methods exist for estimating the permeability of rough natural fractures and the effect of variable closure stress as the reservoir depletes (e.g., Walsh31, Barton and Bandis32), the amount of conductivity that is retained is unclear, primarily because of the unknown condition of the fracture faces.

There is no reason why proppant would be unable to enter any orthogonal fractures opened during the creation of the network, but the distance that the prop would be transported and the amount of conductivity generated remain unanswered questions. The orthogonal fractures should be narrower because of at least slightly higher stress levels, and they would also have much lower flow rates due to the wide distribution of fluid into many network fractures, both suggesting that proppant transport would be considerably less in these fractures. However, it is also possible that the principal benefit of 40/70 and 100 mesh sand used in most shale waterfracs is diversion so that more fractures are created and the reservoirs are more extensively broken apart.

All of these issues are open questions that need extensive investigation to find answers that can further help to optimize stimulations in these reservoirs. What is clear is the necessity of maintaining conductivity to efficiently and effectively drain the reservoir. As shown in the previous reservoir modeling, increased conductivity improves initial production rates and adds reserves. However, methods to add conductivity while maximizing network development have not been clearly formulated and need to be investigated.

Many fracture optimization “rules of thumb” suggest that the required conductivity of a fracture can be optimized by simply knowing the reservoir permeability and fracture half-length – for instance trying to reach a dimensionless conductivity of 30, where FCD = (khf w) / (k * xf). This approach may not always apply in horizontal wells, as it does not consider the intersection between the wellbore and fracture and the associated flow convergence. Dedurin et al33 and Besler et al26 have demonstrated that transverse fractures have entirely different conductivity requirements compared to longitudinal fractures.

If longitudinal fractures are successfully propagated along uncemented laterals, the intersection between the wellbore and fracture is extensive, allowing very low fluid velocity within the fracture, as shown in Figure 17. Also, the oil/gas only travels approximately half the pay height within the proppant pack. In this geometry, almost any proppant would provide essentially infinite conductivity. However, with transverse fracs, the oil/gas may travel many hundreds or thousands of feet within the proppant pack, and exceedingly high fluid velocities are expected due to flow convergence near the wellbore. Even in low productivity wells, very high pressure losses are expected within the propped fracture, and any improvements to fracture width or proppant permeability are expected to generate significant production gains.

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Figure 17 Longitudinal fracs with uncemented liners provide excellent communication between the fracture and wellbore. Transverse fracs provide an extremely small intersection – the circumference of the wellbore

With more complicated networks, the degree of interconnection between the various fracture wings is unclear. In the

CBM mineback experiments previously described (Diamond and Oyler28) very little interconnection was observed between horizontal and vertical fractures, potentially implying that longitudinal growth along a wellbore will not necessarily provide the much-needed connectivity to transverse fracture components. In an ideal world, complex fractures could be designed to place less expensive proppant in the longitudinal components, and reserve the high conductivity proppant for near-wellbore transverse elements. Unfortunately, at this time it appears that the sequence of fracture propagation is not entirely predictable. It is possible that future developments will allow that optimization.

Some of the previous considerations are in stark contrast to conventional wisdom of fracture conductivity requirements in microdarcy and nanodarcy formations. A light sand frac generally has the goal of cheaply fracturing the reservoir with a minimally damaging fluid and a sufficient quantity of proppant to establish reasonable conductivity. Although intuition often suggests that any fracture will provide infinite flow capacity compared to the formation, the immense surface area of propped fractures requires fluid to move hundreds of thousands, or even millions of times faster within the propped fractures than within the matrix.33 Therefore, conductivity of proppant packs remains critical, both for cleanup of frac fluid and subsequent gas production.34,35 More research and direct observations of proppant transport phenomena will hopefully shed more light on this important topic in the future.

Optimizing the Fracture Network

Probably the most agreed upon element of gas-shale stimulation is the need to densely fracture the reservoir,10, 27 which is the driving reason for the variety of stimulation practices that can be found in the Barnett shale. Simultaneous fractures, closely spaced fracture stages, and sequential fractures in one or more adjacent wellbores are designed to impart large amounts of energy into a limited region of the reservoir with the hope of extensively fracturing and interconnecting that volume. While no microseismic maps of such stimulations have been published yet, the general conceptual idea can be gleaned from the behavior of multi-stage stimulations in horizontal wells (Fisher et al6). The successive stimulations of a multi-stage treatment often show a significant influence of the prior stage, including what might best be called “charging” of the reservoir, as indicated in Figure 18. The fluid from the previous stage remains at somewhat elevated pressure, pushing subsequent stages away due to the increased stress generated by the volume of pressurized fluid.

