Thesis (doctoral)--University of Tartu, 2006. / Thesis based on four papers.

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.

A severe shortage of many, to mankind, valuable elements are to be expected in the near future. Therefor is it of utmost importance to find these deposits and a way to refine the elements with as little negative effect on the environment as possible. One deposit of valuable elements such as U, V, Mo and Sr are the so called alum shale. Alum shale is a variety of sulfidic black shale which is rich in pyrite, FeS2, and organic carbon. Primary due to its contents of hydrocarbons and uranium the alum shale has been mined at different sites throughout Sweden. One of these sites was Kvarntorp in the region of Närke. The shale which had have its contents of hydrocarbons extracted through dry distillation was dumped into a heap that is now known as Kvarntorpshögen. The remaining hydrocarbons that this processed material still contain are to this day (2011) warm, with temperatures up to some hundred degrees Celsius. Due to this heat, infiltration of rainwater is held at a minimum. What no one knows however; is for how long Kvarntorpshögen will remain warm. Once it cools; many toxic elements will leak into the surrounding environment due to natural weathering caused by precipitation and frost wedging. The study also included a heating treatment of 70°C which is a temperature that the material of Kvarntorpshögen may be capable of generating by itself. This is assumed to be a good temperature for weathering processes; because it increases the kinetics of chemical reactions but also allows the presence of water. The results of this study shows that summer will be the season that contributes the most to the leaching of elements, of which some are toxic. Newly exposed surfaces of various shale materials often contain elements that is easily leached by water. Once this coat is washed away however, further leaching of that element decreases. Exceptions from this pattern in some shale products were shown by for example vanadium and molybdenum. The digestion data show that the completely processed shale, which makes up the majority of Kvarntorpshögen, still have a high content of rare and valuable elements. Making Kvarntorpshögen itself interesting for extraction processes in the future.

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.

Thesis (Ph. D.)--University of Texas at Austin, 2001. / Vita. Includes bibliographical references. Available also from UMI/Dissertation Abstracts International.

Thesis (Ph. D.)--University of Texas at Austin, 2001. / Vita. Includes bibliographical references (leaves 156-166). Available also in a digital version from Dissertation Abstracts.

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

A sizable amount of literature exists analyzing the effect of confining stress on fracture conductivity in sandstones. This thesis attempts to answer similar questions with regard to shale formations. The low Young’s Moduli and Brinell hardness values characteristic of many prospective shale formations may lead to a great deal of embedment and fines production which can drastically reduce fracture conductivity. Furthermore, shales exhibit sensitivity to aqueous fluids which may cause them to be weakened in the presence of certain fracturing fluids. Previous work analyzing shale fluid sensitivity has failed to preserve the shales’ formation properties by allowing the shale to dry out. This paper presents a study of propped fracture conductivity experiments at reservoir temperature and pressure using various North American shale reservoir cores. Exposure to the atmosphere can alter the mechanical properties of the shale by either drying or hydrating the samples, so care was taken to preserve these shales in their native state by maintaining constant water activity (relative humidity). Variations in applied closure stress and aqueous fluid exposure were analyzed and in certain cases altered the propped fracture conductivity by crushing proppant, embedding the proppant into the fracture face, and producing fines. The damage to fracture conductivity is correlated to mineralogy for the various shale samples. These findings show that a one-size-fits-all frac design will not work in every shale formation, rather a tailored approach to each shale is necessary. In the future, the results of this work will be analyzed alongside easier to perform Brinell hardness tests, swelling tests, and other characterization techniques incorporated into the UT Shale Characterization Protocol. Correlations were developed to relate the simpler tests to the fracture conductivity experiments which yield a straight forward method to determine the role embedment and fluid sensitivity have on post treatment fracture conductivity in shales. The UT Shale characterization Protocol can then be used to optimize the design and execution of fracing treatments. / text

After the success of shale gas development in the United States, countries around the world are looking within their own territories for the possibility of replicating the U.S successes in order to achieve financial and/or energy security objectives. Such enterprise has shown to be not as easy as it might have been perceived to be. Some countries like Argentina, China and Poland, where large reserves of shale resources have been identified, have struggled to obtain beneficial results from their shale operations, with the result that even the more optimistic operators are now showing more caution and are reviewing everything before making any commitments to operate in countries with identified shale resources. Colombia, a country with strong oil and gas roots in its economic history, is actively attempting to attract operators to explore and produce their shale resources. If successful, these efforts have the potential to bring increased foreign investment to the country, while also improving Colombia’s oil and gas reserves, which have been declining over the last five years. This thesis, will address the challenges and opportunities of the development of shale resources in Colombia that operators will face by reviewing several critical aspects of the process. This thesis begins with a discussion of the geology of shale resources in Colombia, followed, first, by a review and analysis of the fiscal and contractual regime established in Colombia for the oil and gas industry, then, second, a risk analysis of possible Colombian shale operations, then third, a financial analysis of a possible shale project and, finally, ends with a summary of the challenges and opportunities an operator could face based on the analysis of the previous topics. / text

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