Shale gas formation exhibits some unusual reservoir characteristics: nano-darcy matrix permeability, presence of natural fractures and gas storage on the matrix surface that makes it unique in many ways. It’s difficult to design an optimum fracture treatment for such formation and even more difficult is to describe production behavior using a reservoir model. So far homogeneous, two wing fracture, and natural fracture models have been used for this purpose without much success. Micro seismic mapping technique is used to measure the fracture propagation in real time. This measurement in naturally fractured shale formation suggests a growth of fracture network instead of a traditional two wing fractures. There is an industry wise consensus that fracture network plays an important role in determining the well productivity of such formations. A well with high density of fracture networks supposed to have better productivity. Shale formations have also exhibited production pattern which is very different from conventional or tight gas reservoir. Initial flow period is marked by steep decline in production while the late time production exhibits a slow decline. One of the arguments put for this behavior is linear flow from a bi-wing fractured well at early time and contribution of adsorbed gas in production at late time. However, bi-wing fracture geometry is not supported by the micro-seismic observation. A realistic model should include both the fracture network and adsorbed gas property. In this research we have proposed a new Power Law Permability model to simulate fluid flow from hydraulically fractured Shale formation. This model was first described by Valko & Fnu (2002) and used for analyzing acid treatment jobs. The key idea of this model is to use a power law permeability function that varies with the radial distance from well bore. Scaling exponent of this power law function has been named power law index. The permeability function has also been termed as secondary permeability. This work introduces the method of Laplace solution to solve the problem of transient and pseudo steady-state flow in a fracture network. Development and validation of this method and its extension to predict the pressure (and production) behaviour of fracture network were made using a novel technic. Pressure solution was then combined with material balance through productivity index to make production forecast. Reservoir rock volume affected by the fracture stimulation treatment that contributes in the production is called effective stimulated volume. This represents the extent of fracture network in this case. Barnett shale formation is a naturally fractured shale reservoir in Fort Worth basin. Several production wells from this formation was analysed using Power Law Model and it was found that wells productivity are highly dependent on stimulated volume. Apparently the wells flow under pseudo steady state for most part of their producing life and the effect of boundary on production is evident in as soon as one months of production. Due to short period of transient flow production from Barnett formations is expected to be largely independent of the relative distribution of permeability and highly dependent on the stimulated area and induced secondary permeability. However, an indirect relationship between permeability distribution and production rate is observed. A well with low power law index shows a better (more even) secondary permeability distribution in spatial direction, larger stimulated volume and better production. A comparative analysis between the new model and traditional fracture model was made. It was found that both models can be used successfully for history matching and production forecasting from hydraulically fractured shale gas formation.

Shale gas extraction is a technology that is recently arriving in Europe and Germany. The technology brings about a considerable amount of potential environmental threats, but the extraction of shale gas also promises energy security rewards. When the European and German systems for energy and environmental regulation were developed, shale gas extraction did not exist as a technical possibility. Both systems are, hence, not entirely adapted to this technology. This work highlights different ways in which the European and German legislator could act to close existing gaps in their regulatory systems. This could mainly be done by supplementing the existing system with new, shale gas specific regulations. These regulations should be summarized in a new-build shale gas law. The current work tracks the different stages of development of such a new shale gas law, starting from the level of rather abstract constitutional objectives, which translate into clearer defined environmental principles, which in turn translate into a concrete law. Experience from other European states with the legal handling of shale gas extraction teaches that there are essentially two different orientations for such a new-build shale gas law. One is the adoption of a prohibitive moratorium and the other is the implementation of a cautious, but permissive shale gas law. This work`s original contribution to knowledge is the insight that constitutional pre-settings on the interplay of environmental protection with energy security make a cautious, but permissive shale gas law a measure that is legally sounder than a shale gas moratorium. Legally sound, in this context, means complying, to the greatest extent possible, with the applicable constitutional and quasi-constitutional objectives. A shale gas moratorium only serves one purpose, environmental protection, and does not take sufficient account of the energy security objective. A shale gas moratorium only serves one purpose, environmental protection, and does not take sufficient account of the energy security objective. A cautious, but permissive shale gas law, by contrast, possesses the ability to reconcile the competing interests of environmental protection and energy security, which makes it more resilient to judicial review than a moratorium. Having said that, it must be emphasised that shale gas regulation is ultimately a political decision and the legislator is allowed to pick either of the described solutions. This work merely describes which solution is the legally soundest in the sense defined above. To sum up, results from this study will extent what is currently known about the constitutional pre-conditions for the development of shale gas regulation. It highlight that constitutional objectives have a significant impact on the shape of energy regulation.

