Date of Graduation

2018

Document Type

Thesis

Degree Type

MS

College

Statler College of Engineering and Mineral Resources

Department

Petroleum and Natural Gas Engineering

Committee Chair

Ming Gu

Committee Co-Chair

Kashy Aminian

Committee Member

Mehrdad Zamirian

Abstract

Shale reservoirs play an increasingly important role in energy supply worldwide. Horizontal wells and hydraulic fracturing have created a new mandate for a better understanding of the resulted production amounts from these shale reservoirs. A parametric study, based on Marcellus shale laboratory Precision Petrophysical Analysis Laboratory (PPAL) experimental data, and reservoir simulation is conducted to understand the effects of gas slippage effect and the geomechanical effects on gas production prediction and completion design. Therefore by analyzing the critical conductivity of a reservoir prior to production it is possible to design a fracture treatment (i.e. proppant pumping strategy) which will have positive impacts on the well performance and increased ROFI (Return on Fracturing Investment). The study is conducted for three shale reservoir scenarios; non-naturally fractured reservoir, low permeable naturally fractured reservoir, and high permeable naturally fractured reservoir.;In this study, we perform a comprehensive parametric study by running reservoir simulations using empirical permeability correlations developed by means of steady-state permeability data obtained under varying stress and pore pressure conditions. The full correlation incorporates both the gas slippage effect and the geomechanic effect. The contrast correlations consider either one of the effects or no effects at all. A simulation of the fluid flow in the hydraulic fracture and matrix are performed by a three-dimensional finite-difference based reservoir model. The primary and natural fractures are modeled explicitly as discrete grid blocks. Additionally, we study the impact of the two matrix permeability effects on the critical conductivity results for different bottomhole pressures, propped fracture lengths, and fracture half spacings. A similar study is also performed for the naturally fractured shale reservoir scenario. The impacts of the slippage effect (matrix) and the geomechanical effects (matrix & natural fracture) are investigated in the same way. Furthermore, an analysis of the geomechanical effect in just the natural fractures is performed, and finally an economic analysis based on the overlying trends from the study is implemented.;The following are key results found throughout the study. First, the gas slippage effect (matrix) appears to play a significant role at lower pore pressures below 1000 psi, and the geomechanical effect (matrix) is significant throughout all pressure levels (250--4500 psi) for the Marcellus Shale sample. Since most production pressure never goes below 1000 psi, it is apparent that the pore pressure effect is negligible. For the production prediction study the following results were determined for all three reservoir types (non-naturally fractured reservoir, low permeable naturally fractured reservoir, and high permeable naturally fractured reservoir). If the geomechanical effect (matrix) is ignored than production will be overestimated 2.3 to 14% from 1 to 20 years. If the pore pressure effect (matrix) is ignored the results are negligible (0.3 to 0.9% underestimation) from 1 to 20 years. In terms of the natural fracture study with low permeability (9.6228 mD), if the geomechanical effect (NF) is ignored than production will be overestimated 232.2 to 91.3% from 1 to 20 year study for low conductive natural fractures (<10 mD-ft.). Lastly, for natural fracture with high permeability (96228.85609 mD), if the geomechanical effect (NF) is ignored the results are negligible (9.8 to 2.0% overestimation) for natural fracture conductivity values above 10 mD-ft. For the critical conductivity results based on the nine parametric studies for each scenario, the relative overestimation error is from 5--13% to 8--20% for non-natraully fractured case, from 1--5% to 2--12% for naturally fractured reservoir with low natural fracture permeability, and from 5--11% to 15--26% for naturally fractured reservoir with high natural fracture permeability. Similar results were reflected in the excess proppant pumping costs calculated for ignoring the permeability effects.;The case study illustrates that that natural fracture geomechanical effect is more significant than the matrix pore pressure effect and matrix geomechanical effect. Therefore, for low permeability shale reservoirs (with an intrinsic permeability as low as 100 nD), the lab characterization of the natural fracture geomechanical effect should be crucial for accurate reservoir production and modeling. Furthermore, based on this matrix permeability study it can be presumed that by increasing the matrix perm 5 to 10 times would directly increase the influence of overestimation by a similar amount. Therefore this study is highly dependent on the lab characterization from the PPAL experimental data. Also, it is important to determine critical conductivity and proper proppant amounts for optimum hydraulic fracturing treatment. Such overestimations found throughout this study can lead to an over-design of the proppant pumping amount, causing early staging or screening-out. This study enables operators and engineers to develop a better understanding of the effects of gas slippage and geomechanics on shale gas well performance, and provides insights for optimization of hydraulic fracturing treatment design for shale gas production with correct core laboratory characterization.

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