CO2 Enhanced Oil Recovery Research Articles

Mechanism of CO2 enhanced oil recovery in shale reservoirs

Combined with NMR, core experiment, slim-tube tests, nano-CT and oil composition analysis, the mechanism of CO2 enhanced oil recovery had been studied. CO2 flooding under supercritical state could achieve higher oil recovery. In the process of crude oil displaced by supercritical CO2, the average oil recovery was 46.98% at low displacement pressures and 73.35% at high displacement pressures. The permeability of cores after CO2 flooding was only 28%–64% of those before flooding. As to the expelled oil, the contents of asphaltenes and non-hydrocarbons decreased, and saturated hydrocarbons of above C25 were absent in some samples, indicating that they had been retained in cores as demonstrated by CT and NMR experiments. In slim-tube tests, the heavy components of oil were expelled when the pressure increased to 30 MPa. There was a reasonable bottom hole pressure (BHP) below which the heavy components driven out from the far-well zone would deposit in the near-well zone, and when the pressure was too high, the nonhydrocarbon detention may cause block. The smaller throat and worse physical properties the porous media had, the higher displacement pressure would be required to achieve a good oil displacement efficiency. The increase in displacement pressure or time of interaction between oil and CO2 could effectively enhance oil recovery.

Economic viability of full-chain CCUS-EOR in Indonesia

Carbon Capture Utilization and Storage (CCUS) is currently the primary technology to allow the use of fossil fuels with deep CO2 reduction. One technology utilizes captured CO2 for Enhanced Oil Recovery (EOR). For developing countries which rely heavily on fossil fuels, CCUS with EOR can serve as a potential solution for national climate change abatement strategies while still sustaining energy security and economic well-being. This paper examines this premise by analysing the cost and benefit of deploying CCUS projects in Indonesia, specifically focusing on gas processing facilities and a nearby oil field in East Java. The key findings are as follows: (1) the cost of CCUS project is approximately $59/tCO2, for capturing, storing and transporting 5,546 tCO2/day, significantly more than offsetting CO2 emissions from additionally produced oil to make it essentially a net CO2 sink; (2) the CCUS – EOR integrated project can provide an additional oil recovery of 54 MMSTB oilfor 15 years of operational life. (3) The cost benefit analysis resulted in a positive NPV and levelized net profit of $3.13/tCO2 for oil price $40/bbl. (4) the study highlights the total distribution of shares for oil & gas contractor and the Indonesian government under a PSC cost recovery scheme, approximating 141 million USD and 211 million USD, respectively. While under a gross split scheme, the Indonesian government share is 271 million USD and contractor share is 81 million USD. (5) Finally, our study reconfirms the economic viability for using high purity CO2 sources combined with CO2 EOR as an early opportunity for CCUS deployment in Indonesia.

Joint Optimization of Well Completions and Controls for CO2 Enhanced Oil Recovery and Storage

Summary Carbon dioxide (CO2) enhanced oil recovery (EOR) is considered one of the technologies to help promote larger scale deployment of geologic CO2 storage because of associated economic benefits through CO2 storage, associated benefits of oil recovery, and the 45Q tax credit (a tax incentive that would reduce CO2 emission in the United States) as well as potential for utilization of existing infrastructure. The objective of this study is to demonstrate how optimal operation strategies (including well completions and controls) can be used to optimize both CO2 storage and oil recovery. The optimization problem was focused on joint estimation of well completions (i.e., fraction of injection/production well perforations in each reservoir layer) and CO2 injection/oil production controls [i.e., rates or bottomhole pressures (BHPs)] that maximize the net present value (NPV) in a combined CO2-EOR and CO2 storage operation. We used the newly developed stochastic simplex approximate gradient (StoSAG), one of the most efficient optimization algorithms in the reservoir optimization community, to solve the optimization problem. The performance of the joint optimization approach was compared with the performance of the well-control-only optimization approach. The superiority of joint optimization was demonstrated with two examples. In addition, the performance of co-optimization of CO2 storage and oil recovery approach was compared with the performances of maximization of only CO2 storage and maximization of only oil recovery approaches.

