Comparison of the Impact of Dip and Vertical Transmissibility on Oil Recovery and Carbon Storage Using Water over Gas Injection in the Forest Reserve Field, Trinidad

2014 ◽  
Author(s):  
S. C. Jones ◽  
L. E. Sobers
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Thick Layer ◽  
Oil Production ◽  
Forest Reserve ◽  
Geologic Storage ◽  
Average Porosity ◽  
Shaly Sand ◽  
Carbon Dioxide Co2 ◽  
The Impact

Abstract A combination of geologic carbon dioxide (CO2) sequestration and CO2 enhanced oil recovery (CO2EOR) can address the two of Trinidad and Tobago's energy sector challenges: falling oil production and increasing CO2 emissions. Geologic storage of CO2 in heavy oil reservoirs can increase oil production while injected CO2 is effectively sequestered. Our investigations are based on 225 ft (~69 m) of the unconsolidated Lower Forest sand, average porosity and permeability of 32% and 125 md, respectively, found within the Forest reserve field, Trinidad. The middle section of this sand package contains a 26 ft (8m) thick layer of shaly sand with average permeability 70 md and average porosity 28%. We used reservoir simulations to determine the impact of dip and reduced transmissibility on the performance of the water over gas injection strategy using CO2. From our results we conclude that the reduced vertical transmissibility and dip affects the formation of the oil bank, water underride and the rate of CO2 migration.

Waterflooding in Carbonate Reservoirs: Does the Salinity Matter?

2014 ◽  
Vol 17 (03) ◽  
pp. 304-313 ◽  
Author(s):  
A.M.. M. Shehata ◽  
M.B.. B. Alotaibi ◽  
H.A.. A. Nasr-El-Din
Keyword(s):  
Oil Recovery ◽  
Sudden Change ◽  
Oil Production ◽  
Deionized Water ◽  
Production Performance ◽  
Shallow Aquifer ◽  
Secondary Recovery ◽  
Tertiary Recovery ◽  
The Impact ◽  
Indiana Limestone

Summary Waterflooding has been used for decades as a secondary oil-recovery mode to support oil-reservoir pressure and to drive oil into producing wells. Recently, the tuning of the salinity of the injected water in sandstone reservoirs was used to enhance oil recovery at different injection modes. Several possible low-salinity-waterflooding mechanisms in sandstone formations were studied. Also, modified seawater was tested in chalk reservoirs as a tertiary recovery mode and consequently reduced the residual oil saturation (ROS). In carbonate formations, the effect of the ionic strength of the injected brine on oil recovery has remained questionable. In this paper, coreflood studies were conducted on Indiana limestone rock samples at 195°F. The main objective of this study was to investigate the impact of the salinity of the injected brine on the oil recovery during secondary and tertiary recovery modes. Various brines were tested including deionized water, shallow-aquifer water, seawater, and as diluted seawater. Also, ions (Na+, Ca2+, Mg2+, and SO42−) were particularly excluded from seawater to determine their individual impact on fluid/rock interactions and hence on oil recovery. Oil recovery, pressure drop across the core, and core-effluent samples were analyzed for each coreflood experiment. The oil recovery using seawater, as in the secondary recovery mode, was, on the average, 50% of original oil in place (OOIP). A sudden change in the salinity of the injected brine from seawater in the secondary recovery mode to deionized water in the tertiary mode or vice versa had a significant effect on the oil-production performance. A solution of 20% diluted seawater did not reduce the ROS in the tertiary recovery mode after the injection of seawater as a secondary recovery mode for the Indiana limestone reservoir. On the other hand, 50% diluted seawater showed a slight change in the oil production after the injection of seawater and deionized water slugs. The Ca2+, Mg2+, and SO42− ions play a key role in oil mobilization in limestone rocks. Changing the ion composition of the injected brine between the different slugs of secondary and tertiary recovery modes showed a measurable increase in the oil production.

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.

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.

scholarly journals The efficiency of gas injection into low-permeability multilayer hydrocarbon reservoirs

2021 ◽  
Vol 3 (10) ◽  
pp. 100-108
Author(s):  
Sudad H AL-Obaidi ◽  
Miel Hofmann ◽  
Falah H. Khalaf ◽  
Hiba H. Alwan
Keyword(s):  
Hydraulic Fracturing ◽  
Oil Recovery ◽  
Gas Injection ◽  
Oil Production ◽  
Recovery Factor ◽  
Low Permeability ◽  
Compositional Model ◽  
Multistage Hydraulic Fracturing ◽  
Low Permeability Reservoirs ◽  
Working Agent

The efficiency of gas injection for developing terrigenous deposits within a multilayer producing object is investigated in this article. According to the results of measurements of the 3D hydrodynamic compositional model, an assessment of the oil recovery factor was made. In the studied conditions, re-injection of the associated gas was found to be the most technologically efficient working agent. The factors contributing to the inefficacy of traditional methods of stimulating oil production such as multistage hydraulic fracturing when used to develop low-permeability reservoirs have been analyzed. The factors contributing to the inefficiency of traditional oil-production stimulation methods, such as multistage hydraulic fracturing, have been analysed when they are applied to low-permeability reservoirs. The use of a gas of various compositions is found to be more effective as a working agent for reservoirs with permeability less than 0.005 µm2. Ultimately, the selection of an agent for injection into the reservoir should be driven by the criteria that allow assessing the applicability of the method under specific geological and physical conditions. In multilayer production objects, gas injection efficiency is influenced by a number of factors, in addition to displacement, including the ratio of gas volumes, the degree to which pressure is maintained in each reservoir, as well as how the well is operated. With the increase in production rate from 60 to 90 m3 / day during the re-injection of produced hydrocarbon gas, this study found that the oil recovery factor increased from 0.190 to 0.229. The further increase in flow rate to 150 m3 / day, however, led to a faster gas breakthrough, a decrease in the amount of oil produced, and a decrease in the oil recovery factor to 0.19 Based on the results of the research, methods for stimulating the formation of low-permeability reservoirs were ranked based on their efficacy.

