An Experimental Study of the Effects of CO2 Injection on Gas/Condensate Recovery and CO2 Storage in Gas-Condensate Reservoirs

2021 ◽  
Author(s):  
Ifeanyi Seteyeobot ◽  
Mahmoud Jamiolahmady ◽  
Philip Jaeger ◽  
Abdulelah Nasieef
Keyword(s):  
Co2 Storage ◽  
Injection Pressure ◽  
Gas Condensate ◽  
Phase Behaviour ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Experimental Phase ◽  
Co2 Gas ◽  
Gas Condensate Reservoirs ◽  
Core Flood

Abstract The application of non-hydrocarbon gas injection for enhanced gas and condensate recovery (EGCR) is still in a developmental stage as the mixing/interaction between the injected gas and resident reservoir fluid is yet to be extensively understood and the inability to optimize the recovery process has led to limited pilot trials. Carbon dioxide (CO2) injection into gas-condensate reservoirs for improved recovery and CO2 storage provides additional and favorable changes in phase and fluid flow behaviour making it economically more attractive compared to other injection gases. However, to make an informed decision, adequate phase and flow behaviour analysis are required to better forecast the reservoir performance under CO2 injection. In this research, appropriate experimental phase behaviour, EOS modeling, and unsteady-state flow tests have been conducted to determine the level of CO2/gas-condensate interaction including condensing/vaporizing mechanisms during CO2 Huff-n-Puff (HnP) injection. A CO2 HnP injection technique was followed to identify the best CO2 flooding conditions. A total of four HnP injection cycles with incremental CO2 volumes of 20, 40, 60, and 80 % of the initial resident fluid volume prior to depletion was considered. CO2 injection pressure and volume are optimized below the saturation pressure. The analysis is based on evaluating the level of interaction between CO2 and resident fluid at the maximum condensate saturation of the corresponding CO2-gas-condensate fluid mixture as determined in a phase equilibria cell. Appropriate experimental phase behaviour and core flood data were generated and analyzed to identify and quantify the level of condensing/vaporizing mechanisms which are vital for adequate optimization of the injection pressure and amount of injected CO2 for both enhanced gas and condensate recovery and CO2 storage purposes. The amount of gas, condensate, and CO2 produced at each core flood stage was recorded. These data allow bridging the gap between conflicting reports on the trend and level of CO2/gas-condensate fluid interactions at pressures below the dew point pressure (Pdew). They also provide a better knowledge of the governing mechanisms during CO2 flooding, which are required for designing appropriate CO2 HnP injection for reservoir engineering applications.

scholarly journals Carbon-Negative Scenarios in High CO2 Gas Condensate Reservoirs

Energies ◽  
2021 ◽  
Vol 14 (18) ◽  
pp. 5898
Author(s):  
Lucija Jukić ◽  
Domagoj Vulin ◽  
Valentina Kružić ◽  
Maja Arnaut
Keyword(s):  
Natural Gas ◽  
Co2 Storage ◽  
Cost Effective ◽  
Gas Production ◽  
Gas Condensate ◽  
Co2 Injection ◽  
Base Case ◽  
Processing Plant ◽  
Gas Condensate Reservoirs ◽  
Northern Croatia

A gas condensate reservoir in Northern Croatia was used as an example of a CO2 injection site during natural gas production to test whether the entire process is carbon-negative. To confirm this hypothesis, all three elements of the CO2 life cycle were included: (1) CO2 emitted by combustion of the produced gas from the start of production from the respective field, (2) CO2 that is separated at natural gas processing plant, i.e., the CO2 that was present in the original reservoir gas composition, and (3) the injected CO2 volumes. The selected reservoir is typical of gas-condensate reservoirs in Northern Croatia (and more generally in Drava Basin), as it contains about 50% CO2 (mole). Reservoir simulations of history-matched model showed base case (production without injection) and several cases of CO2 enhanced gas recovery, but with a focus on CO2 storage rather than maximizing hydrocarbon gas production achieved by converting a production well to a CO2 injection well. General findings are that even in gas reservoirs with such extreme initial CO2 content, gas production with CO2 injection can be carbon-negative. In almost all simulated CO2 injection scenarios, the process is carbon-negative from the time of CO2 injection, and in scenarios where CO2 injection begins earlier, it is carbon-negative from the start of gas production, which opens up the possibility of cost-effective storage of CO2 while producing natural gas with net negative CO2 emissions.

