Fluid In Place Research Articles

Phase Behavior of a High-Pressure Condensate Reservoir Fluid

Abstract 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. Introduction 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. THEORY 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. SAMPLE ANALYSIS 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 ftPressure: 12,780 psigTemperature: 260F Wellhead (static): 9,700 psig Wellhead (flowing)Pressure: 9,330 psigTemperature: 55FTABLE 2 -- TRAPPING DATA1st Stage 2nd Stage Stock TankPressure (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 JPT P. 1001ˆ

Miscible Displacement in a Controlled Natural System

Abstract Three confined five-spot miscible displacements at unity, favorable, and unfavorable mobility ratios were conducted in a shallow, water-saturated sandstone of Pennsylvanian age near Chandler, Okla. These studies, plus associated laboratory experiments, were designed to measure-miscible displacement performance in a controlled natural system, using known scaling criteria to develop an approach to modeling the heterogeneous field system. We have concluded from these studies that: displacement efficiency in the field is a pronounced function of mobility ratio, indicating that miscible fingering observed in simple laboratory models occurs in the field field displacements can be quantitatively predicted by scaled laboratory models if the degree and location of field permeability variations are preserved in the models and arbitrary simplifications of heterogeneity will net necessarily predict observed displacement efficiency, and the simpler the model, the more optimistic the prediction. Introduction Many processes to achieve miscible displacement of reservoir oil by injected fluids have been conceived and field tested by the oil industry. Among the better known are high-pressure gas, enriched gas, and LPG banks. The simplest form of miscible displacement one fluid miscible, displacing another fluid of different viscosity but the same density has been studied extensively in homogeneous laboratory models. Observations of unstable fingering have been made which explain the significant decrease in displacement efficiency as the mobility ratio (ratio of displacing fluid mobility to displaced fluid mobility) increases. General industry experience with field tests of miscible displacement projects, mostly LPG banks, has been premature solvent breakthrough and lower than predicted production rate increases. These results have been attributed to either unstable fingering, unusual or unexpected permeability stratification, or both. Miscible displacement data in a controlled natural system have never been reported, however. Also, it has not been shown that properly designed and constructed laboratory models quantitatively predict field-scale behavior. The purpose of the combined field and laboratory experiments reported in this paper is twofold. The first was to measure miscible displacement performance at different mobility ratios in natural rock approaching field size under precise, controlled conditions. The second purpose was to utilize known scaling criteria plus several approaches to heterogeneity to model the field. Comparison of model and actual field results should then determine whether or not the laboratory phenomena (manifested by miscible displacement efficiency) are exhibited in large, natural rock systems. We carried out our program by first locating a shallow, water-saturated reservoir whose rock properties were representative of oil-bearing reservoirs. Detailed reservoir description by core analysis and interference testing showed the field site to be heterogeneous." A sequence of controlled, aqueous-phase miscible displacements was conducted at unity, favorable and unfavorable mobility ratios. A central, confined pattern was used to obtain the displacement data. A laboratory program using sand-packed models was conducted to determine the modeling criteria necessary to simulate field behavior of miscible displacement in a heterogeneous system. SCALING THEORY The detailed derivations and descriptions of the scaling laws that apply to laboratory models of reservoirs are adequately described elsewhere, so the following discussion will be restricted to facets of importance in this study. For a displacement in which one liquid miscibly displaces another, the following dimensionless groups are required to have the same numerical value in the model as in the field: ........................................(1) The model also must be geometrically similar to the field, be spatially oriented the same as the field (same dip angle), and have the same initial and boundary conditions as the field (same initial fluid saturations and same injection-production well arrangement). When these conditions are satisfied, the theory predicts that at any dimensionless time (pore volumes of produced fluids) the dimensionless flow potential and dimensionless fluid concentrations will be identical at all dimensionless spatial locations within the model and the field. If this prediction is correct, then the local dimensionless velocities must be identical, thus the instantaneous fraction of displaced fluid produced and the cumulative recovery expressed as fraction of original fluids in place must be identical at all dimensionless times. JPT P. 1329ˆ

Potentiometric-model Studies of Fluid Flow in Petroleum Reservoirs

Abstract A simplification of the method of Hurst and McCarty for conductingpotentiometric model studies by the single probe method is presented along withexperimentally determined invasion patterns for certain idealized flowproblems. The analytical solution for one class of these problems is given.Finally, a general description is given of a newly developed instrument whichpermits direct mapping of flow lines and determination of transit times inpotentiometric-model studies. Introduction The object of this paper is to present:A simplification of the method of Hurst and McCarty for conductingpotentiometric-model studies of oil and gas reservoirs by the single probemethod.Results of a series of studies of certain idealized flow problems and thegeneral conclusions to be drawn therefrom.A description of a dew instrument, the Chronocartograph, which greatlyreduces the labor and time required for conducting potentiometric-modelstudies. Certain general conclusions may be drawn as results of theinvestigation of the idealized flow problems. They are:Injection and extraction areas should be separated by as great a distance asconditions permit since, in general the recovery prior to first breakthroughtends to vary as the square of this distance.Little advantage is to be gained by use of more than eight injection wellsor groups of injection wells for the case of circular productive limits.Elongated shapes if productive limits are best exploited by injection on theextended major axis only, with a line of extraction wells lying on the majoraxis.The use of peripheral injection wells for elongated shapes is permissible, if necessary, but requires extension of the lines of extraction wells. The exploitation of an oil or gas field is effected either by the expansion ofthe gas and oil, or by their displacement by another fluid. Both methods may beused simultaneously. When the displacement of the oil or gas is the controllingfactor there arises the problem of mapping the progress of the boundary betweenthe fluid in place and the displacing fluid. This problem is of particularinterest in the operation of a cycling project in a gas-condensate field, wherethe wet gas is produced from one or more wells, commonly called ?extractionwells?. This wet gas is taken into a processing plant where the condensate isremoved. The remaining "dry" gas is injected back into the field through one ormore wells, the gas for future use and also to maintain the pressure in thefield. T.P. 2262