Analysis of Vertical Permeability and Its Influence on CO2 EOR and Storage in a Carbonate Reservoir

2021 ◽  
Author(s):  
Bo Ren ◽  
Jerry Jensen ◽  
Larry Lake ◽  
Ian Duncan ◽  
Frank Male
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
Distribution Functions ◽  
Carbonate Reservoir ◽  
Cumulative Distribution ◽  
Co2 Injection ◽  
Buoyant Flow ◽  
Co2 Eor ◽  
Co2 Flow ◽  
And Storage

Abstract The objective of this study is to improve understanding of the geostatistics of vertical (bed-normal) permeability (kz) and its influence on reservoir performance during CO2 enhanced oil recovery (EOR) and storage. kz is scrutinized far less often than horizontal permeability (kx, ky) in most geological and reservoir modeling. However, our work indicates that it is equally important to understand kz characteristics to better evaluate their influence on CO2 EOR and storage performance prediction. We conducted this study on about 9,000 whole-core triaxial permeability (kx, ky, kz) measurements from 42 wells in a San Andres carbonate reservoir. We analyzed kz data, including heterogeneity, correlation, and sample sufficiency measures. We analyzed wells with the largest and smallest fractions of points with kz > kmax = max(kx, ky), to explore geological factors that coincided with large kz. We quantified these geological effects through conditional probabilities on potential permeability barriers (e.g., stylolites). Every well had at least some whole-cores where kz > kmax. This is a statistically justifiable result; only where Prob(kz > kmax) is statistically different from 1/3 are core samples non-isotropic. In conventional core data interpretation, however, modelers usually assume kz is less than kmax. For the well with the smallest fraction (11%) of cores where kz > kmax, the cumulative distribution functions differ and coincides with the presence of stylolites. We found that kz is about twice as variable as kx in many wells. This makes kz more difficult to interpret because it was (and usually is) heavily undersampled. To understand the influence of kz heterogeneity on CO2 flow, we built a series of flow simulation models that captured these geostatistical characteristics of permeability, while considering kz realizations, flow regimes (e.g., buoyant flow), CO2 injection strategies, and reservoir heterogeneity. CO2 flow simulations showed that, for viscous flow, assuming variable kx similar to the reservoir along with a constant kz/kx = 0.1 yields a close (within 0.5%) cumulative oil production to the simulation case with both kx and kz as uncorrelated variables. However, for buoyant flow, oil production differs by 10% (at 2.0 hydrocarbon pore volume HCPV of CO2 injected) between the two cases. Such flows could occur for small CO2 injection rates and long injection times, in interwell regions, and/or with vertically permeable conduits. Our geostatistical characterization demonstrates the controls on kz in a carbonate reservoir and how to improve conventional interpretation practices. This study can help CO2 EOR and storage operators refine injection development programs, particularly for reservoirs where buoyant flow exists. More broadly, the findings potentially apply to other similar subsurface buoyancy-driven flow displacements, including hydrogen storage, geothermal production, and aquifer CO2 sequestration.

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

2021 ◽  
Vol 73 (06) ◽  
pp. 67-68
Author(s):  
Chris Carpenter
Keyword(s):  
Oil Recovery ◽  
Optimization Problem ◽  
Co2 Storage ◽  
Oil Production ◽  
Joint Optimization ◽  
Optimization Approach ◽  
Well Control ◽  
Co2 Eor ◽  
Well Completions ◽  
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.

