The Department of Chemical Engineering is proud to announce the Thesis Defense of M.S. candidate, Jacob Abraham, “Feasibility Study of a Natural Gas Storage Prospect Reservoir Using Decline Curve and Hysteresis Analysis,” on Thursday, October 23rd, 2014, from 1:30-3:30pm in MEB 3105. Mr. Abraham’s advisor is Dr. John McLennan.
Abstract
Underground natural gas baseload storage facilities are a vital part of the world’s natural gas infrastructure. These facilities allow 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.
Data used is from published sources about Questar Pipeline Company’s Clay Basin storage facility located in Northeastern Utah. Additional data was provided via a confidentiality agreement for an operator located in the Rocky Mountain Region. This data served as an example of all design criteria within the contents of this paper and conclusions and recommendations presented herein are based off of the confidential data.
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 OGIP was 59.4 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 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. If the storage field operator chose to build this facility, supplying the cushion gas, the annual storage rate exceeds what the market can bear at $1.00 a Dth. After reviewing all economic information that was available at this time, it is highly recommended to revisit this project economically if 1) the price of natural gas increases by over $1 a Dth and 2) if the price of natural gas in the off season becomes greater than the effective annual storage rates calculated at this time. 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.