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.

The objective of this thesis is to analyze the considerations regarding the environmental impacts of shale gas development by a rational, objective, fact-based assessment. Flowback and produced water from shale gas development can be treated with the related technologies on-site or off-site for recycling, reuse, discharge, and disposal. However, more efficient technologies should be researched even though current levels are high. Besides, the amount of water used in shale gas development is generally lower than that of other energy sources and most shale gas plays are located in areas with moderate to high levels of annual precipitation. However, growing populations, other industrial water demands, and seasonal variation in precipitation should be considered during shale gas development. Groundwater contamination is directly connected to the integrity of the well casing, not hydraulic fracturing, because there are significant spacious gap and several impermeable layers between target formations and ground water zones. Hydraulic fracturing rarely creates unwanted induced seismicity because the seismic energy created from hydraulic fracturing is too low to be detected in the surface, compared to the waste injection well. / text

The McCully gas field is located approximately 10 km from the town of Sussex in southern New Brunswick, Canada. There are currently 32 active natural gas production wells which produce dry gas and condensates from the low-permeability Hiram Brook sandstone and Frederick Brook shale members of the Carboniferous Albert formation. The wells range from inclined to vertical, and have been hydraulically fractured in order to stimulate production. This study provides new geochemical data that allows for characterization of deep fluids in the McCully field and the porewaters in four shallow cores from fractured sandstone and siltstone units drilled adjacent to gas wells. Deep formation fluids of the Hiram Brook and Frederick Brook reservoirs were characterized by sampling production gas and produced water from the wellheads of production wells. Chemical and stable isotope compositions of the gas samples were determined by gas chromatography (GC) and gas-chromatography isotope-ratio-mass-spectroscopy (GC-IRMS), and compositions of the water samples were determined by inductively-coupled-plasma mass spectroscopy (ICP-MS), optical-emission spectroscopy (ICP-OES), and isotope-ratio mass spectroscopy (IRMS). Results indicate that gas compositions differ significantly between the two reservoirs, with the deeper Frederick Brook displaying greater maturity and evidence of isotope reversal. Results from the production water samples indicate that the salinity of formation water is as high as 53,600 mg/kgw (milligrams per kilogram water), and that salinity of the formation water was likely derived from a marine source. However, the strength of conclusions about the formation water composition is limited because the produced water was affected by refluxing in the wellhead, and by the formation of precipitates after sampling. Porewater from low-permeability drill-core samples was extracted using the ‘paper-absorption’ method. Vertical composition profiles were prepared for four observation wells, and the data indicate that porewater composition in these rocks is strongly controlled by lithology, redox conditions, and proximity to fractures that act as conduits for meteoric water.

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.

No description available.

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.

An investigation of shale pore structure and compositional/geochemical heterogeneities has been undertaken to elucidate the controls upon gas capacities of potential shale gas reservoirs in northeastern British Columbia, western Canada. Methane sorption isotherms, pore structure and surface area data indicate a complex interrelationship of total organic carbon (TOC) content, mineral matter and thermal maturity affect gas sorption characteristics of Devonian-Mississippian (D-M) and Jurassic strata. Methane and carbon dioxide sorption capacities of D-M shales increase with TOC content, due to the microporous nature of the organic matter. Clay mineral phases are also capable of sorbing gas to their internal structure; hence D-M shales which are both TOC- and clay-rich have the largest micropore volumes and sorption capacities on a dry basis. Jurassic shales, which are invariably less thermally mature than D-M shales, do not have micropore volumes which correlate with TOC. The covariance of methane sorption capacity with TOC, independent of micropore volume, indicates a solute gas contribution (within matrix bituminite) to the total gas capacity. On a wt% TOC basis, D-M shales sorb more gas than Jurassic shales: a result of thermal-maturation induced, structural transformation of the D-M organic fraction. Organic-rich D-M strata are considered to be excellent candidates for gas shales in Western Canada. These strata have TOC contents ranging between 1-5.7 wt%, thermal maturities into the dry-gas region, and thicknesses in places of over 1000 m. Total gas capacity estimates range between 60 and 600 bcf/section where a substantial percentage of the gas capacity is free gas, due to high reservoir temperatures and pressures. Inorganic material influences modal pore size, total porosity and sorption characteristics of D-M shales. Carbonate-rich samples often have lower organic carbon contents (oxic deposition) and porosity, hence potentially lower sorbed and free-gas capacities. Highly mature Devonian shales are both silica and TOC-rich (up to 85% quartz and 5 wt% TOC) and as such, deemed excellent potential shale gas reservoirs because they are both brittle(fracable), and gas-charged. However, quartz-rich Devonian shales display tight-rock characteristics, with poorly developed fabric, small median pore diameters and low permeabilities. Hence potential `frac-zones' will require an increased density of hydraulic fracture networks for optimum gas production.