Joint impedance and facies inversion of time-lapse seismic data for improving monitoring of CO2 incidentally stored from CO2 EOR

Time-lapse seismic monitoring is an effective and proven technology for mapping the distribution of CO2 in a subsurface reservoir. When injected CO2 displaces other reservoir fluids, porous-medium properties are changed and thus the seismic impedance changes, causing time-lapse seismic amplitude differences in the injection zones. The analysis and interpretation of images created from these amplitude differences can provide information about reservoir architecture and the CO2 migration within the reservoir. Incorporating seismic inversion and rock physics into the interpretation of time-lapse seismic data can considerably improve the modeling and monitoring to detect and assess the location of CO2 over time. The joint inversion method presented in this paper has an integral representation of the geology in the inversion algorithm using elastic facies, which provides information about the spatial distribution of the geologic heterogeneities controlling the movement of fluids in the reservoir. The method was successfully applied to time-lapse seismic data from a mature oil field undergoing CO2 enhanced oil recovery. The estimated seismic acoustic impedances and facies reflect the characteristics of individual geologic facies and fluid conditions of the reservoir subject to CO2 injection. The probabilities estimated by the joint impedance and facies inversion for the reservoir's litho-fluid facies can be used for forecasting CO2 saturation and pressure changes within the target reservoir.

Cellulose Nanocrystal Switchable Gel Improves CO2 Sweep Efficiency

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201609, “Cellulose Nanocrystal Switchable Gel for Improving CO2 Sweep Efficiency in Enhanced Oil Recovery and Gas Storage,” by Ali Telmadarreie, University of Calgary and Cnergreen; Christopher Johnsen, University of Calgary; and Steven Bryant, University of Calgary and Cnergreen, prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, 5–7 October. The paper has not been peer reviewed. The entanglement of biopolymers is a well-known phenomenon that, when controlled, can result in a smart fluid with strong gelation properties. The authors write that, when a suitable salt is incorporated into the cellulose nanocrystal (CNC), the fluids undergo gelation upon contact with bulk-phase carbon dioxide (CO2) but remain a flowing liquid otherwise. In this study, this composition-selective trigger was applied to improve sweep efficiency in CO2 enhanced oil recovery (EOR) and sequestration. Introduction Hydrogels are hydrophilic structures that swell when hydrated and have various applications in industry. Hydrogels are of interest in EOR because of their ability to respond to stimuli such as pH, temperature, light, and ionic strength. CNCs are nanoparticles derived from cellulose, one of the more sustainable natural resources available. CNC hydrogels could have specific applications as a solution to media het-erogeneity and poor gas-sweep efficiency. The hydrogels can be tuned to set over time, allowing the intentional placement of gels into already-swept areas of a reservoir. CNC hydrogels are unique in that they can be formed when contacted with CO2 and broken by the application of nitrogen (N2) gas. The pH of the solution will be increased as the nitrogen partitions across the gel, reversing the CO2 reaction. This gives the gel-forming solution the added benefit of being transmittable throughout a reservoir. Material and Procedure Spray-dried CNCs with an average length of 100–200 nm and a width of 15 nm were used. Imidazole was used as the salt mixed with water and CNC suspension to create a pH-triggered gel system. CO2 gas and N2 gas were used as received. Mineral oil with a viscosity of approximately 20 cp was used at the oil phase. Solution preparation, and the process for gel strength in bulk testing, are provided in the complete paper. All tests were performed at a pressure of 400 psi and an ambient temperature of 21°C. Two sets of flow experiments were performed. The first included flow in a single sandpack saturated with water to investigate the in-situ gelation and reversibility of the gel. The second set used a dual-sandpack system. The shorter sandpack with higher permeability was saturated with water to create a path of less resistance compared with the longer sandpack with lower permeability saturated with viscous oil. Further details of these experiments are provided in the complete paper.

CO2 EOR Performance Evaluation in an Unconventional Reservoir through Mechanistic Constrained Proxy Modeling

There are multiple parameters including reservoir characteristics, hydraulic fracture design, injection solvent selection, and the enhanced oil recovery (EOR) operational design, etc., that are directly and indirectly involved in the unconventional reservoir development. And due to the lack of field data availability, the key performance indicators for such complex reservoirs are not well defined, therefore, reservoir engineers end up with a huge volume of numerical simulation scenarios to find an optimum field development plan. This approach makes the field development planning process complicated and time-consuming.In this study, a smart unconventional EOR performance evaluation tool is presented utilizing intelligent modeling strategies through proxy modeling approach with mechanistic constraints. The mechanistic constraints incorporate physics-based numerical simulation dataset. Key reservoir and hydraulic fracture topographies including average reservoir pressure and the matrix & hydraulic fracture permeability contrast are used as some of the key input parameters for the Deep Neural Network (DNN) modeling. Total four DNN models are generated for primary and EOR cases presenting the recovery performance prediction at two different timelines. The trained and validated DNN models are finally found well qualified to be applied for the development of the unconventional reservoirs with identical reservoir and hydraulic fracture characteristics for the EOR application forecasting.

