Gasflooding Experiments for the East Side of the Yates Field Unit
- Richard L. Christiansen (Marathon Oil Co.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- February 1990
- Document Type
- Journal Paper
- 14 - 18
- 1990. Society of Petroleum Engineers
- 4.3.4 Scale, 5.6.1 Open hole/cased hole log analysis, 5.4.10 Microbial Methods, 5.4.2 Gas Injection Methods, 4.1.5 Processing Equipment, 5.4 Enhanced Recovery, 5.2.1 Phase Behavior and PVT Measurements, 1.7.5 Well Control, 4.1.2 Separation and Treating, 4.6 Natural Gas, 2.2.2 Perforating, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 5.7.2 Recovery Factors, 1.6.9 Coring, Fishing
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Summary. In a series of immiscible gasflood experiments at current conditions for the east side of the Yates Field Unit (450 psi, 82 *F [3.10 MPa, 301 K]), the oil recovery efficiency of CO2 was compared with that of gas-cap gas (GCG). Flooding rates in vertically mounted, preserved-state cores were near the critical velocities for gravity-stable displacement. Oil recoveries with CO2 were 6 to 11% of original oil in place (OOIP) greater Om those of GCG. Flooding results were interpreted with a modified Buckley-Leverett end-effect simulator. With this simulator, the gas/oil saturation profile that results from capillary end effects could be modeled. The modeling study showed that incremental oil recovery with CO2 resulted from oil swelling, oil-viscosity reduction, and gas/oil interfacial-tension (EFT) reduction.
The Yates field is located in Pecos and Crockett Counties, TX, at the southern tip of the Central Basin Platform of the Permian Basin. A summary of the geology of the Yates reservoir is found in Ref. 1. Estimates of the OOEP vary from 3.7 to 4.3 billion bbl [0.59 x 109 to 0.68 x 109 M3].1 In early 1985, cumulative oil production from the field reached 1 billion bbl [0. 16 x 109 M 3 J. The east side of the Yates Field Unit accounts for the majority of production and reserves in the Yates field. The main mechanism of oil production in the east side is gravity drainage from an expanding gas cap. Pressure maintenance by gas injection into this gas cap began at the time of unitization in 1976. Gases for pressure maintenance included unprocessed field gas, residue gas from the Yates gas plant, and nitrogen. After considerable study, CO2 injection to the east side started in Fall 1985. The gasflooding experiments that preceded the field project are the subject of this paper.
During the course of these experiments, our philosophy and procedures evolved considerably. In the early experiments, much effort was directed toward minimizing capillary end effects. (Capillary end effects result in holdup of the wetting phase at the outlet end of a core. 3-5 In displacements of oil by gas, the end effect can substantially decrease oil recovery in short cores.) To counter the end effect, the area available for flow at the outlet end of cores was made small, and during certain stages of flooding tests, gas injection rates were boosted to 2000 to 4000 Cm3[h]. Unfortunately, both procedures complicated more than they simplified interpretation of the flood results. Thus, in later experiments, the entire cross section at the outlet end of a core was open for flow, and gas injection rates were kept constant (arid low for gravity-stable displacement of the oil). Because the results of these later experiments are representative of results seen in all the previous tests, and because the later experiments are more open to clear interpretation, they will be the focus of discussion.
Core. Table 1 summarizes some of the characteristics of the core sample used for the experiments. The core was used in a native state; it was cut and stored with lease crude from a field separator. The core sample consisted of sucrosic dolomite, representative of a sizable volume of east side reservoir. Given the large PV of the core sample, it was a simple task to keep "dead" volumes in the coreflooding apparatus relatively small.
Fluids. Separator oil and gas were recombined to a bubblepoint pressure of 450 psi at 82 *F [3.10 MPa at 301 K]. The separator samples were collected from a well that produced at low GOR and was free of chemical contaminants. Composition and phase behavior of the recombined oil compared favorably with those of field samples studied 20 years earlier.
In the flooding experiments, oil recovery with CO2 was compared with that with the synthetic GCG described in Table 2. We chose the composition of synthetic GCG to approximate the average composition of free gas in the east side gas cap in mid-1984. Table 3 summarizes the physical properties of the fluids.
Flooding Apparatus. Fig. 1 shows a simplified flowsheet of the latest stage in the evolution of our flooding apparatus. The Hassler-style core holder was aligned vertically to provide gravity drainage as gas entered the top of the core. To prevent gas permeation through the Hassler sleeve, the core was wrapped with a layer of foil. The teflon layer protected the aluminum against perforation when over-burden pressure was applied. Overburden pressure was 950 psi [6.6 MPa].
Oil and gas produced from the bottom of the core were separated at flooding pressure by density difference. The oil level in the separator was maintained constant by a servo valve. Another servo valve kept constant backpressure. Separation of oil and free gas upstream of the servo valves eliminated the problems of pressure control with alternating flow of two phases through backpressure regulators (BPR's). But because of separation, both the level control and the backpressure servo valves were required to function from shut-off to the injection rate. Whitey Micro-Metering valves proved satisfactory for this service. Backpressure can be kept within 0.1 psi [0.7 kpal at flow rates from 0 to 10 cm3/h. Cumulative mass of produced oil was measured in a low-pressure separator. Free- and solution-gas volumes were measured in low-pressure accumulators. Composition of either gas stream can be monitored.
Flooding Procedure. Before flooding experiments, the core was flushed with 2 to 3 PV of separator oil at a backpressure of 200 to 300 psi [1.4 to 2.1 MPa) to eliminate any free-gas saturation. Separator oil was followed with about 2 PV of recombined oil, injected at 5 to 10 cm3/h and 460-psi [3.17-MPa] backpressure. Backpressure was maintained near 460 psi [3.17 MPa] throughout the gas-injection experiments. Pressure drop across the core and produced GOR were used to indicate when replacement of separator oil by recombined oil was reasonably complete.
Critical velocity for gravity-stable displacement of oil by gas was estimated as indicated by Stalkup:
with ug =0 and k, = 1.0. Comparisons of well logs and permeability data for adjacent core samples suggested that permeability should be about 200 md. Based on this permeability estimate, the critical injection rate was about 3.0 cm3/h. We chose to inject gas at 2.0 cm3/h. Postmortem measurements of the permeability yielded 210 md.
Capillary Pressure. Using a Beckman Model L5-50 ultracentrifuge with a Type PIR-20 rotor and bucket assembly, we were able to measure capillary-pressure/saturation relations at reservoir pressure and temperature for native-state core plugs from rock adjacent to the core sample used in the flooding experiments. The procedure is described in Ref. 7. The Hassler-Brunner differential procedure and the Bentsen-Anli integral procedure were used to reduce the centrifuge data (see Fig. 2). We recently tested Rajan's procedure lo for centrifuge data reduction. Although the centrifuge allows measurements at high capillary pressures, only the results for capillary pressure less than 0.5 psi [3.4 kpa] were of interest for interpreting our flooding experiments.
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