Evaluation of Impacts to Underground Sources of Drinking Water by Hydraulic Fracturing of Coalbed Methane Reservoirs Chapter 3 Characteristics of Coalbed Methane Production and Associated Hydraulic Fracturing Practices by the US Environmental Protection Agency, June 2004, EPA 816-R-04-003
Understanding the practice of hydraulic fracturing as it pertains to coalbed methane production is an important first step in evaluating its potential impacts on the quality of USDWs. … Coalbed methane is exceptionally pure compared to conventional natural gas, containing only very small proportions of “wet” compounds (e.g., heavier hydrocarbons such as ethane and butane) and other gases (e.g., hydrogen sulfide and carbon dioxide). … The origin of methane in coal of low rank, such as bituminous coal, is primarily biogenic (i.e., the result of bacterial action on organic matter) (Levine 1993, as cited by the Alabama Oil and Gas Board, 2002). Low rank coals tend to have lower gas content than high rank coals such as anthracite. Anthracite can have extremely high gas content, but the gas tends to desorb so slowly that anthracite is an insignificant source of coalbed methane (Levine, 1993, as cited by the Alabama Oil and Gas Board, 2002). Commercial coalbed methane production takes place in coals of mid-rank, usually low- to highvolatile bituminous coals (Levine, 1993; Rice, 1993).
The primary (or natural) permeability of coal is very low, typically ranging from 0.1 to 30 millidarcies (md) (McKee et al., 1989). According to Warpinski (2001), because coal is a very weak (low modulus) material and cannot take much stress without fracturing, coal is almost always highly fractured and cleated. The resulting network of fractures commonly gives coalbeds a high secondary permeability (despite coal’s typically low primary permeability). Groundwater, hydraulic fracturing fluids, and methane gas can more easily flow through the network of fractures. Because hydraulic fracturing generally enlarges pre-existing fractures and rarely creates new fractures (Steidl, 1993; Diamond, 1987a and b; Diamond and Oyler, 1987), this network of natural fractures is very important to the extraction of methane from the coal.
Only horizontal fractures are shown in this diagram, although hydraulically induced fractures are often vertically oriented. … The extraction of coalbed methane is enhanced by hydraulically enlarging and/or creating fractures in the coal zones. The resulting fracture system facilitates pumping of groundwater from the coal zone, thereby reducing pressure and enabling the methane to be released from the coal and more easily pumped through the fracture system back to the well (and then through the well to the surface). To initiate the process, a production well is drilled into the targeted coalbeds. Fracturing fluids containing proppants are then injected under high pressure into the well and specifically into the targeted coalbeds in the subsurface.
The fracturing fluids are injected into the subsurface at a rate and pressure that are too high for the targeted coal zone to accept. As the resistance to the injected fluids increases, the pressure in the injecting well increases to a level that exceeds the breakdown pressure of the rocks in the targeted coal zone, and the rocks “breakdown” (Olson, 2001). In this way, the hydraulic fracturing process “fractures” the coalbeds (and sometimes other geologic strata within or around the targeted coal zones). This process sometimes can create new fractures, but most often opportunistically enlarges existing fractures, increasing the connections of the natural fracture networks in and around the coalbeds (Steidl 1993; Diamond 1987a and b; Diamond and Oyler, 1987). The pressureinduced fracturing serves to connect the network of fractures in the coalbeds to the hydraulic fracturing well (which subsequently will serve as the methane extraction or production well). The fracturing fluids pumped into the subsurface under high pressure also deliver and emplace the “proppant.” The most common proppant is fine sand; under pressure, the sand is forced into the natural and/or enlarged fractures and acts to “prop” open the fractures even after the fracturing pressure is reduced. The increased permeability due to fracturing and proppant emplacement facilitates the flow and extraction of methane from coalbeds.
Methane within coalbeds is not structurally “trapped” by overlying geologic strata, as in the geologic environments typical of conventional gas deposits. Only about 5 to 9 percent of the coalbed methane is present as “free” gas within the joints and cleats of coalbeds. Most of the coalbed methane is contained within the coal itself (adsorbed to the sides of the small pores in the coal) (Koenig, 1989; Winston, 1990; Close, 1993). Before coalbed methane production begins, groundwater and injected fracturing fluids are first pumped out (or “produced” in industry terminology) from the network of fractures in and around the coal zone. The fluids are pumped until the pressure declines to the point that methane begins to desorb from the coal (Gray, 1987).
