Set Of Relative Permeability Curves Research Articles

Numerical Simulation Of The North Ricinus Cardium A Reservoir

Abstract The North Ricinus Cardium A Pool is a beach barrier system located on the edge of the disturbed belt, approximately 130, km northwest of Calgary, Alberta. The current operating mode for the pool involves a cycling scheme in the retrograde gas cap with the oil leg on primary depletion. A standard 3D-3 phase black oil model, modified with several specialized subroutines, was used to simulate the cycling scheme in the history match and prediction modes. Pseudo-relative permeability curves were used to describe displacement of rich gas by lean gas in the gas cap, while two sets of relative permeability curves were required to match oil production. The model was subsequently utilized to establish reserves and to optimize natural gas liquid recovery by infill drilling in the gas cap. Introduction The Ricinus Cardium A Pool, discovered in January 1969, is located approximately 130 kilometres northwest of Calgary, FIGURE 1. Location map. (Available in full paper) FIGURE 2. North Ricinus geology.(Available in full paper) Alberta (Fig. 1). The pool initially was considered to be a large retrograde condensate gas cap in association with a relatively small oil leg containing a high shrinkage oil. An application in June 1971(1) to concurrently produce the gas and oil based on good production practice was refused by the ERCB. In July 1972 a scheme to cycle the gas cap was subsequently approved with the provision that the operator show cause after one year of production why a VRR of unity need not be maintained(2). Gas cap cycling commenced in April 1973 and a performance review submitted in July 1974(3) indicated that a VRR of between 0.85 and 1.00 had no appreciable effect on gas cap liquid recoveries and the ERCB did not impose a full voidage replacement ratio at that time. Subsequent step out drilling to the north indicated that the oil leg was much larger than previously estimated; and in May 1979, the ERCB(4) requested a study to determine the effect of VRR on the oil recovery and also an updated estimate of original reservoir volumes. A black oil reservoir simulation study, incorporating special modifications, was initiated in June 1979 to address the ERCB's concerns. The model was subsequently utilized to establish pool reserves and to investigate optimization of natural gas liquid recovery by infill drilling. Geology The Ricinus Cardium Pools occur in the Cardium A Sand of Upper Cretaceous age. The reservoir is a beach barrier system trending 20 km in a northwesterly direction and averaging 3 – 5 km in width at a mean depth of 1325 m ss (Fig. 2). The reservoirs are complex structural traps occurring at the edge of the disturbed belt. The Cardium A Pool consists of a retrograde gas cap condensate overlying a volatile oil pool in a weakly folded synclinal structure that plunges gently to the northwest with the gas oil contact occurring at 1463 m ss. A major under thrust forms a pressure barrier to the Cardium K pool to the southwest with porosity pinchouts forming the reservoir boundaries in other directions (Fig. 2).

Relative Permeability Measurements Using Reservoir Fluids

Abstract Water-oil relative permeabilities measured using reservoir fluids and fresh, preserved cores are shown to differ considerably from those obtained routinely using relined fluids and extracted cores. Upon saturating the extracted cores with the reservoir fluids and allowing them to come to equilibrium, in this case for 6 days, the original relative permeability curves were reestablished. Introduction Ordinarily, relative permeabilities are measured using refined fluids and restored-state cores. On occasion, fresh core samples that had been flushed with a refined oil, without any other cleaning or extraction, have been used. To date, no relative permeability measurements have been reported permeability measurements have been reported using reservoir fluids and fresh preserved cores, although a number of published studies have dealt with the influence of core handling and other laboratory experimental factors on results of displacement tests. This is not surprising. Special procedures have to be followed for obtaining, procedures have to be followed for obtaining, preserving, and handling native-state cores; and preserving, and handling native-state cores; and companies are generally reluctant to permit any procedures that may increase the expense or the procedures that may increase the expense or the time required to complete a well. Consequently, suitable cores often are simply not available. Furthermore, only a very few of the petroleum production research laboratories have the facilities production research laboratories have the facilities for measuring interfacial tension, contact angle and relative permeabilities at the elevated temperatures and pressures normally encountered in reservoirs. The following study provides, for the first time, relative permeability data obtained with fresh, preserved cores and reservoir fluids at reservoir preserved cores and reservoir fluids at reservoir pressure and temperature. Measurements were also pressure and temperature. Measurements were also made routinely with refined fluids and extracted cores to afford comparisons. Advancing and receding contact angles were measured as a function of time with the actual reservoir fluids on a solid surface representative of the reservoir rock to characterize the wetting equilibrium during the tests. Finally, a procedure was devised which, for the extracted procedure was devised which, for the extracted cores, yielded the original set of relative permeability curves. permeability curves.

