Risk Assessment and Enhanced Oil Recovery Effect of Gravity Assisted Oxygen-Reduced Air Flooding

2021 ◽  
Author(s):  
Lijuan Huang ◽  
Zongfa Li ◽  
Shaoran Ren ◽  
Yanming Liu
Keyword(s):  
Natural Gas ◽  
Oil Recovery ◽  
Gas Injection ◽  
Oil Production ◽  
Air Injection ◽  
Oil Reservoirs ◽  
Displacement Efficiency ◽  
Risk Area ◽  
Recovery Method ◽  
High Risk Area

Abstract The technology of air injection has been widely used in the second and tertiary recovery in oilfields. However, due to the injected air and natural gas will explode, the safety of the gas injection technology has attracted much attention. Gravity assisted oxygen-reduced air flooding is a new method that eliminates explosion risks and improves oil recovery in large-dip oil reservoirs or thick oil layers. The explosion limit data of different components of natural gas under high pressure were obtained through explosion experiments, which verified the suppression effect of oxygen-reduced air on explosions. The influence of natural gas composition and concentration on explosion limits was also investigated. In addition, a rotatable displacement device was used to study the feasibility of gravity assisted oxygen-reduced air injection for improving the heavy oil reservoirs recovery. Under pressure and temperature conditions of 20MPa and 371K, the sand-filled gravity flooding experiments with different dip angles were carried out using oxygen-reduced air with an oxygen content of 8%. The results show that with the increase of the reservoir dip, the pore volume of the injected fluid at the gas channeling point, the efficient development time of gas injection, and the final displacement efficiency of gas injection development all increase through gravity stabilization caused by gravity differentiation. In the presence of a dip angle, the cumulative oil production before the gas breakthrough point exceeded 80% of the oil production during the entire production process, indicating that gravity assisted oxygen-reduced air flooding is an effective and safe improving oil recovery method. Finally, the explosion risk of each link of the air injection process is analyzed, and the high-risk area and the low-risk area are determined.

The Mechanism of Flue Gas Injection for Enhanced Light Oil Recovery

2004 ◽  
Vol 126 (2) ◽  
pp. 119-124 ◽  
Author(s):  
O. S. Shokoya ◽  
S. A. (Raj) Mehta ◽  
R. G. Moore ◽  
B. B. Maini ◽  
M. Pooladi-Darvish ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Flue Gas ◽  
Gas Injection ◽  
Cost Effective ◽  
Air Injection ◽  
Oil Reservoirs ◽  
Flue Gases ◽  
Low Permeability ◽  
Light Oil ◽  
Light Oil Reservoirs

Flue gas injection into light oil reservoirs could be a cost-effective gas displacement method for enhanced oil recovery, especially in low porosity and low permeability reservoirs. The flue gas could be generated in situ as obtained from the spontaneous ignition of oil when air is injected into a high temperature reservoir, or injected directly into the reservoir from some surface source. When operating at high pressures commonly found in deep light oil reservoirs, the flue gas may become miscible or near–miscible with the reservoir oil, thereby displacing it more efficiently than an immiscible gas flood. Some successful high pressure air injection (HPAI) projects have been reported in low permeability and low porosity light oil reservoirs. Spontaneous oil ignition was reported in some of these projects, at least from laboratory experiments; however, the mechanism by which the generated flue gas displaces the oil has not been discussed in clear terms in the literature. An experimental investigation was carried out to study the mechanism by which flue gases displace light oil at a reservoir temperature of 116°C and typical reservoir pressures ranging from 27.63 MPa to 46.06 MPa. The results showed that the flue gases displaced the oil in a forward contacting process resembling a combined vaporizing and condensing multi-contact gas drive mechanism. The flue gases also became near-miscible with the oil at elevated pressures, an indication that high pressure flue gas (or air) injection is a cost-effective process for enhanced recovery of light oils, compared to rich gas or water injection, with the potential of sequestering carbon dioxide, a greenhouse gas.