Shale gas development is transforming the energy landscape in the United States. Advances in production technologies, notably the dual application of horizontal drilling and hydraulic fracturing, allow the extraction of vast deposits of trapped natural gas that, until recently, were uneconomic to produce. The objective of this work is to develop mixed-integer programming models to support upstream operators in making faster and better decisions that ensure low-cost and responsible natural gas production from shale formations. We propose a multiperiod mixed-integer nonlinear programming (MINLP) model along with a tailored solution strategy for strategic, quality-sensitive shale gas development planning. The presented model coordinates planning and design decisions to maximize the net present value of a field-wide development project. By performing a lookback analysis based on data from a shale gas producer in the Appalachian Basin, we find that return-to-pad operations are the key to cost-effective shale gas development strategies. We address impaired water management challenges in active development areas through a multiperiod mixed-integer linear programming (MILP) model. This model is designed to schedule the sequence of fracturing jobs and coordinate impaired- and freshwater deliveries to minimize water management expenses, while simultaneously maximizing revenues from gas sales. Based on the results of a real-world case study, we conclude that rigorous optimization can support upstream operators in cost-effectively reducing freshwater consumption significantly, while also achieving effective impaired water disposal rates of less than one percent. We also propose a multiperiod MINLP model and a tailor-designed solution strategy for line pressure optimization in shale gas gathering systems. The presented model determines when prospective wells should be turned in-line, and how the pressure profile within a gathering network needs to be managed to maximize the net present value of a development project. We find that backoff effects associated with turn-in line operations can be mitigated through preventive line pressure manipulations. Finally, we develop deterministic and stochastic MILP models for refracturing planning. These models are designed to determine whether or not a shale well should be restimulated, and when exactly to refracture it. The stochastic refracturing planning model explicitly considers exogenous price forecast uncertainty and endogenous well performance uncertainty. Our results suggest that refracturing is a promising strategy for combatting the characteristically steep decline curves of shale gas wells.

The current state of shale gas reservoir dynamics demands understanding long-term production, and existing models that address important parameters like fracture half-length, permeability, and stimulated shale volume assume constant permeability. Petroleum geologists suggest that observed steep declining rates may involve pressure-dependent permeability (PDP). This study accounts for PDP in three potential shale media: the shale matrix, the existing natural fractures, and the created hydraulic fractures. Sensitivity studies comparing expected long-term rate and pressure production behavior with and without PDP show that these two are distinct when presented as a sequence of coupled build-up rate-normalized pressure (BU-RNP) and its logarithmic derivative, making PDP a recognizable trend. Pressure and rate field data demonstrate evidence of PDP only in Horn River and Haynesville but not in Fayetteville shale. While the presence of PDP did not seem to impact the long term recovery forecast, it is possible to determine whether the observed behavior relates to change in hydraulic fracture conductivity or to change in fracture network permeability. As well, it provides insight on whether apparent fracture networks relate to an existing natural fracture network in the shale or to a fracture network induced during hydraulic fracturing.