Molecular Simulation Study on the Density Behavior of n-Alkane/CO2 Systems.

The density and volumetric behavior of three typical n-alkanes (hexane, octane, and decane) influenced by different mole fractions of CO2 injected in them at temperatures from 303 to 363 K and pressures from 3.8 to 8.67 MPa were investigated by performing molecular dynamics simulations. It is shown that the mass density first increases and then decreases with increasing CO2 mole fraction. Correspondingly, the system volume only slightly swells at low CO2 contents while suddenly expanding when the CO2 mole fraction exceeds a value of ∼60%. The calculations of structural properties and interaction energies indicate that at low CO2 mole fractions, there are a few CO2 molecules existing in the gap of alkane molecules, resulting in poor compressibility, while at higher CO2 concentrations, the CO2 molecules begin to separate from the CO2-saturated alkane phase and form a gas phase, leading to higher compressibility. Therefore, at high CO2 mole fractions, the system density and volume can more easily be changed by temperature and pressure than that at low CO2 mole fractions. In addition, since it is harder for alkanes with longer chains to separate from each other, the volume swelling decreases and the density increases with increasing carbon number of n-alkane chains. Finally, we found that the increase in CO2 mole fraction, temperature, and the decrease in alkane chain length would promote the diffusion of both CO2 and alkane molecules. However, the influence of pressure on molecular diffusion is very limited except when P = 8.67 MPa and T = 333 K, where CO2 is in the supercritical state. This work is helpful for understanding the density and volumetric behavior of n-alkane/CO2 mixtures at a molecular level and provides useful information for guiding carbon sequestration and CO2-enhanced oil recovery.

Pegging input prices to output prices—A special price adjustment clause in long-term CO[formula omitted] sales contracts

Oil firms that apply the technique of CO2-enhanced oil recovery inject CO2 into oil reservoirs to increase oil production. The long-term CO2 sales contracts commonly used in the industry often include a special price adjustment clause—the CO2 price is pegged to the oil price faced by the buyer. This is quite different from typical price adjustment clauses in other long-term contracts, which peg the contract price to input costs faced by the supplier. Using a stylized model, we identify plausible conditions under which the pegging practice adopted in the CO2 market is optimal. Numerical simulations calibrated to an active CO2-enhanced oil recovery project suggest that the optimal pegging rate is sensitive to the anticipated oil price level, but not to the oil price variance around that level. The optimal pegging rate is sensitive also to a given oil project’s CO2 “utilization efficiency” – the amount of CO2 required to produce an additional barrel of oil – which is both highly variable across projects and uncertain up front.

Potential of CO2-enhanced oil recovery coupled with carbon capture and storage in mitigating greenhouse gas emissions in the UAE

The potential of adopting CO2-Enhanced Oil Recovery (EOR) coupled with Carbon Capture and Storage (CCS) at a large scale is significant for major oil exporters like the United Arab Emirates. We develop a system dynamics model of the interactions between the demand of CO2-EOR to sustain oil output as reservoirs age, the country's production targets, and the required carbon prices to accelerate the adoption of CO2-EOR with CCS. We simulate 12 scenarios that represents different pathways for oil production, CO2 emissions growth and performance of CO2-EOR. The scenarios consider the sensitivity to key parameters: net utilization factor of CO2 for the marginal barrel of oil produced, the time it takes for injected CO2 to reach the production well (breakthrough time), and the share of EOR wells going to CO2-EOR operation. We find that a carbon price of 10–15 $/t CO2 in the first decade is needed in order to offset the cost of the CCS operations with the potential of breaking even by 2030. The large-scale adoption of CO2-EOR with CCS in the UAE can help in meeting 2.2–39.2% of the UAE 2nd national committed reduction target, i.e., 72.85 million tons of CO2 reduction per year by 2030, depending on CO2 breakthrough time and its net utilization factor. It may also help in freeing natural gas that could supply 12–20% of local energy needs extending its use with the CCS system. This study demonstrates a systematic modeling approach that quantifies complex interactions at the system level towards cleaner production practices.