Wettability measurements on two sandstones: an experimental investigation before and after CO2 flooding

2020 ◽  
Vol 60 (1) ◽  
pp. 117
Author(s):  
Cut Aja Fauziah ◽  
Emad A. Al-Khdheeawi ◽  
Ahmed Barifcani ◽  
Stefan Iglauer
Keyword(s):  
Contact Angle ◽  
Co2 Storage ◽  
Contact Angle Measurement ◽  
Contact Angles ◽  
Angle Measurement ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Berea Sandstone ◽  
Before And After ◽  
Carbon Dioxide Co2

Wettability of rock–fluid systems is an important for controlling the carbon dioxide (CO2) movement and the capacities of CO2 geological trapping mechanisms. Although contact angle measurement is considered a potentially scalable parameter for evaluation of the wettability characteristics, there are still large uncertainties associated with the contact angle measurement for CO2–brine–rock systems. Thus, this study experimentally examined the wettability, before and after flooding, of two different samples of sandstone: Berea and Bandera grey sandstones. For both samples, several sets of flooding of brine (5 wt % NaCl + 1 wt % KCl in deionised water), CO2-saturated (live) brine and supercritical CO2 were performed. The contact angle measurements were conducted for the CO2–sandstone system at two different reservoir pressures (10 and 15 MPa) and at a reservoir temperature of 323 K. The results showed that both the advancing and receding contact angles of the sandstone samples after flooding were higher than that measured before flooding (i.e. after CO2 injection the sandstones became more CO2-wet). Moreover, the Bandera grey samples had higher contact angles than Berea sandstone. Thus, we conclude that CO2 flooding altered the sandstone wettability to be more CO2-wet, and Berea sandstone had a higher CO2 storage capacity than Bandera grey sandstone.

Investigation of CO2–CH4 Displacement and Transport in Shale for Enhanced Shale Gas Recovery and CO2 Sequestration

2016 ◽  
Vol 139 (1) ◽  
Author(s):  
Xi-Dong Du ◽  
Min Gu ◽  
Shuo Duan ◽  
Xue-Fu Xian
Keyword(s):  
Shale Gas ◽  
Co2 Storage ◽  
Fixed Bed ◽  
Co2 Injection ◽  
Gas Reservoir ◽  
Co2 Gas ◽  
Gas Recovery ◽  
Shale Gas Reservoir ◽  
Shale Reservoir ◽  
Adsorption Amount

To gain a better understanding of the enhanced shale gas recovery by CO2 gas injection (CO2-ESGR) technique, the dynamic displacement mechanism of CO2–CH4, the CO2 enhanced shale gas recovery (RCH4), and CO2 storage capacity (VCO2) were studied based on transport properties of CO2 and CH4. Experiments of CO2 injection into shale gas reservoir preadsorbed by CH4 were performed in a fixed bed. Breakthrough curves were obtained under different test conditions and simulated by one-dimension advection-dispersion (AD) model. It was found that dispersion coefficient (K1) rather than molecular diffusivity of CO2 dominated its transport in shale. K1 together with advection velocity (υ) of CO2 during CH4 displacement controls RCH4 and VCO2. When transporting in shale gas reservoir, CO2 had larger dynamic adsorption amount and υ, but smaller K1 than CH4. The competitive transport and adsorption behavior of CO2 and CH4 made it possible for CO2 to store in shale reservoir and to drive the in-place CH4 out of shale reservoir. The transfer zone of CO2–CH4 displacement (CCD) was very wide. High RCH4 and VCO2 were reached at low injection CO2 gas pressure and for small shale particles. Higher injection flow rates of CO2 and temperatures ranging from 298 K to 338 K had a little effect on RCH4 and VCO2. For field conditions, high CO2 injection pressure has to be used because the pore pressure of shale reservoir and adsorption amount of CH4 increase with the increase in depth of shale gas reservoir, but RCH4 is still not high.

