CO2 Injection For Enhanced Oil Recovery Research Articles

Physical-informed deep learning framework for CO[formula omitted]-injected EOR compositional simulation

CO2 injection for enhanced oil recovery (CO2-EOR) is one of the industry’s most widely applied techniques for CO2 utilization. People use the compositional simulation technique to clearly describe CO2 injection processes for EOR, which is always computational-expensive. The main objective of this study is to utilize deep learning (DL) techniques to describe phase behaviors and accelerate compositional simulations. First, we constructed a new DL-based compositional simulation framework. Instead of solving equations of state for every grid cell, this framework can aggregate millions of phase behavior solvers and determine all mixtures’ phase status in one single round of calculation. This trait can significantly improve the efficiency of solving numerical equations. Next, we illustrated how to develop DL-based phase behavior models to determine phase status accurately. Our newly proposed single-phase identification model can resolve the difficulty in inaccurate single-phase labeling within compositional simulations, greatly benefiting the numerical convergence of simulation. Finally, we tested abundant complicated cases covering near-miscible and miscible gas injection processes and demonstrated the new DL-based method’s strength in accelerating the compositional simulation. Besides, we also presented the DL-based method’s more substantial power in numerical convergences that it could succeed in cases where the standard simulation method fails. This work can contribute to more efficiently and effectively describing complex fluid displacement processes, benefiting CO2 injection EOR and other utilizations like CO2 sequestrations.

Case Study: Mature Wells Given New, Carbon-Storage Purpose With Subsurface Data

To ensure success in exploration and production activities, oil and gas companies rely on subsurface data to gain insights that guide operational decisions over the life of their wells. But as wells near the end of their lives and production slows or stops, wells are subsequently shut and abandoned, and the accompanying subsurface data are set aside. However, these data still hold tremendous value when it comes to evaluating mature, near-end-of-life wells and fields to determine if they are suitable candidates for carbon capture, utilization, and storage (CCUS). Reusing wells and fields for CO2 injection provides an opportunity to reduce the time and cost for developing new CCUS infrastructure required by energy mix diversification efforts while avoiding the steep expenses commonly associated with decommissioning. In most cases, when the production cycle ends and all usable hydrocarbons have been extracted, the topside facilities are dismantled, the wellbore is permanently plugged and abandoned, and the surrounding land or seabed is returned to its natural condition. Historically, this complex, multistep process has been a cost center for oil and gas businesses, requiring monumental investment that grows even higher for offshore and deepwater fields. However, now that the CCUS industry is aggressively expanding, operators are presented with the possibility of turning decommissioned wells into a profit center by selling CO2 storage capacity to others. CO2 storage is a crucial component of the CCUS value chain as permanently storing CO2 is the cornerstone of large-scale emissions reductions. The storage process entails capturing, compressing, and injecting CO2 into a reservoir of porous rock beneath an impermeable layer of caprock, which functions as a seal. The caprock prevents the CO2 from reaching the surface, as do other trapping mechanisms including structural, residual, solubility, and mineral trapping. As a result, CO2 is safely stored in geological formations. This is similar to the unexplored state of oil and gas reserves trapped underground for millions of years. Carbon-storage processes are not a new concept in the oil and gas industry. As part of normal well operations, operators routinely perform the CO2 injection enhanced oil recovery (EOR) technique. If CO2 returns to the surface and is separated and then reinjected to form a closed loop when utilizing this EOR method, this results in permanent CO2 storage, which strongly supports the viability for repurposing mature decommissioned wells. In response to growing interest in CCUS and governments worldwide committing to reach a net-zero target for CO2 emissions in the coming decades, a consortium of 20 organizations including research institutions, operators, and regulatory authorities joined together to create REX-CO2 (ReUsing Existing Wells for CO2 Capture and Storage). As part of the REX-CO2 consortium, Ikon Science collaborated with the British Geological Survey (BGS) in the phases of a study that evaluated the potential for well reuse in the UK Continental Shelf (UKCS). It’s forecast that 1,211 wells across 230 fields will be decommissioned through 2028 in the UKCS to the tune of $60 billion, according to Britain’s Oil & Gas Authority’s 2021 Decommissioning Cost Estimate report.