A systematic capacity assessment and classification of geologic CO2 storage systems in India

With rising carbon dioxide emissions and ambitious global targets for climate change mitigation, carbon sequestration has become one of the most promising carbon dioxide removal technologies. It can prove especially beneficial to an emerging country such as India, which must balance its rapid economic growth with a reduction in emissions. A detailed assessment of the cumulative storage capacity is necessary to facilitate the development of CO2 storage pathways in India. Previous assessments for India have primarily estimated the theoretical storage capacity based on limited data. In this study, we have reviewed different methodologies for estimating storage capacities globally, and based on the most current data available, in a first, developed a systematic assessment for theoretical and effective CO2 storage capacities for different geological formations in India. Four storage pathways with adequate potential have been identified: storage through CO2 enhanced oil recovery (EOR), enhanced coalbed methane recovery (ECBMR), storage in deep saline aquifers, and basalt formations. The results indicate considerable potential for CO2 storage in India, especially in saline aquifers (291 Gt) and basalt (97–316 Gt). Even though the storage capacity estimated through EOR (3.4 Gt) and ECBMR (3.7 Gt) is comparatively less, it is adequate to store emissions from nearby large point sources. These methods are also highly feasible due to the ready availability of infrastructure and extensive geological information about the basins involved. In addition, we have developed novel classification systems for different basins in India to represent their prospectivity for CO2 storage.

How Is Ultrasonic-Assisted CO2 EOR to Unlock Oils from Unconventional Reservoirs?

CO2 enhanced oil recovery (EOR) has proven its capability to explore unconventional tight oil reservoirs and the potential for geological carbon storage. Meanwhile, the extremely low permeability pores increase the difficulty of CO2 EOR and geological storage processing in the actual field. This paper initiates the ultrasonic-assisted approach to facilitate oil–gas miscibility development and finally contributes to excavating more tight oils. Firstly, the physical properties of crude oil with and without ultrasonic treatments were experimentally analyzed through gas chromatography (GC), Fourier-transform infrared spectroscopy (FTIR) and viscometer. Secondly, the oil–gas minimum miscibility pressures (MMPs) were measured from the slim-tube test and the miscibility developments with and without ultrasonic treatments were interpreted from the mixing-cell method. Thirdly, the nuclear-magnetic resonance (NMR) assisted coreflood tests were conducted to physically model the recovery process in porous media and directly obtain the recovery factor. Basically, the ultrasonic treatment (40 KHz and 200 W for 8 h) was found to substantially change the oil properties, with viscosity (at 60 °C) reduced from 4.1 to 2.8 mPa·s, contents of resin and asphaltene decreased from 27.94% and 6.03% to 14.2% and 3.79%, respectively. The FTIR spectrum showed that the unsaturated C-H bond, C-O bond and C≡C bond in macromolecules were broken from the ultrasonic, which caused the macromolecules (e.g., resin and asphaltenes) to be decomposed into smaller carbon-number molecules. Accordingly, the MMP was determined to be reduced from 15.8 to 14.9 MPa from the slim-tube test and the oil recovery factor increased by an additional 11.7%. This study reveals the mechanisms of ultrasonic-assisted CO2 miscible EOR in producing tight oils.

Exsolution effects in CO2 huff-n-puff enhanced oil recovery: Water-Oil-CO2 three phase flow visualization and measurements by micro-PIV in micromodel

CO2 huff-n-puff is one of the most important methods to enhanced oil recovery, which can simultaneously improve oil production and achieve CO2 geological storage. Due to the fluctuation of formation pressure, water-oil-CO2 three phase migration in porous structures was affected significantly by supercritical CO2 exsolution and expansion. However, the existing research on phase distribution is not enough to understand the mechanism of three-phase migration and the essential processes beneath the phase distribution are still not clear. Here, we developed a high-temperature and high-pressure micro-PIV (Particle Image Velocimetry) and fluorescence visualization experimental system (10 MPa, 50°C), which realized the simultaneous measurement of the velocity field and phase distribution of the water-oil-CO2 three-phase. The multiphase migration process under different wettability conditions during the supercritical-subcritical CO2 exsolution were captured. The results showed that the exsolution induced CO2 bubbles expansion in aqueous and oil phase blocked the preferential migration passage and dominated different multiphase migration mechanisms under different wettability. It was found that in water-wet condition, the aqueous phase can still migrate downstream through the water film between the CO2/oil and the wall, unable to further drive CO2/oil downstream. While in oil-wet condition, the aqueous phase eventually broke through the oil phase blocked at throats and formed a new preferential migration passage, pushing part of the oil phase encapsulating CO2 bubbles downstream. Our research reveals the multiphase migration mechanism beneath the phase distribution under different wettability during the exsolution process of the huff-n-puff, which provides a new insight for CO2 enhanced oil recovery and geological storage.

