Enhanced Oil Recovery Storage Research Articles

Experimental Investigation on the CO2 Effective Distance and CO2-EOR Storage for Tight Oil Reservoir

CO2 underground storage is an important approach to reduce carbon emissions; meanwhile, the combination of CO2 storage and economic benefits can further promote the long-term development of carbon neutrality. Global tight oil reserves are abundant, but the depletion development of most tight reservoirs is unsatisfactory. Therefore, it is crucial to utilize CO2 storage combined with enhanced oil recovery (EOR) for tight reservoir development. At present, there are few experimental studies on the CO2 effective distance and CO2-EOR storage of huff-n-puff in tight reservoirs. In this paper, the CO2 effective distance and the evolution of saturation profiles in tight cores are first investigated, and CO2-EOR storage is quantitatively evaluated for CO2 huff-n-puff in tight reservoirs based on CT and nuclear magnetic resonance technology. Meanwhile, the influences of oil composition and permeability on the effective distance and CO2-EOR storage are further investigated. The results indicate that the increase of CO2 effective distance gradually slows down with time, and the decrease of permeability significantly reduces the effective distance. Increasing amount of oil is mainly produced in larger pores, which is more than twice of that in smaller pores. CO2-EOR storage experiments quantify that the CO2 storage ratio for a 0.22 × 10–3 μm2 core is up to 72.31% under different depressurization conditions (12, 8, and 0.1 MPa). With the decrease in production pressure, oil recovery gradually increases, while the CO2 storage ratio decreases, indicating that there is a collaborative optimization to maximize the oil production and CO2 storage ratio. Comparison experiments reveal that the oil composition (replaced by fluorocarbon oil) has little influence on the effective distance and CO2-EOR storage, while the influence of permeability is significant. The CO2 effective distance determines the sweep efficiency, so increasing effective distance is essential to enhance oil recovery and CO2 storage. This research is of great significance for CO2 utilization and CO2 storage in tight reservoirs.

A technical turning point-based framework to optimize CO2 EOR-storage: Capacity dynamics of Brownfield Residual Oil Zones

Residual Oil Zones (ROZs) contains considerable oil at residual saturation underlying Main Pay Zones (MPZs), which renders its development challenging in conventional manner. Enhanced oil recovery (EOR), for example, CO2 injection is therefore introduced. This technique unleashes the potentials of ROZs in terms of EOR and carbon storage. In field-scale simulation regard, although some researchers have investigated the effects of several operational variables such as well pattern, perforation interval, injection mode and injection strategy, on CO2 EOR-storage performances, no published work attempts to reveal the EOR-storage capacity dynamics/variations of Brownfield ROZ reservoir upon its development. By addressing the questions: (1) when to start considering ROZ expansion beyond MPZ; (2) the timing when to perform ROZ expansion that could maximize the profit; (3) whether ROZ expansion always benefits the project; (4) what development strategy is more favorable given a certain CO2 availability, this paper reveals the incentives of when to include ROZ into CO2 EOR-storage project beyond MPZ in development strategy regard. Based on the envisioned technical turning point where ROZ outperforms MPZ assuming propensity to oil production, novel performance metrics—ROZ oil production critical point (ROZ-OPCP) and ROZ opportune oil production trade-off point (ROZ-OOPTP), are brought up to technically optimize the development strategy design of Brownfield ROZ reservoir, upon which a resultant designing framework is established. The concepts and framework are envisioned to facilitate development strategy configurations, narrow down the target range for optimization, reduce the cost of trial-and-error and therefore promote the Carbon Capture and Storage (CCS). Simulation study also provides following insights on CO2 EOR-storage in Brownfield ROZ reservoir: (1) above ROZ-OPCP, the development of ROZ beyond MPZ is technically feasible under moderate and sufficient CO2 supply case since positive surpluses in EOR-storage are observed. Project could benefit most from sequential and simultaneous MPZ-ROZ development under moderate and sufficient CO2 supply case, respectively; (2) ROZ expansion without considerable CO2 availability and opportune timing could technically and economically impair the project, and ROZ-OOPTP needs to be considered herein; (3) Designing CO2 injection scenarios requires compromises. e.g., Higher injection rate in ROZ increases CO2 storage and brings forward the peak EOR-storage performance, while the lower injection rate prolongs the desirable EOR-storage performance; (4) The envisioned technical turning point and the CO2 EOR-storage capacity dynamics may strongly depend on original quality of ROZ and the current usage of MPZ, and less usage would lead to later occurrence of technical turning point.

