Inexpensive Assessment of Plume Migration During CO2 Sequestration

The Plains CO2 Reduction (PCOR) Partnership, through the Energy & Environmental Research Center (EERC), continues to support the Petroleum Technology Research Centre (PTRC) Aquistore project. This support has been in the form of geologic characterization; involvement in the Science, Engineering, and Research Committee (SERC); involvement in public outreach; developing geologic models; and running predictive simulations on the expect injection program at the site. The Aquistore project is part of the world’s first commercial postcombustion carbon capture, utilization, and storage project from a coal-fired power-generating facility, the SaskPower Boundary Dam, located in Saskatchewan, Canada, and acts as a storage site for a portion of the captured CO2 from the Boundary Dam power plant. The Aquistore site includes one injection well and a 152-meter offset observation well. Both wells were drilled and completed in the Deadwood and Black Island Formations. Injection at the Aquistore site was initiated in April 2015; at the time of this report, the daily injection rate ranged from approximately 300 to 500 tonnes per day. To better understand the storage implications of injecting carbon dioxide (CO2), history-match field pressure response, and predict CO2 plume evolution at the Aquistore site, the EERC has constructed a simplified simulation model based on reservoir physical properties obtained from previous mean probability (P50) static geologic model realization. Simulations have been conducted utilizing this model to better understand both operational and geologic uncertainties that may exist at the Aquistore site. The simulations are an update to those completed in the previous update of the original report entitled Geologic Modeling and Simulation Report for the Aquistore Project, Deliverable (D) 93, approved in 2014. In this update, a regional-scale model extends beyond the 34-square-kilometer PTRC 3-D seismic survey area. A local grid refinement (LGR) system near both the injection and observation wells was introduced for the history-matching and uncertainty analysis. Spinner log survey and pressure test data provided by partners were used and evaluated to adjust the near-wellbore local permeability in order to history-match the field pressure data. As of January 9, 2016, approximately 24,000 tonnes of CO2 has been injected during a series of relatively short operating periods. However, the injection rate during these short operating periods increased near the end of year 2015 to a level of 300 to 500 tonnes per day, based on the quantity of CO2 made available from the pipeline. The two wells have been closely monitored, and history matching was performed while reconciling rate, pressure, temperature, variations in injectivity, and injection flow. The current data set is well replicated by the simulation. However, CO2 breakthrough at the observation well has not yet been observed, and geophysical imaging of the CO2 plume has not yet been attempted. Thus important performance confirmations remain to be made, and additional reporting of project performance will be appropriate in the future. A new set of injection forecasts is presented, with some cases directly comparable to the previously published, pre-history match results.

Large Volume CO2 Storage and Plume Management in the Southeastern U.S.; Reservoir Characterization and Simulation

CO2 sequestration is considered one of the main pillars in achieving the ongoing decarbonization efforts. A myriad of CO2 sequestration projects targeted sandstone reservoirs since carbonate reservoirs appeared to be unpropitious due to their geological complexity and unfavorable mineralogy and properties. This study investigates CO2 sequestration potential in a carbonate saline aquifer while considering various geological complexities by capitalizing on numerical simulation. A synthetic anticline reservoir model examined the optimum well location and landing zone for CO2 sequestration. Additionally, the model evaluated the role of natural fractures in the migration path of CO2 plume and geochemical reactions throughout the storage process. The study demonstrates that placing the injection well away from the top of the structure in a low-dip region while injecting in the bottom interval would yield the optimum design. After applying a plethora of analyses, geological complexity could impede the migration path of CO2 but eventually produce a similar path when injected in a similar region. The geochemical interactions between the injected CO2 and reservoir fluids and minerals reduce the free and trapped CO2 quantities by dissolving calcite and precipitating dolomite. Furthermore, natural fractures impact the CO2 quantities during early times only when the fractures cross the top layers. Similarly, the CO2 migration differs due to the higher permeability within the fractures, resulting in slightly different CO2 plumes. Consequently, the role of natural fractures should be limited in carbon storage projects, specifically if they do not cross the top of the reservoir. This study reflects a unique perspective on sequestering CO2 while capturing the roles of natural fractures and well placement in depicting the migration path of the CO2 plume. A similar systematic workflow and holistic approach can be utilized to optimize the subsurface storage process for potential formations.