Factors Affecting Fracture Behavior
Fracture behavior is of interest because it contributes to an understanding of the potential impact of fracturing fluid injection on USDWs; the opportunities for fracture connections within or into a USDW are affected by the extent to which a hydraulically induced fracture grows. Specifically, when hydraulic fracturing fluids are injected into formations that are not themselves USDWs, the following scenarios are of potential concern:
• The hydraulically induced fracture may extend from the target formation into a USDW.
• The hydraulically induced fracture may connect with natural (existing) fracture systems and/or porous and permeable formations, which may facilitate the movement of fracturing fluids into a USDW.
Fracture behavior through coal and other geologic formations commonly present above and below coalbeds depends on site-specific factors such as the following:
1. Physical properties, types, thicknesses, and depths of the targeted coalbeds as well as those of the surrounding geologic formations.
2. Presence of existing natural fracture systems and their orientation in the coalbeds and surrounding formations.
3. Amount and distribution of stress (i.e., in-situ stress), and the stress contrasts between the targeted coalbeds and surrounding formations.
4. Hydraulic fracture stimulation design including volume of fracturing fluid injected into the subsurface as well as the fluid injection rate and fluid viscosity.
Many of these factors are interrelated and together will influence whether and how far hydraulic fractures will propagate into or beyond coalbeds targeted for fracturing.
Coalbed depth and rock types in the coal zone have important fundamental influences on fracture dimensions and orientations. According to Nielsen and Hansen (1987, as cited in Appendix A: DOE, Hydraulic Fracturing), generally, at depths of less than 1,000 feet, the direction of least principal stress tends to be vertical and, therefore, at these relatively shallow depths fractures typically have more of a horizontal than a vertical component. Here, horizontal fractures tend to be created because the hydraulically induced pressure forces the walls of the fracture to open in the direction of least stress (which is vertical), creating a horizontal fracture. At these shallower depths, the horizontal fractures result from the low vertical stress due to the relatively low weight of overlying geologic material (due to the shallow depth). Shallow vertical fractures are most likely due to the presence of natural (existing) vertical fractures, from which hydraulically induced vertical fractures can initiate.
Coal is generally very weak (with low modulus) and easily fractures. Siltstones, sandstones, and mudstones (other rock types commonly occurring in coal zones) tend to have higher moduli, greater toughness and fracture less easily (Warpinski, 2001). Thick shales, which commonly overlie coalbeds, often act as a barrier to fracture growth (see Appendix A).
The low permeability of relatively unfractured shale may help to protect USDWs from being affected by hydraulic fracturing fluids in some basins. If sufficiently thick and relatively unfractured shales are present, they may act as a barrier not only to fracture height growth, but also to fluid movement.
Importantly, in several locations in the Diamond (1987a and b) study sites, fluorescent paint was injected along with the hydraulic fracturing fluids and the paint was found in natural fractures from 200 to slightly more than 600 feet beyond the sand-filled (“propped”) portions of hydraulically induced or enlarged fractures. This suggests that the induced/enlarged fractures link into the existing fracture network system and that hydraulic fracturing fluids can move beyond, and sometimes significantly beyond, the propped, sand-filled portions of hydraulically induced fractures (Steidl 1993; Diamond 1987a and b; Diamond and Oyler, 1987).
According to (Naceur and Touboul 1990), the contrast in stress between adjacent rock strata within and surrounding the targeted coal zone is the most important mechanism controlling fracture height. Stress contrast is important in determining whether a fracture will continue to propagate in the same direction when it hits a geologic contact between two different rock types. Often, a high stress contrast results in a barrier to fracture. An example of this would be where there is a geologic contact between a coalbed and an overlying, thick, higher-stress shale.
The fluids used for fracture development are pumped at high pressure into the well. They may be “clear” (most commonly water, but may include acid, oil, or water with frictionreducer additives) or “gelled” (viscosity-modified water, using guar or other gelling agents). Some literature indicates that coalbed fracture treatments use from 50,000 to 350,000 gallons of various stimulation and fracturing fluids, and from 75,000 to 320,000 pounds of sand as proppant (Holditch et al., 1988 and 1989; Jeu et al., 1988; Hinkel et al., 1991; Holditch, 1993; Palmer et al., 1991b, 1993a, and 1993b). More typical injection volumes, based on average injection volume data provided by Halliburton for six coalbed methane locations, indicate a maximum average injection volume of 150,000 gal/well and a median average injection volume of 57,500 gal/well (Halliburton, Inc., 2003). Depending on the basin and treatment design, the composition of these fluids varies significantly, from simple water and sand to complex polymeric substances with a multitude of additives. Types of fracturing fluids are discussed in greater detail in Chapter 4.
