| Gas injection EOR technology is one of the three tertiary oil recovery technologies. CO2 as an effective gas displacing agent has shown good flooding results in the world. At the same time, CO2 is the main greenhouse gas. Developing of CO2 flooding can achieve organic unity of economic and social benefits. The target reservoir of the study is LB oilfield which belongs to high dig angle and low permeability reservoir. The formation energy declined rapidly and the waterflood effiency was very poor because of the high water injection pressure. Therefore, it is necessary to study the development mechanism, water-control mechanism and development scheme of the CO2 tertiary oil recovery. The formation energy would be supplied and oil recovery be improved by pilot implementation which provide a reference for efficient development of high dig angle and low permeability reservoir.The priority goals of the research were:analysis of water flooding developing present situation of the pilot area, PVT test of formation fluids, formation fluid swelling test by CO2 injection, MMP test of oil by CO2 injection, combined long core physical simulation experiments for CO2 displacement efficiency and water-control mechanism, CO2 solubility experiment in formation water, CO2 microscopic oil displacement experiment, Jamin effect and flow characteristics of formation water saturated by CO2 and CO2 microscopic flooding features emerging from formation water. On the basics of these studies, CO2 flooding pilot project was optimized by three-dimensional reservoir numerical simulation, and the field implementation effect was assessed.The main findings include the followings:1. The Baigezhuang fault of LB oilfield is sealed well. The reservoir belongs to low-to-moderate porosity, low permeability, and strong heterogeneity reservoir with a dip angle of 35°～45°.As a result of the high water injection pressure, the water flooding efficiency was very poor and the remaining oil saturation was high. The average formation temperature was 102℃.The original and the current formation pressure of the fault root were respectively 29.5MPa and 24.07MPa. In general, the formation situation was suitable for CO2 EOR.2. The crude oil belongs to ordinary black oil, which has moderate swelling ability and medium density. The oil density decreased slightly with the pressure decrease and decreased with the temperature increase. In the current formation and temperature, when the CO2 injection volume reached 60% (mol), the formation fluid saturation pressure increased 1.35 times and 1.45 times the volume expansion, which was conducive to oil displacement due to expansion, resolution and viscosity break.3. The slim tube test showed that the MMP of reservoir fluid with CO2 injection was 28.18MPa. Therfore, in the current formation pressure 24.07MPa, it could not achieve miscible flooding but near-miscible flooding.4. The combined long core oil displacement experiments indicated that CO2 flooding could enhance oil recovery by 8.7% compared to water flooding under the present formation pressure, and maintaining a high formation pressure could increase the solubility of CO2 in the crude oil, which would help improve oil displacement efficiency and delay gas channeling.5. The microscopic oil displacement test showed that CO2 could make crude oil expand volume, reduce viscocity and improve ability of dissolving flooding. In the process of CO2 near-miscible flooding, the oil flow mainly along with the large pores, and the oil in small pores could also be displaced.6.The force analysis of air colume showed that when the pore throat radius was larger than 3.0μm, the effective buoyancy was greater than the capillary force, so the gas would be migrated upward. In the far wellbore zone, effective buoyancy and drawdown pressure were the same magnitude, and gas floating produced longitudinal separation effect. CO2 could sweep the remaining attic oil, forming a gravity stable displacement. So the main CO2 flooding mechanism of LB oilfield, which belongs to high dig angle and low permeability, was multi-contact, solubility increase, volume expansion, viscocity reduction, gravity stable and near-miscible flooding.7. The CO2 solubility in formation water test indicated that the CO2 solubilty increased with the pressure increase. In the slim tube apparatus, CO2 gradually emerged from the saline water as pressure decreasing, forming two-phase flow. Jamin effect made the rock permeability decrease significantly. In the microscopic model experiment, the same phenomenon was also observed. When the pressure of the saline water saturated with CO2 decreased, CO2 emerged from water. Bubbles converged together to form a gas slug flow passage. In the pore throat, Jamin effect also increased flow resistance. Therefore, during the CO2 field pilot application, a small amount of CO2 would dissolved in the saline water near the injection wells due to high injection presssure, while CO2 would emerge from water around production wells due to pressure drop, which leaded to increase flow resistance and water-control effect.8. The long core waterflood experiment with CO2 slug showed that the water cut decreased 16.4% and the recovery increased 4.7% compared to simple water flooding, which verified the CO2 water-control mechanism in the slime tube test and microscopic model experiment.9. According to domestic and foreign CO2 flooding filed experiences, we advanced the development model of Hybrid Water alternating Gas-Periodical Production. By numerical simulation and reservoir engineering studies, injection and production parameters of LB oilfield CO2 flooding were optimized and the pilot scheme was made.10. At present, four gas injectors were implemented with water alternating gas injection. There were ten stimulated oil wells. The cumulative incremental oil of scale down was 40642t and the enhanced recovery was 5.54%. The water cut decreased to 40.6% and droped 9.47%. |
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