CO2-EOR Operation Research Articles

Dynamic PVT model for CO2-EOR black-oil simulations

A well-planned CO2EOR operation can help meet an ever-increasing need for energy and at the same time reduce the total CO2 footprint from the energy production. Good simulation studies are crucial for investment decisions where increased oil recovery is optimized and balanced with permanent CO2 storage. It is common to use a compositional simulator for CO2 injection to accurately calculate the PVT properties of the mixture of oil and CO2. Compositional simulations have significantly increased simulation time compared to blackoil simulations. Large simulation studies where many simulations are used either to represent uncertainty and/or optimize the results can thus be unpractical. On the other hand existing blackoil formulations often poorly represent the PVT properties of the oil-CO2 mixtures. We therefore present an extended blackoil formulation with dynamic blackoil properties that depends on the fraction of CO2 in the cell. These properties represents the density and viscosity of the hydrocarbon - CO2 mixture more accurately and thus give results closer to the compositional simulator. The dynamic blackoil functions are calculated from numerical slim-tube experiments based on one-dimensional equation-of-state (EOS) simulations. The same simulations also gives estimates of the minimum-miscibility pressure (MMP). We present examples based on data from the Fifth Comparative Solution Project: Evaluation of Miscible Flood Simulators, but uses CO2 as the injection gas. These examples shows that the new blackoil model gives results that are closer to compositional simulations compared to existing blackoil formulations. The model is implemented in the Flow simulator. The Flow simulator is developed as part of the open porous media (OPM) project and is an openly developed and free reservoir simulator that is capable of simulating industry relevant reservoir models with similar single and parallel performance as commercial simulators.

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.

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 Gate-to-Gate Life Cycle Assessment for the CO2-EOR Operations at Farnsworth Unit (FWU)

Greenhouse gas (GHG) emissions related to the Farnsworth Unit’s (FWU) carbon dioxide enhanced oil recovery (CO2-EOR) operations were accounted for through a gate-to-gate life cycle assessment (LCA) for a period of about 10 years, since start of injection to 2020, and predictions of 18 additional years of the CO2-EOR operation were made. The CO2 source for the FWU project has been 100% anthropogenically derived from the exhaust of an ethanol plant and a fertilizer plant. A cumulative amount of 5.25 × 106 tonnes of oil has been recovered through the injection of 1.64 × 106 tonnes of purchased CO2, of which 92% was stored during the 10-year period. An LCA analysis conducted on the various unit emissions of the FWU process yielded a net negative (positive storage) of 1.31 × 106 tonnes of CO2 equivalent, representing 79% of purchased CO2. An optimized 18-year forecasted analysis estimated 86% storage of the forecasted 3.21 × 106 tonnes of purchased CO2 with an equivalent 2.90 × 106 tonnes of crude oil produced by 2038. Major contributors to emissions were flaring/venting and energy usage for equipment. Improvements on the energy efficiency of equipment would reduce emissions further but this could be challenging. Improvement of injection capacity and elimination of venting/flaring or fugitive gas are methods more likely to be utilized for reducing net emissions and are the cases used for the optimized scenario in this work. This LCA illustrated the potential for the CO2-EOR operations in the FWU to store more CO2 with minimal emissions.

Relative Permeability: A Critical Parameter in Numerical Simulations of Multiphase Flow in Porous Media

Effective multiphase flow and transport simulations are a critical tool for screening, selection, and operation of geological CO2 storage sites. The relative permeability curve assumed for these simulations can introduce a large source of uncertainty. It significantly impacts forecasts of all aspects of the reservoir simulation, from CO2 trapping efficiency and phase behavior to volumes of oil, water, and gas produced. Careful consideration must be given to this relationship, so a primary goal of this study is to evaluate the impacts on CO2-EOR model forecasts of a wide range of relevant relative permeability curves, from near linear to highly curved. The Farnsworth Unit (FWU) is an active CO2-EOR operation in the Texas Panhandle and the location of our study site. The Morrow ‘B’ Sandstone, a clastic formation composed of medium to coarse sands, is the target storage formation. Results indicate that uncertainty in the relative permeability curve can impart a significant impact on model predictions. Therefore, selecting an appropriate relative permeability curve for the reservoir of interest is critical for CO2-EOR model design. If measured laboratory relative permeability data are not available, it must be considered as a significant source of uncertainty.

