scholarly journals Intelligent Prediction of Minimum Miscibility Pressure (MMP) During CO2 Flooding Using Artificial Intelligence Techniques

2019 ◽  
Vol 11 (24) ◽  
pp. 7020 ◽  
Author(s):  
Amjed Hassan ◽  
Salaheldin Elkatatny ◽  
Abdulazeez Abdulraheem
Keyword(s):  
Neural Network ◽  
Carbon Dioxide ◽  
Absolute Error ◽  
Analytical Models ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Estimation Errors ◽  
Heterogeneous Reservoirs ◽  
Minimum Miscibility Pressure ◽  
Carbon Dioxide Co2

Carbon dioxide (CO2) injection is one of the most effective methods for improving hydrocarbon recovery. The minimum miscibility pressure (MMP) has a great effect on the performance of CO2 flooding. Several methods are used to determine the MMP, including slim tube tests, analytical models and empirical correlations. However, the experimental measurements are costly and time-consuming, and the mathematical models might lead to significant estimation errors. This paper presents a new approach for determining the MMP during CO2 flooding using artificial intelligent (AI) methods. In this work, reliable models are developed for calculating the minimum miscibility pressure of carbon dioxide (CO2-MMP). Actual field data were collected; 105 case studies of CO2 flooding in anisotropic and heterogeneous reservoirs were used to build and evaluate the developed models. The CO2-MMP is determined based on the hydrocarbon compositions, reservoir conditions and the volume of injected CO2. An artificial neural network, radial basis function, generalized neural network and fuzzy logic system were used to predict the CO2-MMP. The models’ reliability was compared with common determination methods; the developed models outperform the current CO2-MMP methods. The presented models showed a very acceptable performance: the absolute error was 6.6% and the correlation coefficient was 0.98. The developed models can minimize the time and cost of determining the CO2-MMP. Ultimately, this work will improve the design of CO2 flooding operations by providing a reliable value for the CO2-MMP.

A Laboratory Investigation of the Effect of Ethanol-Treated Carbon Dioxide Injection on Oil Recovery and Carbon Dioxide Storage

SPE Journal ◽  
2021 ◽  
pp. 1-17
Author(s):  
Saira ◽  
Emmanuel Ajoma ◽  
Furqan Le-Hussain
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Carbon Capture ◽  
Molar Fraction ◽  
Co2 Injection ◽  
Carbon Dioxide Injection ◽  
Treated Carbon ◽  
Carbon Dioxide Co2 ◽  
And Storage ◽  
Experimental Runs

Summary Carbon dioxide (CO2) enhanced oil recovery is the most economical technique for carbon capture, usage, and storage. In depleted reservoirs, full or near-miscibility of injected CO2 with oil is difficult to achieve, and immiscible CO2 injection leaves a large volume of oil behind and limits available pore volume (PV) for storing CO2. In this paper, we present an experimental study to delineate the effect of ethanol-treated CO2 injection on oil recovery, net CO2 stored, and amount of ethanol left in the reservoir. We inject CO2 and ethanol-treated CO2 into Bentheimer Sandstone cores representing reservoirs. The oil phase consists of a mixture of 0.65 hexane and 0.35 decane (C6-C10 mixture) by molar fraction in one set of experimental runs, and pure decane (C10) in the other set of experimental runs. All experimental runs are conducted at constant temperature 70°C and various pressures to exhibit immiscibility (9.0 MPa for the C6-C10 mixture and 9.6 MPa for pure C10) or near-miscibility (11.7 MPa for the C6-C10 mixture and 12.1 MPa for pure C10). Pressure differences across the core, oil recovery, and compositions and rates of the produced fluids are recorded during the experimental runs. Ultimate oil recovery under immiscibility is found to be 9 to 15% greater using ethanol-treated CO2 injection than that using pure CO2 injection. Net CO2 stored for pure C10 under immiscibility is found to be 0.134 PV greater during ethanol-treated CO2 injection than during pure CO2 injection. For the C6-C10 mixture under immiscibility, both ethanol-treated CO2 injection and CO2 injection yield the same net CO2 stored. However, for the C6-C10 mixture under near-miscibility,ethanol-treated CO2 injection is found to yield 0.161 PV less net CO2 stored than does pure CO2 injection. These results suggest potential improvement in oil recovery and net CO2 stored using ethanol-treated CO2 injection instead of pure CO2 injection. If economically viable, ethanol-treated CO2 injection could be used as a carbon capture, usage, and storage method in low-pressure reservoirs, for which pure CO2 injection would be infeasible.