Technology Focus: EOR Operations (June 2021)

2021 ◽  
Vol 73 (06) ◽  
pp. 62-62
Author(s):  
Sunil Kokal
Keyword(s):  
Climate Change ◽  
Oil Recovery ◽  
Carbon Capture ◽  
Oil Production ◽  
Water Flooding ◽  
Co2 Injection ◽  
Full Potential ◽  
The World ◽  
And Storage

A long time ago, my mentor, Farooq Ali, wrote a thought-provoking paper on the unfulfilled promises of enhanced oil recovery (EOR). His essential summary: EOR had not lived up to its hype and full potential. There were more than a hundred methods and techniques proposed, but only a few had succeeded commercially. Fast-forward a few decades and into the new century, and the message and conclusions have not changed. EOR has definitely not lived up to its promise, especially from the big-picture perspective of daily oil production rates. Before the COVID-19 pandemic, the world was producing close to 100 million BOPD. Of this, only approximately 4 million BOPD was coming from EOR, and the bulk of this was from thermal. The numbers pale even when compared with shale oil, which has dominated US oil production during the past decade. So why has EOR failed so spectacularly? The answer is complex—mostly economic, less technical. It is difficult to compete against water (flooding), where the cost of the injectant is practically free. Compare this with EOR, where you have to inject something other than water—either heat, a gas or solvent, polymer, surfactant, or something exotic such as microbes. These techniques cost money and make EOR inherently expensive. They have become the Achilles’ heel of EOR. So, what is the message for those of us working in EOR? Make EOR cost-competitive, improve waterflooding, or join the sustainability bandwagon that is sweeping the world? That is the call of the hour, and for decades to come. While other EOR methods such as thermal and chemical will have a limited future, injection of carbon dioxide (CO2) for EOR will be a win/win proposition. It provides a way to sequester CO2 and produce additional oil at the same time. The oil revenues provide the “U” in “CCUS” (carbon capture, utilization, and storage) that will play a vital role in the removal of CO2. CCUS is considered by most to be an essential part of the climate-change portfolio of solutions. The papers in this feature are examples of CO2 sequestration either with EOR or in saline aquifers. One provides the EOR and storage potential in the Norwegian continental shelf. Another is a case study of improving asset performance in marginal pay regions. The third is an example that capitalizes on the US government’s 45Q tax credits for incentivizing CO2 injection. Our industry has been the custodian of subterranean reservoirs. We are the experts in managing and developing them. Why not use that expertise to find solutions for climate change by capturing and removing carbon and being part of the solution? Recommended additional reading at OnePetro: www.onepetro.org. SPE 200363 Economic Assessment of Strategies for CO2 EOR and Storage in Brownfield Residual Oil Zones: A Case Study From the Seminole San Andres Unit by Bo Ren, The University of Texas at Austin, et al. OTC 30157 Effects of CO2/Rock/Formation Brine Parameters on CO2 Injectivity for Sequestration by Muhammad Aslam Md Yusof, Universiti Teknologi Petronas, et al. SPE 202276 Is Chemical EOR Finally Coming of Age? by Eric Delamaide, IFP Technologies

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.

Pilot Project Evaluating WAG Efficiency for Carbonate Reservoir in Eastern Siberia

2021 ◽  
Author(s):  
Valentina Zharko ◽  
Dmitriy Burdakov
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Oil Production ◽  
Pilot Project ◽  
Carbonate Reservoir ◽  
Recovery Factor ◽  
Eastern Siberia ◽  
Water Cut ◽  
Wag Injection ◽  
Injection Rates

Abstract The paper presents the results of a pilot project implementing WAG injection at the oilfield with carbonate reservoir, characterized by low efficiency of traditional waterflooding. The objective of the pilot project was to evaluate the efficiency of this enhanced oil recovery method for conditions of the specific oil field. For the initial introduction of WAG, an area of the reservoir with minimal potential risks has been identified. During the test injections of water and gas, production parameters were monitored, including the oil production rates of the reacting wells and the water and gas injection rates of injection wells, the change in the density and composition of the produced fluids. With first positive results, the pilot area of the reservoir was expanded. In accordance with the responses of the producing wells to the injection of displacing agents, the injection rates were adjusted, and the production intensified, with the aim of maximizing the effect of WAG. The results obtained in practice were reproduced in the simulation model sector in order to obtain a project curve characterizing an increase in oil recovery due to water-alternating gas injection. Practical results obtained during pilot testing of the technology show that the injection of gas and water alternately can reduce the water cut of the reacting wells and increase overall oil production, providing more efficient displacement compared to traditional waterflooding. The use of WAG after the waterflooding provides an increase in oil recovery and a decrease in residual oil saturation. The water cut of the produced liquid decreased from 98% to 80%, an increase in oil production rate of 100 tons/day was obtained. The increase in the oil recovery factor is estimated at approximately 7.5% at gas injection of 1.5 hydrocarbon pore volumes. Based on the received results, the displacement characteristic was constructed. Methods for monitoring the effectiveness of WAG have been determined, and studies are planned to be carried out when designing a full-scale WAG project at the field. This project is the first pilot project in Russia implementing WAG injection in a field with a carbonate reservoir. During the pilot project, the technical feasibility of implementing this EOR method was confirmed, as well as its efficiency in terms of increasing the oil recovery factor for the conditions of the carbonate reservoir of Eastern Siberia, characterized by high water cut and low values of oil displacement coefficients during waterflooding.

