The ever increasing energy demand brings about widespread interest to rapidly, profitably and efficiently develop unconventional resources, among which tight gas sands hold a significant portion. However, optimization of development strategies in tight gas fields is challenging, not only because of the wide range of depositional environments and large variability in reservoir properties, but also because the evaluation often has to deal with a multitude of wells, limited reservoir information, and time and budget constraints. Unfortunately, classical full-scale reservoir evaluation cannot be routinely employed by small- to medium-sized operators, given its timeconsuming and expensive nature. In addition, the full-scale evaluation is generally built on deterministic principles and produces a single realization of the reservoir, despite the significant uncertainty faced by operators. This work addresses the need for rapid and cost-efficient technologies to help operators determine optimal well spacing in highly uncertain and risky unconventional gas reservoirs. To achieve the research objectives, an integrated reservoir and decision modeling tool that fully incorporates uncertainty was developed. Monte Carlo simulation was used with a fast, approximate reservoir simulation model to match and predict production performance in unconventional gas reservoirs. Simulation results were then fit with decline curves to enable direct integration of the reservoir model into a Bayesian decision model. These integrated tools were applied to the tight gas assets of Unconventional Gas Resources Inc. in the Berland River area, Alberta, Canada.

With the rapidly increasing demand for energy and the increasing prices for oil and gas, the role of unconventional gas reservoirs (UGRs) as energy sources is becoming more important throughout the world. Because of high risks and uncertainties associated with UGRs, their profitable development requires experts to be involved in the most critical development stages, such as drilling, completion, stimulation, and production. However, many companies operating UGRs lack this expertise. The advisory system we developed will help them make efficient decisions by providing insight from analogous basins that can be applied to the wells drilled in target basins. In North America, UGRs have been in development for more than 50 years. The petroleum literature has thousands of papers describing best practices in management of these resources. If we can define the characteristics of the target basin anywhere in the world and find an analogous basin in North America, we should be able to study the best practices in the analogous basin or formation and provide the best practices to the operators. In this research, we have built an advisory system that we call the Unconventional Gas Reservoir (UGR) Advisor. UGR Advisor incorporates three major modules: BASIN, PRISE and Drilling & Completion (D&C) Advisor. BASIN is used to identify the reference basin and formations in North America that are the best analogs to the target basin or formation. With these data, PRISE is used to estimate the technically recoverable gas volume in the target basin. Finally, by analogy with data from the reference formation, we use D&C Advisor to find the best practice for drilling and producing the target reservoir. To create this module, we reviewed the literature and interviewed experts to gather the information required to determine best completion and stimulation practices as a function of reservoir properties. We used these best practices to build decision trees that allow the user to take an elementary data set and end up with a decision that honors the best practices. From the decision trees, we developed simple computer algorithms that streamline the process.

With the growing interest in low-permeability gas plays, foam fracturing fluids are now well established as a viable alternative to traditional fracturing fluids. Present practices in energized fracturing treatments remain nonetheless rudimentary in comparison to other fracturing fluid technologies because of our limited understanding of multi-phase fluid-loss and phase behavior occurring in these complex fluids. This report assesses the fluid-loss benefits introduced by energizing the fracturing fluid. A new laboratory apparatus has been specifically designed and built for measuring the leak-off rates for both gas and liquid phases under dynamic fluid-loss conditions. This report provides experimental leak-off results for linear guar gels and for N2-guar foam-based fracturing fluids under a wide range of fracturing conditions. In particular, the effects of the rock permeability, the foam quality, and the pressure drop are investigated. Analysis of dynamic leak-off data provide an understanding of the complex mechanisms of viscous invasion and filter-cake formation occurring at the pore-scale. This study presents data supporting the superior fluid-loss behavior of foams, which exhibit minor liquid invasion and limited damage. It also shows direct measurements of the ability of the gas component to leak-off into the invaded zone, thereby increasing the gas saturation around the fracture and enhancing the gas productivity during flowback. Our conclusions not only confirm, but add to the findings of McGowen and Vitthal (1996) for linear gels, and the findings of Harris (1985) for nitrogen foams. / text