Preliminaries Study of Pilot Project Carbon Capture Utilization and Storage in An East Java Oil and Gas Field

A preliminary study for Carbon Capture Utilization and Storage (CCUS) pilot project in an East Java oil and gas field Indonesia has been conducted. CCUS projects have dual purposes: providing a means for increasing production in declined oil fields and reducing greenhouse gas emissions from oil and gas sector by injecting the separated CO2 into the declined oil and gas reservoir. CCUS will be attractive in Indonesia since it could offer additional income for the country from the incremental oil and gas productions and the implementation could use the existing regulations that valid for oil and gas sector. The study of a CCUS pilot project plan has been conducted in order to make sure that the reservoir is suitable for CO2 EOR storage. The CCUS pilot project plan is situated in an oil onshore field in East Java province, Indonesia, which was discovered in 2001. It is situated in the Tuban block, and has nearly 308 million STB of oil in place and more than 100 million barrels of oil in cumulative production. The chosen oil field for has been in production decline for several years and yet the efforts to increase recovery, such as water injection, have been ongoing. Suitability for a CO2-EOR operation is dependent on the petrophysical properties of the reservoir, such as porosity, permeability, and fluid saturation, as well as in-situ reservoir fluid properties such as oil density and viscosity. Reservoir depth is also a key parameter in making a decision as it will impact the miscibility and interaction between CO2 and oil phases. This CO2 EOR pilot project consists of a total of five wells – four production wells at the four corners of a square with an injection well in the middle. The preliminary design for a pilot scale is based on the available CO2 from the field itself, which currently produces 4.4 million SCF (240 tones) of CO2 per day. This pilot-scale test is aimed at examining the performance and viability of a gravity stable CO2 flood. The proposed CO2 injection volumes at the pilot scale are 5 million SCFD respectively, which are estimated to correspond to a production increase of 400 BOPD. For a gravity (gas cap) drive EOR system, the gas (in this case CO2) will be injected into the gas cap above the producing zone. This will help in driving the oil down to the production zones and into the production wells. When injecting into the gas cap, the wellbore integrity in the gas zone and just above the gas zone in the sealing layer must be evaluated. This is to ensure that the CO2 does not escape up the wellbore outside the casing and enter a higher layer. It is essential to include well integrity in the baseline monitoring program to evaluate periodic changes in the well integrity with injection. Monitoring is crucial for the success of a subsurface CO2 injection operation. CO2 injection monitoring is used to verify and compare the injection behaviour with reservoir simulation predictions as well as monitor for potential CO2 leakage through faults or wellbore and avoid any CO2 migration to and accumulation at the surface.

Integrated simulation system of CO2 gas injection application for enhanced oil recovery in the oil field

CO2 gas injection is one of the recommended enhanced oil recovery (EOR) methods by injecting CO2 through reservoir pores after the residual saturation is reached, since CO2 dissolves easily in oil phase as confirmed by many other researchers in pertaining field studies. An integrated system is urgently required for assessing CO2-EOR study, covering multi-disciplinary aspects as follows: geology, geophysics, reservoir, production, process and economic. Hence, those systems must be reliable in suggesting final decision for feasibility of CO2-EOR operation program, applicable either for pilot scale or for full scale. This paper is proposing an integrated system evaluation, which has the following features: (1) estimate fraction of dissolved CO2, (2) estimate viscosity reduction, (3) estimate future oil productivity index resulted, (4) forecast incremental oil production, (5) estimate surface facilities equipment design, (6) evaluate economical aspects and (7) generate final decision for feasibility of CO2-EOR operation program. Finally, as the main objective of this program, those systems will present a picture of essential reason why we need to promote or reject CO2-EOR plan program, and also some recommendations will be presented in case the CO2-EOR plan does not perform as expected.