A variety of site-specific factors will influence the recovery efficiency of fracturing fluids. These factors are summarized as follows:
• Fluids can “leakoff” (flow away) from the primary hydraulically induced fracture into smaller secondary fractures. The fluids then become trapped in the secondary fractures and/or pores of porous rock.
• Fluids can become entrapped due to the “check-valve effect,” wherein fractures narrow again after the injection of fracturing fluid ceases, formation pressure decreases, and extraction of methane and groundwater begins.
• Some fluid constituents can become adsorbed to coal or react chemically with the formation.
• Some volume of the fluids, moving along the hydraulically induced fracture, may move beyond the capture zone of the pumping well, and thus cannot be recovered during fluid recovery. The capture zone of the production well is that portion of the aquifer that contributes water to the well.
• Some fluid constituents may not completely mix with groundwater and therefore would be difficult to recover during production pumping.
Fluids can be “lost” (i.e., remain in the subsurface unrecovered) due to “leakoff” into connected fractures and the pores of porous rocks (Figure 3-7). Fracturing fluids injected into the primary hydraulically induced fracture can intersect and flow (leakoff) into preexisting smaller natural fractures. Some of the fluids lost in this way may occur very close to the well bore after traveling minimal distances in the hydraulically induced fracture before being diverted into other fractures and pores. The volume of fracturing fluids that may be lost in this way depends on the permeability of the rocks and the surface area of the fracture(s). The high injection pressures of hydraulic fracturing can force the fracturing fluids to be transported deep into secondary fractures. The cleats in coal are presumed to play an important role in leakoff (Olson, 2001). Movement into smaller fractures and cleats can be to a point where flowback efforts will not recover them. The pressure reduction caused by pumping during subsequent production is not sufficient to recapture all the fluid that has leaked off into the formation. The loss of fluids due to leakoff into small fractures and pores is minimized by the use of cross-linked gels, discussed in more detail in Chapter 4.
A check-valve effect occurs when natural or propagating fractures open and allow fluids to flow through when fracturing pressure is high, but subsequently prevent the fluids from flowing back towards the production well as they close after fracturing pressure decreases (Warpinski et al., 1988; Palmer et al., 1991a). A long fracture can be pinched off at some distance from the well. This reduces the effective fracture length available to transport methane from various locations within the coalbed to the production well. Fluids trapped beyond the “pinch point” are unlikely to be recovered during flowback. In most cases, when the fracturing pressure is released, the fracture closes in response to natural subsurface compressive stresses. Because the primary purpose of hydraulic fracturing is to increase the effective permeability of the target formation and connect new or widened fractures to the well, a closed fracture is of little use. Therefore, a component of coalbed methane production well development is to “prop” the fracture open, so that the enhanced permeability from the pressure-induced fracturing persists even after fracturing pressure is terminated. To this end, operators use a system of fluids and “proppants” to create and preserve a high-permeability fracture-channel from the well into the formation.
The check-valve effect takes place in locations beyond the zone where proppants have been emplaced (or in smaller secondary fractures that have not received any proppant). Because of the heterogeneous, stratified, and fractured nature of coal deposits, it is likely that some volume of stimulation fluid cannot be recovered due to its movement into zones that were not completely “propped.” Adsorption and Chemical Reactions Adsorption and chemical reactions can prevent the fluid from being recovered. Adsorption is the process by which fluid constituents adhere to a solid surface (i.e., the coal, in this case) and are thereby unavailable to flow with groundwater. Adsorption to coal is likely; however, adsorption to other surrounding geologic material (e.g., shale, sandstone) is likely to be minimal. Another possible reaction affecting the recovery of fracturing fluid constituents is the neutralization of acids (in the fracturing fluids) by carbonates in the subsurface.
Movement of Fluids Outside the Capture Zone
Fracturing fluids injected into the target coal zone flow into fractures under very high pressure. The hydraulic gradients driving fluid flow away from the well during injection are much greater than the hydraulic gradients pulling fluid flow back towards the production well during flowback and production pumping. Some portion of the coalbed methane fracturing fluids could be forced along the hydraulically induced fracture to a point beyond the capture zone of the production well. The size of the capture zone will be affected by the regional groundwater gradients, as well as by the drawdown caused by the well. If fracturing fluids have been injected to a point outside of the well’s capture zone, they will not be recovered through production pumping and, if mobile, may be available to migrate through an aquifer. Site-specific geologic, hydrogeologic, injection pressure, and production pumping details would provide the information needed to estimate the dimension of the production well capture zone and the extent to which the fracturing fluids might travel, disperse, and dilute.