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

Unconventional natural gas resources, particularly tight gas sands, constitute a significant percentage of the natural gas resource base and offer abundant potential for future reserves and production. The premise of this research is that several unique characteristics of these rocks are the consequence of post depositional diagenetic processes including mechanical compaction, quartz and other mineral cementation, and mineral dissolution. These processes lead to permanent alteration of the initial pore structure causing an increase in the number of isolated and disconnected pores and thus in the tortuosity. The objective of this research is to develop a pore scale model of the geological processes that create tight gas sandstones and to carry out drainage simulations in these models. These models can be used to understand the flow connections between tight gas sandstone matrix and the hydraulic fractures needed for commercial production rates. We model depositional and diagenetic controls on tight gas sandstones pore geometry such as compaction and cementation processes. The model is purely geometric and begins by applying a cooperative rearrangement algorithm to produce dense, random packings of spheres of different sizes. The spheres are idealized sand grains. We simulate the evolution of these model sediments into low-porosity (3% to 10%) sandstone by applying different amount of ductile grains and quartz precipitation. A substantial fraction of the original pore throats in the sediment are closed by the simulated diagenetic alteration. Thus, the pore space in typical tight gas sandstones is poorly connected, and is often close to being completely disconnected, with significant effect on flow properties. The drainage curves for model rocks were computed using invasion percolation in a network taken directly from the grain-scale geometry and topology of the model. The drainage simulations show clear percolation behavior, but experimental data frequently do not. This implies that either network models based on intergranular void space are not a good tool for modeling of tight gas sandstone or the experiments are not correctly done on tight gas samples. In addition to reducing connectivity, the porosity-reducing mechanisms change pore throat size distributions. These combined effects shift the drainage water relative permeability curve toward higher values of water saturation, and gas relative permeability shifts toward smaller values of gas. Comparison of simulations with measured relative permeabilities shows a good match although same network fail to match drainage curves. This could happens because the model gives the right fluid configuration but at the wrong values of curvature and saturation. The significance of this work is that the model correctly predicts the relative permeabilities of tight gas sandstones by considering the microscale heterogeneity. The porosity reduction due to ductile grain deformation is a new contribution and correctly matches with experimental data from literature. The drainage modeling of two-phase flow relative permeabilities shows that the notion of permeability jail, a range of saturations over which both gas and water relative permeabilities are very small, does not occur during drainage. / text