Development of a passive sampling technique for offshore CO2 monitoring: Preliminary results from laboratory experiments

Monitoring of sequestered CO2 at storage sites is essential to provide assurance of long-term storage integrity. Thus, the objective of this study was to develop a sorbent-based offshore monitoring concept to monitor CO2 leakage during CO2-EOR operations. The study site, where the CO2-EOR operation is planned to be undertaken, is located in the pre-salt layer offshore Brazil. Perfluorocarbons (PFCs) were selected as tracers for monitoring possible CO2 leakage. A passive sampling technique was proposed to adsorb the injected tracer. Several commercially available sampler materials were initially chosen, among which Carboxen 569 placed inside a polyethersulphone (PES) membrane was tested and selected to be the preferred passive sampler combination. In order to perform tracer uptake rate experiments, a flow through experimental setup was built, optimized and tested under in-situ conditions of 300 bar and 15°C. In addition, a desorption unit was designed to quantify the tracer amount sorbed to the sampler during the experiments. The developed passive sampler combination proved to be successful in sorbing the tracers. The phase distribution of the tracer candidates in a CO2-water-oil system were investigated in a slimtube setup. It is shown that the PFCs have a shorter travel time through the system than CO2 and will potentially provide a warning of CO2 leakage from the reservoir.Although the developed technique successfully proved the proposed concept of monitoring CO2 leakage, further testing to investigate the life cycle of the sampler will be necessary to apply this technique at field scale.

Assessment of options for the development of a stacked storage complex in the Northern Michigan Basin, USA

The Northern Michigan Basin (NMB) Carbon Storage Assurance Facility Enterprise (CarbonSAFE) Integrated Pre-Feasibility Project is part of the U.S. Department of Energy’s (DOE) CarbonSAFE initiative. The objective of the NMB CarbonSAFE pre-feasibility project was to assess the feasibility of an integrated, commercial-scale carbon dioxide (CO2) storage complex in the NMB, which includes one or more deep saline geologic formations with sufficient capacity to permanently store at least 50 million metric tons of CO2 over a 20- to 30-year period. Subsurface injection of CO2 into depleted oil reservoirs for enhanced oil recovery (EOR) was also evaluated in the pre-feasibility study as an additional geologic storage mechanism because there are hundreds of depleted pinnacle reef reservoirs in the NMB, along with an established CO2-EOR operation, a feature that distinguishes this area from most other locations in the United States. Additionally, these reefs are co-located with the most favorable saline formations in the basin – the St. Peter sandstone and the Bass Islands dolomite – making stacked storage a real possibility. The study demonstrates that there are multiple locations in the northern Michigan study area that could support a commercial-scale storage complex with either saline storage or associated storage via CO2-EOR in the depleted pinnacle reefs alone (i.e., each storage mechanism has sufficient capacity alone) or via a combination of the two storage mechanisms. The term stacked storage refers to the concept of using both mechanisms together, in the same area, to achieve the required storage capacity. Key sites were identified in the northern part of the southern Michigan Peninsula that had sufficient geologic storage, nearby CO2 sources, a favorable social and economic setting, and a strong developed team.

Mechanical earth modeling and fault reactivation analysis for CO2-enhanced oil recovery in Gachsaran oil field, south-west of Iran

There is a huge potential for CO2-EOR and CO2 storage in depleted carbonate reservoirs in the south-west of Iran. In the first step of a CO2-EOR operation, a geomechanical assessment is needed to find out geological conditions, mechanical and strength properties of formation rocks (e.g., reservoir rock and caprock), in situ stress magnitudes and orientation and in situ pore pressure profile. An integrated analysis is performed in this work for geomechanical assessment of a reservoir–caprock system in Gachsaran oil field, south-west of Iran. A one-dimensional mechanical earth model (MEM) is built for 47 wells in the studied field based on drilling and logging data, laboratory and in situ tests. Static elastic and strength parameters of various formation rocks (limestone, dolomite, anhydrite, gray marl and salt) are evaluated from laboratory experiments. Empirical correlations are obtained to convert dynamic rock properties and well-log data to static elastic properties and strength parameters. The initial in situ pore pressure is calculated using modified Eaton method. In situ stresses state is evaluated based on the poroelastic method and calibrated using LOT and XLOT tests. The orientation of in situ stresses is obtained based on image logs. Fractures and faults analysis is performed to determine their orientations. An analytical analysis is performed to estimate the maximum sustainable CO2 injection pressure to prevent fault reactivation. This study presents a comprehensive method to reservoir and caprock characterization using laboratory and well-log data and 1D mechanical earth model. It helps the analysis of the geomechanical problems during CO2-EOR and provides the necessary information to build 3D geomechanical model for numerical simulations.