Successful development of shale gas reservoirs is highly dependent on hydraulic fracture treatments. Many questions remain in regards to the geometry of the created fractures. Production data analysis from some shale gas wells quantifies a much smaller stimulated pore volume than what would be expected from microseismic evidence and reports of fracturing fluids reaching distant wells. In addition, claims that hydraulic fracturing may open or reopen a network of natural fractures is of particular interest. This study examines hydraulic fracturing of shale gas formations with specific interest in fracture geometry. Several field cases are analyzed using microseismic analysis as well as net pressure analysis of the fracture treatment. Fracture half lengths implied by microseismic events for some of the stages are several thousand feet in length. The resulting dimensions from microseismic analysis are used for calibration of the treatment model. The fracture profile showing created and propped fracture geometry illustrates that it is not possible to reach the full fracture geometry implied by microseismic given the finite amount of fluid and proppant that was pumped. The model does show however that the created geometry appears to be much larger than half the well spacing. From a productivity standpoint, the fracture will not drain a volume more than that contained in half of the well spacing. This suggests that for the case of closely spaced wells, the treatment size should be reduced to a maximum of half the well spacing. This study will provide a framework for understanding hydraulic fracture treatments in shale formations. In addition, the results from this study can be used to optimize hydraulic fracture treatment design. Excessively large treatments may represent a less than optimal approach for developing these resources.

Reserves estimation in unconventional (low/ultra-low permeability) reservoirs has become a topic of increased interest as more of these resources are being developed, especially in North America. The estimation of reserves in unconventional reservoirs is challenging due to the long transient flow period exhibited by the production data. The use of conventional methods (i.e., Arps' decline curves) to estimate reserves is often times inaccurate and leads to the overestimation of reserves because these models are only (theoretically) applicable for the boundary-dominated flow regime. The premise of this work is to present and demonstrate a methodology which continuously estimates the ultimate recovery during the producing life of a well in order to generate a time-dependent profile of the estimated ultimate recovery (EUR). The "objective" is to estimate the final EUR value(s) from several complimentary analyses. In this work we present the "Continuous EUR Method" to estimate reserves for unconventional gas reservoirs using a rate-time analysis approach. This work offers a coherent process to reduce the uncertainty in reserves estimation for unconventional gas reservoirs by quantifying "upper" and "lower" limits of EUR prior to the onset of boundary-dominated flow. We propose the use of traditional and new rate-time relations to establish the "upper" limit for EUR. We clearly demonstrate that rate-time relations which better represent the transient and transitional flow regimes (in particular the power law exponential rate decline relation) often lead to a more accurate "upper" limit for reserves estimates — earlier in the producing life of a well (as compared to conventional ("Arps") relations). Furthermore, we propose a straight line extrapolation technique to offer a conservative estimate of maximum produced gas which we use as the "lower" limit for EUR. The EUR values estimated using this technique continually increase with time, eventually reaching a maximum value. We successfully demonstrate the methodology by applying the approach to 43 field examples producing from 7 different tight sandstone and shale gas reservoirs. We show that the difference between the "upper" and "lower" limit of reserves decreases with time and converges to the "true" value of reserves during the latter producing life of a well.

This study examines the regional stratigraphic architecture, depositional systems, and petrographic characteristics of the South Texas Pearsall shale-gas system currently developed in the Indio Tanks (Pearsall) and Pena Creek (Pearsall) fields. The Pearsall Formation was deposited as a mixed carbonate-siliciclastic system on a distally steepened ramp over a period of 11.75 million years. It was deposited between maximum floods of two second-order sequences and contains at least five third-order cycles. Up to three Oceanic Anoxic Events (OAE 1-A, Late Aptian Regional Event, and OAE 1-B) figure prominently in the deposition of the Pearsall sediments, and during these intervals, depending on the location within the Maverick Basin, sedimentation rates were between 0.5 and 2 cm/ky. Facies in the Pearsall section arise from interactions between pre-existing topography, oxygenation regime, eustatic sea-level fluctuation, and depositional processes. In the Pearsall Formation, OAEs affected depositional environments and resulting facies patterns during several time periods. The OAEs occurred in association with transgressions but not necessarily in concert with them. Outer ramp OAE facies are siliciclastic-dominated, TOC-rich, and little-bioturbated. Conversely the outer ramp facies deposited under normally oxygenated paleoenvironmental conditions tend to be carbonate-rich, TOC-poor, and are more prominently bioturbated. / text