Advances in Midland Basin Expand Boundaries of CO2 EOR in Marginal Pay Areas

2021 ◽  
Vol 73 (06) ◽  
pp. 65-66
Author(s):  
Judy Feder
Keyword(s):  
Oil Recovery ◽  
Large Scale ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Improved Oil Recovery ◽  
Midland Basin ◽  
The North ◽  
Production Wells ◽  
Original Oil In Place ◽  
Carbon Dioxide Co2

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 200460, “A Case Study of SACROC CO2 Flooding in Marginal Pay Regions: Improving Asset Performance,” by John Kalteyer, SPE, Kinder Morgan, prepared for the 2020 SPE Improved Oil Recovery Conference, originally scheduled to be held in Tulsa, 18–22 April. The paper has not been peer reviewed. As one of the first fields in the world to use carbon dioxide (CO2) in enhanced oil recovery (EOR), the Scurry Area Canyon Reef Operators Committee (SACROC) unit of the Kelly-Snyder field in the Midland Basin of Texas provides a unique opportunity to study, learn from, and improve upon the development of CO2 flood technology. The complete paper reviews the history of EOR at SACROC, discusses changes in theory over time, and provides a look at the field’s future. Field Overview and Development History The first six pages of the paper discuss the field’s location, geology, and development before June 2000, when Kinder Morgan acquired the SACROC unit and took over as operator. Between initial gas injection in 1972 and 2000, approximately 1 TCF of CO2 had been injected into the Canyon Reef reservoir. Since 2000, cumulative CO2 injection has sur-passed 7 TCF and yielded cumulative EOR of over 180 million bbl. The reservoir is a primarily limestone reef complex containing an estimated original oil in place (OOIP) of just under 3 billion bbl. The reservoir ranges from 200 ft gross thickness in the south to 900 ft in the north, where the limestone matrix averages 8% porosity and 20-md permeability. The Canyon Reef structure is divided into four major intervals, of which the Upper Canyon zone provides the highest-quality pay. The field was discovered in 1948 at a pressure of 3,122 psi. By late 1950, 1,600 production wells had been drilled and the reservoir pressure plummeted, settling as low as 1,700 psi. Waterflooding begun in 1954 enabled the field to continue producing for nearly 20 years, at which time the operators deter-mined that another recovery mechanism would be needed to maximize recovery and reach additional areas of the field. The complete paper discusses various CO2 injection programs that were developed and applied—including a true tertiary response from a miscible CO2 flood in 1981—along with their outcomes. Acquisition and CO2-Injection Redevelopment In June 2000 Kinder Morgan acquired the SACROC Unit and took over as operator. Approximately 6.7 billion bbl of water and 1.3 TCF of CO2 had been injected across the unit to that date, but the daily oil rate of 8,700 B/D was approaching the field’s economic limit. An estimated 40% of the OOIP had been produced through the combination of recovery methods that each previous operator had used. Expanding on the conclusions of its immediate predecessor, the operator initiated large-scale CO2-flood redevelopment in a selection of project areas. These redevelopments were based on several key distinctions differentiating them from previous injection operations.

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.

A Practical Method for Minimum-Miscibility-Pressure Estimation of Contaminated CO2 Mixtures

2010 ◽  
Vol 13 (05) ◽  
pp. 764-772 ◽  
Author(s):  
R.T.. T. Johns ◽  
Kaveh Ahmadi ◽  
D.. Zhou ◽  
M.. Yan
Keyword(s):  
Mole Fraction ◽  
Linear Trend ◽  
Estimation Method ◽  
Practical Method ◽  
Co2 Injection ◽  
Displacement Efficiency ◽  
Design And Optimization ◽  
Minimum Miscibility Pressure ◽  
Carbon Dioxide Co2 ◽  
The Impact

Summary Minimum miscibility pressure (MMP) is a key parameter in the design of gasfloods. Injection-gas compositions often vary during the life of a gasflood owing to reinjection and mixing of fluids in situ. Understanding the impact of the gas compositional changes on the MMP is essential to optimal design of fieldwide pressure management and carbon dioxide (CO2) use. Determining the MMP by slimtube or other methods for each possible variation in the gas-mixture composition is impractical. This paper gives an easy and accurate way to determine impure CO2 MMPs for variable field solvent compositions on the basis of just a few MMPs. Alternatively, the approach could be used to estimate the enrichment level required to lower the MMP to a desired pressure. The MMP-estimation method relies on determining the MMP for pure CO2 injection, and also for a few impure binary MMPs at small CO2-contaminant levels. The number of MMPs needed for the method is equal to the number of components in the injection gas. We use the method of characteristics (MOC) and our newly developed mixing-cell method to estimate the required MMPs, although any reliable MMP analytical or experimental method can be used. We demonstrate how to calculate MMPs for several multicomponent oils displaced by CO2 contaminated by mixtures of N2, CH4, C2, C3, and H2S. The results show that the predicted MMPs for a west Texas crude displaced by contaminated-CO2 injection streams are nearly linear over the range from pure-CO2 injection to any mole fraction combination of the five contaminants. The accuracy of the predicted MMPs is within ±15 psia of that from calculations using mixing-cell simulations, slimtube simulations, and slimtube experiments where available. For another example oil displacement by impure CO2, however, the linear trend in MMPs with contamination mole fractions is accurate only for total contamination levels less than approximately 20% mole fraction, but this is still within a useful range for CO2-gasflood design and optimization. We also examine the sensitivity of local displacement efficiency to dispersion for binary gas mixtures using 1D simulation.