Assignment and calibration of relative permeability by hydrostratigraphic units for multiphase flow analysis, case study: CO2-EOR operations at the Farnsworth Unit, Texas

Among the most critical factors for geological CO2 storage site screening, selection, and operation is effective simulations of multiphase flow and transport. Relative permeability is probably the greatest source of potential uncertainty in multiphase flow simulation, second only to intrinsic permeability heterogeneity. The specific relative permeability relationship assigned greatly impacts forecasts of CO2 trapping mechanisms, phase behavior, and long-term plume movement. A primary goal of this study is to evaluate the impacts and implications of different methods of assigning relative permeability relationships for CO2-EOR model forecasts.Most simulation studies published in the literature base selection of relative permeability functions on the geologic formation or rock type alone. In this study, we initially implemented reservoir model grids with previously-identified hydrostratigraphic units based on porosity and permeability relationship of the Morrow ‘B’ Sandstone, then assigned relative permeability functions for those hydrostratigraphic units. Specific, constrained relative permeability relationships were created and assigned to each hydrostratigraphic unit using petrophysical data and Mercury Intrusion Capillary Pressure (MICP) measurements, from core samples of each hydrostratigraphic unit. Results of forward simulations with the newly-calibrated models will be compared to those of previous models as well as to simulation results for a range of different relative permeability relationships.The study site is the Farnsworth Unit (FWU) in the northeast Texas Panhandle, an active CO2-EOR operation. The target formation is the Morrow ‘B’ Sandstone, a clastic formation composed of medium to course sands.

Crediting Carbon Dioxide Storage Associated with Enhanced Oil Recovery

What must be done to get credit for the quantities of carbon dioxide unavoidably stored in association with carbon dioxide enhanced oil recovery (CO2-EOR)? This presentation will explore that question with particular emphasis on several recent developments occurring in December 2015 that will directly affect the answers to that question in the context of the United States Environmental Protection Agency's (EPA's) regulatory scheme for controlling greenhouse gas (GHG) emissions. In 2015 EPA finalized a foundational regulatory framework for controlling GHG emissions from both new and existing fossil-fuelled electric utility generating units. In doing so, EPA conditioned the use of CCS on quantifying stored carbon dioxide through reporting under subpart RR of the part 98 GHG reporting requirements, the reporting approach developed primarily for geological sequestration in saline formations. And subpart RR reporting would be required regardless of whether carbon dioxide storage is achieved through geologic sequestration or in association with carbon dioxide enhanced oil recovery (CO2-EOR). Numerous concerns were raised in comments on the proposed rules and in response to the final rules about the ability for EOR operations to comply with the reporting requirements of subpart RR, and from 2010 until 2015 no one reported under subpart RR because all of the projects injecting carbon dioxide into saline formations had qualified for research exemptions, and no EOR operations had voluntarily opted to report under subpart RR rather than under subparts W and UU.As 2015 came to a close, efforts were launched to get EPA to show that the hurdles to quantifying and reporting for carbon dioxide stored in association with CO2 EOR can be surmounted or to remove those hurdles. On December 22, 2015 EPA approved the first ever use of subpart RR reporting for a CO2-EOR operation by approving a monitoring, reporting and verification (MRV) plan submitted by Occidental Petroleum for the Denver Unit in the Permian Basin of West Texas. In so doing, EPA provided some clarity about how a number of concerns and uncertainties surrounding the use of subpart RR reporting for storage associated with CO2-EOR, and the decision indicates significant flexibility to adapt parts of subpart RR requirements to a substantially different context than saline formation geologic storage. Yet other questions that have been raised remain unanswered in any direct way. And these uncertainties may bar the way to effective implementation of EPA's requirements for existing electric utility generating units. EPA is being called upon to show how the reporting can be achieved without disrupting the EOR operations through clarifications, guidance, policy revisions, or decisions or, alternatively, to remove the hurdles through regulatory actions.This presentation will explain the significant developments in reporting and in regulatory petitions that occurred at the end of 2015 and assess how this affects the viability of CCUS that relies on storage associated with CO2-EOR. It will also survey the potential effects of other developments in the implementation of other CO2 storage quantification and reporting regimes at the subnational, national and international levels in comparison with the requirements being implemented by EPA at the federal level.