scholarly journals Simulation Study of Allied In-Situ Injection and Production for Enhancing Shale Oil Recovery and CO2 Emission Control

Energies ◽  
2019 ◽  
Vol 12 (20) ◽  
pp. 3961
Author(s):  
Haiyang Yu ◽  
Songchao Qi ◽  
Zhewei Chen ◽  
Shiqing Cheng ◽  
Qichao Xie ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Co2 Emission ◽  
Gas Injection ◽  
Water Injection ◽  
Oil Production ◽  
Injection Rate ◽  
Oil Reservoirs ◽  
Shale Oil ◽  
Shale Oil Reservoirs

The global greenhouse effect makes carbon dioxide (CO2) emission reduction an important task for the world, however, CO2 can be used as injected fluid to develop shale oil reservoirs. Conventional water injection and gas injection methods cannot achieve desired development results for shale oil reservoirs. Poor injection capacity exists in water injection development, while the time of gas breakthrough is early and gas channeling is serious for gas injection development. These problems will lead to insufficient formation energy supplement, rapid energy depletion, and low ultimate recovery. Gas injection huff and puff (huff-n-puff), as another improved method, is applied to develop shale oil reservoirs. However, the shortcomings of huff-n-puff are the low sweep efficiency and poor performance for the late development of oilfields. Therefore, this paper adopts firstly the method of Allied In-Situ Injection and Production (AIIP) combined with CO2 huff-n-puff to develop shale oil reservoirs. Based on the data of Shengli Oilfield, a dual-porosity and dual-permeability model in reservoir-scale is established. Compared with traditional CO2 huff-n-puff and depletion method, the cumulative oil production of AIIP combined with CO2 huff-n-puff increases by 13,077 and 17,450 m3 respectively, indicating that this method has a good application prospect. Sensitivity analyses are further conducted, including injection volume, injection rate, soaking time, fracture half-length, and fracture spacing. The results indicate that injection volume, not injection rate, is the important factor affecting the performance. With the increment of fracture half-length and the decrement of fracture spacing, the cumulative oil production of the single well increases, but the incremental rate slows down gradually. With the increment of soaking time, cumulative oil production increases first and then decreases. These parameters have a relatively suitable value, which makes the performance better. This new method can not only enhance shale oil recovery, but also can be used for CO2 emission control.

The Mechanism of Flue Gas Injection for Enhanced Light Oil Recovery

2002 ◽  
Author(s):  
O. S. Shokoya ◽  
S. A. Mehta ◽  
R. G. Moore ◽  
B. B. Maini ◽  
M. Pooladi-Darvish ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Flue Gas ◽  
Gas Injection ◽  
Cost Effective ◽  
Air Injection ◽  
Oil Reservoirs ◽  
Flue Gases ◽  
Low Permeability ◽  
Light Oil ◽  
Light Oil Reservoirs

Flue gas injection into light oil reservoirs could be a cost-effective gas displacement method for enhanced oil recovery, especially in low porosity and low permeability reservoirs. The flue gas could be generated in situ as obtained from the spontaneous ignition of oil when air is injected into a high temp erature reservoir, or injected directly into the reservoir from some surface source. When operating at high pressures commonly found in deep light oil reservoirs, the flue gas may become miscible or near miscible with the reservoir oil, thereby displacing it more efficiently than an immiscible gas flood. Some successful high pressure air injection (HPAI) projects have been reported in low permeability and low porosity light oil reservoirs. Spontaneous oil ignition was reported in these projects, at least from laboratory experiments; however, the mechanism by which the generated flue gas displaces the oil has not been discussed in clear terms in the literature. An experimental investigation was carried out to study the mechanism by which flue gases displace light oil at a reservoir temperature of 116 °C and typical reservoir pressures ranging from 4,028 psi (27.77 MPa) to 6,680 psi (46.06 MPa). The results showed that the flue gases displaced the oil in a forward contacting process resembling a combined vaporizing and condensing multi-contact gas drive mechanism. The flue gases also became near-miscible with the oil at elevated pressures, an indication that high pressure flue gas (or air) injection is a cost-effective process for enhanced recovery of light oils, compared to rich gas or water injection, with the potential of sequestering greenhouse gases.

