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 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 growing demand for energy provides an incentive to pursue unconventional resources. Among these resources, tight gas and shale gas reservoirs have gained significant momentum because recent advances in technology allowed us to produce them at an economical rate. More importantly, they seem likely to contain a significant volume of hydrocarbon. There are, however, many questions concerning hydrocarbon production from these unconventional resources. For instance, in tight gas sandstone, we observe a significant variability in the producibilities of wells in the same field. The heterogeneity is even present in a single well with changes in depth. It is not clear what controls this heterogeneity. In shale gas, the pore connectivity inside the void space is not well explored and hence, a representative pore model is not available. Further, the effects of an adsorbed layer of gas and gas slippage on shale permeability are poorly understood. These effects play a crucial role in assigning a realistic permeability for shale in-situ from a laboratory measurement. In the laboratory, in contrast to in-situ, the core sample lacks the adsorbed layer because the permeability measurements are typically conducted at small pore pressures. Moreover, the gas slippages in laboratory and in-situ conditions are not identical. The present study seeks to investigate these discrepancies. Drainage and imbibition are sensitive to pore connectivity and unconventional gas transport is strongly affected by the connectivity. Hence, there is a strong interest in modeling mercury intrusion capillary pressure (MICP) test because it provides valuable information regarding the pore connectivity. In tight gas sandstone, the main objective of this research is to find a relationship between the estimated ultimate recovery (EUR) and the petrophysical properties measured by drainage/imbibition tests (mercury intrusion, withdrawal, and porous plate) and by resistivity analyses. As a measure of gas likely to be trapped in the matrix during production---and hence a proxy for EUR---we use the ratio of residual mercury saturation after mercury withdrawal (S[subscript gr]) to initial mercury saturation (S[subscript gi]), which is the saturation at the start of withdrawal. Crucially, a multiscale pore-level model is required to explain mercury intrusion capillary pressure measurements in these rocks. The multiscale model comprises a conventional network model and a tree-like pore structure (an acyclic network) that mimic the intergranular (macroporosity) and intragranular (microporosity) void spaces, respectively. Applying the multiscale model to porous plate data, we classify the pore spaces of rocks into macro-dominant, intermediate, and micro-dominant. These classes have progressively less drainage/imbibition hysteresis, which leads to the prediction that significantly more hydrocarbon is recoverable from microporosity than macroporosity. Available field data (production logs) corroborate the higher producibility of the microporosity. The recovery of hydrocarbon from micro-dominant pore structure is superior despite its inferior initial production (IP). Thus, a reservoir or a region in which the fraction of microporosity varies spatially may show only a weak correlation between IP and EUR. In shale gas, we analyze the pore structure of the matrix using mercury intrusion data to provide a more realistic model of pore connectivity. In the present study, we propose two pore models: dead-end pores and Nooks and Crannies. In the first model, the void space consists of many dead-end pores with circular pore throats. The second model supposes that the void space contains pore throats with large aspect ratios that are connected through the rock. We analyze both the scanning electron microscope (SEM) images of the shale and the effect of confining stress on the pore size distribution obtained from the mercury intrusion test to decide which pore model is representative of the in-situ condition. We conclude that the dead-end pores model is more representative. In addition, we study the effects of adsorbed layers of CH₄ and of gas slippage in pore walls on the flow behavior in individual conduits of simple geometry and in networks of such conduits. The network is based on the SEM image and drainage experiment in shale. To represent the effect of adsorbed gas, the effective size of each throat in the network depends on the pressure. The hydraulic conductance of each throat is determined based on the Knudsen number (Kn) criterion. The results indicate that laboratory measurements made with N₂ at ambient temperature and 5-MPa pressure, which is typical for the transient pulse decay method, overestimate the gas permeability in the early life of production by a factor of 4. This ratio increases if the measurement is run at ambient conditions because the low pressure enhances the slippage and reduces the thickness of the adsorbed layer. Moreover, the permeability increases nonlinearly as the in-situ pressure decreases during production. This effect contributes to mitigating the decline in production rates of shale gas wells. Laboratory data available in the literature for methane permeability at pressures below 7 MPa agree with model predictions of the effect of pressure. / text

The Karoo Basin of South Africa holds an estimated 906 billion to 11 trillion cubic meters of unconventional shale gas within the shales of the Whitehill and Collingham formations of the Ecca Group. Evaluation of this potential resource has been limited due to the lack of exploration and a scarcity of existing drill core data. In order to circumnavigate this problem this study was undertaken to evaluate the potential target horizons exposed in outcrops along the southern portion of the Karoo Basin, north of Grahamstown in the Eastern Cape Province. Detailed field logging was done on the exposed Whitehill and Collingham formations as well as a possible conventional sandstone (turbidite) reservoir, the Ripon Formation, along road cuttings of the Ecca Pass. Palaeocurrent data, jointing directions and fossil material were also documented. Samples were analysed for mineralogy, porosity, permeability, and total organic carbon content (TOC). The extensively weathered black shales of the Whitehill Formation contain a maximum TOC value of 0.9% and the Collingham Formation shales contain a maximum TOC value of 0.6%. The organic lithic arkose sandstones of the Ripon Formation are classified as ‘tight rock’ with an average porosity of 1% and an average permeability of 0.05 mD. The Whitehill Formation in the southern portion of the Karoo Basin has experienced organic matter loss due to low grade metamorphism as well as burial to extreme depths, thus reducing shale gas potential. The Ripon Formation is an unsuitable conventional reservoir along the southern basin boundary due to extensive cementation and filling of pore spaces.