The Potential of Carbon Dioxide Gas Injection Application in Improving Oil Recovery

2000 ◽  
Author(s):  
D. Abdassah ◽  
S. Siregar ◽  
D. Kristanto
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Gas Injection ◽  
Carbon Dioxide Gas

Field Test of Carbon Dioxide Gas Channeling Foam Plugging

2013 ◽  
Vol 316-317 ◽  
pp. 769-772
Author(s):  
Yun Bo Bao
Keyword(s):  
Carbon Dioxide ◽  
Gas Injection ◽  
Oil Field ◽  
Low Permeability ◽  
Displacement Efficiency ◽  
Oil Displacement ◽  
Carbon Dioxide Gas ◽  
Oil Displacement Efficiency ◽  
Gas Channeling ◽  
Swept Volume

Gas channeling is tending to happen in CO2 immiscible flooding process, and that would seriously influence gas injection development. In order to plugging gas channeling channel effectively, improve inspiration and production profile, and enhance swept volume and oil displacement efficiency of the gas injection, field trials of foam seal channeling are carried out. The tests showed that carbon dioxide foam can effectively plugging the gas channeling channel, expand the swept volume of carbon dioxide gas, reduce invalid circulation, and enhancing oil displacement efficiency. The anti-sealing channeling technology is cost-efficient, and it is suitable for Daqing peripheral low permeability oil field on gas injection development. It has good prospects, and it will provide a strong technical support on gas injection development of low permeability reservoir.

scholarly journals An experimental study of alternative hot water alternating gas injection in a fractured model

2018 ◽  
Vol 37 (3) ◽  
pp. 945-959 ◽  
Author(s):  
Amirhossein Ebadati ◽  
Erfan Akbari ◽  
Afshin Davarpanah
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Conventional Technique ◽  
Hot Water ◽  
Recovery Factor ◽  
Water Flooding ◽  
Fractured Reservoir ◽  
Carbon Dioxide Gas ◽  
Water Alternating Gas ◽  
Alternative Water

Alternative injection of gas as slugs with water slugs, or alternative water gas injection, is the conventional technique for improving the recovery factor due to its high potential for mobilizing the residual oil in place in the reservoirs and to control gas mobility. The water alternating gas methodology is a combination of two oil recovery procedures: gas injection and waterflooding. The principal parameters that must be evaluated in water alternating gas injection in laboratory scale are reservoir heterogeneity, rock type, and fluid properties. In the current investigation, a feasibility study has been performed to analyze the five various scenarios of enhanced oil recovery techniques and compare them experimentally. The laboratory experiments are done for one of the Iranian reservoirs which have been subjected to waterflooding for several years, and the amount of recovery factor for water flooding is about 42%. The results of this study illustrate that water alternating gas injection and hot water alternating gas injection exert a profound impact on the amount of recovery factor. Moreover, the primary purpose of this study is to assess the application of alternative hot water and hot carbon dioxide gas injections in the conventional and fractured reservoir model.

scholarly journals Enhanced oil recovery application in low permeability formations by the injections of CO2, N2 and CO2/N2 mixture gases

2021 ◽  
Vol 11 (4) ◽  
pp. 1963-1971
Author(s):  
E. S. Bougre ◽  
T. D. Gamadi
Keyword(s):  
Carbon Dioxide ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Injection Pressure ◽  
Limiting Factors ◽  
Limiting Factor ◽  
Breakthrough Time ◽  
Carbon Dioxide Gas ◽  
Cost Constraints ◽  
Gas Flooding