Determination of Minimum Miscibility Pressure of CO2-Oil System: A Molecular Dynamics Study.

CO2 enhanced oil recovery (CO2-EOR) has become significantly crucial to the petroleum industry, in particular, CO2 miscible flooding can greatly improve the efficiency of EOR. Minimum miscibility pressure (MMP) is a vital factor affecting CO2 flooding, which determines the yield and economic benefit of oil recovery. Therefore, it is important to predict this property for a successful field development plan. In this study, a novel model based on molecular dynamics to determine MMP was developed. The model characterized a miscible state by calculating the ratio of CO2 and crude oil atoms that pass through the initial interface. The whole process was not affected by other external objective factors. We compared our model with several famous empirical correlations, and obtained satisfactory results—the relative errors were 8.53% and 13.71% for the two equations derived from our model. Furthermore, we found the MMPs predicted by different reference materials (i.e., CO2/crude oil) were approximately linear (R2 = 0.955). We also confirmed the linear relationship between MMP and reservoir temperature (TR). The correlation coefficient was about 0.15 MPa/K in the present study.

The integration of hydrogenation and carbon capture utilisation and storage technology: A potential low‐carbon approach to chemical synthesis in China

The development of carbon emission reduction technologies and clean energy utilisation are two critical drivers for reducing and controlling greenhouse gas (GHG) emission from human activities. Carbon capture, utilisation, and storage (CCUS) is an established and crucial emission reduction technology capable of achieving near-zero-emission from fossil fuels. Hydrogen, a zero-carbon fuel, provides energy security while improving air quality. However, hydrogen is commonly derived from fossil fuels with significant associated CO2 emission. Hence, this study investigates the feasibility of integrating CCUS in the hydrogen industry, particularly from technical, sustainability, and policy perspectives. This study also critically reviews existing CCUS and hydrogen production technologies and discusses the prospects and challenges of each. Studies show that CO2 enhanced oil recovery (CO2-EOR) and CO2 enhanced coal-bed methane recovery (CO2-ECBM) are promising CCUS technologies in China, while producing clean hydrogen from fossil fuels with CCUS and water electrolysis are ideal development route. Specifically, this study proposes the coupling technical route of CCUS + SMR (steam methane reforming) and CCUS + CTH (coal-to-hydrogen) to accelerate carbon emission reduction by 2050 considering their promising carbon reduction potential and the ratio of hydrogen with CCUS. Besides, CO2 hydrogenation integrated chemical production is becoming increasingly popular to achieve carbon emission reduction and low-carbon economy. However, the relatively high costs and lack of hydrogen transportation infrastructure is currently the major bottleneck restricting the development of CCUS and hydrogen industry. Therefore, government subsidies, standardised operation of the carbon market, and technological innovation are useful strategies to address this issue.

Experimental and microscopic simulation study on CO2 diffusion in an oil-water liquid system

CO2 diffusion is important in CO2 enhanced oil recovery and CO2 capture and storage. However, most reported studies only focused on diffusion in single phase. In this study, a new model considering CO2 diffusion in multi-phase was established, and a new mathematical model is proposed based on the diffusion stage division. Diffusion experiments were conducted to determine the diffusion coefficients. Then, microscopic simulations were conducted to investigate CO2 diffusion in porous media using the determined coefficients. According to the results, the coupling between the experimental pressure and model indicated the accuracy of the model. The pressure and temperature were key parameters for controlling the coefficients. Water distribution had a critical impact on CO2 diffusion in porous media. CO2 diffusion shows worse performance in models with severe water block effect. The findings of this study can help guide the design of CO2 EOR and CCS projects.

