Producing Sour Oil and Gas in the Jay Field
- J.B. Chambers (Exxon Co. U.S.A.) | R.B. Hillegeist (Exxon Co. U.S.A.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- June 1975
- Document Type
- Journal Paper
- 701 - 706
- 1975. Society of Petroleum Engineers
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- 289 since 2007
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The presence of hydrogen sulfide in oil from the Jay field required complex facilities to produce salable oil and gas. The modular-facility design concept permitted full allowable production to be attained in minimum time. Although expensive and potentially hazardous, production of sour oil and gas can be accomplished safely and without damaging the environment.
Because of the presence of hydrogen sulfide in Jay field crude oil, complex facilities, including oil stabilization, gas sweetening, and sulfur-recovery units, were required to produce salable oil and gas. To initiate field production and to provide extended well tests, a small 2,000-B/D facility was installed initially. As development drilling proceeded, 6,500- and 12,000-B/D modules were built proceeded, 6,500- and 12,000-B/D modules were built when and where needed. By using the modular-facility design concept, the field producing capacity was more than 90,000 B/D within 2 1/2 years of discovery.
Design concepts were used to minimize hazards to personnel, to prevent corrosion, and to protect the personnel, to prevent corrosion, and to protect the environment. Special operating procedures, personnel safety equipment, and training completed these design concepts. An extensive ambient-air monitoring network was established to insure that ambient-air standards were met to protect the environment.
The Jay field was discovered in June 1970 with the St. Regis No. 1 well, located about 35 miles north of Pensacola, Fla. (Fig. .1). Initial well testing confirmed Pensacola, Fla. (Fig. .1). Initial well testing confirmed that the reservoir oil contained an appreciable amount of hydrogen sulfide (Table 1). The approximate 9 mol percent hydrogen sulfide required treating facilities to percent hydrogen sulfide required treating facilities to make the oil and gas salable.
Following testing of the St. Regis No. 1 well, studies were immediately undertaken for initiation of production from the field. Two alternatives were considered for sizing a treating facility: (1) conduct a short-term productivity test using separation and storage facilities productivity test using separation and storage facilities for the crude, and bum all produced gas, and (2) install a small treating and sulfur-recovery unit for an extended test.
In both cases, a larger facility was proposed if and when development drilling so dictated. The decision to install a small testing and sulfur-recovery unit was made because of economic, environmental, and safety considerations. This alternative provided a means of initiating field production while continuing definition drilling. It was also advantageous to have extended tests under actual production operations to better establish reserves and productivity guidelines for evaluating a large plant. The small treating and sulfur-recovery unit also minimized the pollution problems associated with flaring sour gas containing about 15 mol percent hydrogen sulfide, and eliminated the potential hazards involved in disposing weathered crude with a sulfur content of 2,000 ppm.
Less than 1 month after discovery, an engineering contractor was selected to dismantle a surplus amine-treating, Claus sulfur-recovery facility located in Cass County, Tex., and to reassemble the facility at Jay. This surplus facility consisted of an oil stripping unit to remove hydrogen sulfide from the crude oil, an MEA gas-treating unit to recover hydrogen sulfide gas from casinghead gas and stripping vapors, and a two-Stage Claus sulfur-recovery unit to convert the hydrogen sulfide to elemental sulfur. At that time, the State of Florida had not established air quality standards for Northwest Florida.
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