Gas- and Liquid-Phase Relative Permeabilities for Cold Production From Heavy-Oil Reservoirs
- Guo-Qing Tang (Reservoir Engineering Research Inst.) | Abbas Firoozabadi (Reservoir Engineering Research Inst.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- April 2003
- Document Type
- Journal Paper
- 70 - 80
- 2003. Society of Petroleum Engineers
- 4.6 Natural Gas, 1.6.9 Coring, Fishing, 4.3.3 Aspaltenes, 1.2.3 Rock properties, 5.3.2 Multiphase Flow, 5.2.1 Phase Behavior and PVT Measurements, 5.4.1 Waterflooding, 4.1.5 Processing Equipment, 5.7.2 Recovery Factors, 5.3.1 Flow in Porous Media, 4.1.2 Separation and Treating, 2.4.3 Sand/Solids Control
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Solution-gas drive with two heavy oils, a mineral oil with a viscosity of some 32,000 cp (at 24 °C), and a heavy crude with viscosities of 85,000 cp and 9,200 cp (at 24 and 35 °C, respectively) is carefully studied. Both oils show recovery in excess of 10% at test termination; the recovery for the heavy crude exceeds 15%. Had we continued the test, the recovery could have been higher.
From the measured pressure and fluid-flow rates, gas and oil relative permeabilities are estimated by a simple mathematical expression. The results establish that high recoveries are mainly caused by the low gas relative permeability. The results on mineral oil and heavy crude also demonstrate that the widely held belief that efficient solution-gas drive in heavy crude is caused by the foamy nature cannot be justified. An increase in temperature would reduce the oil viscosity, which in turn increases the gas mobility, thereby reducing the efficiency of solution-gas drive for cold production.
Gradual progress in the understanding of the high efficiency of solution-gas drive in heavy-oil reservoirs has been made in recent years.1-6 Basic mechanisms and reservoir engineering parameters, however, remain unknown. Most authors attribute the high efficiency of solution-gas drive in heavy-oil reservoirs to foam; the term "foamy crude" is used to describe the process.1,2,7,8 We have not shared this viewpoint and have purposely avoided the use of the term "foamy oil".6,9
This work centers on two important issues related to cold production from heavy-oil reservoirs. The first issue relates to the relevance of the foamy nature of a heavy crude to recovery efficiency. For this purpose, in one set of experiments we use a viscous mineral oil, which supposedly cannot be foamy, to examine its efficiency under solution-gas drive.
The second issue relates to gas- and liquid-phase mobility and the influence of temperature and gravity force. Gas and oil relative permeabilities are the prime parameters for the study of solution-gas drive in heavy-oil reservoirs. In a previous work,9 we concluded that the gas phase may not be continuous during two-phase flow; gas flow is intermittent. Grattoni et al.10 have also reported a similar observation from solution-gas drive in a waterflood residual oil process for a heavy mineral oil. The presumption that in immiscible two-phase flow, the effective permeability-to-liquid phase becomes zero when that phase is disconnected has also been rejected by Avraam and Payatakes.11 These authors carried out a systematic study of immiscible two-phase flow in a visual micromodel and observed that disconnected oil contributes substantially to the flow. In the second set of experiments, we use a heavy crude to study in detail recovery performance at two temperatures: 24 and 35 °C. For both the viscous mineral oil and the heavy crude, gas- and liquid-phase relative permeabilities for the solution-gas drive process are estimated based on measured production rates and pressure drop across the core.
In this paper, we first present the experimental apparatus, the fluid and rock system, and the procedure for performing the experiments. Then, the measured and observed data are presented. A simple mathematical model is used to estimate gas- and liquid-phase relative permeabilities. At the end, several conclusions are drawn from the work.
Fluids and Porous Media.
A silicone oil (commercial product of Accumetric Inc., Boss-100, Canada) with API gravity of 14.4 and a crude oil (oil-E) with API gravity of 9 are used as the oil phase. Methane is used as the gas phase in all the experiments. Oil and gas are mixed in a high-pressure cylinder at a solution gas/oil ratio (GOR) of 6.5 vol/vol to prepare the live oil. The properties of the live oils are presented in Table 1. The oil viscosity is measured with a capillary viscometer at the test temperatures and at three different flow rates [10, 30, and 50 cm3/hr in a tube with an inside diameter (ID) of 1.5 mm]. The viscosity does not change with the flow rate. Distilled water is used to calibrate the capillary viscometer before the viscosity measurement. The silicone oil is clear, and we can observe gas-bubble nucleation, growth, and coalescence and flow behavior from the transparent coreholder. The sand in the coreholder is made up of clean Ottawa sand with a grain size of 212-355 µm. The sand is placed in a clear acrylic tube with an ID of 6.35 cm. At the top of the sandpack, a 1.5-cm layer of coarse sand (grain size of 600-800 µm) is used to prevent gas holdup under a stainless steel screen with an opening of 425 mu m. The measured absolute permeability, porosity, and pore volume are 13.7 darcies, 35.6%, and 608 cm3, respectively (Table 2). The permeability is measured by using normal decane (in a liquid state).
Fig. 1 shows a sketch of the experimental apparatus, which is similar to the one described in Ref. 9. The main component is the visual coreholder, which can be rotated up to 180° along its middle and center. For silicone-oil tests, the window allows observing and video recording the flow pattern of gas bubbles. An ISCO pump is used for measuring oil and gas production during the test by reversing the movement of the piston (the depletion process). Two Validyne pressure transducers are mounted at both ends of the sandpack to measure pressure; the reading accuracy is ±0.5 psi. Two differential pressure transducers are mounted at the middle of the coreholder for measuring the differential pressure across the sandpack; the reading accuracy is ±0.01 psi. The coreholder, pressure transducers, capillary viscometer, and ISCO pump are placed in an air bath, and the temperature is controlled with an accuracy of ±0.1 °C. A high-pressure cylinder containing the live crude oil, a gas/oil separator for measuring gas- and oil-production rates, and a heater are placed outside the air bath. A computer installed with LabView software (an automation software by Natl. Instrument Corp., Texas) is used to control the air-bath temperature and to record pressure data.
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