Modelling of the Phase-Partitioning Behaviors for CO2-Brine System at Geological Conditions

Abstract An improved phase-partitioning model is proposed for the prediction of the mutual solubility in the CO2-brine system containing Na+, K+, Ca2+, Mg2+, Cl-, and SO42-. The correlations are computationally efficient and reliable, and they are primarily designed for incorporation into a multiphase flow simulator for geology- and energy-related applications including CO2 sequestration, CO2-enhanced geothermal systems, and CO2-enhanced oil recovery. The model relies on the fugacity coefficient in the CO2-rich phase and the activity coefficient in the aqueous phase to estimate the phase-partitioning properties. In the model, (i) the fugacity coefficients are simulated by a modified Peng-Robinson equation of state which incorporates a new alpha function and binary interaction parameter (BIP) correlation; (ii) the activity coefficient is estimated by a unified equilibrium constant model and a modified Margules expression; and (iii) the simultaneous effects of salting-out on the compositions of the CO2-rich phase and the aqueous phase are corrected by a Pizter interaction model. Validation of the model calculations against literature experimental data and traditional models indicates that the proposed model is capable of predicting the phase-partitioning behaviors in the CO2-brine system with a higher accuracy at temperatures of up to 623.15 K and pressures of up to 350 MPa. Using the proposed model, the phase diagram of the CO2+H2O system is generated. An abrupt change in phase compositions is revealed during the transfer of the CO2-rich phase from vapor to liquid or supercritical. Furthermore, the preliminary simulation shows that the salting-out effect can considerably decrease the water content in the CO2-rich phase, which has not been well experimentally studied so far.

Effect of permeability and fractures on oil mobilization of unconventional resources during CO2 EOR using nuclear magnetic resonance

CO2 EOR (enhanced oil recovery) will be one of main technologies of enhanced unconventional resources recovery. Understanding effect of permeability and fractures on the oil mobilization of unconventional resources, i.e. tight oil, is crucial during CO2 EOR process. Exposure experiments based on nuclear magnetic resonance (NMR) were used to study the interaction between CO2 and tight oil reservoirs in Chang 8 layer of Ordos Basin at 40 °C and 12 MPa. Effect of permeability and fractures on oil mobilization of exposure experiments were investigated for the different exposure time. The oil was mobilized from matrix to the surface of matrix and the oil recovery increased as the exposure time increased. The final oil recovery increased as the core permeability increased in these exposure experiments. Exposure area increased to 1.75 times by fractures resulting in that oil was mobilized faster in the initial stage of exposure experiment and the final oil recovery increased to 1.19 times from 28.8 to 34.2%. This study shows the quantitative results of effect of permeability and fractures on oil mobilization of unconventional resources during CO2 EOR, which will support CO2 EOR design in Chang 8 layer of Ordos Basin.

Risk assessment on the CCUS project using risk breakdown structure methodology: A case study on Jilin oilfield CO2‐EOR Hei‐79 block

AbstractThe risk potential matrix method can be used as a reference for the optimization of the traditional risk matrix in geological CO2 storage. This study used monitoring data for environmentally sensitive receptors in the Jilin Oilfield CO2‐enhanced oil recovery (CO2‐EOR) Hei‐79 block in conjunction with a hazard event store to create an updated risk assessment of CO2 capture, use, and storage (CCUS) as a guide for risk management. The assessment built upon the overall project operation status to evaluate six and five sub‐categories of hazard and sensitivity, respectively. The environmental sensitivity threshold integrated ecosystems and secondary geological disasters to amplify potential risks. The results of the risk assessment of the CO2‐EOR Hei‐79 block in the Jilin Oilfield showed that despite an overall risk level of Ⅱ, the hazard level resulted in an unacceptable increase in overall risk. Formations are usually stimulated by fracturing in Jilin Oilfield, particularly for oil and gas production. © 2021 Society of Chemical Industry and John Wiley & Sons, Ltd.