Influence of oil field production life on optimal CO2 flooding strategies: Insight from the microscopic displacement efficiency

2021 ◽  
Author(s):  
Anna Chernova ◽  
Andrey Afanasyev ◽  
Anna Andreeva
Keyword(s):  
Oil Recovery ◽  
Optimal Strategy ◽  
Net Present Value ◽  
Gas Injection ◽  
Oil Field ◽  
Displacement Efficiency ◽  
Present Value ◽  
Recovery Method ◽  
Gas Flooding ◽  
Injection Rates

<p>We investigate the influence of the microscopic displacement processes on optimal gas flooding strategies. We couple a 1-D compositional reservoir model with an economic model of the flooding to assess profitability of the strategies. In general, we aim at the net present value maximisation, although the oil recovery and CO<sub>2 </sub>storage efficiencies are also estimated. Under certain assumptions, we reduce the number of parameters controlling selection of optimal strategy to just a few dimensionless quantities characterising both physical and economic processes. We show that the production life of oil fields should not be fixed in optimisation studies, especially at low oil prices. A significantly larger net present value can be achieved by varying the reservoir lifetime in addition to the injection rates and volumes and other well controls. Herewith, the optimal strategy can differ from that in the case of a presumed production time. We conclude that waterflooding is the optimal recovery method if the injection rate is low, whereas gas (WAG) flooding applied as a primary method and followed by waterflooding is most optimal for large injection rates. Gas flooding applied as the tertiary recovery method is most optimal for an intermediate range of the rates. In the latter case, gas injection should begin much earlier than water breaks through to producing wells. Finally, we investigate how oil price influences the range of parameters suitable for gas injection.</p><p>The authors acknowledge funding from the Russian Foundation for Basic Research under grant # 20-31-80009.</p>

Pilot Project Evaluating WAG Efficiency for Carbonate Reservoir in Eastern Siberia

2021 ◽  
Author(s):  
Valentina Zharko ◽  
Dmitriy Burdakov
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Oil Production ◽  
Pilot Project ◽  
Carbonate Reservoir ◽  
Recovery Factor ◽  
Eastern Siberia ◽  
Water Cut ◽  
Wag Injection ◽  
Injection Rates

Abstract The paper presents the results of a pilot project implementing WAG injection at the oilfield with carbonate reservoir, characterized by low efficiency of traditional waterflooding. The objective of the pilot project was to evaluate the efficiency of this enhanced oil recovery method for conditions of the specific oil field. For the initial introduction of WAG, an area of the reservoir with minimal potential risks has been identified. During the test injections of water and gas, production parameters were monitored, including the oil production rates of the reacting wells and the water and gas injection rates of injection wells, the change in the density and composition of the produced fluids. With first positive results, the pilot area of the reservoir was expanded. In accordance with the responses of the producing wells to the injection of displacing agents, the injection rates were adjusted, and the production intensified, with the aim of maximizing the effect of WAG. The results obtained in practice were reproduced in the simulation model sector in order to obtain a project curve characterizing an increase in oil recovery due to water-alternating gas injection. Practical results obtained during pilot testing of the technology show that the injection of gas and water alternately can reduce the water cut of the reacting wells and increase overall oil production, providing more efficient displacement compared to traditional waterflooding. The use of WAG after the waterflooding provides an increase in oil recovery and a decrease in residual oil saturation. The water cut of the produced liquid decreased from 98% to 80%, an increase in oil production rate of 100 tons/day was obtained. The increase in the oil recovery factor is estimated at approximately 7.5% at gas injection of 1.5 hydrocarbon pore volumes. Based on the received results, the displacement characteristic was constructed. Methods for monitoring the effectiveness of WAG have been determined, and studies are planned to be carried out when designing a full-scale WAG project at the field. This project is the first pilot project in Russia implementing WAG injection in a field with a carbonate reservoir. During the pilot project, the technical feasibility of implementing this EOR method was confirmed, as well as its efficiency in terms of increasing the oil recovery factor for the conditions of the carbonate reservoir of Eastern Siberia, characterized by high water cut and low values of oil displacement coefficients during waterflooding.