Best Practice for Transitioning from Carbon Dioxide (CO2) Enhanced Oil Recovery EOR to CO2 Storage

The purpose of Carbon Capture and Storage (CCS) is to reduce emissions of greenhouse gases to the atmosphere as a climate change mitigation activity. However, given the relatively high costs currently associated with CCS, coupling CCS with Enhanced Oil Recovery (EOR) could provide a critical financial incentive to facilitate development of CCS projects in the near term. One issue is that projects to enhance oil production are primarily implemented to increase oil production with (tertiary recovery methods and any long term storage of CO2 is considered a potential ancillary benefit. When projects are designed as CCS from the start, there is typically a site evaluation process to review the storage formation according to best practice criteria for CCS. In EOR, the formation where CO2 would be stored is predetermined by the existing oil bearing reservoir, raising potential questions about monitoring, long-term CO2 storage liabilities, potential, leakage, permanence and other issues that must be addressed in CCS projects but may fall outside the boundaries of a typical EOR project. Finally, although this paper is premised on historical and current experiences with enhanced oil recovery projects, similar considerations could also be given to enhanced recovery of natural gas.There are no specific technological barriers or challenges in transitioning and converting a pure CO2-EOR operation into a CO2 storage operation but there are a number of legal, regulatory and economic differences which must be addressed if an EOR project is to serve as a CCS project. Lack of experience or unresolved issues related to EOR becoming CCS could create barriers unless the issues are fully understood and managed to the satisfaction of regulators. Understanding best practice and the policy and regulatory frameworks affecting CCS from EOR is an important driver for ensuring that CO2-EOR projects are developed in a manner which will enable the carbon stored to be recognised as a mitigation activity under local legislation/carbon market schemes and in national GHG inventories which support monitoring progress under the COP21 Paris Agreement.The paper provides an overview of the key issues in the USA, Canada, EU, Australia, and Brazil and provides recommendations for what companies need to do should they wish to transition from EOR to CCS for existing or future operations.

Monitoring technology ranking methodology for CO2-EOR sites using the Weyburn-Midale Field as a case study

In a carbon dioxide (CO2) enhanced oil recovery (EOR) operation, CO2 is injected into a hydrocarbon reservoir to enhance hydrocarbon production. Much of this CO2 is recycled for reinjection when the hydrocarbons are produced; however, a large amount is permanently stored in the reservoir. If a CO2-EOR operation intends to claim CO2 storage credit for this stored CO2, it needs to demonstrate that the CO2 is safely stored in the subsurface by strategically deploying monitoring technologies. For the operation to maintain profitability goals, these monitoring technologies also need to be cost-effective. If the safety of the CO2 storage is demonstrated, the project will be classified a carbon capture, utilization, and storage (CCUS) project.The main goal of CO2-EOR is oil production, not CO2 storage. Because CO2-EOR originated as an oil production technique, the EOR process is subject to a less stringent regulatory environment than CCUS projects. These differences in the CO2 storage accounting and the regulatory environment mean that CO2-EOR projects need to demonstrate the long-term containment of CO2 within the reservoir with additional monitoring in order to claim any CO2 emission credits. Converting a CO2-EOR project to a CCUS project requires a tailored site-specific approach. The methodology employed will differ from project to project due to differences in project risk, geology, operations history, and regulatory environment.This paper takes the CO2-EOR Weyburn-Midale Field (WMF) as a case study to rank monitoring strategies that may be required to shift the WMF from CO2-EOR to CCUS. This study consisted of an in-depth review of the identified risks, the potential leakage pathways, various regulatory requirements, and the already deployed monitoring techniques. The goal was to develop a risk-, economic-, and regulatory-based monitoring technology ranking system that is suitable for the WMF. While specific to the WMF, the methodology presented here can be adapted by other CO2-EOR operators who endeavor to demonstrate that the non-recycled portion of the CO2 injected into the formation(s) by their project(s) is permanently stored.

