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.

Shale gas has become increasingly important to United States energy supply. During recent decades, the mechanisms of shale gas storage and transport were gradually recognized. Gas desorption was also realized and quantitatively described. Models and approaches special for estimating rate decline and recovery of shale gas wells were developed. As the strategy of the horizontal well with multiple transverse fractures (MTFHW) was discovered and its significance to economic shale gas production was understood, rate decline and pressure transient analysis models for this type of well were developed to reveal the well behavior. In this thesis, we considered a “Triple-porosity/Dual-permeability” model and performed sensitivity studies to understand long term pressure drawdown behavior of MTFHWs. A key observation from this study is that the early linear flow regime before interfracture interference gives a relationship between summed fracture half-length and permeability, from which we can estimate either when the other is known. We studied the impact of gas desorption on the time when the pressure perturbation caused by production from adjacent transference fractures (fracture interference time) and programmed an empirical method to calculate a time shift that can be used to qualify the gas desorption impact on long term production behavior. We focused on the field case Well A in New Albany Shale. We estimated the EUR for 33 wells, including Well A, using an existing analysis approach. We applied a unified BU-RNP method to process the one-year production/pressure transient data and performed PTA to the resulting virtual constant-rate pressure drawdown. Production analysis was performed meanwhile. Diagnosis plots for PTA and RNP analysis revealed that only the early linear flow regime was visible in the data, and permeability was estimated both from a model match and from the relationship between fracture halflength and permeability. Considering gas desorption, the fracture interference will occur only after several centuries. Based on this result, we recommend a well design strategy to increase the gas recovery factor by decreasing the facture spacing. The higher EUR of Well A compared to the vertical wells encourages drilling more MTFHWs in New Albany Shale.

The objective of this paper is to help new investors and project developers identify the challenges of shale gas E&P and to enlighten them of the currently available strategies so that they can develop the best project plan and execute it without suffering unexpected challenges. This paper categorizes the challenges into five groups and concentrates on shale-gas-specific challenges. It excludes conventional oil and gas development challenges because by and large these five major challenge groups seem to decide the success and failure of most shale gas projects. The five groups are the identification of shale gas potentials, the technical challenges in well design and stimulation strategies, the economic challenges such as high cost of new technologies, the environmental challenges concerning the hydraulic fracturing water, and the international challenges of performing projects outside the US. The strategies are yet to be well established and are still evolving rapidly. Hence, before starting a shale gas project, shale gas developers need to perform extensive and intensive check-ups on the challenges and on current available strategies as well as to stay up to date thereafter on new strategies. / text

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

In today’s energy sector, it has been observed a revolutionary increase in shale gas recovery induced by reservoir fracking. So-called unconventional reservoirs became profitable after introducing a well stimulation technique. Some of the analysts expect that shale gas is going to expand worldwide energy supply. However, there is still a lack of an efficient as well as accurate modeling techniques, which can provide a good recovery and production estimates. Gas transports in shale reservoir is a complex process, consisting of slippage effect, gas diffusion along the wall, viscous flow due to the pressure gradient. Conventional industrial simulators are unable to model the flow as the flow doesn’t follow Darcy’s formulation. It is significant to build a unified model considering all given mechanisms for shale reservoir production study and analyze the importance of each mechanism in varied conditions. In this work, a unified mathematical model is proposed for shale gas reservoirs. The proposed model was build based on the dual porosity continuum media model; mass conservation equations for both matrix and fracture systems were build using the dusty gas model. In the matrix, gas desorption, Knudsen diffusion and viscous flow were taken into account. The model was also developed by implementing thermodynamic calculations to correct for the gas compressibility, or to obtain accurate treatment of the multicomponent gas. Previously, the model was built on the idealization of the gas, considering every molecule identical without any interaction. Moreover, the compositional variety of shale gas requires to consider impurities in the gas due to very high variety. Peng-Robinson equation of state was used to com- pute and correct for the gas density to pressure relation by solving the cubic equation to improve the model. The results show that considering the compressibility of the gas will noticeably increase gas production under given reservoir conditions and slow down the production decline curve. Therefore, for a more accurate prediction of shale gas production, it is crucial to consider compressibility behavior of the gas.

