Huiying Guo
Ziqiang Wang
Yuankai Zhang
Ning Xu
Zhen Li
PetroChina Xinjiang Oilfield Co.
Xinjiang Karamay, China
Carbon dioxide (CO2) huff-and-puff simulation experiments in China’s Junggar basin shale oil reservoirs analyzed the number of huff-and-puff cycles, production pressure, reservoir permeability, and reservoir porosity as factors that affect secondary recovery.
The study showed that periodic huff and puff recovery decreases with the number of cycles, with cumulative recovery mainly confined to 3-5 cycles. Recovery increases with higher permeability and porosity. Cumulative hydrocarbon recovery increases 4.7-5.5 fold using CO2 huff and puff over primary compaction-drive recovery.
Shale oil huff-and-puff
Ordos, Songliao, Junggar, and other basins in China are key areas for shale oil exploration and development. These reservoirs have ultra-low porosity, ultra-low permeability, heterogeneity, narrow pore-throats, and complex pore-structures. Decline rates are 40-90%.
Gas injection recovers additional oil after initial depletion from compaction, but water injection is not suitable for these reservoirs. As a high-efficiency oil displacement agent, CO2 effectively restores formation energy, improves crude oil flow, and increases recovery.
After initial depletion, oil content in the formation remains relatively high. Carbon dioxide injection (the huff phase) partially restores formation energy due to good solubility of CO2 in crude oil. CO2 dissolution also causes volume expansion and oil viscosity reduction. Crude interfacial tension and seepage resistance also shrinks, increasing flow capacity. The volume of injected CO2 increases due to the expansion effect, occupying part of the remaining oil space, resulting in the discharge of this portion of crude oil. The formerly non-flowing crude flows during production (the puff phase).
With additional huff-and-puff cycles, remaining oil content decreases gradually. CO2 backflows during each cycle, decreasing gas utilization and deteriorating the huff-and-puff effect. As a result, periodic recovery decreases gradually, and the bump in cumulative recovery from huff and puff gradually decreases.
Most CO2 huff-and-puff studies in China concentrated on heavy-oil reservoirs, fractured-vuggy reservoirs, and low-permeability reservoirs. Junggar basin’s shale-oil reservoir has not been subject to similar studies, and the current work includes core-level simulations to determine CO2 huff-and-puff feasibility in the basin.
Huff-and-puff core test
Experimental oil was prepared from a combination of degassed oil in the Lucaogou formation of the Jimsar Sag and kerosene, with a final density of 0.86g/cu cm. Basic physical core parameters are measured per the National Standard GB/T29172-2012 Core Analysis Method and industry standard SY/T5336-2006 Core Analysis Method. Specific core data are shown in the table.
A Core Lab Co. CFS-200 multi-functional core displacement integrated system performed the tests using a high-precision displacement pump, intermediate container, pressure sensor, core holder, confining pressure pump, gas-liquid separation device, back pressure pump, gas-liquid flowmeter, and thermostat. Confining pressure of 46 megaPascals (MPa), initial flow pressure of 43 megaPascals (MPa), and 80° C. core temperature matched original formation conditions. Production pressure after primary depletion (compaction recovery) was set to either 20 MPa or 30 MPa.
The core was washed and dried to constant weight, placed under vacuum, saturated with simulated oil, and reweighed. It was subsequently inserted into a sleeve and subjected to confining pressure and back pressure. Core pressure was increased to formation pressure and initial core production simulated primary (depletion drive) production until core pressure dropped to 20 MPa. Carbon dioxide was subsequently injected at a constant 43 MPa.
The core holder was sealed for 12 hr after core pressure equalized with injection pressure. After shut-in, a valve was opened to produce oil until flow stopped. Recorded data included total produced oil and gas. The core was replaced and the test re-run with the endpoint set at 30-MPa production pressure instead of 20 MPa.
Core test results
Primary recovery of Core 1, Core 2, and Core 3 was 4.98%, 4.72%, and 3.50% respectively. Under 30-MPa production pressure, recovery under huff-and-puff decreased logarithmically, and the early stage decreased rapidly. After eight huff-and-puff cycles, cumulative recovery of Core 1, Core 2, and Core 3 was 27.60%, 23.91%, and 16.52% respectively (Fig. 1). Cumulative recovery of the first 3-5 cycles accounted for 80-90% of the final recovery rate.