The reservoir charging potentially can be harnessed in some way by (1) conducting multiple fractures from close offset wells at the same time, or (2) conducting quick sequential fracture stages in one well or in several closely spaced wells. The interaction of the fluid from the different fractures might provide some additional energy to enhance the intensity of fracturing, either through higher net pressures or forced diversion of the fluids as they contact other fluid-filled fractures. Figure 19 shows an example of the much more rapid drainage and pressure depletion that would occur if the rocks could be more finely fractured. This approach also may enhance conductivity by increasing the shear offset induced by the fracturing. Many of the blocks of rock are likely to have fluid at significantly different pressures on the various sides, thus resulting in larger shear stresses to shift the rocks.

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Figure 19 Example calculation of depletion in offset horizontal well fracture networks.

It is possible that such enhanced fracturing might be

reflected in the microseismic activity, either through greater numbers of microseisms or larger amplitude events induced by large-scale block movements. One approach to categorizing fracture intensity through microseisms was suggested by Maxwell et al36 and involved computing a seismic moment density and observing its distribution. The seismic moment is a measure of the intrinsic strength of the microseismic event that corrects for distance and attenuation (removes any viewing bias). Areas that are more intensely fractured or have undergone larger-scale movement should show a greater moment density. Figure 20 shows an example seismic moment density map for two stages of a stimulation of a horizontal well in the Barnett shale. The hotter colors represent areas of higher moment density. Although greater moment density was found to correlate well with production when combined with areal extent, this approach has not yet been applied to simultaneous or sequential fracture treatments (no published data sets).

Modeling Unconventional Fracturing Modeling of fracture treatments in any of these reservoirs is complicated by a poor understanding of the processes that

occur during the treatment, but probably just as much from the lack of data to input into the models. The lack of data is particularly evident for treatments in tight sands, where the most important information – the stress in the various layers – is not measured. Proxy information, mainly from dipole sonic logs,37 are routinely used to compute stress profiles based on clearly inappropriate assumptions of rock mass behavior, amounting to a situation where the stresses are guessed based upon lithology. The basic assumptions of (1) linearly elastic behavior even though all rocks are fractured (and most apparently in an incipient failure state38) and (2) vertical dynamic property measurements along a relatively competent wellbore to represent horizontal rock properties through heterogeneous materials are indefensible under any scientific methodology, yet they continue to be used and believed. The reason why calibrated models (models based on mapping results) are so necessary and so useful is probably more attributable to the widespread use of log-derived stress data than any other factor.

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Similar, but less severe, problems arise when attempting to use log-derived elastic moduli and some correlation of dynamic-to-elastic moduli. Luckily, other important quantities such as the closure stress and the leakoff coefficient can actually be measured during the fracturing process and accurate values can readily be obtained.39-42

For the gas shales, unfortunately, even good quality input data would not suffice to allow accurate modeling. The complexity of the process makes it very difficult to formulate algorithms to describe the fundamental mechanistic behavior, and the asymmetry observed in many mapping tests suggest that various combinations of rock, stress, and natural fracture features also have a major influence on the development of the fracture network in an areal sense in addition to the well-recognized layered effects. At this time, there are no known design models for network shale fracturing. A reasonable model would need to account for the primary hydraulic fracture that connects to the wellbore and the activation and opening of the network of fractures that are connected to it. Fluid flow and proppant transport within such an interconnected network will require new formulations to account for the complexity and the interaction.