Theoretical and Numerical Investigation of Supersonic Multiphase Gas Injection

2021 ◽  
Author(s):  
Da Zhu ◽  
Mohan Sivagnanam ◽  
Ian Gates
Keyword(s):  
Shock Wave ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Single Phase ◽  
Gas Injection ◽  
Continuous Phase ◽  
Solid Particles ◽  
Gas Flows ◽  
Theoretical Derivation ◽  
The Impact

Abstract Supersonic gas injection can help deliver gas uniformly to a reservoir, regardless of reservoir conditions. This technology has played a key role in enhanced oil recovery (EOR) and in particular, thermal enhanced oil recovery operations. Most previous studies have focused on single phase gas injection whereas in most field applications, multiphase and multicomponent situations occur. In the research documented in this paper, we report on results of evaluations of compressible multiphase supersonic gas flows in which gas is the continuous phase is seeded with dispersed liquid droplets or solid particles. Theoretical derivation and numerical simulations with and without relative motions between continuous and disperse phases are examined first. The results illustrate that the shock wave structures and flow properties associated with the multiphase gas flows are different than that of single-phase isentropic flows. The existence and importance of relaxation zones after the normal shock wave in multiphase flow is described. Numerical computational fluid dynamics (CFD) simulations are conducted to show how the multiphase multicomponent flow affects gas phase injection under different conditions. The impact of solid/liquid mass loading on flow performance is discussed. Finally, the practical application of the findings is discussed.

Minimum Miscibility Pressure of CO2/Hydrocarbon Systems Within Nanopores

2021 ◽  
Author(s):  
Gang Yang ◽  
Xiaoli Li
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Unconventional Reservoirs ◽  
Minimum Miscibility Pressure ◽  
Theoretical Approaches ◽  
Fluid Systems ◽  
Confined Fluid ◽  
Miscible Gas Injection ◽  
Fluid Characterization ◽  
The Impact

Abstract Minimum miscibility pressure (MMP), as a key parameter for the miscible gas injection enhanced oil recovery (EOR) in unconventional reservoirs, is affected by the dominance of nanoscale pores. The objective of this work is to investigate the impact of nanoscale confinement on MMP of CO2/hydrocarbon systems and to compare the accuracy of different theoretical approaches in calculating MMP of confined fluid systems. A modified PR EOS applicable for confined fluid characterization is applied to perform the EOS simulation of the vanishing interfacial tension (VIT) experiments. The MMP of multiple CO2/hydrocarbon systems at different pore sizes are obtained via the VIT simulations. Meanwhile, the multiple mixing cell (MMC) algorithm coupled with the same modified PR EOS is applied to compute the MMP for the same fluid systems. Comparison of these results to the experimental values recognize that the MMC approach has higher accuracy in determining the MMP of confined fluid systems. Moreover, nanoscale confinement results in the drastic suppression of MMP and the suppression rate increases with decreasing pore size. The drastic suppression of MMP is highly favorable for the miscible gas injection EOR in unconventional reservoirs.

scholarly journals Prediction of asphaltene precipitation upon injection of various gases at near-wellbore conditions: A simulation study using PC-SAFT EoS

2019 ◽  
Vol 74 ◽  
pp. 63 ◽  
Author(s):  
Saba Mahmoudvand ◽  
Behnam Shahsavani ◽  
Rafat Parsaei ◽  
Mohammad Reza Malayeri
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Gas Injection ◽  
Drop Out ◽  
Maximum Point ◽  
Asphaltene Precipitation ◽  
Wide Range ◽  
Tertiary Oil Recovery ◽  
The Impact ◽  
Oil Type

The depletion of oil reservoirs and increased global oil demand have given impetus to employ various secondary and tertiary oil recovery methods. Gas injection is widely used in both secondary and tertiary modes, though the major problem associated with this process is the precipitation and deposition of asphaltene, particularly at near-wellbore conditions. In-depth knowledge of asphaltene phase behavior is therefore essential for the prediction of asphaltene precipitation. Previous studies reported the impact of gas injection on asphaltene phase behavior, but the knowledge of precipitation of asphaltene as a function of different mole fractions of injected gas is also imperative. In this study, the thermodynamic model of PC-SAFT EoS is used to discern the phase equilibrium of asphaltene by analyzing the asphaltene drop-out curve during gas injection. Asphaltene drop-out curves of two different live oil samples are analyzed by injecting CO2, CH4, and N2 gases at different mole percentages and temperatures. The results revealed that PC-SAFT EoS can serve as a reliable tool for estimating bubble pressure and asphaltene onset pressure for a wide range of temperatures, pressures, and compositions. The simulation results for the injection of CO2, CH4, and N2 also showed that CO2 gas gives minimum asphaltene precipitation. It reduces the size of the drop-out curve or moves it toward higher pressures. CH4 and N2 expand the drop-out curve by raising the upper onset point. CH4 increases the maximum point of the drop-out curve for two types of oil studied (A and B) at two different temperatures. N2 raises the maximum point of oil type “A” by approximately 57% at 395 K, while it has no effect on the maximum point of oil type “B”. In addition, reducing the temperature resulted in either decrease or increase of asphaltene solubility, demonstrating that the impact of temperature on asphaltene precipitation is closely related to the composition of the crude.

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.

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