Effect of Temperature on the Gas/Oil Relative Permeability of Orinoco Belt Foamy Oil

SPE Journal ◽  
2016 ◽  
Vol 21 (01) ◽  
pp. 170-179 ◽  
Author(s):  
Songyan Li ◽  
Zhaomin Li
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Heavy Oil ◽  
High Viscosity ◽  
Viscosity Reduction ◽  
Gas Oil ◽  
Foamy Oil ◽  
Solution Gas Drive ◽  
Gas Drive ◽  
Solution Gas

Summary Foamy-oil flow has been successfully demonstrated in laboratory experiments and site applications. On the basis of solution-gas-drive experiments with Orinoco belt heavy oil, the effects of temperature on foamy-oil recovery and gas/oil relative permeability were investigated. Oil-recovery efficiency increases and then decreases with temperature and attains a maximum value of 20.23% at 100°C. The Johnson-Bossler-Naumann (JBN) method has been proposed to interpret relative permeability characteristics from solution-gas-drive experiments with Orinoco belt heavy oil, neglecting the effect of capillary pressure. The gas relative permeability is lower than the oil relative permeability by two to four orders of magnitude. No intersection was identified on the oil and gas relative permeability curves. Because of an increase in temperature, the oil relative permeability changes slightly, and the gas relative permeability increases. Thermal recovery at an intermediate temperature is suitable for foamy oil, whereas a significantly higher temperature can reduce foamy behavior, which appears to counteract the positive effect of viscosity reduction. The main reason for the flow characteristics of foamy oil in porous media is the low gas mobility caused by the oil components and the high viscosity. High resin and asphaltene concentrations and the high viscosity of Orinoco belt heavy oil increase the stability of bubble films and prevent gas breakthrough in the oil phase, which forms a continuous gas, compared with the solution-gas drive of light oil. The increase in the gas relative permeability with temperature is caused by higher interfacial tensions and the bubble-coalescence rate at high temperatures. The experimental results can provide theoretical support for foamy-oil production.

An Experimental Investigation of Viscous-Oil Recovery Efficiency as a Function of Voidage-Replacement Ratio

SPE Journal ◽  
2016 ◽  
Vol 21 (04) ◽  
pp. 1236-1253 ◽  
Author(s):  
Tae Wook Kim ◽  
E.. Vittoratos ◽  
A. R. Kovscek
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Crude Oils ◽  
Replacement Ratio ◽  
Two Phase ◽  
Foamy Oil ◽  
Three Phase ◽  
Solution Gas Drive ◽  
Gas Drive ◽  
Solution Gas

Summary Recovery processes with a voidage-replacement ratio (VRR) (VRR = injected volume/produced volume) of unity rely solely on viscous forces to displace oil, whereas a VRR of zero relies on solution-gas drive. Activating a solution-gas-drive mechanism in combination with waterflooding with periods of VRR less than unity (VRR < 1) may be optimal for recovery. Laboratory evidence suggests that recovery for VRR < 1 is enhanced by emulsion flow and foamy (i.e., bubbly) crude oil at pressures under bubblepoint for some crude oils. This paper investigates the effect of VRR for two crude oils referred to as A1 (88 cp and 6.2 wt% asphaltene) and A2 (600 cp and 2.5 wt% asphaltene) in a sandpack system (18-in. length and 2-in. diameter). The crude oils are characterized with viscosity, asphaltene fraction, and acid/base numbers. A high-pressure experimental sandpack system (1 darcy and Swi = 0) was used to conduct experiments with VRRs of 1.0, 0.7, and 0 for both oils. During waterflood experiments, we controlled and monitored the rate of fluid injection and production to obtain well-characterized VRR. On the basis of the production ratio of fluids, the gas/oil and /water relative permeabilities were estimated under two-phase-flow conditions. For a VRR of zero, the gas relative permeability of both oils exhibited extremely low values (10−6−10−4) caused by internal gas drive. Waterfloods with VRR < 1 displayed encouraging recovery results. In particular, the final oil recovery with VRR = 0.7 [66.2% original oil in place (OOIP)] is more than 15% greater than that with VRR = 1 (55.6% OOIP) with A1 crude oil. Recovery for A2 with VRR = 0.7 (60.5% OOIP) was identical to the sum of oil recovery for solution-gas drive (19.1% OOIP) plus waterflooding (40.1% OOIP). An in-line viewing cell permitted inspection of produced fluid morphology. For A1 and VRR = 0.7, produced oil was emulsified, and gas was dispersed as bubbles, as expected for a foamy oil. For A2 and VRR < 1, foamy oil was not clearly observed in the viewing cell. In all cases, the water cut of VRR = 1 is clearly greater than that of VRR = 0.7. Finally, three-phase relative permeability was explored on the basis of the experimentally determined two-phase oil/water and liquid/gas relative permeability curves. Well-known algorithms for three-phase relative permeability, however, did not result in good history matches to the experimental data. Numerical simulations matched the experimental recovery vs. production time acceptably after modification of the measured krg and krow relationships. A concave shape for oil relative permeability that is suggestive of emulsified oil in situ was noted for both systems. The degree of agreement with experimental data is sensitive to the details of gas (gas/oil system) and oil (oil/water system) mobility.

