CO2 Enhanced Oil Recovery Operations Research Articles

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 The paper has not been peer reviewed.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.

Technical and environmental viability of a European CO2 EOR system

Captured CO2 from large industrial emitters may be used for enhanced oil recovery (EOR), but as of yet there are no European large-scale EOR systems. Recent implementation decisions for a Norwegian carbon capture and storage demonstration will result in the establishment of a central CO2 hub on the west-coast of Norway and storage on the Norwegian Continental Shelf. This development may continue towards a large-scale operation involving European CO2 and CO2 EOR operation. To this end, a conceptual EOR system was developed here based on an oxyfuel power plant located in Poland that acted as a source for CO2, coupled to a promising oil field located on the Norwegian Continental Shelf. Lifecycle assessment was subsequently used to estimate environmental emissions indicators. When averaged over the operational lifetime, results show greenhouse gas (GHG) emissions of 0.4 kg CO2-eq per kg oil (and n kWh associated electricity) produced, of which 64 % derived from the oxyfuel power plant. This represents a 71 % emission reduction when compared to the same amount of oil and electricity production using conventional technology. Other environmental impact indicators were increased, showing that this type of CO2 EOR system may help reach GHG reduction targets, but care should be taken to avoid problem shifting.

Passive Microseismic Monitoring of CO2 EOR and Associated Storage Using a Downhole Array in a Noisy Subsurface Environment

A passive microseismic monitoring study of CO2 enhanced oil recovery operations at the Bell Creek Field was conducted. Two distinctive low signal-to-noise ratio environments were observed: a diurnal, dominated by high-amplitude coherent noise in the same frequency band as the signal, and a nocturnal, characterized by weak signals buried in random noise. Using estimations from a synthetic microseismic model as a reference and applying conventional, relatively simple event detection, picking and location estimation algorithms to nocturnal seismograms, we were able to identify microseismicity. We propose and demonstrate a low-cost tool correction method to simplify logistic field and data processing operations.

Carbon Sequestration through CO2 Foam-Enhanced Oil Recovery: A Green Chemistry Perspective

Abstract Enhanced oil recovery (EOR) via carbon dioxide (CO2) flooding has received a considerable amount of attention as an economically feasible method for carbon sequestration, with many recent studies focusing on developing enhanced CO2 foaming additives. However, the potential long-term environmental effects of these additives in the event of leakage are poorly understood and, given the amount of additives injected in a typical CO2 EOR operation, could be far-reaching. This paper presents a summary of recent developments in surfactant and surfactant/nanoparticle-based CO2 foaming systems, with an emphasis on the possible environmental impacts of CO2 foam leakage. Most of the surfactants studied are unlikely to degrade under reservoir conditions, and their release can cause major negative impacts on wildlife. With recent advances in the use of additives (e.g., nonionic surfactants, nanoparticles, and other chemicals) the use of harsh anionic surfactants may no longer be warranted. This paper discusses recent advances in producing foaming systems, and highlights possible strategies to develop environmentally friendly CO2 EOR methods.

Quantifying CO2 storage efficiency factors in hydrocarbon reservoirs: A detailed look at CO2 enhanced oil recovery

Carbon dioxide (CO2) enhanced oil recovery (EOR) will likely be the primary means of geologic CO2 storage during the early stages of commercial-scale carbon capture and storage (CCS) because of the inherent economic incentives as well as the abundant experience and demonstrated success in the United States, where CO2 EOR has been employed since 1974. The work presented here estimates CO2 storage efficiency factors in CO2 EOR operations using a unique industry database of CO2 EOR sites and 12 different reservoir simulation models. The simulation models encompass fluvial clastic and shallow shelf carbonate depositional environments for reservoir depths of 1219 and 2438 m (4000 and 8000 feet) and 7.6-, 20-, and 64-m (25-, 66-, and 209-foot)-thick pay zones. A novel statistical modeling technique incorporating the Michaelis–Menten function is used to generate empirical percentile estimates of CO2 storage efficiency factors.West Texas San Andres dolomite water alternating gas (WAG) CO2 flood performance data were used to derive P10, P50, and P90 CO2 storage efficiency factors of 0.76, 1.28, and 1.74 Mscf/STB (stock tank barrel) of original oil in place. Median CO2 storage efficiency factors from continuous CO2 injection following conventional waterflood varied from 15% to 61% and 8% to 40% for fluvial clastic and shallow shelf carbonate simulation models, respectively, while those from WAG injection varied from 14% to 42% and 8% to 31%, respectively. Variation in the CO2 storage efficiency factors was largely attributable to reservoir depth (a surrogate for reservoir pressure and temperature) and lithology (clastic versus carbonate). The results of this work provide practical information that can be used to quantify CO2 storage resource estimates in oil reservoirs during CO2 EOR operations (as opposed to storage following depletion) and the uncertainty associated with those estimates.