Mobility of Ethomeen C12 and Carbon Dioxide (CO2) Foam at High Temperature/High Salinity and in Carbonate Cores

SPE Journal ◽  
2016 ◽  
Vol 21 (04) ◽  
pp. 1151-1163 ◽  
Author(s):  
Leyu Cui ◽  
Kun Ma ◽  
Maura Puerto ◽  
Ahmed A. Abdala ◽  
Ivan Tanakov ◽  
...  
Keyword(s):  
Carbon Dioxide ◽  
High Temperature ◽  
High Salinity ◽  
Local Equilibrium ◽  
Co2 Flooding ◽  
Sweep Efficiency ◽  
Co2 Foam ◽  
Foam Model ◽  
Wide Range ◽  
Carbon Dioxide Co2

Summary The low viscosity and density of carbon dioxide (CO2) usually result in the poor sweep efficiency in CO2-flooding processes, especially in heterogeneous formations. Foam is a promising method to control the mobility and thus reduce the CO2 bypass because of the gravity override and heterogeneity of formations. A switchable surfactant, Ethomeen C12, has been reported as an effective CO2-foaming agent in a sandpack with low adsorption on pure-carbonate minerals. Here, the low mobility of Ethomeen C12/CO2 foam at high temperature (120 °C), high pressure (3,400 psi), and high salinity [22 wt% of total dissolved solids (TDS)] was demonstrated in Silurian dolomite cores and in a wide range of foam qualities. The influence of various parameters, including aqueous solubility, thermal and chemical stability, flow rate, foam quality, salinity, temperature, and minimum-pressure gradient (MPG), on CO2 foam was discussed. A local-equilibrium foam model, the dry-out foam model, was used to fit the experimental data for reservoir simulation.

scholarly journals Minimum miscibility pressure computation in eor by flare gas flooding

2018 ◽  
Vol 10 (2) ◽  
pp. 61
Author(s):  
Tjokorde Walmiki Samadhi ◽  
Utjok W.R. Siagian ◽  
Angga P Budiono
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Gas Injection ◽  
Molar Ratio ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Minimum Miscibility Pressure ◽  
Gas Flooding ◽  
Model Oil ◽  
Gas Drive

The technical feasibility of using flare gas in the miscible gas flooding enhanced oil recovery (MGF-EOR) is evaluated by comparing the minimum miscibility pressure (MMP) obtained using flare gas to the MMP obtained in the conventional CO2 flooding. The MMP is estimated by the multiple mixing cell calculation method with the Peng-Robinson equation of state using a binary nC5H12-nC16H34 mixture at a 43%:57% molar ratio as a model oil. At a temperature of 323.15 K, the MMP in CO2 injection is estimated at 9.78 MPa. The MMP obtained when a flare gas consisting of CH4 and C2H6 at a molar ratio of 91%:9% is used as the injection gas is predicted to be 3.66 times higher than the CO2 injection case. The complete gas-oil miscibility in CO2 injection occurs via the vaporizing gas drive mechanism, while flare gas injection shifts the miscibility development mechanism to the combined vaporizing / condensing gas drive. Impact of variations in the composition of the flare gas on MMP needs to be further explored to confirm the feasibility of flare gas injection in MGF-EOR processes. Keywords: flare gas, MMP, miscible gas flooding, EORAbstrakKonsep penggunaan flare gas untuk proses enhanced oil recovery dengan injeksi gas terlarut (miscible gas flooding enhanced oil recovery atau MGF-EOR) digagaskan untuk mengurangi emisi gas rumah kaca dari fasilitas produksi migas, dengan sekaligus meningkatkan produksi minyak. Kelayakan teknis injeksi flare gas dievaluasi dengan memperbandingkan tekanan pelarutan minimum (minimum miscibility pressure atau MMP) untuk injeksi flare gas dengan MMP pada proses MGF-EOR konvensional menggunakan injeksi CO2. MMP diperkirakan melalui komputasi dengan metode sel pencampur majemuk dengan persamaan keadaan Peng-Robinson, pada campuran biner nC5H12-nC16H34 dengan nisbah molar 43%:57% sebagai model minyak. Pada temperatur 323.15 K, estimasi MMP yang diperoleh dengan injeksi CO2 adalah 9.78 MPa. Nilai MMP yang diperkirakan pada injeksi flare gas yang berupa campuran CH4-C2H6 pada nisbah molar 91%:9% sangat tinggi, yakni sebesar 3.66 kali nilai yang diperoleh pada kasus injeksi CO2. Pelarutan sempurna gas-minyak dalam injeksi CO2 terbentuk melalui mekanisme dorongan gas menguap (vaporizing gas drive), sementara pelarutan pada injeksi flare gas terbentuk melaui mekanisme kombinasi dorongan gas menguap dan mengembun (vaporizing/condensing gas drive). Pengaruh variasi komposisi flare gas terhadap MMP perlu dikaji lebih lanjut untuk menjajaki kelayakan injeksi flare gas dalam proses MGF-EOR.Kata kunci: flare gas, MMP, miscible gas flooding, EOR

