Phase Behavior of a High-Pressure Condensate Reservoir Fluid
- K.H. Kilgren (Chevron Research Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- August 1966
- Document Type
- Journal Paper
- 1,001 - 1,005
- 1966. Society of Petroleum Engineers
- 5.2 Reservoir Fluid Dynamics, 4.1.2 Separation and Treating, 4.1.5 Processing Equipment, 5.2.1 Phase Behavior and PVT Measurements, 5.1.1 Exploration, Development, Structural Geology, 4.1.9 Tanks and storage systems, 5.8.8 Gas-condensate reservoirs
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At high formation pressures the distillate produced from a gas-condensate reservoir may be black in color. In this event the dense gas phase existing above the dew point is correspondingly dark. Volumetric phase data and an analysis of a reservoir fluid exhibiting these characteristics, together with a description of the visual equilibrium cell in which these observations were made, are presented in this paper.
Previously the author, like many others in the oil and gas industry perhaps, tacitly assumed that the expressions black or dark oil system, crude oil system and bubble-point system were synonymous. Crude oil reservoir fluids are bubble-point systems and yield a black or dark stock-tank oil of relatively low API gravity. Conversely, a clear or amber colored trap distillate of high API gravity is assumed indicative of a dew point system or a gas-condensate reservoir fluid. This broad classification appears satisfactory for shallow reservoirs, but as the following study demonstrates, may be misleading when applied to deep reservoirs. Theoretically, there is no reason to exclude the possibility of producing a dark, low-gravity distillate from a gas-condensate reservoir. At sufficiently high values of pressure and temperature. heavy, dark-colored hydrocarbons may exist in the vapor state of a multi-component system. If enough dark-colored components are present in the reservoir vapor phase, the resulting condensate will be dark. The reservoir fluid investigated in the present study supports this contention. Stock-tank production was black in color and measured 29' API gravity. From outward appearances, the liquid closely resembled a medium gravity crude oil. Experimental measurements proved the reservoir fluid was in reality a gas-condensate system. Volumetric phase data for this high-pressure system and a description of the visual cell in which the study was conducted successfully are presented in this paper.
Phase behavior of a reservoir fluid can be predicted accurately with reference to a pressure-temperature phase diagram. If the reservoir temperature is lower than the critical temperature of the hydrocarbon fluid in place, bubble-point behavior will be observed. If the reservoir temperature lies between the critical and cricondentherm temperature, dew point behavior and retrograde condensation will occur. For reservoir temperatures above the cricondentherm, only a single gas phase can exist in the reservoir regardless of pressure. Providing the composition of the reservoir fluid were known, it would be possible to predict the critical temperature and estimate the phase behavior from equilibrium relationships. However, the usual practice is to obtain a sample of reservoir fluid, subject it to varying pressures at the reservoir temperature and observe the phase behavior experimentally. The latter method was used to obtain the data reported here.
WELL AND TRAPPING INFORMATION
A summary of pertinent data for the well from which the reservoir fluid was sampled is presented in Table 1. This well is located offshore Louisiana. Except for the pressure which substantially exceeds hydrostatic pressure, the information does not appear unusual. Prior to the sampling program, the well was produced for 22 hours at a stock tank oil rate of 139 B/D. Average trapping conditions and gauging data for the six-hour test period that followed are summarized in Table 2. Samples of the first-stage trap gas and liquid were obtained during the latter portion of the test period. Ambient temperature remained 5 to 10F below trap temperature and presented no problem for sampling. Surface wind and moderate foaming of stock-tank oil presented some difficulty in obtaining accurate stock-tank gauges.
Compositions of the gas and liquid samples are shown in Table 3. The trap gas was analyzed by isothermal chromatography which revealed only a trace of heptane in the stream. The trap liquid was initially analyzed by low-temperature fractional distillation, yielding a bottom product of heptane and heavier components. Specific gravity of this fraction was measured and the mol weight was determined by freezing point depression. TABLE 1 -- WELL DATA
Bottom-hole (static) Subsea depth: 14,440 ft Pressure: 12,780 psig Temperature: 260F
Wellhead (static): 9,700 psig
Wellhead (flowing) Pressure: 9,330 psig Temperature: 55F TABLE 2 -- TRAPPING DATA 1st Stage 2nd Stage Stock Tank Pressure (psig) 1,070 78 0 Temperature (degrees F) 54 51 50 Gas rate (Mscf/D) 716 27 3 Oil rate (B/D) 154 136 134 Oil gravity (degrees API) 38.3 29
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