Summary This paper reviews implementation of a gravity-stable, miscible CO2 solvent flood in a reservoir located in the coastal marshes of south Louisiana. Key reservoir properties are presented, and field tests to determine residual oil saturation and to define reservoir limits and continuity are described. Unique equipment used to transport and inject the CO2 solvent is discussed along with the special instrumentation used for quality control. Also itemized are the regulatory agencies contacted and the permits acquired before the project could be implemented. Introduction Texaco U.S.A. initiated a gravity-stable, miscible CO2 solvent flood on Jan. 20, 1981, in the Bay St. Elaine field, Terrebonne Parish, LA (Fig. 1). The flood in the 8000 Foot Reservoir E Sand Unit (RESU) is being conducted to prove the effectiveness of gravity-stable, miscible CO2 solvent flooding in a steeply dipping, depleted sand. The results of this project will help to determine whether fieldwide CO2 flooding will be economical in similar south Louisiana reservoirs. The project consists of three wells-one injector and two producers. A structure map of the 8000 Foot RESU is shown in Fig. 2. Approximately 84.4 Mg/D [84.4 metric tons/d] CO2 solvent, consisting of CO2, methane, and normal butane, was injected into updip Well 22–26 over a 9-month period. The CO2 solvent slug occupied one-third of the reservoir PV. The CO2 solvent slug size and composition was designed by Texaco's Bellaire (TX) Research Laboratories. Nitrogen, used as a drive gas, is being injected into Well 22–26 to displace the CO2 solvent slug downdip in the reservoir. The CO2 solvent, as it moves downdip, will become miscible with the in-place residual oil. Production of tertiary oil will be from downdip Wells 22–5 and 22–31. An estimated 11 924.0 stock-tank m3 [75,000 STB] tertiary oil is expected to be produced from this depleted water-drive reservoir. The CO2 and n-butane were trucked in liquid states and off-loaded into storage tanks at Cocodrie, LA. These fluids were later transferred to similar storage tanks mounted on barges. The barges then were transported 11.3 km [7 miles] to the injection facility in the Bay St. Elaine field. The methane was obtained from the gas-lift system already in the field. The three components were mixed and injected into Well 22–26. Reservoir Description. The Bay St. Elaine field overlies a salt dome. The recoverable oil is found in numerous sands separated by shale layers. Fig. 3 is a typical electric log of the 8000 Foot Sand from Well 22–5. These sands dip steeply as a result of the upward movement of the salt dome. The 8000 Foot Sand is separated into segments by faults radiating from the salt dome. The 8000 Foot RESU varies in net sand thickness from about 9.1 m [30 ft] near the updip unconformity to about 30.5 m [100 ft] in the downdip portion of the project area. This Miocene sand exhibits high permeability and porosity. The reservoir oil has an 840-kg/m3 [36API] gravity and was produced at a normal GOR. The reservoir has a strong edgewater drive. Key reservoir parameters are presented in Table 1. The 8000 Foot RESU was determined a suitable candidate for a gravity-stable, miscible CO2 solvent flood for the following reasons. Well-Defined Reservoir. Reservoir E and Segment 790 are isolated from the rest of the 8000 Foot Sand by well-established faults. Well Availability. All wells in the two segments except Well 22–3 are completed in the 800 Foot Sand with no remaining primary or secondary potential. Well-Delineated Sand. The 12.7-cm [5-in.] log of Well 22–5 (Fig. 3) indicates significant shale breaks between the sands. The 8000 Foot RESU is not in communication with any other sand within the project area. Fairly Homogeneous Sand. The few shale streaks within the 8000 Foot Sand are not continuous, and the sand is uniform. Expansion Potential. Large reservoirs with millions of barrels of residual oil are adjacent to Segment 790 in both the 8000 Foot Sand and the 8050 Foot Sand (directly beneath the 8000 Foot Sand). The reservoir characteristics are quite similar and the same CO2 solvent flooding process can be used in these reservoirs. JPT P. 101^
Wetland losses and their progressive conversion to open water around producing oil and gas fields in the Gulf Coast region have been attributed to a variety of natural and anthropogenic processes. Three large, mature hydrocarbon fields in coastal southeast Texas were examined to evaluate competing hypotheses of wetland losses and to characterize subaerial and submerged surfaces near reactivated faults and zones of subsidence Topographic and bathymetric profiles at the Port Neches, Clam Lake, and Caplen Fields and shallow cores at the Port Neches and Caplen Fields provide a basis for distinguishing between (1) extensive land-surface subsidence without significant subaqueous erosion, and (2) localized minor subsidence near faults accompanied by extensive subaqueous erosion. Subaqueous erosion results from submergence of wetlands, current and wave excavation of surface sediments and organic detritus, and exportation of the eroded sediments through adjacent water bodies with swift currents such as navigation channels. Geologic settings and responses to induced subsidence and fault reactivation are different at each field site. Detailed stratigraphic correlations of sediment cores show that at Port Neches, subsidence of 35 to 90 cm and minor marsh erosion (20 to 35 cm) created more than 15 million m3 of accommodation space in a nearly circular pattern over the field. At Caplen the marsh surface subsided only about 4 cm, but the surface eroded 30 to 40 cm vertically, creating about 3.5 million m3 of accommodation space. The breakup of wetlands and their conversion to open water appears to be in an initial stage at the Clam Lake Field. At Clam Lake, minor subsidence along a fault is submerging the marsh plants that will weaken and eventually die either as a result of water logging or saltwater intrusion. The different surficial responses and wetland losses at each field are also related to the primary type and rate of hydrocarbon production. The greatest land-surface subsidence occurred at the Port Neches Field where a large volume of gas was produced rapidly. At the Caplen Field, both oil and gas were produced in significant quantities and there was a period of accelerated gas production. The wetland loss, which coincided with the rapid production phase, was controlled by fault reactivation and subsequent marsh erosion. Oil was the primary hydrocarbon produced at the Clam Lake Field where a reactivated fault is responsible for the observed wetland loss. Results from this study show that although the absolute magnitude of induced subsidence may be less than 1 m, even a minor reduction in land elevation is sufficient to initiate marsh degradation that quickly results in major wetland losses.
quent and recent aerial photographs provides a basis for evaluating the morphological stability of each area and explaining some of the stratigraphic successions recorded in the vibracores. The oldest map of the area is a preliminary survey conducted in 1852 by the U.S. Coast Survey. The 1852 map was not included in the morphological analysis because it appears to be a generalized illustration of the area with limited horizontal control. In contrast, the 1871 map (Fig. 2) provides accurate details that can be judged of exceptionally high quality by its agreement with modern geographically controlled depictions of stable land features. The 1999 aerial photographs, representing the most recent geographically controlled depiction of the area, also served as a base for mapping depositional environments (Fig. 1), locating field observation sites (Figs. 3-5), and locating topographic transects (Fig. 6).
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