One of the most prominent unexplained phenomena observed in the Marcellus and some other shale plays is the concentration of dissolved salts in produced waters after hydraulic stimulation. In this paper, we present both geochemical and lithologic laboratory and field data to address the salt question. Is salt being dissolved from the shale, or are deep saline aquifers being breached during hydraulic fracturing? What evidence do we have to support or refute either theory? To address these questions, over 100 flowback analyses were collected over 18 months from both the southwestern and northeastern regions of the Marcellus Shale play. These data incorporate both cation and anion water analyses in either a full or partial determination of the cation and anion balance. Detailed inorganic geochemical and mineralogical analyses of shale samples were integrated to help determine the presence or absence of physical evidence of minerals that may be the root cause for high salinity. If present in the shale, is halite dissolution desirable from a formation stimulation perspective? If so, is this gain a worthwhile trade when balanced against the costs of returned load water handling and reuse or disposal? This paper provides interpretations at both the regional and local scales to try to explain basinal variations observed in the data. It discusses implications of the phenomenon of high saline frac flowback fluids, along with methods being used to mitigate environmental problems associated with the post-frac flowback water geochemistry. Problem Statement Our own and citizen concerns about the potential environmental impacts on surface water purity, municipalities' worries about possible diminishing fresh water supplies, and increased scrutiny by various regulatory agencies are drivers behind efforts by the natural gas industry to reduce both the consumptive use of fresh water by large fracture stimulation jobs and subsequent discharge of post-frac flowback fluids to the environment. This is especially the case in the Marcellus Shale play in Pennsylvania, where rapid development is occurring and deep-well disposal capacity is very scarce. Highly saline produced waters from Marcellus wells are presenting an enormous challenge to both regulators and operators. Flowback waters from the Marcellus characteristically carry high levels of total dissolved solids (TDS) in the form of soluble chloride salts. The make-up water used to fracture the well is normally fresh. Operating and well-service companies have approached the problem of renewable freshwater supply by separating, filtering, and even distilling produced formation waters and frac-fluid flowback waters for future use or surface discharge (Weatherford Telegram 2007). What to do with the post-frac flowback waters in the light of scarce brine disposal facilities and substantial handling costs is an enormous burden to the economic development of the Marcellus natural gas resource. In the Commonwealth of Pennsylvania, new regulatory limits have been proposed further limiting discharges. The Pennsylvania Department of Environmental Protection announced on April 15, 2009 that all industrial discharges will be limited to 500 mg/L TDS on January 1, 2011. There are currently no facilities in the state that can treat flowback fluids to this level. The options for an economic solution are few for operators in dealing with these saline flowback fluids. Evaporation/crystallization (EC), the only established technology for treatment of the produced waters that can achieve the newly proposed TDS limit, produces a very highly concentrated brine solution or large volumes of crystalline salt cake that still must be disposed. A 1 million gal/day crystallization plant will generate approximately 400 tons/day of salt waste. Unless some beneficial use for these residues can be found, they will require disposal in a secure solid waste facility. A typical municipal landfill cannot accept large volumes of crystalline salts and suitable facilities can do so only at a premium. Further, an EC plant is very energy intensive and thus has the potential for increased air quality impact and greenhouse gas emissions in addition to its cost of operation. The Marcellus shale gas industry may be left with no economically viable disposal options.
In general shale is thought to be relatively nonreactive to low pH or acidic fluids. This is because of the general belief the clay, silt, and organic materials comprising the major components of shale formations exhibit insignificant bulk solubility in acid. What we find however is that shale units are highly laminated and contain acid-soluble minerals homogenized in the shale bulk matrix and natural fractures. XRD analysis and SEM images of shale samples show a great diversity and distribution of soluble material in the shale producing unit. SEM images of the shale fracture face before and after exposure to certain reactive fluids show a remarkable amount of surface texture disruption and micro-etching of the fractured surface. Based on these observations, it is concluded that reactive fluids are capable of (1) enhancing gas diffusion into and through narrow-aperture induced fractures, and (2) increasing surface area for flow of gas from the shale matrix. Such fluids are also capable of enhancing flow through mineral-filled microcracks or other secondary porosity. Initial production response from wells treated with reactive low pH fluids has been promising. This paper documents X-ray and SEM analyses of many shale plays in Oklahoma. Production enhancement mechanisms are proposed to explain the observed physical effects of these fluids on shale. Introduction Shale can be defined as a laminated sediment in which the constituent particles are predominantly of the clay size (<0.004 mm, <0.000157-in.) distribution. Shale includes the indurated, laminated, or fissile claystones and siltstones. The anisotropy is that of bedding and such other secondary cleavage or fissility that is approximately parallel to bedding. The secondary cleavage has been produced by the pressure of overlying sediments, dewatering during diagenesis, and plastic flow. The fine particles that compose shale can remain suspended in water long after the larger and denser particles of sand have deposited out. Shales are typically deposited in low-energy environments and are often found in lake and lagoonal deposits, in river deltas, on floodplains, and offshore of beach/sand bar systems. Major producing shales exist throughout the U.S. (Fig. 1). Samples of Woodford, Caney, and Barnett shales are used in this paper to illustrate the diverse makeup of mid-continent shale. Fig. 1-Major shale plays in the U.S. Productive shale plays are unique in that they are source rock, reservoir rock, and trap. The primary storage and producing mechanism of shales are a topic of heated debate. In general, most agree that there is a "free" and "adsorbed" component of hydrocarbon present in most shale plays. Exactly where the hydrocarbon is and how it got there are still topics of research. A conceptual model that seems to have some degree of acceptance is one where the "free gas" is stored and produced from microporosity in lamina and natural fractures and the "adsorbed gas" is stored and produced from the bulk shale matrix (Fig. 2). Shale Types In general, we have classified the shale plays in the U.S. with the descriptions shown in Table 1.