Undersaturated Hydrocarbon Reservoir Waterflooding: A simulation Approach to Performance Assessment

2021 ◽  
Author(s):  
Adekunle Tirimisiyu Adeniyi ◽  
Miracle Imwonsa Osatemple ◽  
Abdulwahab Giwa
Keyword(s):  
Oil Recovery ◽  
Net Present Value ◽  
Oil Production ◽  
Base Case ◽  
Present Value ◽  
Sweep Efficiency ◽  
Recovery Method ◽  
Solution Approach ◽  
Hydrocarbon Reservoir

Abstract There are a good numbers of brown hydrocarbon reservoirs, with a substantial amount of bypassed oil. These reservoirs are said to be brown, because a huge chunk of its recoverable oil have been produced. Since a significant number of prominent oil fields are matured and the number of new discoveries is declining, it is imperative to assess performances of waterflooding in such reservoirs; taking an undersaturated reservoir as a case study. It should be recalled that Waterflooding is widely accepted and used as a means of secondary oil recovery method, sometimes after depletion of primary energy sources. The effects of permeability distribution on flood performances is of concerns in this study. The presence of high permeability streaks could lead to an early water breakthrough at the producers, thus reducing the sweep efficiency in the field. A solution approach adopted in this study was reserve water injection. A reverse approach because, a producing well is converted to water injector while water injector well is converted to oil producing well. This optimization method was applied to a waterflood process carried out on a reservoir field developed by a two - spot recovery design in the Niger Delta area of Nigeria that is being used as a case study. Simulation runs were carried out with a commercial reservoir oil simulator. The result showed an increase in oil production with a significant reduction in water-cut. The Net Present Value, NPV, of the project was re-evaluated with present oil production. The results of the waterflood optimization revealed that an increase in the net present value of up to 20% and an increase in cumulative production of up to 27% from the base case was achieved. The cost of produced water treatment for re-injection and rated higher water pump had little impact on the overall project economy. Therefore, it can conclude that changes in well status in wells status in an heterogenous hydrocarbon reservoir will increase oil production.

scholarly journals Investigation of Oil Recovery in Fractured Carbonate Rock by

2016 ◽  
Vol 6 (1) ◽  
pp. 14
Author(s):  
H. Karimaie ◽  
O. Torsæter
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Water Injection ◽  
Co2 Injection ◽  
Recovery Method ◽  
Asmari Limestone ◽  
Fractured Carbonate ◽  
Efficient Recovery ◽  
Live Oil ◽  
Non Equilibrium

The purpose of the three experiments described in this paper is to investigate the efficiency of secondary andtertiary gas injection in fractured carbonate reservoirs, focusing on the effect of equilibrium gas,re-pressurization and non-equilibrium gas. A weakly water-wet sample from Asmari limestone which is the mainoil producing formation in Iran, was placed vertically in a specially designed core holder surrounded withfracture. The unique feature of the apparatus used in the experiment, is the capability of initializing the samplewith live oil to obtain a homogeneous saturation and create the fracture around it by using a special alloy whichis easily meltable. After initializing the sample, the alloy can be drained from the bottom of the modified coreholder and create the fracture which is filled with live oil and surrounded the sample. Pressure and temperaturewere selected in the experiments to give proper interfacial tensions which have been measured experimentally.Series of secondary and tertiary gas injection were carried out using equilibrium and non-equilibrium gas.Experiments have been performed at different pressures and effect of reduction of interfacial tension werechecked by re-pressurization process. The experiments showed little oil recovery due to water injection whilesignificant amount of oil has been produced due to equilibrium gas injection and re-pressurization. Results alsoreveal that CO2 injection is a very efficient recovery method while injection of C1 can also improve the oilrecovery.