Effective Prediction and Management of a CO2 Flooding Process for Enhancing Oil Recovery Using Artificial Neural Networks

2017 ◽  
Vol 140 (3) ◽  
Author(s):  
Si Le Van ◽  
Bo Hyun Chon
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Environmental Benefits ◽  
Co2 Production ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Injection Process ◽  
Artificial Neural

The injection of CO2 has been in global use for enhanced oil recovery (EOR) as it can improve oil production in mature fields. It also has environmental benefits for reducing greenhouse carbon by permanently sequestrating CO2 (carbon capture and storage (CCS)) in reservoirs. As a part of numerical studies, this work proposed a novel application of an artificial neural network (ANN) to forecast the performance of a water-alternating-CO2 process and effectively manage the injected CO2 in a combined CCS–EOR project. Three targets including oil recovery, net CO2 storage, and cumulative gaseous CO2 production were quantitatively simulated by three separate ANN models for a series of injection frames of 5, 15, 25, and 35 cycles. The concurrent estimations of a sequence of outputs have shown a relevant application in scheduling the injection process based on the progressive profile of the targets. For a specific surface design, an increment of 5.8% oil recovery and 4% net CO2 storage was achieved from 25 cycles to 35 cycles, suggesting ending the injection at 25 cycles. Using the models, distinct optimizations were also computed for oil recovery and net CO2 sequestration in various reservoir conditions. The results expressed a maximum oil recovery from 22% to 30% oil in place (OIP) and around 21,000–29,000 tons of CO2 trapped underground after 35 cycles if the injection began at 60% water saturation. The new approach presented in this study of applying an ANN is obviously effective in forecasting and managing the entire CO2 injection process instead of a single output as presented in previous studies.

scholarly journals Experimental Investigation of the Mechanisms of Salt Precipitation during CO2 Injection in Sandstone

2019 ◽  
Vol 5 (1) ◽  
pp. 4 ◽  
Author(s):  
Yen Adams Sokama-Neuyam ◽  
Jann Rune Ursin ◽  
Patrick Boakye
Keyword(s):  
Co2 Storage ◽  
Simulation Models ◽  
Co2 Injection ◽  
Salt Precipitation ◽  
Physical Mechanisms ◽  
Low Salinity ◽  
Core Flood ◽  
Dry Out ◽  
The Impact ◽  
Brine Salinity

Deep saline reservoirs have the highest volumetric CO2 storage potential, but drying and salt precipitation during CO2 injection could severely impair CO2 injectivity. The physical mechanisms and impact of salt precipitation, especially in the injection area, is still not fully understood. Core-flood experiments were conducted to investigate the mechanisms of external and internal salt precipitation in sandstone rocks. CO2 Low Salinity Alternating Gas (CO2-LSWAG) injection as a potential mitigation technique to reduce injectivity impairment induced by salt precipitation was also studied. We found that poor sweep and high brine salinity could increase salt deposition on the surface of the injection area. The results also indicate that the amount of salt precipitated in the dry-out zone does not change significantly during the drying process, as large portion of the precipitated salt accumulate in the injection vicinity. However, the distribution of salt in the dry-out zone was found to change markedly when more CO2 was injected after salt precipitation. This suggests that CO2 injectivity impairment induced by salt precipitation is probably dynamic rather than a static process. It was also found that CO2-LSWAG could improve CO2 injectivity after salt precipitation. However, below a critical diluent brine salinity, CO2-LSWAG did not improve injectivity. These findings provide vital understanding of core-scale physical mechanisms of the impact of salt precipitation on CO2 injectivity in saline reservoirs. The insight gained could be implemented in simulation models to improve the quantification of injectivity losses during CO2 injection into saline sandstone reservoirs.