Shale gas formations are known to have low permeability. This low permeability can be as low as 100 nano darcies. Without stimulating wells drilled in the shale gas formations, it is hard to produce them at an economic rate. One of the stimulating approaches is by drilling horizontal wells and hydraulically fracturing the formation. Once the formation is fractured, different flow patterns will occur. The dominant flow regime observed in the shale gas formation is the linear flow or the transient drainage from the formation matrix toward the hydraulic fracture. This flow could extend up to years of production and it can be identified by half slop on the log-log plot of the gas rate against time. It could be utilized to evaluate the hydraulic fracture surface area and eventually evaluate the effectiveness of the completion job. Different models from the literature can be used to evaluate the completion job. One of the models used in this work assumes a rectangular reservoir with a slab shaped matrix between each two hydraulic fractures. From this model, there are at least five flow regions and the two regions discussed are the Region 2 in which bilinear flow occurs as a result of simultaneous drainage form the matrix and hydraulic fracture. The other is Region 4 which results from transient matrix drainage which could extend up to many years. The Barnett shale production data will be utilized throughout this work to show sample of the calculations. This first part of this work will evaluate the field data used in this study following a systematic procedure explained in Chapter III. This part reviews the historical production, reservoir and fluid data and well completion records available for the wells being analyzed. It will also check for data correlations from the data available and explain abnormal flow behaviors that might occur utilizing the field production data. It will explain why some wells might not fit into each model. This will be followed by a preliminary diagnosis, in which flow regimes will be identified, unclear data will be filtered, and interference and liquid loading data will be pointed. After completing the data evaluation, this work will evaluate and compare the different methods available in the literature in order to decide which method will best fit to analyze the production data from the Barnett shale. Formation properties and the original gas in place will be evaluated and compared for different methods.

The estimation of porosity, water saturation, kerogen concentration, and mineral composition is an integral part of unconventional shale reservoir formation evaluation. Porosity, water saturation, and kerogen content determine the amount of hydrocarbon-in-place while mineral composition affects hydro-fracture generation and propagation. Effective hydraulic fracturing is a basic requirement for economically viable flow of gas in very-low permeability shales. Brittle shales are favorable for initiation and propagation of hydraulic fracture because they require marginal or no plastic deformation. By contrast, ductile shales tend to oppose fracture propagation and can heal hydraulic fractures. Silica and carbonate-rich shales often exhibit brittle behavior while clay-rich shales tend to be ductile. Many operating companies have turned their attention to neutron capture gamma-ray spectroscopy (NCS) logs for assessing in-situ mineral composition. The NCS tool converts the energy spectrum of neutron-induced captured gamma-rays into relative elemental yields and subsequently transforms them to dry-weight elemental fractions. However, NCS logs are not usually included in a well-logging suite due to cost, tool availability, and borehole conditions. Conventional well logs are typically acquired as a minimum logging program because they provide geologists and petrophysicists with the basic elements for tops identification, stratigraphic correlation, and net-pay determination. Most petrophysical interpretation techniques commonly used to quantify mineral composition from conventional well logs are based on the assumption that lithology is dominated by one or two minerals. In organic shale formations, these techniques are ineffective because all well logs are affected by large variations of mineralogy and pore structure. Even though it is difficult to separate the contribution from each mineral and fluid component on well logs using conventional interpretation methods, well logs still bear essential petrophysical properties that can be estimated using an inversion method. This thesis introduces an inversion-based workflow to estimate mineral and fluid concentrations of shale gas formations using conventional well logs. The workflow starts with the construction and calibration of a mineral model based on core analysis of crushed samples and X-Ray Diffraction (XRD). We implement a mineral grouping approach that reduces the number of unknowns to be estimated by the inversion without loss of accuracy in the representation of the main minerals. The second step examines various methods that can provide good initial values for the inversion. For example, a reliable prediction of kerogen concentration can be obtained using the ΔlogR method (Passey et al., 1990) as well as an empirical correlation with gamma-ray or uranium logs. After the mineral model is constructed and a set of initial values are established, nonlinear joint inversion estimates mineral and fluid concentrations from conventional well logs. An iterative refinement of the mineral model can be necessary depending on formation complexity and data quality. The final step of the workflow is to perform rock classification to identify favorable production zones. These zones are selected based on their hydrocarbon potential inferred from inverted petrophysical properties. Two synthetic examples with known mineral compositions and petrophysical properties are described to illustrate the application of inversion. The impact of shoulder-bed effects on inverted properties is examined for the two inversion modes: depth-by-depth and layer-by-layer. This thesis also documents several case studies from Haynesville and Barnett shales where the proposed workflow was successfully implemented and is in good agreement with core measurements and NCS logs. The field examples confirm the accuracy and reliability of nonlinear inversion to estimate porosity, water saturation, kerogen concentration, and mineral composition. / text

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.