Flowback and Load Recovery

Figure 21 gives a simulation result showing the potential effect of cleanup on the pressure distribution and production from a fracture network in a horizontal shale well. A typical treatment volume of water was injected into the network and then produced together with the gas. Relative permeability curves in the fracture and matrix were adjusted to achieve roughly 40% load recovery after one year of production (consistent with observations in the Barnett shale of load recoveries of about 30% to 40%). The graph shows that cleanup will delay drainage from the network, resulting in lower cumulative production even after 5 years. In reality, portions of the fracture network may never efficiently cleanup since the pressure drop and fracture network conductivity are insufficient to remove the water from the far reaches of the network, especially through junctions of orthogonal sets of fractures where conductivity is potentially even lower. The diminishing returns of very large SRV’s as shown in Figure 8 are evident for just gas production as a result of low fracture conductivity and will be even further aggravated by the inability to move water through a complex network. These considerations have a major impact on optimum treatment sizes and well spacing to ensure optimum drainage and recovery factors. In addition, one may postulate that rapid fluid cleanup with a high percentage of load recovery (more than 50%) may actually be an indication that a significant fracture network was not generated and only a simple fracture was created that acts like a “balloon” and deflates quickly back into the wellbore with very little leakoff into a “super-tight” matrix.

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An additional topic is fluid cleanup along the horizontal well. Many shale reservoirs require horizontal wells that are several thousands of feet long with multiple fracture stages. Most staged fractures are not flowed back individually but are commingled once the last stage has been finished at the heel. It is unclear if all stages clean up uniformly and there are especially concerns that the toe stages cannot clean up as efficiently as the heel-side stages. Chemical tracers have been employed to quantify the relative cleanup of all fracture stages,27 and they often show poorer load recovery from the toe region. In addition, many operators drill the laterals at a slight incline to facilitate the removal of water from the lateral.

Mapping Unconventional Fractures The surest way to begin to understand the complexities of the unconventional systems is to perform mapping and diagnostics – that is, gather data – and then find methods to correlate net pressure behavior and production results with what is observed during the mapping. Mapping of fracture networks in gas shales is currently performed using downhole microseismic receiver arrays to detect and locate the very small earthquakes (microseisms) that occur as a result of the fracturing process.43,44

Other diagnostic technologies can provide some limited information on the fracturing processes. Surface tiltmeters can be used to calculate how the volume of fluid is distributed between the primary fracture azimuth and other fractures planes that open, thus providing a measure of complexity. In addition surface tiltmeters can also provide information on where a fracture is occurring along the length of a horizontal well, although there are limits on resolution based on the depth of the fracture. Radioactively tagged proppant can be used to assess the completion behavior and cement quality in horizontal wells, and chemical tracers can distinguish interconnections between wells and flowback percentages for the various stages. As always, pressure diagnostics prior to, during, and after fracturing are useful for assessing fracturing behavior. In tight gas sands, downhole tiltmeters can be employed in vertical wells to assess height growth and zonal coverage, both in offset wells and treatment wells. Similarly, in tight gas sands radioactively tagged proppant is often employed to evaluate proppant placement.

While all of these other technologies have widespread usefulness when applied to the horizontal well stimulations in the gas shales, it is the downhole microseismic technology that has provided the information about the detailed structure of the network fracturing process. High quality microseismic mapping data can be essential to understand completion and stimulation behavior. Obtaining a successful microseismic monitoring test is largely a matter of proper viewing conditions for the microseismic array. The important factors are (1) distance to the events, (2) size of the event, (3) attenuation, (4) noise levels in the monitor well, and (5) an accurate velocity model through the region of observation.

Having an acceptable monitoring distance is primarily a matter of placement of the observation well, but in most cases existing wells are used for monitoring and it is a matter of finding an appropriately situated one. For monitoring long horizontal laterals, it may be necessary to have two monitor wells, depending on the viewing distance. The maximum distance at which microseisms can be accurately detected depends on factors 2-4. Small events can only be observed short distances, attenuating media (such as diatomite) reduce viewability, and high noise levels can overwhelm many or all of the microseisms.

There are now sufficient published mapping tests in numerous formations that it is possible to assemble plots illustrating viewing conditions. Figure 22 shows a plot of measured moment magnitudes as a function of distance for five different reservoirs in North America. The moment magnitude is similar to the Richter magnitude of large earthquakes, except it is not based on any particular instrument; it is a magnitude (log) scale representation of the seismic moment of the microseismic events, which are calculated from shear amplitudes and distance. There are several important elements of this plot. First, it is clear that larger magnitude events can be seen at much larger distances. A magnitude -4 event is probably only visible within ~200 ft of the monitor well, whereas a magnitude -2 event can be observed from several thousand feet. A bounding line can be drawn on the lower edge of the event distribution that will indicate the viewing

