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Reservoir heterogeneity and inter-reservoir communication due to fracturing pose major challenges for our industry in terms of reservoir characterization and fluid flow modeling. Improved understanding and representation of their role in static and dynamic models is becoming a pivotal component for effective field management. Normally, multiple sources of both static and dynamic information are integrated to generate models used to simulate reservoir performance in order to identify optimal practices for efficient production and recovery. This paper presents a thorough reservoir study focused on the investigation of the use of temperature measurements to inform on fluid flow within and between reservoirs. The study addresses mainly the communication that exists in the reservoir beyond the well-bore, attributed to fracture corridors and faults. The interpretation of temperature measurements are integrated with other sources of dynamic and static information such as open-hole logs, production profiles, fluid losses, and pressure transient analysis. The study area covers a portion of an oil field that has been under peripheral water flooding for more than 30 years, producing mainly from the upper of the two reservoir units. As expected, the injected cold water imposes a significant variation in temperature profile across the reservoir which helps to describe the flood performance and understand the underlying geology. Additionally, we found that the rate of change of temperature with respect to time over the entire area shows that increasing temperatures are correlated with locations showing high structural relief. Our existing mapping shows these areas as being more densely fractured, with high fluid flow capacity. The coincidence of these factors with the temperature anomalies we observed strongly suggests that the faults and fractures in these areas may be responsible for mass and heat transfers between the two reservoirs.The outcomes of this study are used to optimize development and production plans such as balancing the off-take between high-structure and down-dip areas to prevent undesired water flood advances. They are also fully integrated with other sources of information to construct geological and flow simulation models in order to assess sweep performance and recovery estimation.
Reservoir heterogeneity and inter-reservoir communication due to fracturing pose major challenges for our industry in terms of reservoir characterization and fluid flow modeling. Improved understanding and representation of their role in static and dynamic models is becoming a pivotal component for effective field management. Normally, multiple sources of both static and dynamic information are integrated to generate models used to simulate reservoir performance in order to identify optimal practices for efficient production and recovery. This paper presents a thorough reservoir study focused on the investigation of the use of temperature measurements to inform on fluid flow within and between reservoirs. The study addresses mainly the communication that exists in the reservoir beyond the well-bore, attributed to fracture corridors and faults. The interpretation of temperature measurements are integrated with other sources of dynamic and static information such as open-hole logs, production profiles, fluid losses, and pressure transient analysis. The study area covers a portion of an oil field that has been under peripheral water flooding for more than 30 years, producing mainly from the upper of the two reservoir units. As expected, the injected cold water imposes a significant variation in temperature profile across the reservoir which helps to describe the flood performance and understand the underlying geology. Additionally, we found that the rate of change of temperature with respect to time over the entire area shows that increasing temperatures are correlated with locations showing high structural relief. Our existing mapping shows these areas as being more densely fractured, with high fluid flow capacity. The coincidence of these factors with the temperature anomalies we observed strongly suggests that the faults and fractures in these areas may be responsible for mass and heat transfers between the two reservoirs.The outcomes of this study are used to optimize development and production plans such as balancing the off-take between high-structure and down-dip areas to prevent undesired water flood advances. They are also fully integrated with other sources of information to construct geological and flow simulation models in order to assess sweep performance and recovery estimation.
Heavy oil has gained significant attention and importance recently because of a multitude of reasons—growing demand of oil from developing economies, declining availability of easily recoverable or "conventional" oil, and significant advances in required technology. Even though the current estimates of heavy oil in place are three times that of conventional oil, they have only recently become economically viable because of sustained high oil prices. Improved technology has also driven down the recovery risk to minimal levels. The earliest recovery methods for heavy oil were largely cyclic stimulation, with steamflooding gaining acceptance in the 1970s. Despite other thermal and non-thermal recovery methods for heavy oil, steamflooding remains the most widely used technology. Current production by steamfloods alone totals more than 1.1 million BOPD. Previous studies have established how steamfloods are affected by parameters, such as rock properties, oil composition, degree of steam override, sweep efficiency, steam quality, and steam injection rate. However, the capital-intensive nature and low profit margins of the steamfloods mean that each field development decision is crucial and the oil recovery and margins are much more susceptible to uncertainties in oil price, well performance, facility costs, and subsurface parameters. While studies have been performed to corroborate the effect of subsurface parameters and economic uncertainties separately, there has been little advancement in terms of coupling all of them together in one unified study. In this paper, the effects of uncertainties on project net present value (NPV) are studied by coupling numerical reservoir simulation; a design- of-experiments based approach to handle uncertainty, an established economic model, and a commercial optimizing tool to determine the optimal field operating variables.
Kuwait Oil Company (KOC) is running two pilot projects in South Ratqa Field to evaluate steam injection using cyclic steam stimulation (CSS) and steam flooding (SF) methods. These projects are the first of their kind in KOC history and one of the major milestones in the North Kuwait Heavy Oil Development. Two large-scale thermal pilot (LSTP) projects are located north and south of the South Ratqa Field, with the north running two different areas of 10 and 5 acres and well completion and the south running one area of 5 acres. KOC has been injecting steam in these pilots in an unconsolidated high viscous formation since 2015, beginning with a CSS process that migrating to SF during the second half of 2017. A fundamental goal to help ensure success with this type of project is carefully monitoring the injected steam per well and per formation layer by installing fiber optic distributed temperature sensing (DTS) and pressure gauges in a portion of the wells; this goal was defined at the beginning of the project. For this purpose, 12 wells were drilled as observation wells and 6 idle wells were used for fiber-optic deployment to monitor the reservoir 24 hours a day, 7 days a week for the injection life of the pilots. The observation wells with DTS and pressure gauges were distributed along the pilots to cover a large predetermined observation area for the pilots. The observation wells with DTS and pressure gauges in the north and south LSTP areas were also distributed along these pilots to cover a large area. The benefits of installing this technology in the pilots are to:To develop an understanding of steam breakthrough zones along the pay-zone interval of production wellsTo help improve the understanding of the steam injection profile for steam-injector wellsTo help improve the real-time temperature profile along the length of producer’s wellboreTo develop an understanding of heat management during steam flooding This paper discusses the success story between two companies installing DTS and thermal pressure gauges and includes a description of DTS, the installation procedure of downhole and surface equipment, real-time data transfer, and data analysis.
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