Fundamental understanding and application of process parameters in numerical simulation that leads to optimized gravity drainage oil recovery at field scale is still a major challenge. Reservoir simulations studying the effects of well patterns and type of gas injection wells have not been reported so far. In first ever attempt, the mechanistic benefits of production strategy on gravity drainage oil recovery are identified in this paper. Effects of irregular and regular well patterns and vertical and horizontal gas injection wells are investigated using a fully compositional 3D reservoir model in both the secondary immiscible and miscible modes under the conditions of voidage balance, constant injection and production pressure and injection rates below the critical rate. Regular well pattern provided longer oil production time at a constant rate until CO2 breakthrough compared to irregular well pattern. It then dropped almost vertically at the same cumulative oil recovery even at higher production rates. However, gravity drainage oil recovery was higher at higher rate combination after CO2 breakthrough. Results also suggested that the regular pattern could result in horizontal CO2 floodfront parallel to the horizontal producers, maintaining reservoir pressure, thus optimizing the oil recovery by additional 2.5% OOIP. Vertical injection and horizontal production wells in both the immiscible and miscible modes provided nearly identical cumulative gravity drainage oil recovery compared to the combination of horizontal injection and production wells in the regular well pattern. This suggests that the type of injection wells may not be a significant factor to impact the CO2-assisted gravity drainage mechanism. Results obtained herein would help in the optimization of CO2-assisted gravity drainage EOR process.

The matrix acidization operation has been extensively associated with unconformity. The challenge remains to distribute the acid treatment fairly along the wellbore. It has been observed that acid prefers the less resistance spots along the wellbore which are characterized by high permeability streaks / fractures. During the operation, the injection to these areas is highest which further increases its permeability whereas low permeability zones never receive the similar treatment and are left out with lower permeability. To counter this challenge, an approach of utilizing an advance completion consisting of Autonomous Outflow Control Device's (AOCD) was implemented. Although there are multiple case histories of successful installation of AOCD in water injection wells for conformance, the high rate of stimulation operation poses a major challenge. This study involves developing a methodology to ascertain that a similar performance of acid stimulation can be achieved with much lower rates through optimization. This will be possible by conforming stimulation fluids through the wellbore, allowing operation to be executed at lower rates than Open hole or standard completion. The solution will also provide cost effectiveness as a much less volume of fluids will be required to produce better performance as compared to non-optimized completion. The study also involved upgrading a stimulation software to convert it into a fit for purpose platform which will incorporate the operational envelope of AOCD. The AOCD is a rate-controlled device. At the heart of the device is a spring-based mechanism that reacts to the pressure drop/flow rate across the nozzle. Once a predefined upper flow-rate limit is reached at a zone, the valve autonomously closes. This eliminates the impact of the thief zone on acid injection conformance and maintains a prescribed acid distribution. The technology is proven in water or polymer injection wells; this study highlights the value addition that AOCD can bring to matrix stimulation operations; further presenting AOCD as a fit for purpose solution for injection wells irrespective of the injection type or application. A novel approach is developed through modelling to display that Autonomous Flow Control Devices can provide substantial value in stimulation operations. This will enable the operators to minimize the impacts of heterogeneity on the acid conformance and the completion system will autonomously respond to a dynamic change in reservoir properties, specifically the growth of wormholes.

Dynamic simulation and history matching at Ketzin (CO2SINK)

As experience in field development shows, unplanned growth of injection well cracks does not always have a positive effect on the development of oil reserves, but, on the contrary, causes premature flooding of producing wells. Currently, most of the fields are at the final stages of development, and an increase in reservoir coverage by flooding is an important task of developing oil fields. The article discusses and analyzes the effect of injection well capacity on the growth of self-induced fracturing fractures and the relationship with oil production on the example of one of the fields in Western Siberia. Using the hydrodynamic simulator and the geomechanical module, the best option was chosen and the positive effect was evaluated. An example is a production well of a highly watered stock. The reasons for the premature well flooding are considered by analyzing the graphical dynamics of capacity and flow rate of injection and production wells. As confirmation of the fracture growth or closing, the results of the adaptation of a single-layer two-phase model using the automatic hydraulic fracture are presented. The analysis of the geomechanical properties of the layers was carried out, during which the dependence of the crack length on the bottomhole pressure was determined. This dependence is compared with the results of the model adaptation. According to this adaptation of the hydrodynamic model, several variants of calculations were made in order to identify the optimal bottomhole pressure and compare this variant with the actual one. According to the data obtained, it was found that with optimal injectivity, a positive effect was observed already in the first month. The information obtained during the analysis of actual data and calculation on the hydrodynamic and geomechanical module, confirms the need to control bottomhole pressure at injection wells. Calculations show that there is a significant loss of oil production after the crack has opened. Using a calculation on the geomechanical module, optimal bottomhole pressures were given for a given injection well, at which there would be no increase in the crack of the injection well followed by watering of the production well. Calculations to determine the optimal values of the bottomhole pressure of the selected injection well can be applied to the wells of other fields.