Impact of CO2 Impurity on MMP and Oil Recovery Performance of the Bell Creek Oil Field

Bell Creek Field is undergoing CO2 enhanced oil recovery operations. Impurities (mostly CH4) in the reproduced CO2 are included in the recycle injection gas, but the effect of this on oil recovery was uncertain. Laboratory experiments were conducted to determine oil MMP with different mole percentage mixtures of CO2 and CH4. The reservoir simulation was then used to predict oil production for various solvent compositions. Results showed that the reinjection of the gas mixture was able to ensure the storage of large volumes of CO2 while improving project economics by not requiring full separation of impurities from the injection stream.

Planning and scheduling of CO2 capture, utilization and storage (CCUS) operations as a strip packing problem

CO2 capture, utilization and storage (CCUS) is an important carbon management strategy that involves capturing CO2 from flue gas, transporting it, utilizing it for economically productive activities (carbon capture and utilization, or CCU), and/or permanently disposing it in non-atmospheric sinks (carbon capture and storage, or CCS). Some technologies, such as enhanced oil recovery (EOR) allow simultaneous CCUS, while other alternatives are either purely CCS (e.g., geological storage) or purely CCU (e.g., use of CO2 as a process plant feedstock). In this work, CCUS is addressed in the context of a large-scale CO2 chain that contains both CCS and CCU options. It is necessary to consider the availability of CO2 sources and sinks to develop a profitable allocation plan for such CCUS systems. Thus, a modeling framework using a geometric representation is proposed to optimize both scheduling and allocation in a CCUS system, given multiple CO2 sources and sinks. Two mixed integer linear programming (MILP) models are developed to address three important factors for planning downstream CCUS operations, i.e., scheduling of CO2 capture and EOR operations, allocation of CO2 supply for EOR operations, and source–sink matching subject to injectivity and capacity constraints. Two case studies are then solved to illustrate the two MILP models.

CO2 storage safety and leakage monitoring in the CCS demonstration project of Jilin oilfield, China

AbstractJilin oilfield is conducting the first large‐scale demonstration project on CO2 storage and enhanced oil recovery (EOR) in the northeast of China. A comprehensive monitoring program has been designed and deployed in the target reservoir of block H‐59 using a wide range of techniques to monitor the injection and production systems, the CO2 migration fronts, and potential CO2 leakage pathways. Tube fault detection, corrosion inhibitors, anti‐CO2 corrosion cement, and production dynamic analysis have been adopted to guarantee the safety at the well site. CO2 movement in the reservoir is detected mainly by gas tracer, electric spontaneous potential measurement, and fluid sampling. Near‐surface environmental monitoring is also conducted around the injection site. Field experience has shown that the monitoring targets should be focused on the reservoir, near‐surface, and injection and production systems. Applying monitoring techniques to ensure the integrity of wellbores can not only prevent the leakage of CO2, but also avoid the blind expansion of monitoring program scopes. It is reliable and economical to take full advantage of techniques based on wellbores to monitor CO2 movement in oil reservoirs with dense well patterns. Up to April 2013, nearly 21.7 × 104 tons of CO2 has been injected without obvious leakage caused by integrity failure of wells or the geological structure of reservoir. More than 96% of injected CO2 has been safely stored with the rest of injected CO2 normally breakthrough in the production wells. The preliminary monitoring experience obtained can provide valuable guidance for the future enlarged Jilin project and other CO2 EOR and storage operations.

Shifting Sands in a CO2 Desert: Replacing Extracted CO2 with By-product CO2 for Use in Enhanced Oil Recovery

Efforts to sequester or otherwise manage carbon dioxide emissions on a large scale will require an improved understanding of the geospatial characteristics of anthropogenic CO2 sources. Recent work by the authors using newly collected data from the US Environmental Protection Agency showed that even though there are some regions of the US with access to significant supply of CO2, most regions of the country do not have sources that are concentrated enough or large enough to support large-scale carbon management activities. What's more, the life cycle carbon burdens of different CO2 sources varied considerably with some sources, e.g., extracted wells, having a much larger carbon footprint than those where CO2 is a by-product, e.g., acid gas processing facilities. Here, the effect of source switching was explored in the context of CO2-enhanced oil recovery (CO2-EOR). At present most CO2-EOR operations in the United States rely on CO2 that is extracted from dedicated wells generating nearly pure CO2. By-product CO2, in contrast, is produced from a number of other industries including natural gas processing plants where small mass fractions of CO2 are removed from the gas stream. The emissions implications of these two sources of CO2 are significant in the context of CO2-EOR application because in one case, CO2 emissions are being avoided but in another they are not. Yet the switch from an industrial paradigm in which extracted CO2 is used to one in which by-product CO2 may not be as straightforward as it appears. Here, the SimCCS model is applied to the oil-producing Permian basin in west Texas to understand what the effect of source switching would be on CO2 demand, infrastructure, and overall emissions. The results suggest that at present scales of deployment, the costs associated with switching to by-product CO2 are higher than extracted CO2 because of the need for new infrastructure. Nevertheless, the observed emissions reductions are large in an absolute sense and suggest that this strategy be more seriously considered. A new infrastructure would be needed to connect by-product CO2 sources with CO2-EOR sinks but the cost of this is not so great that with a modest economic incentive, source switching of CO2 could represent a near-term strategy for reducing CO2 emissions and increasing oil production.