Early stimulation work in Peat Field of Queensland, Australia involved application of cavity completion techniques to produce methane gas at commercial rates in the first wells completed in the reservoir gas cap. Early in the project life, cavity completion treatments resulted in promising and acceptable gas flow rates. However, excessive cost associated with this technique led to consideration of alternate stimulation approaches by the design team. The main objective was to achieve similar or better gas rates at the lowest cost. Multi-seam nitrogen-foam stimulation was conducted in several wells of the Peat field to assess the effectiveness of this technique in terms of:production enhancement and cost reduction;location of the coal-seam intervals in the gas cap (i..e. gas-saturated coals) and;improved completion efficiency. To minimise the effects of tortuosity and multiple far-field fractures in addition to ensuring that each coal-seam interval received adequate treatment, a staged stimulation approach in combination with other remedies such as sand slugs and high injection rates was adopted and successfully applied. Zonal Isolation was achieved through the use of the newly developed, easily drillable composite plugs that allow staged treatment with flowback capabilities. Field data of representative Peat wells will be used to demonstrate the successful application of the hydraulic fracturing approach that resulted in methane gas rates that more than compete with the early cavity completion techniques either from a cost or production improvement point of view. The following specifics are addressed in the paper:A novel fracture design approach and modeling of fracturing treatments that can be of value to a broad audience of operators and design engineers.Real-time fracture stimulation methodology, analysis, and execution.Remedies to minimize the near-wellbore tortuosity and multiple far field fractures to avoid premature "screenout" and carry the fracture treatment to completion.Chemical optimization of fracture fluid designed based on coal characteristics.Use of newly developed composite epoxy-glass fracture and bridge plugs that provide a more efficient and cost effective way to carry out staged stimulation treatments.Post-fracture production tests to estimate the nitrogen-foam fracture treatment effectiveness in multi-seam CBM wells. Introduction The Peat field1 is located on the eastern edge of the Bowen Basin about 20 km east of the town of Wandoan (Fig. 1). The field is approximately 8 km wide and 26 km long and comprises Late Permian Baralaba Coal Measures overlying the Burunga Anticline, the largest anticlinal feature in the Bowen Basin. Aggregate net coal thicknesses range from about 7.1 m to 22.7 m over an interval of between 100 m to 140 m. Individual seam thicknesses range up to 13.7 m. Coal depths range from 600 m below ground and are currently being investigated to as deep as 1200 m. Within 15 km to the west coal depths reach over 2000 m.
This paper provides a look-back review of lessons learned from early exploration to the full-scale development phase of the Marcellus shale in Pennsylvania. Fracture stimulation of over 100 wells has resulted in an in-depth understanding of details needed to achieve optimal frac performance. Much of the necessary learning curve is derived from the empirical testing of theory and what many refer to as "trial and error." The ability to evaluate and capture the best practices and develop them into a standing operating procedure (SOP) is one of the most important aspects in development of a new unconventional play. Lessons learned involving fracturing strategies and technologies to date have greatly narrowed the learning curve enabling more rapid advancement toward full-scale development. Introduction Shale reservoirs are characterized by extremely low permeability rock that has a number of unique attributes, including high organic content, high clay content, extremely fine grain size, plate-like microporosity, little to no macroporosity, and fickian vs. darcy flow through the rock matrix. This combination of traits has led to the evolution of hydraulic-fracture stimulation involving high rates, low-viscosities, and large volumes of proppant. Production from shale is dependent upon many variables including hydrocarbon content, total organic carbon, shale maturity, porosity, permeability, kerogen content, formation pressure, and net thickness. Improvements in drilling and completion techniques have improved gas recovery, namely landing a horizontal borehole strategically and creating a series of multiple staged hydraulic fractures. Even though horizontal drilling and fracturing have become the completion methods most commonly applied, a significant number of successful wells are being completed vertically in the Marcellus Shale. The extremely low permeability of shale requires a complex fracture to create primary induced fractures, reactivate and/or intercept more naturally occurring fractures or parting planes and ultimately expose more surface area. Early increased production is dependent upon the number of natural fractures intercepted and long-term production is dependent upon the amount of surface area exposed in the fracture network. Total improved production is dependent upon complex fracture geometry, which is influenced by many factors: stress contrasts, fluid leakoff, natural fractures, layering, weak planes, brittleness, fracture height growth, differing critical stress, post-fracture retention of connectivity to the created frac network, and mechanical stratigraphy, which controls the frac network creation. Large stimulation volumes of slickwater have been employed to create the extremely complex fracture fairway. High rate is needed to carry the large proppant volumes in a slickwater system and stimulation is achieved by bridging and diverting in induced fractures and natural fractures. The created fracture network is more productive than a dominant single fracture plane in a shale reservoir because more surface area is exposed for gas desorption and long-term natural gas production. Although many lessons have been learned from previous successful shale plays, many new lessons and unique "tricks of the trade" have been developed or tailored specifically for the Marcellus. This is especially true of the fluid systems and geochemical environment that has driven a number of new developments and fluid innovations.
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