Potential of Russian Regions to Implement CO2-Enhanced Oil Recovery

The paper assesses the techno-economic potential of Russia to implement carbon capture and storage technologies that imply the capture of anthropogenic CO2 and its injection into geologic reservoirs for long-term storage. The focus is on CO2 enhanced oil recovery projects that seem to be the most economically promising option of carbon capture and storage. The novelty of the work lies in the formulation of a potential assessment method of CO2 enhanced oil recovery, which allows for establishing a connection between energy production and oil extraction from the viewpoint of CO2 supply and demand. Using linear optimization, the most promising combinations of CO2 sources and sinks are identified and an economic evaluation of these projects is carried out. Based on this information, regions of Russia are ranked according to their prospects in regards to CO2 capture and enhanced oil recovery storage. The results indicate that Russia has a significant potential to utilize its power plants as CO2 sources for enhanced oil recovery projects. It has been estimated that 71 coal-fired power plants, and 185 of the gas-fired power plants of Russia annually produce 297.1 and 309.6 Mt of CO2 that can cover 553.4 Mt of the demand of 322 Russian oil fields. At the same time, the total CO2 storage capacity of the Russian fields is estimated at 7382.6 Mt, however, due to geological and technical factors, only 22.6% can be used for CO2-EOR projects. Of the 183 potential projects identified in the regional analysis phase, 99 were found to be cost-effective, with an average unit cost of € 19.07 per ton of CO2 and a payback period of 8.71 years. The most promising of the estimated regions is characterized by a well-developed energy industry, relatively low transportation costs, numerous large and medium-sized oil fields at the final stages of development, and favorable geological conditions that minimize the cost of injection. Geographically, they are located in the North-Western, Volga, and Ural Federal districts.

Cost-effective balance between CO2 vessel and pipeline transport: Part II – Design of multimodal CO2 transport: The case of the West Mediterranean region

As part of large scale application of CO2 capture and storage, million tons CO2 per year have to be transported by pipelines and/or vessels from capture to storage sites. In previous studies, costs of, pipeline systems and point-to-point vessel connections have been estimated. In this research, these cost analysis are supplemented by adding a transport system combining vessel and pipeline transport. The cost savings potential of this multimodal CO2 transport system has been analyzed for the West Mediterranean region (i.e. Spain, Portugal, and Morocco) – where vessel transport can play an important role. In detail: A multimodal extended adaption of a pipeline system optimization model has been defined and was then parameterized adapting a nonlinear vessel and pipeline transport cost model. Next, cost savings due to vessel transport were quantified for the West Mediterranean region. When CO2 emissions are stored in the region itself, cost could be lowered by up to 20% on routes with low transport volumes and in a complementary way by a redirection of flows at the expense of longer transport distances to prevent costly offshore storage. In case of a European CO2 transport infrastructure including North Sea storage, transport of CO2 by vessel could be profitable if CO2 is used for enhanced oil recovery (EOR). However, North Sea neighboring countries can be expected to crowd out Iberian CO2 of the market for EOR storage volumes.

Quick-look assessments to identify optimal CO2 EOR storage sites

A newly developed, multistage quick-look methodology allows for the efficient screening of an unmanageably large number of reservoirs to generate a workable set of sites that closely match the requirements for optimal CO2 enhanced oil recovery (EOR) storage. The objective of the study is to quickly identify miscible CO2 EOR candidates in areas that contain thousands of reservoirs and to estimate additional oil recovery and sequestration capacities of selected top options through dimensionless modeling and reservoir characterization. Quick-look assessments indicate that the CO2 EOR resource potential along the US Gulf Coast is 4.7 billion barrels, and CO2 sequestration capacity is 2.6 billion metric tons. In the first stage, oil reservoirs are screened and ranked in terms of technical and practical feasibility for miscible CO2 EOR. The second stage provides quick estimates of CO2 EOR potential and sequestration capacities. In the third stage, a dimensionless group model is applied to a selected set of sites to improve the estimates of oil recovery and storage potential using appropriate inputs for rock and fluid properties, disregarding reservoir architecture and sweep design. The fourth stage validates and refines the results by simulating flow in a model that describes the internal architecture and fluid distribution in the reservoir. The stated approach both saves time and allows more resources to be applied to the best candidate sites.