Tight gas sands, coal-bed methane, and gas shales are commonly called unconventional reservoirs. Tight gas sands (TGS) are often described as formations with an expected average permeability of 0.1mD or less. Gas production rates from TGS reservoirs are usually low due to poor permeability. As such, state-of-the-art technology must be used to economically develop the resource. TGS formations need to be hydraulically fractured in order to enhance the gas production rates. A majority of these reservoirs can be described as thick, multilayered gas systems. Many reservoirs are hundreds of feet thick and some are thousands of feet thick. The technology used to complete and stimulate thick, tight gas reservoirs is quite complex. It is often difficult to determine the optimum completion and stimulating techniques in thick reservoirs. The optimum methods are functions of many parameters, such as depth, pressure, temperature, in-situ stress and the number of layers. In multilayered reservoirs, it is important to include several sand layers in a single completion. The petroleum literature contains information on the various diversion techniques involved in the completion of these multilayered reservoirs. In this research, we have deduced and evaluated eight possible techniques that have been used in the oil and gas industry to divert multilayered fracture treatments in layered reservoirs. We have developed decision charts, economic analyses and computer programs that will assist completion engineers in determining which of the diversion methods are feasible for a given well stimulation. Our computer programs have been tested using case histories from the petroleum literature with results expressed in this thesis. A limited entry design program has also being developed from this research to calculate the fluid distribution into different layers when fracture treating multilayered tight gas reservoirs using the limited entry technique. The research is aimed at providing decision tools which will eventually be input into an expert advisor for well completions in tight gas reservoirs worldwide.

Tight gas sands, coal-bed methane, and gas shales are commonly called unconventional reservoirs. Tight gas sands (TGS) are often described as formations with an expected average permeability of 0.1mD or less. Gas production rates from TGS reservoirs are usually low due to poor permeability. As such, state-of-the-art technology must be used to economically develop the resource. TGS formations need to be hydraulically fractured in order to enhance the gas production rates. A majority of these reservoirs can be described as thick, multilayered gas systems. Many reservoirs are hundreds of feet thick and some are thousands of feet thick. The technology used to complete and stimulate thick, tight gas reservoirs is quite complex. It is often difficult to determine the optimum completion and stimulating techniques in thick reservoirs. The optimum methods are functions of many parameters, such as depth, pressure, temperature, in-situ stress and the number of layers. In multilayered reservoirs, it is important to include several sand layers in a single completion. The petroleum literature contains information on the various diversion techniques involved in the completion of these multilayered reservoirs. In this research, we have deduced and evaluated eight possible techniques that have been used in the oil and gas industry to divert multilayered fracture treatments in layered reservoirs. We have developed decision charts, economic analyses and computer programs that will assist completion engineers in determining which of the diversion methods are feasible for a given well stimulation. Our computer programs have been tested using case histories from the petroleum literature with results expressed in this thesis. A limited entry design program has also being developed from this research to calculate the fluid distribution into different layers when fracture treating multilayered tight gas reservoirs using the limited entry technique. The research is aimed at providing decision tools which will eventually be input into an expert advisor for well completions in tight gas reservoirs worldwide.

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