Recently there has been an increasing interest in simultaneous water-alternating-gas (SWAG) in oil recovery operations. This method involves the simultaneous injection of water at the top of the reservoir formation and injecting gas at the bottom of the formation. The difference in water and gas densities will provide a sweeping mechanism in which water tends to sweep hydrocarbons downward and the gas tends to sweep the hydrocarbons upward. It is expected that the two displacement mechanisms will work on establishing a flood front, which will increase the sweep efficiency and thus the oil recovery. This study investigated the performance of SWAG in oil recovery operations. A three-dimensional finite-difference black oil reservoir simulator has been used to determine the reservoir management strategies in order to optimize the oil recovery using SWAG injection technique. A specific strategy that was studied includes the use of horizontal injectors in conjunction with vertical producers. This well configuration has been shown to yield the best oil recovery compared to other well configurations. The management strategies involved studying different design parameters to maximize the recovery performance. Such parameters include; mobility ratio between oil and water phases, viscosity ratio between gas and oil phases, location of the water and the gas injectors, and injection rates of water and gas. Results showed the investigated parameters are critical in the success of the proposed injection SWAG scheme. The study provides the conditions under which this SWAG injection technique may yield higher recovery performance. Introduction Oil is considered the main source that provides energy to consumers around the world. The proper utilization of oil resources is a vital issue among world nations. The reservoirs, where oil is trapped, are natural occurring geological structures with mechanisms that move oil toward production wells. These mechanisms are depleted as oil production continues. The need for maintaining or enhancing these mechanisms plays a significant role in keeping the flow of oil. Injection of external fluids into oil reservoirs is a very well known practice in the oil industry that is aimed to sweep oil toward production wells. Water and gas are the most injected fluids into oil reservoirs. The careful design of the flooding operation is a key factor in achieving the objectives of the injection operations. Many injection settings have been followed in the industry with varying degrees of success. An injection technique in which gas and water are injected into reservoirs simultaneously is considered in this study. Gas is injected at the bottom of reservoir while water is being injected at the top. This technique makes advantages of the difference in water and gas densities to increase the hydrocarbon recovery. In primary recovery methods, oil is displaced toward production wells by the natural reservoir energy. Sources of natural reservoir energy are fluid and rock expansion, solution gas drive, gravity drainage and the influx of water from aquifers. When this natural energy of the reservoir is depleted and the drive mechanism is no longer can displace the oil toward production wells, improved oil recovery techniques are introduced to increase the oil recovery. Several methods have been tried to improve the recovery from hydrocarbon reservoirs. Most of these methods use vertical wells, however, horizontal wells shows some advantages in improved oil recovery operations. The primary reason for utilizing horizontal wells is that a horizontal well provides a large contact area with the reservoir under considerations, and therefore enhances well productivity/injectivity and hence the recovery efficiency. In addition, the costs of drilling horizontal wells, nowadays, are achieving those for the conventional vertical wells due to the advancement of horizontal well drilling technology.
The natural energy of hydrocarbon reservoirs gets depleted as production continues. The restoration of reservoir energy involves the injection of gas and/or water to support reservoir pressure and to provide a sweeping mechanism. Due to the unfavorable gas-oil mobility ratio, gas injection alone often results in early breakthrough and thus poor sweep efficiency. Water and gas might be injected alternatively, as in water-alternating-gas (WAG) processes, or together, as in simultaneous water-alternating-gas (SWAG) processes, to improve the sweep efficiency. These processes improve the sweep efficiency by stabilizing the displacement front. In this paper, we study a new design of SWAG process, in which water is injected at the top of the reservoir and gas is injected at the bottom. The difference in water and gas densities provides a sweeping mechanism in which water tends to sweep hydrocarbons downward and the gas tend to sweep the hydrocarbons upward. It is expected that the two displacement mechanisms will work together to enhance the overall sweep efficiency and thus the oil recovery. In this paper, the drive mechanisms responsible for oil production under this injection technique are analyzed. The effects of several design parameters on these drive mechanisms are investigated for both homogeneous and heterogeneous reservoirs. Such parameters include; mobility ratio between water and oil phases, viscosity ratio between gas and oil phases, lateral aspect ratio, location of the water and the gas injection wells, and injection rates of water and gas. Introduction Water Alternating Gas (WAG) injection method was originally proposed to improve sweep efficiency of gas injection through better mobility control. In recent years, WAG injection process has gained an increasing interest as an improved oil recovery method especially with the aging of mature reservoirs. Higher Oil recovery factors are anticipated in WAG projects compared to waterflooding due to the combined improvements in the microscopic displacement efficiency associated with gas injection and the macroscopic sweep efficiency of water injection. Christensen et al.1 presented an extensive review of WAG applications on 59 field cases. The first reported WAG field pilot was in the North Pembina field, Alberta, Canada in 1957. The review shows that WAG has been applied successfully in most field trials. The majority of these projects have resulted in significant incremental oil recoveries ranging from 5 to 10%. Attanucci et al.2 investigated the effects of water and gas slug sizes and tapering sequence on the performance of WAG process. Their results indicated that implementing WAG process with reduced injection cycle lengths has the potential to increase the recovery efficiency and to improve oil lift efficiencies which will result in reducing operating costs.
Several efforts have been made in the past for generating an Integrated Asset Model (IAM) for the Greater Burgan field in Kuwait with mixed results on sustained utilization and benefits. A new effective full field Integrated Asset Model has now been developed within an Integrated Operational Excellence (IOX) program towards Digital Transformation of the Greater Burgan field. A proven model centric approach has been adopted to bring multiple interdependent wells, pipelines networks, and process facilities models together into one single truly integrated asset model. The IAM platform also includes a water processing facility model which consists of 2 effluent water disposal plants, a crude oil export pipeline network and a water injection network model. Development of this integrated wells-network-facility-crude export-water processing facility-water injection network model incorporating the 14 gathering centers in the South and East Kuwait (SEK) asset focused on providing all the essential valuable inputs to business processes for better asset management, faster and more accurate decision-making and optimizing the hydrocarbon flow path all the way from the reservoir till the export point. The assessment was done at full field level where the complete system constraints, interactions and back pressure effects between more than 2000 different wells were fully accounted up to the crude processing facilities. The availability of this fully integrated asset model with up-todate calibrated wells and network models and process models enables Kuwait Oil Company (KOC) engineers to better understand current well performance and production potential, identify any possible bottlenecks imposed by the large complex surface network and process facilities of Greater Burgan Oilfield. The simulated results such as pressure gradient, temperature gradient and erosional velocity ratio gradient across the production networks are presented on the GIS map for easy opportunity identification. The paper describes how the Integrated Asset Modeler tool enables the asset teams to evaluate different operating scenarios to further enhance well performance and the overall asset productivity via re-routing well flow path to an appropriate header, identifying well workover opportunities, re-evaluating artificial lift design, adding new wells for field development and comprehensive understanding of well integrity and flow assurance studies. The integrated asset model can be coupled to the Greater Burgan reservoir model for comprehensive field development studies in future.
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