The influence of viscosity on stability of foamy oil in the process of heavy oil solution gas drive

2009 ◽  
Vol 66 (1-2) ◽  
pp. 69-74 ◽  
Author(s):  
Jian Wang ◽  
Yingzhong Yuan ◽  
Liehui Zhang ◽  
Ruihe Wang
Keyword(s):  
Heavy Oil ◽  
Foamy Oil ◽  
Solution Gas Drive ◽  
Gas Drive ◽  
Solution Gas

Enhanced heavy oil recovery after solution gas drive by water flooding

2016 ◽  
Vol 137 ◽  
pp. 113-124 ◽  
Author(s):  
Teng Lu ◽  
Zhaomin Li ◽  
Songyan Li ◽  
Peng Wang ◽  
Zhuangzhuang Wang ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Water Flooding ◽  
Heavy Oil Recovery ◽  
Solution Gas Drive ◽  
Gas Drive ◽  
Solution Gas

The Calculated Performance of Solution-Gas-Drive Reservoirs

1961 ◽  
Vol 1 (03) ◽  
pp. 142-152 ◽  
Author(s):  
J.S. Levine ◽  
M. Prats
Keyword(s):  
Steady State ◽  
Differential Equations ◽  
Relative Permeability ◽  
Absolute Permeability ◽  
Gas Oil ◽  
Pvt Properties ◽  
Partial Differential ◽  
Solution Gas Drive ◽  
Gas Drive ◽  
Solution Gas

Abstract Several methods are available for calculating the performance of solution-gas-drive reservoirs from the PVT properties of the oil and from the relative permeability and other properties of the formation. These methods require a number of simplifying assumptions. The present method of computation has made use of a high-speed computer to solve simultaneously the nonlinear partial differential equations that describe two-phase flow by solution-gas drive in order to calculate the performance of a reservoir. Some of the results obtained by the nonlinear partial differential equation solution are compared with those obtained with an approximate method, which has been called the semi-steady-state solution. The pressure and saturation profiles from the wellbore to outer boundary calculated by the two methods are compared for one constant-terminal-rate case and two constant-terminal-pressure cases. The agreement in these profiles, as well as in the values of average reservoir pressure and cumulative recovery, leads to the conclusion that, for most engineering calculations, the semi-steady-state method will give a reasonable approximation to the numerical solution of the differential equations describing solution-gas drive. An unfavorable (as regards ultimate oil production) set of relative permeability curve was used in the calculations in the belief that the effect of the parameters which were studied would be emphasized to a greater degree. Furthermore, the reservoir was assumed to be completely homogeneous, and these results should not be considered applicable to any other type of reservoir. Gravity effects are not considered. The absolute permeability was varied from 25 to 0.5 md. At an economic limit of 2 B/D, the recovery for a 25-md reservoir is about 1.8 times as great as that for a 0.5-md reservoir. The effect of permeability on the producing gas-oil ratio is minor. Once PVT properties of the oil and the relative permeability properties of the reservoir are fixed, the producing gas-oil ratio is found to be a function of the fraction of oil recovered.

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