Sensitivity analysis for fault reactivation in potential CO2-EOR site with multi-layers of permeable and impermeable formations

CO2-EOR is considered as a promising solution for enhanced oil recovery (EOR) and is attracting attention as being a more economical CO2 geological sequestration solution along with oil recovery enhancement. However, injecting CO2 at high pressure may cause many geomechanical changes and potential instabilities in surrounding formation such as ground uplift, caprock fracturing, and nearby fault reactivation. Such instabilities could significantly influence the stability of both surface facilities and subsurface structures. Especially, miscible CO2-EOR, by which recovers more oil than immiscible one but, uses less CO2, requires an injection pressure exceeding the minimum miscible pressure (MMP), which is determined by characteristics of reservoir conditions and oil compositions. Thus, for successful and safe CO2-EOR operation, injection pressure interval between MMP and the maximum pressure that could be tolerated from geomechanics safety concerns should be appropriately designed considering site-specific reservoir conditions. In this study, we perform a numerical simulation of coupled multiphase fluid flow and geomechanical analysis using TOUGH-FLAC simulator for the potential CO2-EOR site in Indonesian oil field, and demonstrate how much fault reactivation is sensitive to fault structure, slip-weakening property of faults, reservoir permeability, and in situ stress conditions. The model site consists of impermeable shale and permeable sandstone reservoir units so that the potential for fault slip through this multilayered formation is highlighted in the simulations. Our simulation results showed that fault slip initiation can be reached earlier period when in situ stress is anisotropic and reservoir is more permeable, because the stress state at the faults is near the frictional strength limit and the pore pressure buildup reaches to the fault much faster. The analysis shows that multilayered formations with high- and low-permeability layers are advantageous in CO2-EOR since intense pore pressure buildup and subsequent fault reactivation could be impeded by pressure dissipation in high-permeability layers. However, we noted that fault reactivation may become substantial when the fault has a slip-weakening property and the residual frictional coefficient of the site-specific fault is very low.

Monitoring the Safety of CO2 Sequestration in Jingbian Field, China

The first CCS-EOR (Enhanced Oil Recovery) pilot project in Shaanxi Province of China is being conducted. Although there are still many technical obstacles need to be solved, the major concern with this CCS (Carbon Capture and Sequestration) project is the risks of CO2 leaking from the subsurface storage site. While the industry worries about the efficiency of CO2-EOR in such low porosity and ultra- low permeability reservoir. In the present work, we assess the potential risks as well as reservoir properties in CO2 geological storage site in Jingbian Field, North of Shaanxi. We design a comprehensive monitoring system, which covers geophysical, geological and surface environmental monitoring, in order to detect plume behaviour and leakage of CO2 during different stages of CO2 sequestration. The study of monitoring data and CO2-EOR operation in Jingbian CCS pilot project will increase our understanding of underground process during CO2 injection and after site closure in Ordos Basin.

The CO2-EOR sequestration equation: recovery, dynamic monitoring, and co-optimization

Industry has recognized the usefulness of injecting CO2 in geological formations for the past fifty years. The aim of this injection has not been for sequestration/storage, but to displace/dissolve oil, enhancing oil production (EOR). Though a lot of the injected CO2 remains trapped in an oil reservoir, the majority of the floods cannot be considered sequestration/storage projects since the CO2 source is another geological formation. The CO2-EOR operation aims at recovering the maximum amount of oil while consuming the minimum amount of CO2. The sequestration goal is to store the maximum amount of CO2 and to guarantee that it is safely stored.