scholarly journals Enabling Large-Scale Carbon Capture, Utilisation, and Storage (CCUS) Using Offshore Carbon Dioxide (CO2) Infrastructure Developments—A Review

Energies ◽  
2019 ◽  
Vol 12 (10) ◽  
pp. 1945 ◽  
Author(s):  
Lars Ingolf Eide ◽  
Melissa Batum ◽  
Tim Dixon ◽  
Zabia Elamin ◽  
Arne Graue ◽  
...  
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Carbon Capture ◽  
Large Scale ◽  
Business Models ◽  
Reservoir Performance ◽  
High Investment ◽  
Co2 Eor ◽  
Carbon Dioxide Co2 ◽  
And Storage

Presently, the only offshore project for enhanced oil recovery using carbon dioxide, known as CO2-EOR, is in Brazil. Several desk studies have been undertaken, without any projects being implemented. The objective of this review is to investigate barriers to the implementation of large-scale offshore CO2-EOR projects, to identify recent technology developments, and to suggest non-technological incentives that may enable implementation. We examine differences between onshore and offshore CO2-EOR, emerging technologies that could enable projects, as well as approaches and regulatory requirements that may help overcome barriers. Our review shows that there are few, if any, technical barriers to offshore CO2-EOR. However, there are many other barriers to the implementation of offshore CO2-EOR, including: High investment and operation costs, uncertainties about reservoir performance, limited access of CO2 supply, lack of business models, and uncertainties about regulations. This review describes recent technology developments that may remove such barriers and concludes with recommendations for overcoming non-technical barriers. The review is based on a report by the Carbon Sequestration Leadership Forum (CSLF).

scholarly journals Source Sink Matching for Field Scale CCUS CO2-EOR Application in Indonesia

2021 ◽  
Vol 44 (2) ◽  
pp. 97-106
Author(s):  
Usman Usman ◽  
Dadan DSM Saputra ◽  
Nurus Firdaus
Keyword(s):  
Oil Recovery ◽  
Carbon Capture ◽  
Greenhouse Gas Emission ◽  
Oil Field ◽  
Governmental Organization ◽  
Co2 Eor ◽  
Source Sink ◽  
And Storage

The carbon capture utilization and storage (CCUS) referred in this paper is limited to the use of CO2 to the enhanced oil recovery (CO2-EOR). The CCUS CO2-EOR technology can magnify oil production substantially while a consistent amount of the CO2 injected remains sequestrated in the reservoir, which is beneficial for reducing the greenhouse gas emission. Therefore, this technology is a potentially attractive win-win solution for Indonesia to meet the goal of improved energy supply and security, while also reducing CO2 emissions over the long term. The success of CCUS depends on the proper sources-sinks matching. This paper presents a systematic approach to pairing the CO2 captured from industrial activities with suitable oil fields for CO2-EOR. Inventories of CO2 sources and oil reservoirs were done through survey and data questionnaires. The process of sources-sinks matching was preceded by identifying the CO2 sources within the radius of 100 and 200 km from each oil field and clustering the fields within the same radius from each CO2 source. Each cluster is mapped on the GIS platform included existing and planning right of way for trunk pipelines. Pairing of source-sink are ranked to identify high priority development. Results of this study should be interest to project developers, policymakers, government agencies, academicians, civil society and environmental non-governmental organization in order to enable them to assess the role of CCUS CO2-EOR as a major carbon management strategy.

