scholarly journals Investigation of Properties Alternation during Super-Critical CO2 Injection in Shale

2019 ◽  
Vol 9 (8) ◽  
pp. 1686 ◽  
Author(s):  
Sai Wang ◽  
Kouqi Liu ◽  
Juan Han ◽  
Kegang Ling ◽  
Hongsheng Wang ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Supercritical Co2 ◽  
Indentation Test ◽  
Nitrogen Adsorption ◽  
Xrd Analysis ◽  
Bet Surface Area ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Recovery Method ◽  
Injection Process

The low recovery of oil from tight liquid-rich formations is still a major challenge for a tight reservoir. Thus, supercritical CO2 flooding was proposed as an immense potential recovery method for production improvement. While up to date, there have been few studies to account for the formation properties’ variation during the CO2 Enhanced Oil Recovery (EOR) process, especially investigation at the micro-scale. This work conducted a series of measurements to evaluate the rock mechanical change, mineral alteration and the pore structure properties’ variation through the supercritical CO2 (Sc-CO2) injection process. Corresponding to the time variation (0 days, 10 days, 20 days, 30 days and 40 days), the rock mechanical properties were analyzed properly through the nano-indentation test, and the mineralogical alterations were quantified through X-ray diffraction (XRD). In addition, pore structures of the samples were measured through the low-temperature N2 adsorption tests. The results showed that, after Sc-CO2 injection, Young’s modulus of the samples decreases. The nitrogen adsorption results demonstrated that, after the CO2 injection, the mesopore volume of the sample would change as well as the specific Brunauer–Emmett–Teller (BET) surface area which could be aroused from the chemical reactions between the CO2 and some authigenic minerals. XRD analysis results also indicated that mesopore were altered due to the chemical reaction between the injected Sc-CO2 and the minerals.

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 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.

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.

The Effect of Phase Equilibria on the CO2 Displacement Mechanism

1979 ◽  
Vol 19 (04) ◽  
pp. 242-252 ◽  
Author(s):  
R.S. Metcalfe ◽  
Lyman Yarborough
Keyword(s):  
Carbon Dioxide ◽  
Phase Equilibria ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Miscible Displacement ◽  
Co2 Flooding ◽  
Recovery Method ◽  
Two Fluids ◽  
Reservoir Conditions

Abstract Carbon dioxide flooding under miscible conditions is being developed as a major process for enhanced oil recovery. This paper presents results of research studies to increase our understanding of the multiple-contact miscible displacement mechanism for CO2 flooding. Carbon dioxide displacements of three synthetic oils of increasing complexity (increasing number of hydrocarbon components) are described. The paper concentrates on results of laboratory flow studies, but uses results of phase-equilibria and numerical studies to support the conclusions.Results from studies with synthetic oils show that at least two multiple-contact miscible mechanisms, vaporization and condensation, can be identified and that the phase-equilibria data can be used as a basis for describing the mechanism. The phase-equilibria change with varying reservoir conditions, and the flow studies show that the miscible mechanism depends on the phase-equilibria behavior. Qualitative predictions with mathematical models support our conclusions.Phase-equilibria data with naturally occurring oils suggest the two mechanisms (vaporization and condensation) are relevant to CO2 displacements at reservoir conditions and are a basis for specifying the controlling mechanisms. Introduction Miscible-displacement processes, which rely on multiple contacts of injected gas and reservoir oil to develop an in-situ solvent, generally have been recognized by the petroleum industry as an important enhanced oil-recovery method. More recently, CO2 flooding has advanced to the position (in the U.S.) of being the most economically attractive of the multiple-contact miscibility (MCM) processes. Several projects have been or are currently being conducted either to study or use CO2 as an enhanced oil-recovery method. It has been demonstrated convincingly by Holm and others that CO2 can recover oil from laboratory systems and therefore from the swept zone of petroleum reservoirs using miscible displacement. However, several contradictions seem to exist in published results.. These authors attempt to establish the mechanism(s) through which CO2 and oil form a miscible solvent in situ. (The solvent thus produced is capable of performing as though the two fluids were miscible when performing as though the two fluids were miscible when injected.) In addition, little experimental work has been published to provide support for the mechanisms of multiple-contact miscibility, as originally discussed by Hutchinson and Braun.One can reasonably assume that the miscible CO2 process will be related directly to phase equilibria process will be related directly to phase equilibria because it involves intimate contact of gases and liquids. However, no data have been published to indicate that the mechanism for miscibility development may differ for varying phase-equilibria conditions.This paper presents the results of both flow and phase-equilibria studies performed to determine the phase-equilibria studies performed to determine the mechanism(s) of CO2 multiple-contact miscibility. These flow studies used CO2 to displace three multicomponent hydrocarbon mixtures under first-contact miscible, multiple-contact miscible, and immiscible conditions. Results are presented to support the vaporization mechanism as described by Hutchinson and Braun, and also to show that more than one mechanism is possible with CO2 displacements. The reason for the latter is found in the results of phase-equilibria studies. SPEJ P. 242