The Effects of Co2 Injection Amount and Formation of In-Situ New Phase on Oil Phase Behavior During Co2 Injection Enhanced Oil Recovery (Eor) in Tight Oil Reservoirs

The Effects of Co2 Injection Amount and Formation of In-Situ New Phase on Oil Phase Behavior During Co2 Injection Enhanced Oil Recovery (Eor) in Tight Oil Reservoirs

Identification of a Minimum Dataset for CO2-EOR Monitoring at Weyburn, Canada

CO2 leakage at geological carbon storage (GCS) sites, driven by increased system pressure and higher CO2 saturations, represents a major risk to secure containment of injected CO2. For long-term GCS monitoring, it is critical to determine a level of material information needed to minimize leakage risks while keeping costs under control. This study demonstrates a goal-oriented, retrospective design concept called minimum data set requirement (MDR) for the Weyburn-Midale Project (WMP), a commercial-scale, CO2-injection enhanced oil recovery site in Canada that has been extensively characterized for R & D purposes. More than a decade of research at the WMP site has led to an extensive collection of site characterization data (thousands of wells with geophysical logs and cores, seismic surveys), a situation that is unlikely to be true for many other GCS projects around the world. The main purpose of this study is to perform a retrospective design of the WMP to identify the MDR. By screening existing data retrospectively, our MDR identification process seeks to establish a level of data needed to define a sufficient reservoir model for guiding post-EOR monitoring, under user-defined performance metrics. Our starting point is an existing history-matched WMP reservoir model and three datasets consisting of logs from hundreds of wells and seismic survey.An iterative Monte Carlos approach is taken here to systematically and gradually reduce the level of information used in parameterizing a geological model, from which conditional stochastic realizations of model properties are generated and simplified reservoir models are developed. Results show that (a) the minimum dataset for predicting CO2 migration depends on the heterogeneity and anisotropy of selected parameters of the field, (b) parameterization scheme for data reduction should be flexible and also objective oriented and problem dependent, and (c) for the Phase 1A area of the Weyburn field about 80% out of the 403 wells can be eliminated without having detrimental impact on the simulated pressure field.

Identification of a representative dataset for long-term monitoring at the Weyburn CO2-injection enhanced oil recovery site, Saskatchewan, Canada

Leakage at geological carbon storage (GCS) sites, driven by increased system pressure and higher CO2 saturations, represents a key risk to secure containment of injected CO2. For long-term GCS monitoring, it is critical to determine a level of information needed to minimize leakage risks while keeping costs under control. This study demonstrates a goal-oriented, retrospective design concept called minimum data set requirement (MDR) for Weyburn Midale Project (WMP), a commercial-scale, CO2-injection enhanced oil recovery (EOR) site in Canada. More than a decade of research at the WMP site has led to an extensive collection of site characterization data, a situation that is unlikely to be true for many other GCS projects around the world. By screening existing data retrospectively, our MDR identification process seeks to establish a level of data needed to define a sufficient reservoir model for guiding post-EOR monitoring, under user-defined performance metrics. Our starting point is an existing history-matched WMP reservoir model and three datasets consisting of logs from hundreds of wells and a seismic survey. An iterative approach is taken to systematically and gradually reduce the level of information used in parameterizing a geological model, from which conditional stochastic realizations of model properties are generated and simplified reservoir models are developed. Results show that the minimum dataset for predicting CO2 migration is based on the heterogeneity and anisotropy of selected parameters of the field. For WMP, about 80% of the 403 wells can be eliminated without having a detrimental impact on the simulated pressure field.

06/00439 MOnitoring of fluid-rock interaction and CO 2storage through produced fluid sampling at the Weyburn CO 2-injection enhanced oil recovery site, Saskatchewan, Canada : Emberley, S. et al. Applied Geochemistry, 2005, 20, (6), 1131–1157

06/00439 MOnitoring of fluid-rock interaction and CO 2storage through produced fluid sampling at the Weyburn CO 2-injection enhanced oil recovery site, Saskatchewan, Canada : Emberley, S. et al. Applied Geochemistry, 2005, 20, (6), 1131–1157

Monitoring of fluid–rock interaction and CO 2 storage through produced fluid sampling at the Weyburn CO 2-injection enhanced oil recovery site, Saskatchewan, Canada