Measuring transport properties of rock samples under stress is essential to understanding and predicting the migration of fluids within the Earth's crust. Mudrocks play an essential role in petroleum systems as they are often the source rock and may act as a seal due to their low permeability. With increasing production from unconventional reservoirs where the mudrock is source, reservoir and seal, there is now even greater demand to understand the permeability and storativity of mudstones and tight sandstones. When hydraulic fracture treatment is used to enhance production, flow of hydrocarbons into the fractures will be ultimately controlled by the matrix permeability. Knowledge of the fluid transport properties of mudstones is currently hindered by a scarcity of published experimental data. In this thesis, a combination of permeability and ultrasonic velocity measurements allied with image analysis is used to distinguish the primary microstructural controls on effective stress dependent permeability. Permeabilities of cylindrical samples of Whitby Mudstone and Eagle Ford Shale have been measured using the oscillating pore pressure method at confining pressures ranging between 30-95 MPa and pore pressures ranging between 1-80 MPa. The results show that samples must be pressure cycled in order to obtain a reproducible behaviour, after which the relationship between permeability and effective stress can be described by an exponential law. The permeability of the Whitby Mudstone samples ranges between 7 ×10-21 m2 and 2 ×10-19 m2 (7 nd to 188 nd) and decreases by ~1 order of magnitude across the applied effective stress range. The permeability of the Eagle Ford Shale samples is slightly higher ranging between 2 ×10-18 m2 and 42 ×10-18 m2 (2 μd to 42 μd) and decreases by half an order of magnitude across the applied effective stress range. Permeability is shown to be more sensitive to changes in pore pressure than changes in confining pressure yielding values of alpha between 1.1-2.1 for Whitby Mudstone and 1.6-4.6 for Eagle Ford Shale. Gas slippage (Klinkenberg) effects are restricted to pore pressures below 10 MPa in the Whitby Mudstone and therefore do not affect the results presented. The permeability-effective stress relationship is thus empirically described using a modified effective stress law in terms of confining pressure, pore pressure and a Klinkenberg effect. Use of a simple reservoir model demonstrates that if pressure dependent permeability is not taken into account, substantial overestimation of gas flow rate and original gas in place will be made from well tests. Changes in ultrasonic velocity and pore volume were related to the observed loss of permeability with increasing effective stress, providing further insight into the nature of the permeability-controlling pore network. Combining the petrophysical data with pore conductivity modelling and microstructural analysis shows that at low effective stresses, permeability is controlled by a network of long, thin crack-like pores associated with grain boundaries. At high effective stresses, these cracks are closed and fluid is restricted to flowing through a less permeable network of higher aspect ratio, stiffer, nm-scale pores in the clay matrix. Applying the methods developed in the present work to different mudstones with a range of compositions and textures will help to refine understanding of the variability in fluid-conducting pore networks, thereby advancing the interpretation of data from well logs and well tests used for reservoir evaluation.

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In this research the conflict between economic and conservation imperatives in the proposed exploration of shale gas in the South Western Karoo Basin was investigated. The primary aim of this study was to come to a theoretical understanding of the situation through a critical analysis of existing documents which allowed me to outline in detail the two opposing perspectives that either promote or resist a shale gas exploration project. The second objective of this research was to present empirical data from both a questionnaire completed by 20 respondents and two interviews, that helps amplify and verify arguments for or against a shale gas exploration project. The theoretical and empirical components of the research offer the basis for a balanced assessment of the viability of shell gas exploration in the Karoo. Using three fundamental assessment criteria (social, economic and environmental) for what constitutes a sustainable development project the gathered data was analysed in order to help ascertain whether or not the shale gas exploration project is a worthwhile development project. The question answered was whether a shale gas exploration project meets its social, economic and environmental mandates. From this, the final objective of this research was to make recommendations concerning what a responsible policy would be concerning land use in the Karoo.