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Shale gas reservoirs have become a major source of energy in recent years. Developments in hydraulic fracturing technology have made these reservoirs more accessible and productive. Apart from other dissimilarities from conventional gas reservoirs, one major difference is that a considerable amount of gas produced from these reservoirs comes from desorption. Ignoring a major component of production, such as desorption, could result in significant errors in analysis of these wells. Therefore it is important to understand the adsorption phenomenon and to include its effect in order to avoid erroneous analysis. The objective of this work was to imbed the adsorbed gas in the techniques used previously for the analysis of tight gas reservoirs. Most of the desorption from shale gas reservoirs takes place in later time when there is considerable depletion of free gas and the well is undergoing boundary dominated flow (BDF). For that matter BDF methods, to estimate original gas in place (OGIP), that are presented in previous literature are reviewed to include adsorbed gas in them. More over end of the transient time data can also be used to estimate OGIP. Kings modified z* and Bumb and McKee’s adsorption compressibility factor for adsorbed gas are used in this work to include adsorption in the BDF and end of transient time methods. Employing a mass balance, including adsorbed gas, and the productivity index equation for BDF, a procedure is presented to analyze the decline trend when adsorbed gas is included. This procedure was programmed in EXCEL VBA named as shale gas PSS with adsorption (SGPA). SGPA is used for field data analysis to show the contribution of adsorbed gas during the life of the well and to apply the BDF methods to estimate OGIP with and without adsorbed gas. The estimated OGIP’s were than used to forecast future performance of wells with and without adsorption. OGIP estimation methods when applied on field data from selected wells showed that inclusion of adsorbed gas resulted in approximately 30 percent increase in OGIP estimates and 17 percent decrease in recovery factor (RF) estimates. This work also demonstrates that including adsorbed gas results in approximately 5percent less stimulated reservoir volume estimate.

The Mississippian Barnett Formation is a prolific shale-gas reservoir that was deposited in the Fort Worth Basin, Texas. Many previous studies of the Barnett Formation have been conducted in the main production area; few studies have been made of the Barnett Formation in the southern part of the basin, which is a less productive area. In the present research, several cores from the Barnett Formation in Hamilton County, southeast Fort Worth Basin, are studied in detail. Two vertical, continuous cores from Hamilton County, Texas, were studied to delineate the depositional setting, lithofacies, pore types, and reservoir quality of the Barnett Formation in the area. Five lithofacies were defined by analysis of the two cores: (1) laminated clay-rich silty and skeletal peloidal siliceous mudstone; 2) laminated skeletal silty peloidal siliceous mudstone; 3) nonlaminated silty peloidal calcareous mudstone; 4) laminated and nonlaminated skeletal calcareous mudstone; and 5) skeletal phosphatic packstone to grainstone. As indicated from this study, the dominant organic matter type is a mixture of Type II (major) and Type III (minor) kerogen having a mean TOC content of approximately 4%. Analysis of Rock Eval data shows that most of the interval is within the oil window; calculated Ro is approximately 0.9%. Organic geochemistry shows that the hydrocarbon generation potential of the abundant oil-prone kerogen was excellent. Mineralogical analysis reveals that the two types of siliceous mudstone, which are similar in composition to the siliceous mudstone in the main producing area in the northern Fort Worth Basin, are good for hydraulic fracturing and production, but they are also limited by their marginal thickness. Organic matter pores, which are the dominant pore types in these two cores, are consistent with pore types found in currently producing wells in the Newark East Field. This research also suggests that the deposition of Barnett Formation was controlled largely by basinal geometry, suspension settling, and slope-originated gravity-flow events. Skeletal deposits and carbonate-silt starved ripples suggest gravity-flow deposits and bottom-current reworking during deposition. Redox-sensitive elements and degree of pyritization both indicate anoxic/euxinic conditions during the deposition of the Barnett Formation. / text