APPLICATION OF THE BLACK OIL PVT REPRESENTATION TO SIMULATION OF GAS CONDENSATE RESERVOIR PERFORMANCE

1987 ◽  
Vol 27 (1) ◽  
pp. 370
Author(s):  
W.H. Goldthorpe ◽  
J.K. Drohm
Keyword(s):  
Oil And Gas ◽  
Volatile Oil ◽  
Gas Condensate ◽  
Phase Behaviour ◽  
Dew Point ◽  
Pressure Drops ◽  
Gas Condensate Reservoirs ◽  
Reservoir Performance ◽  
Black Oil ◽  
Condensate Reservoir

Special attention must be paid to the generation of PVT parameters when applying conventional black oil reservoir simulators to the modelling of volatile oil and gas-condensate reservoirs. In such reservoirs phase behaviour is an important phenomenon and common approaches to approximating this, via the black oil PVT representation, introduce errors that may result in prediction of incorrect recoveries of surface gas and condensate. Further, determination of production tubing pressure drops for use in such simulators is also prone to errors. These affect the estimation of well potentials and reservoir abandonment pressures.Calculation of black oil PVT parameters by the method of Coats (1985) is shown to be preferred over conventional approaches, although the PVT parameters themselves lose direct physical meaning. It is essential that a properly tuned equation of state be available for use in conjunction with experimental data.Production forecasting based on simulation output requires further processing in order to translate the black oil surface phase fluxes into products such as sales gas, LPG and condensate. For gas-condensate reservoirs, such post-processing of results from the simulation of depletion or cycling above the dew point is valid. In principle it is invalid for cycling below the dew point but in practice it can still provide useful information.

scholarly journals Simulation of Immiscible Water-Alternating-CO2 Flooding in the Liuhua Oilfield Offshore Guangdong, China

Energies ◽  
2020 ◽  
Vol 13 (9) ◽  
pp. 2130 ◽  
Author(s):  
Gang Hu ◽  
Pengchun Li ◽  
Linzi Yi ◽  
Zhongxian Zhao ◽  
Xuanhua Tian ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Carbon Capture ◽  
Co2 Storage ◽  
Simulation Models ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Full Field ◽  
Water Alternating Gas ◽  
Production History ◽  
And Storage

In this paper, the immiscible water-alternating-CO2 flooding process at the LH11-1 oilfield, offshore Guangdong Province, was firstly evaluated using full-field reservoir simulation models. Based on a 3D geological model and oil production history, 16 scenarios of water-alternating-CO2 injection operations with different water alternating gas (WAG) ratios and slug sizes, as well as continuous CO2 injection (Con-CO2) and primary depletion production (No-CO2) scenarios, have been simulated spanning 20 years. The results represent a significant improvement in oil recovery by CO2 WAG over both Con-CO2 and No-CO2 scenarios. The WAG ratio and slug size of water affect the efficiency of oil recovery and CO2 injection. The optimum operations are those with WAG ratios lower than 1:2, which have the higher ultimate oil recovery factor of 24%. Although WAG reduced the CO2 injection volume, the CO2 storage efficiency is still high, more than 84% of the injected CO2 was sequestered in the reservoir. Results indicate that the immiscible water-alternating-CO2 processes can be optimized to improve significantly the performance of pressure maintenance and oil recovery in offshore reef heavy-oil reservoirs significantly. The simulation results suggest that the LH11-1 field is a good candidate site for immiscible CO2 enhanced oil recovery and storage for the Guangdong carbon capture, utilization and storage (GDCCUS) project.

scholarly journals CO2 Storage in Low Permeable Carbonate Reservoirs: Permeability and Interfacial Tension (IFT) Changes During CO2 Injection in an Iranian Carbonate Reservoir

2019 ◽  
Vol 64 (4) ◽  
pp. 491-504
Author(s):  
Mohammad Afkhami Karaei ◽  
Bizhan Honarvar ◽  
Amin Azdarpour ◽  
Erfan Mohammadian
Keyword(s):  
Interfacial Tension ◽  
Co2 Sequestration ◽  
Co2 Storage ◽  
Experimental Studies ◽  
Injection Pressure ◽  
Confining Pressure ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Co2 Injection ◽  
Permeability Alteration