AbstractLow oil recovery which is very predominant in shale oil reservoirs has stimulated petroleum engineers to investigate the applications of enhanced oil recovery methods in these formations. One such application is the injection of gases into the formation to stimulate increased oil recovery. In many gas flooding projects performed in the field, the miscibility of the gas injected is usually the most desired displacement mechanism, and carbon dioxide (CO2) gas has been recognized to be the best performing gas for injection due to its ability to be miscible with oil in the reservoir at low pressures compared to other gases such as nitrogen. This minimum miscibility pressure (MMP) is of very crucial importance because it is the primary limiting factor in the feasibility of a miscible gas flooding project. However, there are other limiting factors such as cost and availability and, in these instances, nitrogen (N2) and lean gas are the more preferred candidate as opposed to carbon dioxide gas. Mixing carbon dioxide gas with lean gas or with nitrogen in a required ratio can allow us to design an injection gas that will be suitable enough to satisfy both the availability and cost constraints and at the same time allow us to achieve a reachable and reasonable miscibility pressure. The objective of this paper is to investigate the effect of mixing nitrogen gas and carbon dioxide gas in a 50:50 ratio on oil recovery in tight oil formations. The experiment was performed with controlled constraints such as the same core sample, same crude oil and same core cleaning and saturation process which was repeated for each trial. The oil used was live oil from Eagle ford formation, and the gases used were nitrogen (99.9% purity), carbon dioxide and a mixture of nitrogen and carbon dioxide in a 50:50 ratio. The injection pressure ranged from 1000 to 5000 psi with pressure increments of 1000 psi, and the same flooding time was 6 h. The potential of the N2, CO2 and N2–CO2 mixture for improving oil recovery was assessed along with the breakthrough time. The results showed that CO2 gas had the highest recovery followed by the N2–CO2 mixture and N2 gas had the lowest recovery. The gas breakthrough time results showed that the N2–CO2 mixture had the longest breakthrough time, N2 had the shortest breakthrough time, and CO2 had a significantly longer breakthrough time than pure N2 gas. The RF increased with increasing pressure, but the gas breakthrough time decreased with increasing pressure. However, the incremental RF decreased in all three cases when the injection pressure was above 3000 psi.

Design of Simultaneous Enhanced Oil Recovery and Carbon Dioxide Storage With Potential Application to Offshore Trinidad

SPE Journal ◽  
2013 ◽  
Vol 18 (02) ◽  
pp. 345-354 ◽  
Author(s):  
Lorraine E. Sobers ◽  
Martin J. Blunt ◽  
Tara C. LaForce
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Gas Injection ◽  
Water Injection ◽  
Injection Rate ◽  
Gas Composition ◽  
Reservoir Properties ◽  
Injection Strategy ◽  
Oil Density ◽  
Carbon Dioxide Co2

Summary We developed an injection strategy to recover moderately heavy oil and store carbon dioxide (CO2) simultaneously. Our compositional simulations are founded on pressure/volume/temperature- (PVT-) matched properties of oil found in an unconsolidated deltaic sandstone deposit in the Gulf of Paria, offshore Trinidad. In this region, oil density ranges between 940 and 1010 kg/m3 (9 to 18°API). We use countercurrent injection of gas and water to improve reservoir sweep and trap CO2 simultaneously; water is injected in the upper portion of the reservoir, and gas is injected in the lower portion. The two water-injection rates investigated, 100 and 200 m3/d, correspond to the water-gravity numbers 6.3 to 3.1 for our reservoir properties. We applied this injection strategy using vertical producers with two injection configurations: single vertical injector and a pair of horizontal parallel laterals in a simplified representation of the unconsolidated Forest sand found offshore Trinidad. Twelve simulation runs were conducted, varying injection-gas composition for miscible- and immiscible-gas drives, water-injection rate, and injection-well orientation. Our results show that water-over-gas injection can realize oil recoveries ranging from 17 to 30%. In each instance, more than 50% of injected CO2 remained in the reservoir, with less than 15% of the retained CO2 in the mobile phase.