Geologic parameters, geophysical logging, injection testing, and operational metrics from wastewater injection wells were integrated to develop a preliminary design of a carbon storage facility in the Appalachian Basin. A scattered group of 10–20 commercial wastewater injection wells dispose off produced water from oil and gas wells in the region, utilizing a sequence of stacked deep saline formations for injection zones. These wastewater injection wells provide practical benchmarks for understanding the feasibility of carbon dioxide (CO2) storage. Geologic models were developed based on characterization data from the wastewater injection wells. Reservoir simulations were calibrated according to injection testing and operational data from the wastewater injection wells. Long‐term operational data on injection flow rates and pressures measured in the wastewater injection wells were especially useful to evaluate the performance of carbon storage applications. The simulations were used to estimate injection pressures, radius of CO2 saturation, and pressure response for industrial scale CO2 storage applications. Results were also used to provide a design basis in terms of number of injection wells, well spacing, area of review, injection system components, monitoring plan, and CO2 pipeline distribution system. The analysis demonstrates that there is sufficient injectivity in the deep saline formations in the west‐central Appalachian Basin to store commercial volumes of anthropogenic CO2. The geologic system appears suitable for supporting CO2 injection rates of 0.5–1.0 million metric tons per year at injection pressures below formation fracture pressure in a single well. The long‐term operational data of wastewater injection wells within the study area suggested a lower permeability‐thickness values than indicated by initial reservoir tests. A workflow for developing realistic permeability values for input into reservoir simulations is presented. © 2020 Society of Chemical Industry and John Wiley & Sons, Ltd.

Bottom-hole Pressure Data Integration for CO2 Sequestration in Deep Saline Aquifers

Dynamic modeling studies of basin-scale pressure interference and CO2 plume evolution in multi-well geologic CO2 storage

A new technique is presented which aids in maximizing water injection rates in wells recently converted to injection, thereby accelerating offset oil production response. This method is applicable to waterflood operations where injection wells are surface pressure controlled and where bottom-hole injection just below formation parting pressure (FPP) is desired. Two plotting methods are shown to be instrumental in monitoring the acceleration of fill-up and average reservoir pressure growth in an actual field case. One is the Hall method1: plotting a function of bottom-hole injection pressure versus cumulative water injection, and the other was Introduced by Hearn2: plotting the inverse injec-tivity index versus cumulative water injection. After initiating injection into several converted wells at pressure limits well below the average offset parting pressures, periodic surface pressure increases were made at each well over a period of several months. Monitoring the Hall and Hearn plots as the pressure and rates increased rendered qualitative interpretations of whether the rates were being maintained below FPP. Accelerated reservoir pressure growth was achieved which resulted in earlier than expected offset oil response. Application of these plots also reduce, and sometimes eliminate, the need to perform periodic step-rate tests designed to determine FPP during the injection start-up period, thereby significantly reducing operating costs.

This paper provides an overview of the trial implementation of Focused fracture jetting, a solution aimed at effectively stimulating long horizontal open-hole wells in the oil and gas industry. The goal of this method is to create multiple fractures that penetrate deeper into the reservoir, increasing the overall stimulated surface area. Previous techniques, such as HCl stimulations, delayed reaction acid, abrasive jetting, and fishbones, did not achieve the desired improvements in injectivity for microporous water injection and oil producer wells. As a result, alternative methods were explored, leading to the adoption of Focused fracture jetting. This methodology utilizes high velocity jetting and dynamic diversion to create controlled fractures etched with acid, providing permanent increases in effective wellbore area. This paper focuses on the trial implementation of Focused fracture jetting in two water injection wells and one oil producer, named as WI-1, WI-2 and OP#1. In WI#1, 25 stages were pumped over a 700m interval with 30m spacing between stages, while in WI#2, 20 stages were pumped over a shorter interval of approximately 500m with 25m spacing between stages and OP#1, 11 stages were pumped over a shorter interval of approximately 680m with 29m spacing between stages. The stimulation was successful in improving water injection rates, resulting in a significant increase in the initial rate and approximately doubling the stable injection rate as well as production was enhanced drastically from the oil producer OP#1. The deployment of Focused fracture jetting has the potential to unlock the microporous reservoir's development, particularly in tight reservoirs with long open-hole sections, offering competitive costs and sustainable results.

Deep-water sandstones of the Delaware Mountain Group in west Texas and southeast New Mexico contained an estimated 1.8 billion bbl of original oil in place, but primary recovery from these fields is commonly less than 20%. East Ford field in Reeves County, Texas, which produces from the Ramsey sandstone in the upper Bell Canyon Formation, went directly from primary production to tertiary recovery by CO2 flooding. Field production has increased from 30 to more than 185 BOPD. Oil recovery has been improved by the CO2 flood, but not as much as expected. Geologic heterogeneities such as interbedded siltstones are apparently influencing reservoir displacement operations in the East Ford unit. A depositional model of the East Ford unit was developed using data from Bell Canyon outcrops and subsurface data. The Ramsey sandstones were deposited by turbidity currents in a basin-floor setting. The sandstones are interpreted as having been deposited in a channel-levee system that terminated in broad lobes; overbank splays filled topographically low interchannel areas. Injection wells located in splay sandstones apparently have poor communication with wells in channel sandstones, perhaps because communication is restricted through levee and channel-margin deposits. The south part of the unit is responding well to the flood because the injection and production wells are in the same interconnected lobe depositional environment.

Analysis of CO2 injection strategy and storage in the kujung formation using reservoir simulation

An efficient deep learning-based workflow for real-time CO2 plume visualization in saline aquifer using distributed pressure and temperature measurements