Master of Science

thesisUnderground natural gas baseload storage facilities are a vital part of the world's natural gas infrastructure. These facilities allow Exploration & Production (E&P) and transmission pipeline companies to utilize natural gas assets year round while providing means for consistent gas supply throughout the year. The purpose of this thesis is to present a process in which a feasibility study can be conducted for a prospective baseload storage facility. This was accomplished by explaining 1) the theory of natural gas storage reservoir engineering; 2) geologic consideration for underground storage prospects; 3) design of a new underground baseload facility using decline curve analysis and hysteresis analysis; and 4) a detailed economic analysis of a storage prospect. A depleted natural gas reservoir was evaluated for its potential to become an underground baseload storage facility for natural gas. For this underground reservoir, it is estimated the Original Gas in Place (OGIP) was 59.4 Billion Cubic Feet (BCF) using hysteresis analysis. The cushion gas requirement was solved to be 50% of the OGIP, or 29.7 BCF. There is currently 7.4 BCF of native gas present in the reservoir. The required injection cushion gas requirement is estimated at 22.3 BCF. The maximum field deliverability was estimated to be 284.3 Thousand Cubic Feet per Day (MCF/D) at a reservoir pressure of 868.5 psia. The minimum field deliverability was estimated to be 83.8 MCF/D at a cushion gas pressure of 434.1 psia. Maximum and minimum deliverabilities assume 30 injection/withdrawal wells are present at 6 different well pads throughout the field. After analyzing three different economic scenarios for the prospective storage field it was determined this project is not economically feasible under current market conditions. Recommendations for future work include the operating company conducting a 3D seismic survey and re-evaluating the project using 3D reservoir simulation evaluating the possibilities of 1) using horizontal drilling to minimize number of wells, 2) simulate storage well performance if vertical wells are hydraulically fractured, and/or 3) simulate if the prospective storage facility can be pressurized over the original discovery pressure

Optimization of hydraylic fracturing of tight gas formations in horizontal wells

honors thesisCollege of EngineeringChemical EngineeringJohn McLennanThe discoveries of significant resources of oil and gas in the Barnett, Bakken, Marcellus, and other shale formations have presented an opportunity for national petroleum independence and possible export in the relatively near future. These formations are considered to be "unconventional" resources because of the extremely low formation permeability. This means that traditional oil and gas recovery mechanisms are not economical in these formations. With the development of methods for performing multiple hydraulic fractures in horizontally drilled wells in reasonable periods of time economic production of these formations has been seen throughout the world. However, little is known about the optimal spacing of these fractures in horizontal wellbores - how close together should they be to optimize the net present value (balancing costs of drilling, stimulation and production with future revenue). This paper outlines current hydraulic fracturing propagation theory and describes fracture interaction phenomena such as fractures linking-up or one set of fractures inhibiting the growth of others. This leads to insights related to hydraulic fracture spacing. The optimization of hydraulic fracturing spacing was simulated using mShaleTM from Baker Hughes. It was discovered however that the interference of multiple fractures in a defined zone can be modeled with the mShale software package and it serves as a good pseudo design estimation of optimum fracture spacing