Experimental Analysis of the Effects of Varying Temperature and Viscosities on Foamy Oil Production

2021 ◽  
Author(s):  
Jasmine Shivani Medina ◽  
Iomi Dhanielle Medina ◽  
Gao Zhang
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Elevated Temperatures ◽  
Oil Production ◽  
Oil Reservoirs ◽  
Oil Viscosity ◽  
Gas Recovery ◽  
Foamy Oil ◽  
Heavy Oil Reservoirs ◽  
Pressure Depletion

Abstract The phenomenon of higher than expected production rates and recovery factors in heavy oil reservoirs captured the term "foamy oil," by researchers. This is mainly due to the bubble filled chocolate mousse appearance found at wellheads where this phenomenon occurs. Foamy oil flow is barely understood up to this day. Understanding why this unusual occurrence exists can aid in the transfer of principles to low recovery heavy oil reservoirs globally. This study focused mainly on how varying the viscosity and temperature via pressure depletion lab tests affected the performance of foamy oil production. Six different lab-scaled experiments were conducted, four with varying temperatures and two with varying viscosities. All experiments were conducted using lab-scaled sand pack pressure depletion tests with the same initial gas oil ratio (GOR). The first series of experiments with varying temperatures showed that the oil recovery was inversely proportional to elevated temperatures, however there was a directly proportional relationship between gas recovery and elevation in temperature. A unique observation was also made, during late-stage production, foamy oil recovery reappeared with temperatures in the 45-55°C range. With respect to the viscosities, a non-linear relationship existed, however there was an optimal region in which the live-oil viscosity and foamy oil production seem to be harmonious.

Production Optimization Coupling Multiple Reservoirs and Facilities With Sour Gas Re-Injection for Miscible EOR in South Oman

2021 ◽  
Author(s):  
Kamlesh Kumar ◽  
Varun Pathak ◽  
Pankaj Agrawal ◽  
Zaal Alias ◽  
Tushar Narwal ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Production System ◽  
Gas Injection ◽  
Ghg Emissions ◽  
Development Project ◽  
Production Optimization ◽  
Oil Reservoirs ◽  
Fully Implicit ◽  
Gas Utilization ◽  
Sour Gas

Abstract Effective gas utilization is critical to any gas injection development project to maximize recoveries for a given purchase of make-up gas, whilst reducing the Green Gas House (GHG) emissions. This paper describes the use of a fully implicit Integrated Production System Model (IPSM) for two inter-connected production system networks, coupling multiple, critically sour oil reservoirs undergoing Miscible Gas Injection (MGI) for Enhanced Oil Recovery (EOR) using produced sour gas from oil and condensate fields in South Oman. The IPSM model links sixteen reservoir models with varying levels of complexities to the facilities network. Complexities in the facilities include multiple nodal constraints that necessitate the use of an Equation of State model (EOS). The IPSM model honors the gas balance implicitly. Gas flood optimization includes prioritizing low GOR production wells (at reservoir and well level) whilst maintaining reservoir pressure above Minimum Miscibility Pressures (MMP). Development schedule optimization also helps in optimizing the compressor size, the key Capex component. Compositional modeling allows continuous tracking of souring levels at different nodes, providing integrity status of overall production system network. The current IPSM model helps in optimization of schedule for the phased development of the oil reservoirs and eventually the most efficient gas utilization. This has enabled low pressure operation in some reservoirs providing oil at very low unit technical cost while waiting for gas availability. Compositional tracking for H2S helps in operating the facilities within design limits whilst planning future developments to cater to this design. Some key parameters can be parameterized for quick sensitivity analysis for an informed decision making for business opportunities. The production potential of the system is also tracked to ensure there is a cushion in the system to deal with any unexpected changes. This feature helps in planning and optimizing the scheduled turn-around activities for these two inter-connected production system networks. The novelty of this work is collaboration across multiple disciplines, especially the surface and subsurface because of complex interactions between facilities constraints and reservoir performance (associated with produced gas reinjection). Compositional tracking and injection gas apportionment across multiple reservoirs is key to the overall value maximization in this complex development.

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