scholarly journals MODEL-BASED OPTIMIZATION OF CYCLES OF CO2 WATER-ALTERNATING-GAS (CO2-WAG) INJECTION IN CARBONATE RESERVOIR

2022 ◽  
Vol 15 (4) ◽  
pp. 139-149
Author(s):  
F. G. A. Pereira ◽  
V. E. Botechia ◽  
D. J. Schiozer
Keyword(s):  
Oil Recovery ◽  
Carbonate Reservoir ◽  
Co2 Production ◽  
Co2 Injection ◽  
Optimal Size ◽  
Control Variables ◽  
Limit Values ◽  
Water Alternating Gas ◽  
Production Wells ◽  
The Impact

Pre-salt reservoirs are among the most important discoveries in recent decades due to the large quantities of oil in them. However, high levels of uncertainties related to its large gas/CO2 production prompt a more complex gas/CO2 management, including the use of alternating water and gas/CO2 injection (WAG) as a recovery mechanism to increase oil recovery from the field. The purpose of this work is to develop a methodology to manage cycle sizes of the WAG/CO2, and analyze the impact of other variables related to the management of producing wells during the process. The methodology was applied to a benchmark synthetic reservoir model with pre-salt characteristics. We used five approaches to evaluate the optimum cycle size under study, also assessing the impact of the management of producing wells: (A) without closing producers due to gas-oil ratio (GOR) limit; (B) GOR limit fixed at a fixed value (1600 m³/m³) for all wells; (C) GOR limit optimized per well; (D) joint optimization between GOR limit values of producers and WAG cycles; and (E) optimization of the cycle size per injector well with an optimized GOR limit. The results showed that the optimum cycle size depends on the management of the producers. Leaving all production wells open until the end of the field's life (without closing based on the GOR limit) or controlling the wells in a more restricted manner (with closing based on the GOR limit), led to significant variation of the results (optimal size of the WAG/CO2 cycles). Our study, therefore, demonstrates that the optimum cycle size depends on other control variables and can change significantly due to these variables. This work presents a study that aimed to manage the WAG-CO2 injection cycle size by optimizing the life cycle control variables to obtain better economic performance within the premises already established, such as the total reinjection of gas/CO2 produced, also analyzing the impact of other variables (management of producing wells) along with the WAG-CO2 cycles.

The Characteristics of CO2 Flow and Thermal Field in a Porous Media

2010 ◽  
Author(s):  
Hang Seok Choi ◽  
Yeon Seok Choi ◽  
Hoon Chae Park ◽  
Cheol Huh ◽  
Seong-Gil Kang ◽  
...  
Keyword(s):  
Porous Structure ◽  
Co2 Storage ◽  
Co2 Injection ◽  
Physical Conditions ◽  
Thermal Fields ◽  
Level Model ◽  
Temperature And Pressure ◽  
Set Up ◽  
Co2 Flow ◽  
And Storage

International attention has been considerably paid for the technology of CO2 capture and storage (CCS) these days because of global warming. Among the technologies of CCS, the prediction of CO2 behavior in underground is very crucial for CO2 storage design. In the present study, a pore-scale level model is developed to mimic real porous structure and by using CFD (computational fluid dynamics) the characteristics of the CO2 flow and thermal fields are investigated in the pore-level micro porous structure. Varying the CO2 injection conditions such as flow rate, pressure and temperature, the behavior of CO2 is calculated. Especially, the physical conditions such as temperature and pressure are set up equivalent to the underground condition at which CO2 is injected. From the results, the injection condition of CO2 is very critical to the characteristics of the flow and thermal fields in the micro-scale porous structure.

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