Summary Four pattern-scale CO2-foam field trials were conducted to determine the effectiveness of foam in reducing CO2 channeling, to evaluate the economic potential of the process, and to develop application criteria and procedures. The trials were conducted under various process and geologic conditions so that the resulting technology would be applicable in a number of different CO2 floods. Two different surfactants, Rhodapex (formerly Alipal) CD-128 and Chaser CD-1045, and two injection methods, alternating vs. coinjection of CO2 and surfactant, were tested in San Andres (west Texas) and platform carbonate (southeast Utah) reservoirs. In all, 161,000 lbm of active surfactant was injected in the four field trials, with one well undergoing foam treatment for as long as 18 months. The treatments resulted in a significant reduction in gas production and indications of increased oil production. The total cost of the four treatments (excluding labor and overhead) was $700,000. Introduction In recent years, foam has been applied to reduce gas channeling in steam, hydrocarbon gas, and CO2 miscible floods, and significant academic and industry research has focused on the processes involved. Application of foam involves injecting a surfactant along with water and gas into the reservoir through either an injection or a producing well. This work is limited to foam applied through injection wells. The surfactant stabilizes liquid films (lamellae) that form in the rock, thus trapping and reducing the permeability of the porous media to gas. Reports of five CO2-foam field treatments have appeared in the literature; Ref. 5 reports a recent major U.S. Dept. of Energy (DOE)/industry treatment that has highlighted interest in the process. CD-128, one surfactant used in all the treatments reported here, has been studied extensively for use as a CO2-foaming agent. Potential Benefits of Foam. The benefits of foam in CO2 flooding may include (1) improved CO2 utilization efficiency (reduced CO2 requirement per unit of oil produced), (2) reduced gas production and associated processing costs, (3) increased oil recovery (through improved reservoir sweep), and (4) accelerated oil production. Channeling and premature breakthrough of the high-mobility gas can result in increased CO2 requirements and increased gas processing costs. Foam reduces the gas mobility, and may thereby reduce gas channeling and the relative rate of gas production. Oil recovery may increase because the bottomhole injection pressure can often be increased with foam, which may result in increased CO2 flow to previously unswept areas of the reservoir.
Horizontal wells with multistage hydraulic fractures have become the most common practice to obtain viable commercial production from shale and tight gas reservoirs. With a marked increase of gas production emerging from these tight reservoirs, it is necessary to further study the effects of formation damage due to condensate dropout and how best to prevent and mitigate this damage. There are two common ways to mitigate and treat condensate banking. The first method is to fracture the existing well. This allows bypassing the condensate and therefore increasing well productivity. The second method is to shut-in the well and allow pressure to build up so that the dropped out liquids are revaporized back into the gas. These options, respectively, involve large capital expenses and temporary decrease of production. Before deploying these solutions, the condensate dropout damage can be strongly reduced at no (field) cost by optimizing the well location.This objective in this study was to determine the optimum well location to mitigate formation damage due to condensate dropout in a tight gas well. Compositional reservoir simulations were conducted with different condensate gas ratios and relative permeability curves to quantify the loss of productivity due to formation damage under different conditions. The target formation was 100 ft thick, and a tartan grid was used to represent the hydraulic fractures within the tight gas well.This study determined that well placement plays a key role in preventing damage due to condensate banking. The optimized placement of the well can drastically enhance the viability of a project by allowing for a larger recovery.
One of the main challenges of producing tight or low-permeability gas reservoirs is condensate banking when production starts as the reservoir pressure drops below the dewpoint pressure. Condensate banking causes formation damage and subsequently damages production. The normal procedure to mitigate condensate banking is to hydraulically fracture the well to bypass the condensate bank and improve production from that well. Modeling the condensate banking along the hydraulic fracture is critical to understanding the loss of productivity.We investigated the feasibility of simulating a cyclic CO 2 injection scheme to mitigate formation damage due to gas condensate dropout in a low-permeability gas reservoir. The field was modeled using a tartan grid to be able to model the hydraulic fracture explicitly. In addition to the hydraulic fracture, the study examined how much of a role the condensate-gas ratio (CGR) plays in the condensate banking and how to best position a well in a low-, medium-, and high-CGR fluid. For the mitigation phase, different cyclic parameters such as injection rate, injection pressure, and soaking time for the cyclic CO 2 injection were considered.The study found that the volume of the GCR played a critical role in determining injection rates and pressure to best be able to mitigate damage due to condensate banking.
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