Comparison of Calculated with Experimental Imbibition Relative Permeability

Abstract Two-phase imbibition relative permeability was measured in an attempt to validate a method of calculating imbibition relative permeability. The stationary-liquid-phase method was used to measure several hysteresis loops for alundum and Berea sandstone samples. The method of calculating imbibition relative permeability is described, and calculated relative permeability curves are compared with measured curves. The calculated relative Permeability is shown to be a reasonably good Permeability is shown to be a reasonably good approximation of measured values if an adjustment is made to some necessary data. Due to the compressibility of gas, which is used as the nonwetting phase, a correction to the measured trapped gas saturation is necessary to make it agree with the critical gas saturation of the imbibition relative permeability curve. Introduction The existence of hysteresis in the relationship of relative permeability to saturation has been recognized for many yews. Geden et al. and Osoba et al. called attention to the occurrence of hysteresis and the importance of the direction of saturation change on the relative permeability-saturation relations. It is generally believed that relative permeability is a function of saturation alone for a permeability is a function of saturation alone for a given direction of saturation change, but that there is a distinct difference in relative permeability curves for saturation changes in different directions. The reservoir engineer should be aware of this hysteresis, and he should select the relative permeability curve which is appropriate for the permeability curve which is appropriate for the recovery process of interest. The directions of saturation change have been designated "drainage" and "imbibition" in reference to changes in the wetting-phase saturation. In a two-phase system, an increase in the wetting-phase saturation is referred to as imbibition, while a decrease in wetting-phase saturation is called drainage. The solution-gas-drive recovery mechanism is controlled by relative permeability to oil and gas in which the saturation of oil, the wetting phase, is decreasing. In waterflooding a water-wet reservoir rock, the saturation of water, the wetting phase, is increasing. These two sets of relative permeability curves, gas-oil and oil-water, do not have the same relationship to the wetting-phase saturation. This difference is not due to the difference in fluid properties, but is a result of the difference in properties, but is a result of the difference in direction of saturation change. The flow properties of the drainage and imbibition systems differ because of the entrapment of the nonwetting phase during imbibition. As drainage occurs, the nonwetting phase occupies the most favorable flow channels. During imbibition, part of the nonwetting phase is bypassed by the increasing wetting phase, leaving a portion of the nonwetting phase in an immobile condition. This trapped part phase in an immobile condition. This trapped part of the nonwetting phase saturation does not contribute to the flow of that phase, and at a given saturation the relative permeability to the nonwetting phase is always less in the imbibition direction phase is always less in the imbibition direction than in the drainage direction. The concept that some of the nonwetting phase is mobile and some is immobile during a saturation change in the imbibition direction previously was used to develop equations for imbibition relative permeability. In this development, it was assumed permeability. In this development, it was assumed that the amount of entrapment at any saturation can be obtained from the relationship between initial nonwetting-phase saturations established in the drainage direction and residual saturations after complete imbibition. The equations for imbibition relative permeability were not verified by laboratory measurements. The purpose of this report is m give the results of a laboratory study of imbibition relative permeability and to present a comparison of calculated relative permeability with relative permeability from laboratory measurements. permeability from laboratory measurements. In two-phase systems, hysteresis is more prominent in the relative permeability to the nonwetting phase than in that to the wetting phase. The hysteresis in the wetting-phase relative permeability is believed to be very small, and thus difficult to distinguish tom normal experimental error.