The Weyburn Oil Field is a carbonate reservoir in south central Saskatchewan, Canada and is the site of a large CO 2 injection project for purposes of enhanced oil recovery. The Weyburn Field, in the Mississippian Midale Formation, was discovered in 1954 and was under primary production until secondary recovery by water flood began in 1964. The reservoir comprises two units, the Vuggy and the Marly, and primary and secondary recovery are thought to only have significantly depleted the Vuggy zone, leaving the Marly with higher oil saturations. In 2000, PanCanadian Resources (now EnCana), the operator of the field, began tertiary recovery by injection of CO 2 and water, primarily into the Marly. The advent of this project was an opportunity to study the potential for geological storage of CO 2. Using 43 Baseline samples collected in August 2000, before CO 2 injection at Weyburn, and 44 monitoring samples collected in March 2001, changes in the fluid chemistry and isotope composition have been tracked. The initial fluid distribution showed water from discovery through water flood in the Midale Formation with Cl ranging from 25,000 to 60,000 mg/L, from the NW to the SE across the Phase 1A area. By the time of Baseline sampling the produced water had been diluted to Cl of 25,000–50,000 mg/L as a result of the addition of make up water from the low TDS Blairmore Formation, but the pattern of distribution was still present. The Cl distribution is mimicked by the distribution of other dissolved ions and variables, with Ca (1250–1500 mg/L) and NH 3 (aq) increasing from NW to SE, and alkalinity (700–300 mg/L), resistivity, and H 2S (300–100 mg/L) decreasing. Based on chemical and isotopic data, the H 2S is interpreted to result from bacterial SO 4 reduction. After 6 months of injection of CO 2, the general patterns are changed very little, except that the pH has decreased by 0.5 units and alkalinity has increased, with values over 1400 mg/L in the NW, decreasing to 500 mg/L in the SE. Calcium has increased to range from 1250 to 1750 mg/L, but the pattern of NW–SE distribution is altered. Chemical and isotopic data suggest this change in distribution is caused by the dissolution of calcite due to water–rock reactions driven by CO 2. The Baseline samples varied from −22 to −12‰ δ 13C (V-PDB) for CO 2 gas. The injected CO 2 has an isotope ratio of −20‰. The Monitor-1 samples of produced CO 2 ranged from −18 to −13‰, requiring a heavy source of C, most easily attributed to dissolution of carbonate minerals. Field measured pH had increased and alkalinity had decreased by the second monitoring trip (July 2001) to near Baseline values, suggesting continued reaction with reservoir minerals. Addition of CO 2 to water–rock mixtures comprising carbonate minerals causes dissolution of carbonates and production of alkalinity. Geochemical modeling suggests dissolution is taking place, however more detail on water–oil–gas ratios needs to be gathered to obtain more accurate estimates of pH at the formation level. Geological storage of CO 2 relies on the potential that, over the longer term, silicate minerals will buffer the pH, causing any added CO 2 to be precipitated as calcite. Some initial modeling of water–rock reactions suggests that silica sources are available to the water resident in the Midale Formation, and that clay minerals may well be capable of acting as pH buffers, allowing injected CO 2 to be stored as carbonate minerals. Further work is underway to document the mineralogy of the Midale Formation and associated units so as to define more accurately the potential for geological storage.

Geochemical monitoring of fluid-rock interaction and CO 2 storage at the Weyburn CO 2-injection enhanced oil recovery site, Saskatchewan, Canada

The Weyburn Oil Field, Saskatchewan is the site of a large (5000 tonnes/day of CO 2) CO 2-EOR injection project By EnCana Corporation. Pre- and post-injection samples (Baseline and Monitor-1, respectively) of produced fluids from approximately 45 vertical wells were taken and chemically analyzed to determine changes in the fluid chemistry and isotope composition between August 2000 and March 2001. After 6 months of CO 2 injection, geochemical parameters including pH, [HCO 3], [Ca], [Mg], and δ 13CO 2(g) point to areas in which injected CO 2 dissolution and reservoir carbonate mineral dissolution have occurred. Pre-injection fluid compositions suggest that the reservoir brine in the injection area may be capable of storing as much as 100 million tonnes of dissolved CO 2. Modeling of water-rock reactions show that clay minerals and feldspar, although volumetrically insignificant, may be capable of acting as pH buffers, allowing injected CO 2 to be stored as bicarbonate in the formation water or as newly precipitated carbonate minerals, given favorable reaction kinetics.