With increasing huff-and-puff cycles, gas-oil ratio (GOR) increased exponentially (Fig. 2). This is because the experiment adopts the method of constant pressure gas injection. After each CO2 huff and puff, the pressure was restored to the original formation pressure by continuous gas injection. As remaining oil content decreased, cyclic gas injection gradually increased to restore original formation pressure. Simultaneously, gas flowback affected oil throughput and reduced CO2 utilization. Cyclic oil production gradually decreased, leading to increasing GOR. GOR increased slowly in the first five huff-and-puff cycles and increased rapidly after the sixth cycle, indicating that the utilization rate of CO2 decreased sharply at this time. CO2 huff and puff, therefore, should be controlled within five cycles in this core configuration.
Fig. 3 shows that the lower production pressure (20 MPa) yields higher periodic recovery with CO2 huff and puff. This is because more CO2 is required under lower production pressure to restore pressure to the original formation pressure (43 MPa). The higher volume of CO2 results in more elastic energy released by the gas as it evolves from the crude oil. Also, the lower production pressure yields more compaction in the rock.
In the same huff-and-puff cycle, periodic recovery increases logarithmically with the increase in permeability or porosity, but the influence of permeability on the periodic recovery is less than that of production pressure (Fig. 4).
Jimsar field huff-and-puff
Jimsar shale oil has low recovery. Based on the above experimental analysis, four typical wells in Jimsar were selected for CO2 huff-and-puff testing. Three wells significantly increased oil production, but one well produced poor results.
Vertical well J36 was hydraulically fractured and started CO2 huff-and-puff operations after 2,395 days of depletion. CO2 injection volume reached 1,063 tonnes and oil pressure increased by 16 MPa. Cumulative injection time was 13 days with 79 days shut-in time.
After opening the well, crude oil production increased significantly, with 10 tonnes/day produced in the early stage of secondary recovery. After 975 days, a cumulative 1,588.86 tonnes of oil were recovered. The oil change rate is 1.49 tonne oil/tonne CO2, demonstrating efficient oil recovery.
In horizontal well JH126, after a cumulative 6,580 tonnes of oil produced, injection of 3,503 tonnes of CO2 increased oil to 10.6 tonnes/day from 4 tonnes/day, recovering an additional 1,570 tonnes of oil for a 0.44 oil/CO2 change rate. Oil pressure increased by 16 MPa, and the well resumed natural production. Estimated ultimate recovery (EUR) increased by 8% to 2.1×104 tonnes from 1.98×104 tonnes.
JH132 is an isolated horizontal well with an 1,834-m lateral section. CO2 huff and puff started after 494 days of depletion. Cumulative injection time was 37 days with 3504.61 tonnes total CO2 injection at 1.91 tonne CO2/m intensity. The well was shut-in for 72 days. Upon establishing production, the well recovered a cumulative 812.9 tonnes of oil over 79 days. Decline is high, with an annual rate of 93.36%. Estimated total cumulative recovery after huff-and-puff operations is 1,027 tonnes.
JH024 is a horizontal well with a 1,305-m lateral section. Average reservoir thickness is 10 m. Two adjacent wells in the surrounding area were fractured, and preliminary pressure and production data indicate that fractures connect the three wells. The well produced for 1,438 days during early depletion with about 3.5% recovery. After depletion, a total of 3,889.40 tonnes CO2 was injected over 21 days with 2.98 tonnes CO2/m gas injection intensity.
After 13 days of shut-in, the well only produced gas. Daily oil production did not significantly increase after switching to pumping. Due to the influence of the adjacent wells, the overall oil production of the well group increased by 842 tonnes, and the oil change rate was only 0.22 tonne CO2/tonne oil. The effect of CO2 injection on improving oil recovery was not significant.
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Authors
Huiying Guo ([email protected]) is senior engineer at Research Institute of Experiment and Detection of PetroChina Xinjiang Oilfield Co. She holds an MS (2013) from Xi 'an Shiyou University. She is a member of Xinjiang petroleum society.
Ziqiang Wang ([email protected].) is director at Research Institute of Experiment and Detection of PetroChina Xinjiang Oilfield Co. He holds an MS (2008) from China University of Petroleum (East China). He is a member of Xinjiang petroleum society.
Yuankai Zhang([email protected]) is senior engineer at Research Institute of Experiment and Detection of PetroChina Xinjiang Oilfield Co. He holds an MS (2020) from Southwest Petroleum University. He is a member of Xinjiang petroleum society.
Ning Xu ([email protected]) is senior engineer at Research Institute of Experiment and Detection of PetroChina Xinjiang Oilfield Co. He holds an MS (2006) from Xi 'an Shiyou University. He is a member of Xinjiang petroleum society.
Zhen Li([email protected]) is senior engineer at Research Institute of Experiment and Detection of PetroChina Xinjiang Oilfield Co. He holds a BS (1997) from China University of Petroleum, Beijing. He is a member of Xinjiang petroleum society.