Greensites and brownsites: Implications for CO2 sequestration characterization, risk assessment, and monitoring

Proposed CO2 sequestration storage sites will require different approaches in characterization, risk assessment, and monitoring, given prior site history and land use. Those sites lacking previous subsurface development are defined as greensites, whereas sites where the subsurface is developed, particularly for hydrocarbon production, are defined as brownsites. Greensite CO2 injection is specifically for storage of CO2. Most CO2 enhanced oil recovery operations using incidental storage would be characterized as a brownsite. Application of monitoring approaches developed for greensites is inadequate when applied to brownsites because intrinsically different uncertainties may lead to investment in ineffective monitoring.Subsurface data are sparse at greensites. Characterization and monitoring must ensure that the subsurface can accept and retain CO2 in large volumes and that the confining system will isolate CO2 from the atmosphere over extended time frames. Brownsites will have extensive data on capacity, injectivity, and fluid retention from past operations. However, brownsite confining-system integrity may be compromised by the nature of past development.Greensite pore fluids are typically unperturbed and relatively stable, providing a simpler environment for characterization and monitoring. Brownsite reservoir fluids, however, may have been modified by resource recovery. Geologic processes commonly have introduced trace hydrocarbons into the shallow subsurface. At the surface, brownsite legacy infrastructure and contamination must be evaluated so that preinjection transients do not mimic or mask leakage signals. To be effective, policies and regulations need to recognize inherent differences between greensites and brownsites during CO2 storage project development.

Evaporite Caprock Integrity: An Experimental Study of Reactive Mineralogy and Pore-Scale Heterogeneity during Brine-CO2 Exposure

We present characterization and geochemical data from a core-flooding experiment on a sample from the Three Fingers evaporite unit forming the lower extent of caprock at the Weyburn-Midale reservoir, Canada. This low-permeability sample was characterized in detail using X-ray computed microtomography before and after exposure to CO(2)-acidified brine, allowing mineral phase and voidspace distributions to be quantified in three dimensions. Solution chemistry indicated that CO(2)-acidified brine preferentially dissolved dolomite until saturation was attained, while anhydrite remained unreactive. Dolomite dissolution contributed to increases in bulk permeability through the formation of a localized channel, guided by microfractures as well as porosity and reactive phase distributions aligned with depositional bedding. An indirect effect of carbonate mineral reactivity with CO(2)-acidified solution is voidspace generation through physical transport of anhydrite freed from the rock matrix following dissolution of dolomite. The development of high permeability fast pathways in this experiment highlights the role of carbonate content and potential fracture orientations in evaporite caprock formations considered for both geologic carbon sequestration and CO(2)-enhanced oil recovery operations.

Life-Cycle Analysis of CO2 EOR on EOR and Geological Storage through Economic Optimization and Sensitivity Analysis Using the Weyburn Unit as a Case Study

At the global, national, and subnational levels, many policies have been created or are in the process of development to deal with greenhouse gas (GHG) emissions, particularly CO2. CO2 enhanced oil recovery (EOR) is an option available to governments and industry to help meet emission reduction levels. In addition to increasing the production of oil, the CO2 can be stored in the oil reservoir for a very long period of time. However, CO2 capture and CO2 EOR operation result in significant costs and energy penalties, for example, CO2 capture from a point source, transportation to the site of use, and recycling produced CO2. This article evaluates the life cycle of CO2 storage from delivery to the oil field through the production, transportation, and refining of the oil and identifies opportunities for optimization. Information from the IEA GHG Weyburn Monitoring and Storage Project is used to provide baseline information for the storage of CO2. The value of this life-cycle study lies in the development of an understanding of the “carbon” economics of the EOR process and the impact on net storage of changes to the value of different components in the chain. These results provide a mechanism whereby environmental consequences can be evaluated within economic decision-making.