A Novel Improved Condensate-Recovery Method by Cyclic Supercritical CO2 Injection

2007 ◽  
Author(s):  
Millan Arcia Einstein ◽  
Yeirys Caridad Gerder Castillo ◽  
Jenny Coromoto Gil
Keyword(s):  
Supercritical Co2 ◽  
Co2 Injection ◽  
Recovery Method ◽  
Supercritical Co2 Injection

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 Researches in Making In-Situ Thermal Foam System as a New Enhanced Heavy Oil Recovery Method

2021 ◽  
Author(s):  
Vladimir Nikolaevich Kozhin ◽  
Andrey Valerevich Mikhailov ◽  
Konstantin Vasilievich Pchela ◽  
Ivan Ivanovich Kireev ◽  
Sergey Valerevich Demin ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Ionic Composition ◽  
Chemical Effect ◽  
Recovery Method ◽  
Injection Process ◽  
Viscous Oil ◽  
Reservoir Conditions ◽  
Displacement Factor ◽  
Water Gas

Abstract The paper presents the results of lab and filtration studies aimed at improving the procedure of thermal/gas/chemical effect (TGCE) with the generation of thermogenic system in reservoir conditions, proposed as an alternative to the methods of increasing oil recovery, such as water-gas effect procedure and foam injection process. The objects of research were thermal/gas generating compositions at the basis of sodium salts of sulfamic and nitric acids. Moreover, the influence of the ionic composition of the aqueous solution and temperature on the surface properties of the attracted solutions of surfactants (surfactants) was also evaluated. Filtration tests have shown that the use of a thermal/gas generating composition leads to additional displacement of high-viscous oil. The introduction of surfactants in the thermal/gas generating composition promotes foaming in the porous medium of the reservoir model and prevents gas breakthrough that leads to an increase in the oil displacement factor up to 24 %.

scholarly journals Assessment of CO2 flooding as enhanced oil recovery

2021 ◽  
Vol 340 ◽  
pp. 01021
Author(s):  
Akhat Makhambetov ◽  
Nursultan Azilkhanov
Keyword(s):  
Carbon Dioxide ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Carbonate Reservoir ◽  
Oil Fields ◽  
Co2 Flooding ◽  
Carbon Dioxide Injection ◽  
Recovery Method ◽  
Stage Of Development ◽  
Temperature And Pressure

This article discusses evaluating CO2 injection as an enhanced oil recovery method. Carbon dioxide injection is a secondary and tertiary enhanced oil recovery method and is used in the final stage of development. Carbon dioxide mixes well with oil and can dissolve heavy components. Also, CO2 maintains reservoir pressure, which prevents the flow rate from dropping. In order for carbon dioxide and oil to mix, it must be brought to a critical state by increasing the temperature and pressure. After reaching the required conditions, both substances are fully compatible. The result of this combination is a medium that can easily seep through a porous medium. In fact, gas injection would be appropriate to use in a carbonate reservoir, and in our country and all over the world there are many oil fields that are located in carbonate rock. This work is based on data on a field located in the Krasnoyarsk region, which is part of the Angara fold zones. The field itself is represented mainly by carbonate reservoirs. Also, application of this method for Kazakhstan oilfield will be considered, using an example Zhetybay oilfield.

The Experimental Study on the Flooding Regularities of Various CO2 Flooding Modes Implemented on Ultralow Permeability Cores

2018 ◽  
Vol 140 (7) ◽  
Author(s):  
Aifen Li ◽  
Xiaoxia Ren ◽  
Shuaishi Fu ◽  
Jiao Lv ◽  
Xuguang Li ◽  
...  
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Water Injection ◽  
Water Flooding ◽  
Co2 Injection ◽  
Rapid Decline ◽  
Co2 Flooding ◽  
Gas Oil ◽  
Water Cut ◽  
Ultralow Permeability

The application of water flooding is not successful for the development of low permeability reservoirs due to the fine pore sizes and the difficulty of water injection operation. CO2 can dissolve readily in crude oil and highly improve the mobility of crude oil, which makes CO2 flooding an effective way to the development of the ultralow-permeability reservoirs. The regularities of various CO2 displacement methods were studied via experiments implemented on cores from Chang 8 Formation of Honghe Oilfield. The results show that CO2 miscible displacement has the minimum displacement differential pressure and the maximum oil recovery; CO2-alternating-water miscible flooding has lower oil recovery, higher drive pressure, and relatively lower gas-oil ratio; water flooding has the minimum oil recovery and the maximum driving pressure. A large amount of oil still can be produced under a high gas-oil ratio condition through CO2 displacement method. This fact proves that the increase of gas-oil ratio is caused by the production of dissolved CO2 in oil rather than the free gas breakthrough. At the initial stage of CO2 injection, CO2 does not improve the oil recovery immediately. As the injection continues, the oil recovery can be improved rapidly. This phenomenon suggests that when CO2 displacement is performed at high water cut period, the water cut does not decrease immediately and will remain high for a period of time, then a rapid decline of water cut and increase of oil production can be observed.

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