Browsing by Author "Lopez Jimenez, Bruno Armando"
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- ItemOpen AccessCharacterization and Construction of 3D Numerical Simulators for Oil and Liquids-Rich Multi-Porosity Shale Reservoirs(2017) Lopez Jimenez, Bruno Armando; Aguilera, Roberto; Mehta, Sudarshan A.; Moore, Robert Gordon; Harding, Thomas Grant; Bentley, Laurence Robert; Camacho-Velazquez, RodolfoProduction from oil and shale gas-condensate reservoirs in the United States and Canada has increased during the past few years. However, an understanding of shale rocks and fluid flow through them is still limited. Thus, the objective of this research is to develop methodologies for characterizing multi-porosities in shale petroleum reservoirs and for simulating fluid flow of oil and condensates through these types of rocks. The characterization part is carried out with the use of (1) an original petrophysical model built for quantification of total organic carbon (TOC), Knudsen number, water saturation, and multiple porosities in shales, (2) measurement of gas permeability from shale samples in the laboratory using commercial equipment, and (3) an original laboratory-based correlation for estimating stress-dependent permeability, porosity and compressibility of tight rocks. The simulation part is carried out with the use of (1) an original radial numerical model developed for calculating sorption-dependent permeability of shales, (2) a commercial 3D model for investigating pore size-dependency of pressure-temperature envelopes in shale gas-condensate reservoirs, and (3) an original fully-implicit 3D-3phase pseudo-compositional model for oil and condensate shale reservoirs developed with capabilities to handle multiple porosities and stress-dependent properties of natural and hydraulic fractures. Key challenges include the handling of (1) adsorbed porosity, (2) organic porosity, (3) inorganic porosity, (4) natural fracture porosity, (5) hydraulic fracture porosity, (6) diffusion from solid kerogen, and (7) fluid transport in the small pores of shales, which deviate significantly from the behavior in conventional reservoirs. It is concluded that the methods developed in this thesis provide important foundation for the characterization and simulation of shale petroleum reservoirs.
- ItemOpen AccessShale Gas Numerical Simulation: A Quintuple Porosity Approach(2014-07-17) Lopez Jimenez, Bruno Armando; Aguilera, RobertoNatural gas is stored in shales in different ways: (1) gas adsorbed in the kerogen material, (2) free gas in inorganic inter-particle and intraparticle (matrix) porosity, (3) free gas in a pore network developed within the organic matter or kerogen, (4) free gas in microfracture and slot porosity, and (5) free gas stored in hydraulic fractures created during stimulation of the shale reservoir. An additional storage element is provided by gas dissolved in kerogen. These observations and the dominant nanoscale porosity in shale reservoirs were the focus of the present research and led to the following original developments: 1. A method for calculating an adsorbed porosity based on the strict definition of porosity, i.e., ratio of pore volume to bulk volume. Mathematical expressions for both intrinsic and scaled to bulk volume adsorbed porosities are presented in this thesis. 2. A physics-based quintuple porosity model for handling storage and fluid flow in shale gas reservoirs. The governing equations that describe the gas mass balance in the quintuple porosity model are presented in detail. 3. 2D radial and orthogonal numerical simulation fully implicit models built from scratch for handling the different types of porosities mentioned above and diffusion of gas dissolved in kerogen. The adsorbed porosity mentioned in item 1 above is based on calculation of the thickness of the methane adsorbed monolayer and the size of organic pores in shales at a given pressure and temperature. The complexity of quintuple porosity shales radial and orthogonal numerical models mentioned in items 2 and 3 above is high but they account successfully for viscous and non-Darcy flow in shale nanopores (slip flow and Knudsen diffusion). Consequently, they help to provide a better understanding of the flow mechanisms occurring in these reservoirs. Real data from Devonian gas shales are used to illustrate the effect of free gas, adsorbed gas and dissolved gas in kerogen in a material balance crossplot of P/Z vs. cumulative gas production. It is concluded that not taking into account all the porosities mentioned above plus diffusion of gas dissolved in kerogen can lead to pessimistic values of original gas in place (OGIP) and recoveries. This has been the case of Devonian shales in the Appalachian Basin in North-Eastern United States where hydraulically fractured vertical wells have been producing for several decades far beyond original expectations. In many cases fluid flow has been observed to go on for 25 years without reaching boundary dominated flow.