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distance for that reservoir and receiver conditions. It is generally very difficult to make sense out of any microseisms below this limit, primarily because the P-wave energy is too low to detect through the noise. Most of the reservoirs have very similar viewing conditions based on this magnitude calculation, except for the Utah data that was obtained with a stacked geophone array to enhance the signal strength.18

In the Barnett and some other reservoirs where microseisms can be detected at large distances, the event magnitudes generally range from -2.5 to -3.5. In many tight gas sands, the events are more typically -3 to -4. However, in all cases it is possible to generate very large amplitude events (>-1) when the hydraulic fractures intersect and activate large faults. These events can often be seen >4,000 ft, but this is also a danger since the faults are often very different from the fractures in azimuth and in height. If a monitor well is placed too far away, then the only events that might be seen are the ones associated with the faults, potentially giving an erroneous picture of fracture behavior. This is also a danger with trying to view microseisms from the surface.

Since the size of the microseism is obviously one of the main parameters controlling the viewing distance of any test, it is worthwhile to speculate on what factors influence the size response. From experience, it is observed that higher rates and larger volumes generate more microseismic events. In the Barnett shale, the containment provided by the Viola shale in the “core area” around Wise County allows for high injection rates that generate large microseisms that can be detected at great distances. In the outer areas of the Barnett development, the lower rates used in an effort to avoid breaking into Ellenberger water have the effect of generating fewer and smaller microseisms. Not many microseisms are observed at any reasonable monitoring distance when rates drop much below 15 bpm or volumes are less than 100 bbl, probably because so little energy is imparted to the formation under low rate and small volume conditions. Since the amplitude of the event also depends upon how far the rocks slip and the size of the fault plane, large amplitude events are expected in thick sequences where fracture planes can become extensive, which is a likely reason why such large events occur in these thick shale reservoirs. It is also another possible reason why microseisms in the fringe areas of development are smaller, since the Barnett is thinner there.

Noise may become a limiting factor when treatment and observation wells are located on the same drilling pad – equipment noise can easily couple into the monitor wellbore. In network fractures, noise can overwhelm microseismic signals if the fracture breaks into the observation well or a fracture network connected to it; this type of noise problem is a fairly common occurrence. Other noise sources are nearby drilling rigs and seismic surveys, production operations, and wind.

Finally, the velocity structure is a very important factor in obtaining an accurate event map. Dipole sonic logs are a good starting point for determining layers and initial velocity estimates for calibration procedures, but dipole-log vertical velocities are often significantly different than the horizontal velocity appropriate for downhole monitoring. Similarly, vertical seismic profiles (VSP) also provide the wrong velocity. Perforation timing45 and procedures similar to joint hypocentral determinations46 need to be employed to obtain correct velocities from the fracture well to the monitoring positions.

Assuming all of the factors above can be appropriately handled, the resulting map can then provide significant information on fracture development and the final stimulated reservoir volume (SRV). Linear features, which most likely indicate the opening of fracture planes, can be identified and mapped. Height growth and entry into faults (identification of large magnitude events) can also be discerned, as well as interaction between stages and wells and complications with completion tools or cement quality. However, it is very important to understand the uncertainty of individual events in order to make proper use of the mapping data. A careful review of event uncertainty and data quality are necessary for reliable evaluation.47

Recommendations For gas shale development, the main objective is to obtain a large, highly fractured network that can produce from the ultra-low permeability rock. To achieve this, multi-stage horizontal wells with large waterfracs are currently being used with good success in many areas, and large volumes of fluid and proppant are required. It is not envisioned that any new developments are going to significantly change this basic concept. What can be investigated further are the numbers of perforation clusters per stage, the separation between stages, the total length of the horizontal well, the spacing between wells, the sequence of fracturing operations for single well and multi well stimulations, the type and quantity of proppant introduced to achieve diversion and for improved conductivity, methods to optimize the volume of fluid and proppant per stage, and any new technologies to improve the transport of proppant, fluid cleanup, and the efficiency of the operations. Evaluation of the success of changes to the current practice will ultimately rest on long-term production data, but mapping information can be used immediately to evaluate the overall network development and hopefully provide a suitable proxy for assessment purposes.