The lack of fundamental experimental studies on low permeable carbonate reservoirs for CO2 sequestration purposes is essential for further application of CO2 sequestration as a highly-anticipated CO2 mitigation method in deep saline aquifers, specifically those with low permeabilities. The core samples were taken from a carbonate reservoir in Iran and the brine composition was based on that of the same formation. The objective of this study is to investigate permeability alteration during CO2 sequestration in the aquifers of a low permeable Iranian carbonate reservoir. Various parameters have been investigated. The effects of different parameters such as injection pressure, confining pressure, and temperature on permeability alteration of the cores was investigated. Moreover, the interfacial tension (IFT) of CO2/brine was also determined at pressures and temperatures up to 7 MPa and 100 °C, respectively. The experimental results showed CO2 solubility and rock dissolution to be the governing mechanism when CO2 was injected into carbonate cores. The permeability measurements showed that permeability increases by increasing injection pressure and decreases by increasing confining pressure and temperature. The IFT measurement results showed that the IFT decreases significantly when there is an increase in pressure and temperature.

Integrated CO2 Modeling Studies to Assess CO2 Sequestration Prospect in a Depleted Carbonate Gas Reservoir, Malaysia

2021 ◽  
Author(s):  
Mohd Azran A. Jalil ◽  
Sharidah M. Amin ◽  
Siti Syareena M. Ali
Keyword(s):  
Co2 Sequestration ◽  
Co2 Storage ◽  
Injection Pressure ◽  
Injection Rate ◽  
Co2 Injection ◽  
Coupled Modelling ◽  
Compositional Model ◽  
Development Concept ◽  
Modelling Study

Abstract This paper presented an integrated CO2 injection and sequestration modelling study performed on a depleted carbonate gas reservoir, which has been identified as one of potential CO2 sequestration site candidate in conjunction with nearby high CO2 gas fields development and commercialization effort to monetize the fields. 3D compositional modelling, geomechanical and geochemical assessment were conducted to strategize optimum subsurface CO2 injection and sequestration development concept for project execution. Available history matched black oil simulation model was converted into compositional model. Sensitivity analyses on optimum injection rate, number and types of injectors, solubility of CO2 in water, injection locations and impact of hysteresis to plume distribution were investigated. Different types of CO2 trapping mechanisms including hydrodynamic, residual/capillary, solubility and mineral trapping were studied in detailed. Coupled modelling study was performed on base case scenario to assess geomechnical and geochemical risks associated with CO2 injection and sequestration process before-, during- and post- CO2 injection operation to provide assurance for a safe and long-term CO2 sequestration in the field. Available history matched black oil model was successfully converted into compositional model, in which CO2 is treated and can be tracked as a separate component in the reservoir throughout the production and injection processes. Integrating all the results obtained from sensitivities analyses, the proposed optimum subsurface CO2 injection and sequestration development concept for the field is to inject up to 400 MMscf/D of CO2 rate via four injectors. CO2 injection rate is forecasted to sustain more than 3 years from injection start date before declining with time. In terms of CO2 storage capacity, constraining injection pressure up to initial reservoir pressure, maximum CO2 storage capacity is estimated ~65 Million tonnes. Nevertheless, considering maximum allowable CO2 injection pressure estimated from coupled modelling study and operational safety factor, the field is capable to accommodate a total of ~77 Million tonnes of CO2, whereby 73% of total CO2 injected will exists in mobile phase and trapped underneath caprock whilst the other 24% and 3% will be trapped as residual/capillary and dissolved in water respectively. Changes of minerals and porosity were observed from 3D geochemical modelling, however, changes are negligible due to the fact that geochemical reaction is a very slow process. This paper highlights and shares simulation results obtained from CO2 injection and sequestration studies performed on 3D compositional model to generate an optimum subsurface CO2 injection and sequestration development concept for project execution in future. Integration with geomechanical and geochemical modelling studies are crucial to assess site's capability to accommodate CO2 within the geological formation and provide assurance for a safe and long-term CO2 sequestration.

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