Incomplete Mixing of Fracturing Fluids with Water
Steidl (1993) documented the occurrence of a gelling agent that did not dissolve completely and formed clumps at 15 times the injected concentration in the fracture induced by one well. Steidl (1993) also directly observed, in his mined-through studies, gel hanging in stringy clumps in many other fractures induced by that one well. As Willberg et al. (1997) noted, laboratory studies indicate that fingered flow of water past residual gel may impede fluid recovery. Therefore, some fracturing fluid gels appear not to flow with groundwater during production pumping and remain in the subsurface unrecovered. Such gels are unlikely to flow with groundwater during production, but may present a source of gel constituents to flowing groundwater during and after production.
Since 1980, coalbed methane production has grown rapidly, spurred by tax incentives to develop non-conventional energy production. … Methane within coalbeds is not “trapped” under pressure as in conventional gas scenarios. Only about 5 to 9 percent of the methane is present as “free” gas within the natural fractures, joints, and cleats. Almost all coalbed methane is adsorbed within the micro-porous matrix of the coal (Koenig, 1989; Winston, 1990; Close, 1993). … Coalbed methane production starts with high-pressure injection of fracturing fluids and proppant into targeted coal zones. The resulting induced or enlarged fractures improve the connections of the production well to the fracture networks in and around the coal zone. When production begins, water is pumped from the fractures in the coal zone to reduce pressure in the formation. When pressures are adequately reduced, methane desorbs from the coal matrix, moves through the network of induced and natural fractures in the coal toward the production well, and is extracted through the well and to the surface.
Fractures that are created at shallow depths (less than approximately 1,000 feet) typically have more of a horizontal than a vertical component. Vertical fractures created at deeper depths can propagate vertically to shallower depths where they may develop a horizontal component. These “T-fractures” may involve the fracture “turning” and developing horizontally at a coalbed-mudstone interface.
Fracture behavior through coal, shale, and other geologic strata commonly present in coal zones depends on site-specific factors such as relative thicknesses and in-situ stress differences between the target coal seam(s) and the surrounding geologic strata, as well as the presence of pre-existing natural fractures. Often, a high stress contrast between adjacent geologic strata results in a barrier to fracture propagation. This occurs in coal zones where there is a geologic contact between a high-stress coal seam and an overlying, thick, relatively low-stress shale.
The fluids used for fracture development are injected at high pressure into the targeted coal zone in the subsurface. These fluids may be “clear” (primarily consisting of water, but may include acid, oil, or water with friction-reducer additives) or “gelled” (viscositymodified water using guar or other gelling agents). Hydraulic fracturing in coalbed methane wells may require 50,000 to 350,000 gallons of fracturing fluids and 75,000 to 320,000 pounds of sand as proppant to prop or maintain the opening of fractures after the injection (fracturing) pressure is reduced (Holditch et al., 1988 and 1989; Jeu et al., 1988; Hinkel et al., 1991; Holditch, 1993; Palmer et al., 1991b, 1993a, and 1993b). More typical injection volumes, based on average injection volume data provided by Halliburton for six coalbed methane locations, indicate a maximum average injection volume of 150,000 gal/well and a median average injection volume of 57,500 gal/well (Halliburton, Inc., 2003).
In any fracturing job, some fracturing fluids cannot be recovered and are said to be “lost” to the formation. Palmer (1991a) observed that for fracture stimulations in multi-layered coal formations, 61 percent of stimulation fluids were recovered during a 19-day production sampling of a coalbed methane well in the Black Warrior Basin. He further estimated that from 68 percent to possibly as much as 82 percent would eventually be recovered. A variety of site-specific factors, including leakoff into the coal seams and surrounding strata, the check-valve effect, adsorption and other geochemical processes, and flow through the hydraulic fracture beyond the well’s capture zone will serve to reduce recovery of hydraulic fracturing fluids injected into subsurface coal zones to promote coalbed methane extraction.
The mined-through studies by the U.S. Bureau of Mines (see Diamond, 1987a and b) and others provide important directly-measured characteristics of hydraulic fracturing in coal seams and surrounding strata. Further, paint tracer studies conducted as part of Diamond’s (1987a and b) mined-through studies can provide estimates on the extent of hydraulic fracturing fluid movement, which may be greater than the extent of sand-filled (propped) hydraulic fracture heights or lengths given fluid movement through natural fractures. These estimates of the extent of fluid movement are usually limited by the area exposed to mining. [Emphasis added]