In more challenging areas, such as the fringes of the Barnett and the Woodford shale, the prevalence of faults and karsts, proximity to water, significant regional dip, potentially larger stress bias, thinner sections, and potentially different natural fracture conditions can reasonably be expected to require different completion and stimulation strategies to adequately slice up the reservoir into producible units. It is unfortunate that mapping is also more difficult in many of these areas because of the smaller microseisms generated by lower rate and volume stimulations and other factors, but adequate mapping tests can be accomplished with proper design, planning and equipment.

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Conclusions Unconventional reservoirs offer myriad challenges for successful completion, stimulation and production. The extremely low permeability of gas shales requires some type of network connectivity for economic production, either through existing permeable natural fractures or through the development of an engineered fracture system. The technology for engineering a connected reservoir system has evolved into the use of horizontal wells fractured with light sand fracs in multiple stages, often in conjunction with fracture treatments in other offset wells. This technology works well in the Barnett shale where the apparent low stress bias allows the creation of such a network, but there is no guarantee that it is applicable in other shale reservoirs. It is only through mapping technology – primarily microseismic – that such networks have been discovered and are beginning to be optimized. Other reservoirs will most likely require different strategies, but mapping will be a principal component of any effort to understand and optimize the development strategy, targeting not just the treatment size and implementation, but also the optimal well spacing.

Tight gas sands can rely on other development strategies when improved matrix permeabilities allow reasonable drainage of the reservoir volume. Network fractures are not as likely to develop (or at least have not been documented yet), so maximizing drainage efficiency probably involves minimizing damage of any (usually marginal) natural fracture system by the treatment fluids, which is the direct opposite of the approach in gas shales. Understanding the fracture azimuth and length, usually through mapping, allows for positioning of wells to optimally fit the drainage ellipses. Perhaps the most difficult problems are optimizing the number of fracture zones per well to intersect the largest possible gas sands volume with the minimum of treatment materials and operations, and providing adequate conductivity to effectively clean up the fracturing fluids.

It is clear that many of the rules of thumb, tools, and intuition applied in our industry do not adequately describe the hydraulic fractures that are the key to development of unconventional tight gas and shale gas reservoirs. Fractures are rarely (never?) single planar features of constant width and uniform proppant distribution. Proppant is not deposited within fractures as predicted by Stoke’s Law or other transport models. Gas flow within fractures does not obey Darcy’s Law. Fracturing fluid is non-Newtonian and requires a certain yield stress to be overcome before gas production can begin. Commonly published crush and conductivity data for proppants are for conditions that do not even approximate reality – with pressure losses perhaps a hundred times higher than suggested from these ideal test conditions. Our industry has been mathematically obliged to describe fractures as linear, smooth channels of uniform width. However, real fractures are rough, tortuous, branching, - hydraulically non-ideal. It is much harder to recover gel (or convey gas) through a complex network than a simple fracture. While reservoir contact is improved, hydraulic continuity is poorer and in some cases may be the limiting factor in productivity gains.

Improved understanding of our fractures via fracture mapping and development of calibrated tools will improve our ability to describe and alter the fracture complexity via operational changes to the well design and treatment implementation. Increased effort to evaluate production and ultimate recovery from these fractures will be necessary to understand the long-term performance of fractures in unconventional reservoirs. In these unconventional reservoirs, it is clear that hydraulic stimulation is the key to unlocking the reserves. However, the fracture is by far the most poorly understood feature of the entire exploration, drilling, and completion process. Unconventional reservoirs are technology plays – if history is a guide, increased use of technology will be key towards making the next steps to efficiently and effectively produce these resources. Acknowledgments The authors would like to acknowledge the behind-the-scenes support of numerous technical personnel at Pinnacle and CARBO who actually acquire and process the data that we rely on for these analyses and papers. Nomenclature ASG = apparent specific gravity

d = particle diameter, L FCD = dimensionless conductivity g = gravity, L/T2 k = permeability, L2 khf = hydraulic fracture permeability, L2 t = time, T VS = settling velocity, L/T w = fracture width, L xf = hydraulic fracture wing length, L y = distance fluid penetrates into a natural fracture or fissure, L ΔP = pressure drop, specifically treating pressure minus reservoir pressure, M/LT2 μ = fluid viscosity, M/LT ρf = fluid density, M/L3 ρp = particle density, M/L3 ϕ = porosity

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