An Experimental and Numerical Analysis of Water-Alternating-Gas and Simultaneous-Water-and-Gas Displacements for Carbon Dioxide Enhanced Oil Recovery and Storage

SPE Journal ◽  
2016 ◽  
Vol 22 (02) ◽  
pp. 521-538 ◽  
Author(s):  
Fatemeh Kamali ◽  
Furqan Hussain ◽  
Yildiray Cinar
Keyword(s):  
Carbon Dioxide ◽  
Enhanced Oil Recovery ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Co2 Storage ◽  
Gas Injection ◽  
Shielding Effect ◽  
Miscible Displacements ◽  
Water Alternating Gas ◽  
Optimization Function

Summary This paper presents an experimental and numerical study that delineates the co-optimization of carbon dioxide (CO2) storage and enhanced oil recovery (EOR) in water-alternating-gas (WAG) and simultaneous-water-and-gas (SWAG) injection schemes. Various miscibility conditions and injection schemes are investigated. Experiments are conducted on a homogeneous, outcrop Bentheimer sandstone sample. A mixture of hexane (C6) and decane (C10) is used for the oil phase. Experiments are run at 70°C and three different pressures (1,300, 1,700, and 2,100 psi) to represent immiscible, near-miscible, and miscible displacements, respectively. WAG displacements are performed at a WAG ratio of 1:1, and a fractional gas injection (FGI) of 0.5 is used for SWAG displacements. The effect of varying FGI is also examined for the near-miscible SWAG displacement. Oil recovery, differential pressure, and compositions are recorded during experiments. A co-optimization function for CO2 storage and incremental oil production is defined and calculated by use of the measured data for each experiment. The results of SWAG and WAG displacements are compared with the experimental data of continuous-gas-injection (CGI) displacements. A compositional commercial reservoir simulator is used to examine the recovery mechanisms and the effect of mobile water on gas mobility. Experimental observations demonstrate that the WAG displacements generally yield higher co-optimization function than CGI and SWAG with FGI = 0.5 displacements. Numerical simulations show a remarkable reduction in gas relative permeability for the WAG and SWAG displacements compared with CGI displacements, as a result of which the vertical-sweep efficiency of CO2 is improved. More reduction of gas relative permeability is observed in the miscible and near-miscible displacements than in the immiscible displacement. The reduced gas relative permeability lowers the water-shielding effect, thereby enhancing oil recovery and CO2-storage efficiency. More water-shielding effect is observed in SWAG with FGI = 0.5 than in WAG. However, increasing FGI from 0.5 to 0.75 in the near-miscible SWAG displacement shows a significant increase in oil recovery, which is attributed to reduced water-shielding effect. So, an optimal FGI needs to be determined to minimize the water-shielding effect for efficient SWAG displacements.

Carbon Dioxide Flooding Technology Research and Field Test in Liuzan North Block

2014 ◽  
Vol 13 (05n06) ◽  
pp. 1460007
Author(s):  
Hanshi Zhang ◽  
Pingya Luo ◽  
Lei Sun ◽  
Zhijun Fu
Keyword(s):  
Carbon Dioxide ◽  
Field Test ◽  
Oil Recovery ◽  
Formation Energy ◽  
Gas Injection ◽  
Water Injection ◽  
Injection Pressure ◽  
Simulation Method ◽  
High Water ◽  
Carbon Dioxide Injection

The fault roots of Liuzan north block in Jidong oilfield of China have been long-term explored by solution gas drive. Recently, oil production declined rapidly because of shortage of formation energy and needing high water injection pressure. Carbon dioxide injection pressure is found to be generally low, and CO 2 has good solubility in crude oil to supply formation energy and achieve high oil recovery efficiency. In this work, a pilot program of CO 2 EOR technology was carried out. The slim tube test results showed that the minimal miscible pressure of Liuzan north block was 28.28 MPa. The injection parameters were optimized by numerical simulation method: the injection method was continuous, the slug size was 0.2 HCPV and the EOR efficiency was 7.23%. After two months of gas injection field test, the formation pressure of two gas injectors just increased by 14.02 MPa and 2.98 MPa, respectively, indicating that carbon dioxide could supply the formation energy effectively. 16 months after gas injection, the CO 2 injection amount was 14640 t, and the oil increment was 16424 t. The present work demonstrates the potential applicability of CO 2 flooding technology from high water injection reservoirs.

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