Recent studies have estimated that oceans have naturally sequestrated, by dissolving and mixing with deep waters, about 40% of the anthropogenic CO 2 emitted since the start of the industrial revolution. Moreover, the International Maritime Organization has recently announced that storage of CO 2 under the seabed would be allowed starting in 2007. To date, almost all studies, simulations and technical papers concerning carbon sequestration have focused on storing supercritical CO 2 in deep saline aquifers or depleted oil and gas reservoirs. However, a critical limiting factor for such carbon sequestration is the need for proper physical trapping and the necessity for monitoring the upward migration due to buoyancy effects and mobility of supercritical CO 2 . Carbon sequestration in deepwater sub-seabed formations provides an attractive alternative.This paper presents a feasibility study of carbon sequestration in deepwater formations in the Gulf of Mexico with the existing technologies available in the offshore industry. We describe each step of the carbon capture and storage process and discuss the technical limitations when trying to capture CO 2 from industrial processes, transport it offshore via tanker, drill a CO 2 injector well and then, inject the CO 2 from floating facilities such as drill ships or semi-submersible vessels. Due to high pressures and low temperatures reigning at water depths deeper than 9,000 feet, the liquid CO 2 injected in the first few hundred feet of deposits will have a higher density than the surrounding formation pore-fluid and therefore will be buoyantly trapped. In addition, CO 2 hydrates that may form and fill up pore spaces will act as an additional trapping mechanism. Finally, at these great depths, the CO 2 that could leak will dissolve by reacting with ocean waters and forming mainly bicarbonate compounds.Because oceans cover about 70% of the Earth's surface with an average water depth of 12,500 feet, deepwater sub-seabed sequestration provides an enormous storage capacity to counteract increasing world consumption of fossil fuels. However, large time and space-scale simulations need to be performed to estimate the impact of the change in geochemistry in the deepwater seabed region. Also, the injection of liquid CO 2 will force and displace formation fluid into the seabed surface zone, which will change the ocean chemistry.
Tight formations are being developed by drilling in the Midland Basin. Target intervals include Clearfork, Wolfcamp, Spraberry, Strawn, Cline, Atoka, and Mississipian formations, which are usually found between 6000 feet and 11,500 feet true vertical depth (TVD). Development is typically with vertical wells, which are stimulated with multiple hydraulic fractures targeting the expected pay intervals and are produced commingled. A significant challenge for operators is determining the optimum well locations and spacing for efficient reserve development. Operators use various field data and analytics to determine well spacing, although limited data pose challenges to making the best decisions. Numerical models can yield insights about drainage patterns and potential interference. This paper reports a case study using a geologic model, hydraulic stimulation models, and a reservoir simulation model to evaluate reduced well spacing impacts on recovered oil and economics. A three-dimensional geologic model was constructed for a 14-section area in the Midland Basin. An extensive core-log statistical study yielded calibrated rock types at the wells. Reservoir and geomechanical properties were then spatially distributed using geostatistical techniques subject to data constraints. A reservoir simulation model was then utilized on a sector area of the full model. The sector model was history-matched to early production data and historical type curves. Each well had 10–12 fracture stages, which were explicitly modeled using parameters derived from post-execution analysis of fracture job data. The paper presents history-matched simulation models that were executed to predict production and economics for 40-acre and 20-acre well spacing cases.
Permanent underground storage of carbon dioxide (CO2) has been proposed as a potential mitigator for greenhouse gases in the atmosphere. In such underground reservoirs, CO2 is trapped through a complex combination of physical and chemical processes. Also, injected CO2 in contact with subsurface water can decrease the cement strength, deteriorating wellbore integrity. Current industry programs, such as reservoir simulators and wellbore-cementing programs, provide powerful models for the physical processes. This paper discusses a model for the remaining geochemical processes. This model is designed for implementation in existing industry programs, enabling the industry, while planning carbon capture and sequestration (CCS) projects, to take advantage of experience acquired throughout many years. A self-contained solution procedure has been developed to solve geochemical equilibrium calculations. The equilibrium within the brine phase is computed with activity coefficients calculated by use of either the general Helgeson-Kirkham-Flowers (HKF) electrolyte model, or the more-accurate Pitzer ion model. A correlation from open literature has been selected to calculate the equilibrium between CO2 and brine phases. Once equilibrium is established, the model calculates precipitation or dissolution rates for common minerals. The solution procedure has been designed for optimum balance between robustness and calculation speed while solving the nonlinear geochemical equilibrium problem. A novel initialization scheme and a three-pass solution procedure are introduced. During Pass 1, activity coefficients are set to unity while a nonlinear minimization algorithm is used to locate the neighborhood of the equilibrium solution; in Pass 2, the first pass is repeated with the activity coefficients being calculated by use of the selected model. Finally, during the final pass, the solution is refined to the desired accuracy by the use of a nonlinear solver. The solution model fits observed data. The CO2 solubility and brine phase pH can be computed for temperatures between 300K (80°F) and 478K (400°F), pressures up to 414 bar (6,000 psia), and brine strengths up to 6 mol NaCl/kg H2O. The more than 50 primary and secondary mineral species in the database represent common carbonate and clastic formation components. Temperature-dependent dissolution and mineralization rates can be predicted at similar conditions. As the industry plans CCS projects, it must document projections of formation and well integrity during the project lifetime. The solution procedure is suitable for inclusion in various oil and gas industry models, including cementing simulators or reservoir simulators, to model CCS in subsurface aquifers and enhanced oil recovery (EOR). This paper provides guidance on how the algorithms should be implemented within reservoir simulators.
This paper discusses a methodology for the design of wells in carbon capture and sequestration (CCS) projects. In addition to carbon dioxide (CO2) injection wells, CCS wells include observation or monitoring wells, as well as utility wells, which are used to reduce pressure by removing formation water. The paper first outlines the differences between CCS wells and conventional oil and gas wells. These differences include much longer regulatory lifetimes, increasing pressure over well lifetimes, inherently corrosive environment, intermittent operation and large variation of CO2 injection stream properties depending on its impurities. These differences require a different approach to well design for CCS projects. A well design philosophy, which has been developed to address these differences, is presented. The paper outlines the material selection guidelines and tubular load cases. The design philosophy, material guidelines and load cases are illustrated through several example well designs. For CCS wells, the design should start with the completion size required to achieve the desired CO2 injection rate, and progress outwards. Dual containment is essential; the second barrier must not only be designed for the corrosive environment, but the second barrier and its associated equipment must be periodically inspected or tested. All CCS wells, including injection, monitoring and utility wells, must be designed for potential CO2 exposure. Highest loads may be imposed during transient or upset operations, and may originate from changing thermal conditions. Cement integrity is essential to prevent undetected migration of stored CO2 out of the storage zones. Finally, it is necessary to have pre-prepared contingency plans to detect, shut-in, kill, repair and/or P&A failed wells. The differences between CCS wells and conventional oil and gas wells require a different approach to well design. If CCS wells were to be designed using conventional methods, the wells might fail to maintain their integrity, thus resulting in the failure to contain injected CO2 in the sequestration zone.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.