Lower Cambrian Eriboll Formation sandstones of the Ardvreck Group that crop out in the Hebridean foreland west of the Paleozoic Moine Thrust Zone (MTZ) in the Northwest Highlands of Scotland contain five sets of opening-mode fractures with varying degrees of quartz deposits (cement) and topographically prominent but small displacement (mostly less than 10 m) northeast-striking faults. The faults crosscut and in some places displace the MTZ. I interpret these faults to post-date the MTZ and consider them to be late structures (kinematically unrelated to MTZ emplacement). Sparse slip lineations on fault surfaces and offset patterns are evidence for strike-slip to oblique slip. Using geologic mapping I show that relative to their lateral and vertical extents, the faults display small amounts of offset (less than 5 to 10 m). My research documented the patterns and petrology of fractures in a well exposed section of the foreland, documented for the first time fracture patterns adjacent to and within the post-MTZ fault zones, and proposes an account of how fault and fracture patterns developed and their probable effects on fluid flow. Fractures are barren (joints), partially filled (quartz lined), or completely filled (veins). Older fracture sets are typically completely filled, whereas younger sets may be lined with a thin veneer of quartz cement or are barren. Listed in order from oldest to youngest fractures containing quartz strike north, NW to WNW, NE, west, and north (sets A through E respectively). Previously proposed relative ages of the sets were confirmed using crosscutting relationships and preferred orientations of macro- and microfractures (Laubach and Diaz-Tushman, 2009). This study focuses on late northeast-striking fractures (set C) which I interpret to be related to the formation of the small-offset faults. Many of the attributes of late fractures and faults in the Eriboll Formation resemble those found in core from highly quartz cemented sandstone natural gas reservoirs ("tight gas sandstones"). I demonstrate that the well exposed fracture patterns I documented are good analogs for tight gas sandstones, by investigating fracture characteristics such as network configurations and connectivity, fracture intensity (abundance), fracture scaling, fracture length and spacing, and the degree of quartz cement deposits in fractures and cataclastic fault rock. Many of the narrow macroscopic fractures and microfractures I documented using CL methods contain varying amounts of quartz deposits. The excellent preservation of Eriboll outcrops is probably a manifestation of little or no fracture pore space preservation in many of the numerous fractures that are apparent in outcrop. Set C fracture abundance is not distributed in a uniform envelope (or "halo") around the late faults. Using scanlines, I show that set C fracture distribution is heterogeneous and highly variable over short lateral distances (tens of centimeters to meters). I also investigate wing crack assemblages (secondary opening-mode fractures) that are locally associated with set C fractures. The assemblages accommodate small amounts of the distributed displacement (a few millimeters) adjacent to fault zones and are locally responsible for increased amounts of fracture connectivity by linking neighboring fractures. Variations in fracture pattern complexity appears to be related to the presence (or absence) of wing crack assemblages. Localized wing crack development on closely spaced, en echelon set C fractures also leads to precursory development of fragmented lozenges of highly deformed volumes of rock (damage zones) that resemble geometries similar to those seen in preserved Eriboll fault cores. Fault-related deformation in the Eriboll Formation is markedly different than that in the underlying Late Proterozoic Torridonian Applecross Formation (subarkose fluvial sandstone), which is characterized by simple halos fault-related fracture arrays surrounding the same late (post-MTZ) faults. In addition to composition, the Eriboll and Applecross differ in mechanical layer thickness (centimeters versus > tens of meters), mechanical properties (high versus low brittleness), and greater propensity for fractures to be filled with quartz cement in Eriboll sandstones owing to quartz cement growth being impaired by the abundance of non-quartz substrate (feldspar and clay minerals) along fracture walls in the Applecross Formation. Although the Eriboll sandstones are more highly fractured than the older Applecross sandstones, Eriboll fractures are more prone to be filled by quartz cement. In this thesis I also report previously unrecognized early (set A; pre-MTZ) minor normal faults, sandstone petrography and rock mechanical properties of selected Eriboll sandstone samples, and the influence of fractures on the glacial geomorphology of the area. I also describe a previously unmapped igneous dyke. I describe previously unrecognized vugs that are partly strata bound and partly localized along fractures. The attributes of these vugs and a review of the literature suggests that these features could represent evidence of pre-glacial silici-karst in Eriboll quartzites. / text

The large amount of produced oil and gas come from conventional resources all over the world and these resources are being depleted rapidly. This fact and the increasing oil and gas prices force the producing countries to find and search for new methods to recover more oil and gas. In order to meet the demand, the oil and gas industry has been turning towards to unconventional oil and gas reservoirs which become more popular every passing day. In recent years, they are seriously considered as supplementary to the conventional resources although these reservoirs cannot be produced at an economic rate or cannot produce economic volumes of oil and gas without assistance from massive stimulation treatments, special recovery processes or advanced technologies. The vast increase in demand for petroleum and gas has encouraged the new technological development and implementation. A wide range of technologies have been developed and deployed since 1980. With the wellbore technology, it is possible to make use of highly deviated wellbores, extended reach drilling, horizontal wells, multilateral wells and so on. All of the new technologies and a large number of new innovations have allowed development of increasingly complex economically marginal fields where shale gas and coal bed methane are found. In this study, primary target is to compare different production methods in order to obtain better well performance and improved production from different types of reservoirs. It is also be given some technical information regarding the challenges such as hydraulic fracturing and multilateral well configuration of the unconventional gas reservoir modeling and simulation. With the help of advances in algorithms, computer power, and integrated software, it is possible to apply and analyze the effect of the different well trajectories such as vertical, horizontal, and multilateral well on the future production performance of coal bed methane, shale gas, and tight gas reservoirs. A commercial simulator will be used to run the simulations and achieve the best-case scenarios. The study will lead the determination of optimum production methods for three different reservoirs that are explained above under the various circumstances and the understanding the production characteristic and profile of unconventional gas systems.

