Application of Gas Lift Technology to a High-Water-Cut Heavy-Oil Reservoir in Intercampo Oilfield, Venezuela
- Hong'en Dou (Research Inst. of Petroleum Exploration and Development, PetroChina) | Yu wen Chang (Research Inst. of Petroleum Exploration and Development, PetroChina) | Dandan Hu (Research Inst. of Petroleum Exploration and Development, PetroChina) | Wenxin Cai (CNPC America Ltd) | Guozhen Zhao (CNPC America Ltd)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- February 2007
- Document Type
- Journal Paper
- 46 - 49
- 2007. Society of Petroleum Engineers
- 5.3.2 Multiphase Flow, 5.2 Reservoir Fluid Dynamics, 1.6 Drilling Operations, 5.4.2 Gas Injection Methods, 4.1.2 Separation and Treating, 3.1.7 Progressing Cavity Pumps, 2.4.3 Sand/Solids Control, 4.6 Natural Gas, 3.1.2 Electric Submersible Pumps, 5.1.2 Faults and Fracture Characterisation, 3.1 Artificial Lift Systems, 3.1.6 Gas Lift, 5.2.1 Phase Behavior and PVT Measurements, 3.1.1 Beam and related pumping techniques
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This paper presents successful applications of gas lift technology to heavy-oil reservoirs in Intercampo oilfield, Lake Maracaibo, Venezuela. Liquid production rates range from 10 to 320m3/day per well. Gas lift was selected as the first artificial lift method in the oilfield. The paper describes the gas lift mechanisms applied in a high-water-cut heavy-oil (below 15 API) reservoir. The theoretical analysis showed that the injection gas rate for gas lift and the gas/oil ratio (GOR) of an oil well have direct effects on the fluid flow from the wellbore.
Theoretical design and actual gas lift production are described in the paper. The correlations used for artificial gas lift design for high-water-cut heavy oil need to be refined to match the field data. The difference between theoretical design and actual production is significant for high-water-cut heavy oil lower than 15 API. Formation of oil/water emulsion was not observed during gas lifting of low-API, high-water-cut oil from wells.
In this study, a correction coefficient for gas lift design was applied to a high-water-cut, low-API field. Further work is needed to refine this gas lift design software. It should prove particularly useful for production engineers in optimizing the design of gas lifting equipment.
Continuous gas lift has been employed in lifting heavy crude for many years (Blann et al. 1980; Redden et al. 1974; Boberg et al. 1973; Abdel et al. 1996). The gas lift method has been widely applied in the former Soviet Union and in Venezuela (Ferrer and Maggiolo 1991; Apyev 1978; Ametov et al. 1985). In fact, heavy oil with a density of between 0.934~0.9659g/cm3 and viscosity lower than 50cp is commonly processed by continuous gas lift in Venezuela.
Experimental investigation shows that when a 3% hydrocarbon solvent is injected during gas lifting, daily oil production will increase. Actual data from former Soviet Union oilfields show that if the water cut is lower than 40%, the solvent does the work. If the water cut is higher than 50%, the hydrocarbon solvent effect is minimal. Solvent will have no effect at all when the water cut is higher than 70% (Apyev 1978; Ametov et al. 1985).
Generally, rod pumps have proven to be the best artificial lift method in heavy oil reservoirs, especially for heavy crude oil at densities between 0.96 and 1.0g/cm3.
Some researchers have thought that gas lift is not suitable for lifting low-API crude (Berevkiy and Pershchev 1982; Diaz 1981; Brown 1982; Clegg et al. 1993);others have said that it is not feasible for lifting low GOR oil because the gas rate from the field may be too low to support the gas lift operation (Douglas et al. 1989; Johnson 1968). However, gas lift has been successfully applied to this type of well in Venezuela with good results. It has been suggested that gas lift, if applied appropriately, could be the best artificial lift method for heavy oil with water cut from an economic point of view.
The literature indicates that the fluid-flow behavior in gas lift resembles the natural flow in a vertical or near-vertical well. ("Executive Committee?? 1984; Palke 1996; Begges 1991; Pengju 2003; Baker-Hughes 2003). However, as a matter of fact, change of phase regimes induced by gas lift are much more complex than those in natural flow, because high-velocity gas, as it enters the well tubing through the gas lift valve and then mixes with oil, gas, and water in the reservoir fluid, brings in not only an external gas mass but also an external energy supplement. The high-velocity flow creates a new multiphase fluid regime, changing from the liquid phase to a continuous gas phase (transitional flow). Gas bubbles join together and liquid may be entrained into the bubbles. Although the liquid-phase effects are significant, the gas-phase effects are dominant. In a later stage, annular flow, mist flow, or both occur, the gas phase becomes continuous, and the liquid is entrained as droplets in the gas phase. Gas phase controls the pressure gradient rather than following the three types of flow regime in a gas/liquid flow typical of vertical tubing. The resulting multiphase flow consists of bubble, slug, plug, and mist flow all the way from the bottomhole to the wellhead. Factors influencing the flow regime include borehole deviation, proportion of each phase, relative differences in phase densities, surface tension and viscosity of each phase, average velocity, tubing roughness, and chock size. Kickoff pressure and casinghead pressure are functions of the previously mentioned factors.
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