Design Considerations of a Subsea Shuttle Tanker System for Liquid Carbon Dioxide Transportation

2020 ◽  
Author(s):  
Yihan Xing ◽  
Muk Chen Ong ◽  
Tor Hemmingsen ◽  
Kjell Einar Ellingsen ◽  
Lorents Reinås
Keyword(s):  
Carbon Dioxide ◽  
Production Systems ◽  
Electrical Power ◽  
Weather Conditions ◽  
Co2 Injection ◽  
Field Development ◽  
Design Considerations ◽  
Liquid Co2 ◽  
Carbon Dioxide Co2 ◽  
Subsea Pipelines

Abstract Subsea pipelines and umbilicals are used for the transportation of fluids and electrical power between subsea installations and floating production systems (FPUs). The installation and maintenance of these systems can be expensive. In a conventional subsea field development, the produced fluids can be transported from the well to a FPU where they can be offloaded to a tanker (surface ship). In the case of carbon dioxide (CO2) injection into the well, the direction of flow is reversed, i.e., CO2 flows from the tanker to the FPU, down the riser base and through the subsea pipelines to the well. This offloading process is weather-dependent and cannot be performed in severe weather conditions, i.e., strong winds and large waves. This paper presents a novel subsea shuttle tanker system proposed by Equinor ASA designed to be a possible alternative to subsea pipelines, umbilicals and tanker ships. The subsea shuttle is intended to operate submerged under the sea surface to transport liquid CO2 from an existing offshore/land facility where CO2 is captured to a subsea well where the CO2 is injected into the reservoir. As the shuttle is subsea, it can operate under any type of weather conditions. Even though the subsea shuttle is proposed as a vehicle for liquid CO2 transport, it can also transport other types of cargo such as hydrocarbons, injection fluids, electrical power or subsea tools. The paper will discuss the most important design considerations surrounding the subsea shuttle tanker.

Approximate Analytical Solutions for CO2 Injectivity Into Saline Formations

2013 ◽  
Vol 16 (02) ◽  
pp. 123-133 ◽  
Author(s):  
Ehsan Azizi ◽  
Yildiray Cinar
Keyword(s):  
Boundary Conditions ◽  
Relative Permeability ◽  
Analytical Solutions ◽  
Outer Boundary ◽  
Analytical Models ◽  
Co2 Injection ◽  
Approximate Analytical Solutions ◽  
New Models ◽  
Saline Formation ◽  
Carbon Dioxide Co2

Summary This paper presents new analytical models to estimate the bottomhole pressure (BHP) of a vertical carbon dioxide (CO2) injection well in a radial, homogeneous, horizontal saline formation. The new models include the effects of multiphase flow, CO2 dissolution in formation brine, and near-well drying out on the BHP. CO2 is injected into the formation at a constant rate. The analytical solutions are presented for three types of formation outer boundary conditions: closed boundary, constant-pressure boundary, and infinite-acting formation. The sensitivity of BHP computations to gas relative permeability, retardation factors, and CO2 compressibility is examined. The predictive capability of the analytical models is tested by use of numerical reservoir simulations. The results show a good agreement between the analytical and numerical computations for all three boundary conditions. Variations in gas compressibility, retardation factors, and gas relative permeability in the drying-out zone are found to have moderate effects on BHP computations. It is demonstrated for several hypothetical but realistic cases that the new models can estimate CO2 injectivity reliably.

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