The so-called "Arps" rate decline relations are by far the most widely used tool for assessing oil and gas reserves from rate performance. These relations (i.e., the exponential and hyperbolic decline relations) are empirical where the starting point for their derivation is given by the definitions of the "loss ratio" and the "derivative of the loss ratio", where the "loss ratio" is the ratio of rate data to derivative of rate data, and the "derivative of the loss ratio" is the "b-parameter" as defined by Arps [1945]. The primary goal of this work is the interpretation of the b-parameter continuously over time and thus the better understanding of its character. As is shown below we propose "monotonically decreasing functional forms" for the characterization of the b-parameter, in addition to the exponential and hyperbolic rate decline relations, where the b-parameter is assumed to be zero and constant, respectively. The proposed equations are as follow: b(t)=constant (Arps' hyperbolic rate-decline relation), []tbbtb10exp)(-bt= (exponential function), (power-law function), 10)(btbtb=)/(1)(10tbbtb+= (rational function). The corresponding rate decline relation for each case is obtained by solving the differential equation associated with the selected functional for the b-parameter. The next step of this procedure is to test and validate each of the rate decline relations by applying them to various numerical simulation cases (for gas), as well as for field data cases obtained from tight/shale gas reservoirs. Our results indicate that b-parameter is never constant but it changes continuously with time. The ultimate objective of this work is to establish each model as a potential analysis/diagnostic relation. Most of the proposed models yield more realistic estimations of gas reserves in comparison to the traditional Arps' rate decline relations (i.e., the hyperbolic decline) where the reserves estimates are inconsistent and over-estimated. As an example, the rational b-parameter model seems to be the most accurate model in terms of representing the character of rate data; and therefore, should yield more realistic reserves estimates. Illustrative examples are provided for better understanding of each b-parameter rate decline model. The proposed family of rate decline relations was based on the character of the b-parameter computed from the rate-time data and they can be applied to a wide range of data sets, as dictated by the character of rate data.

The petroleum engineering literature clearly shows that large proppant volumes and concentrations are required to effectively stimulate low-permeability gas sands. To pump large proppant concentrations, one must use a viscous fluid. However, many operators believe that low-viscosity, low-proppant concentration fracture stimulation treatments known as ??waterfracs?? produce comparable stimulation results in low-permeability gas sands and are preferred because they are less expensive than gelled fracture treatments. This study evaluates fracture stimulation technology in tight gas sands by using case histories found in the petroleum engineering literature and by using a comparison of the performance of wells stimulated with different treatment sizes in the Cotton Valley sands of the East Texas basin. This study shows that large proppant volumes and viscous fluids are necessary to optimally stimulate tight gas sand reservoirs. When large proppant volumes and viscous fluids are not successful in stimulating tight sands, it is typically because the fracture fluids have not been optimal for the reservoir conditions. This study shows that waterfracs do produce comparable results to conventional large treatments in the Cotton Valley sands of the East Texas basin, but we believe it is because the conventional treatments have not been optimized. This is most likely because the fluids used in conventional treatments are not appropriate or have not been used appropriately for Cotton Valley conditions.

The Desmoinesian Marmaton Group, along the southern portion of the Anadarko Basin in the Granite Wash, comprises over 2,000 feet of stacked tight sandstones and conglomerates, containing unconventional reservoirs. Uncertainty around facies variability and lateral continuity of these reservoirs represents challenges to accurate reservoir characterization due to laterally restricted submarine fan systems, and mountainront faulting. This study examines 206 wire-line well-log suites and nine ice-house flooding surfaces across an 810-square mile study area to frame fine-scale sequences, track facies changes, and estimate fault timing and duration. This high-resolution stratigraphic framework comprises a hierarchy of cycles: one third-order, three fourth-order, and eight fifth-order cycles; these were mapped across fault blocks. Mapping at the fifth-order scale documented previously un-published faults, and showed that movement occurred during two separate fifth-order cycles. Within the stratigraphic framework, well log trends, calibrated to core descriptions, enabled prediction of depositional environments in uncored wells.