Modeling Evaluates CO2 EOR, Storage Potential in Depleted Reservoirs

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 200560, “CO2-EOR and Storage Potentials in Depleted Reservoirs in the Norwegian Continental Shelf,” by Elhans Imanovs, SPE, and Samuel Krevor, SPE, Imperial College London, and Ali Mojaddam Zadeh, Equinor, prepared for the 2020 SPE Europec featured at the 82nd EAGE Conference and Exhibition, originally scheduled to be held in Amsterdam, 8–11 June. The paper has not been peer reviewed. A combination of carbon dioxide (CO2) enhanced oil recovery (EOR) and storage schemes could offer an opportunity to produce additional oil from depleted reservoirs and permanently store CO2 in the subsurface in an economically efficient manner. The complete paper evaluates the effect of different injection methods on oil recovery and CO2 storage potential in a depleted sandstone reservoir in the Norwegian Continental Shelf (NCS). The methods include continuous gas injection (CGI), continuous water injection (CWI), water alternating gas (WAG), tapered WAG (TWAG), simultaneous water above gas coinjection (SWGCO), simultaneous water and gas injection (SWGI), and cyclic SWGI. CO2 EOR and Storage in the NCS In recent years, the number of newly explored fields in the NCS has decreased. Approximately 47% of total resources in the NCS have been produced, and approximately 20% of resources are estimated as recoverable reserves. To fill in the gap between energy demand and recoverable reserves, EOR methods could be employed. One of the most efficient EOR methods is CO2 injection, because complete microscopic sweep efficiency can be achieved, leading to a total depletion of the reservoir. The three major types of CO2 EOR processes—miscible, near-miscible, and immiscible—are described and discussed in the full paper. Four primary CO2-trapping mechanisms are used in the subsurface: structural/stratigraphic, solubility, residual, and mineral trapping. The main locations for underground geological storage are depleted oil and gas reservoirs, coal formations, and saline aquifers. Currently, underground CO2 storage is believed to be a major technology to dramatically reduce CO2 amounts in the atmosphere. According to the International Energy Agency, 54 major oil basins around the world have the potential to produce 75 Bsm3 of additional oil and store 140 Gt of CO2. CO2 EOR and storage projects in the NCS could have several benefits. First, surface and subsea facility availability in the NCS region reduces capital expenditures. Second, in addition to the revenue from extra oil production, carbon credits could be awarded for the CO2 storage. The main challenges of CO2 EOR and storage offshore projects are high operational and capital expenditures. In depleted reservoirs, these include modification of offshore platform materials; additional power supply for CO2 compression and recycling; and replacement of the tubing because wet CO2 is highly corrosive, resulting in scale, asphaltene, and hydrates formation. Contamination of a gas cap with injected CO2 might lead to loss of hydrocarbon gas market value. Only one CO2 EOR project has been implemented offshore—the Lula field in Brazil’s Santos Basin—meaning that industry has very limited experience in such projects.

Joint Optimization of Well Completions and Controls for CO2 Use and Storage

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200316, “Joint Optimization of Well Completions and Controls for CO2 Enhanced Oil Recovery and Storage,” by Bailian Chen, SPE, and Rajesh Pawar, Los Alamos National Laboratory, 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. Carbon dioxide (CO2) storage through CO2 enhanced oil recovery (EOR) has been considered an option for larger-scale deployment of CO2 storage because of the economic benefits of oil recovery, 45Q tax credits, and the use of existing infrastructure. The complete paper investigates how optimal reservoir management and operation strategies can be used to optimize both CO2 storage and oil recovery. Results of the authors’ study showed that joint optimization of well completions and well controls can achieve a higher final net present value (NPV) than that obtained from the optimization of well controls only. Introduction In CO2 EOR associated with storage processes, poorly designed well-operating conditions or completions can lead to low oil recovery factors and suboptimal CO2 storage. Co-optimization of oil production and CO2 storage has been recognized as a feasible technique to maximize benefit in terms of oil production and CO2 storage tax credit. To the best of the authors’ knowledge, settings for well completions have not been considered as optimization variables in a CO2 EOR and storage co-optimization process. The objective of this study is to conduct joint optimization of well completions and controls [well rates or bottomhole pressures (BHP)] that maximize life-cycle NPV in CO2 EOR and storage processes and demonstrate the superiority of joint optimization over well-control-only optimization. Optimization Problem In this study, the optimization problem considered is the joint optimization of well completions and well controls for a CO2 EOR and storage process. The mathematical process behind this determination is detailed in the complete paper. The optimization problem was focused on jointly estimating the well completions (i.e., fraction of injection/production well perforations in each reservoir layer) and CO2 injection and oil-production controls that maximize NPV in a CO2 EOR and storage operation. The authors used a newly developed stochastic simplex approximate gradient algorithm to solve the optimization problem. The performance of the joint optimization approach was compared with the performance of the well-control-only optimization approach. In addition, the performance of the co-optimization of CO2 storage and oil-recovery approach was compared with that of the maximization of only-CO2-storage and only-oil-recovery approaches.