Steam conformance control in horizontal injectors is important for efficient reservoir heat management in heavy oil fields. Suboptimal conformance and non-uniform heating of the reservoir can substantially impact the economics of the field development, oil production response and result in non-uniform steam breakthrough. In order to achieve the required control, it is essential to have an appropriate well completion architecture and robust surveillance. Five fiber optic systems, each utilizing a unique steam conformance control completion configuration, have been installed in two horizontal steam injectors to help mature steam injection flow profiling and conformance control solutions. These fiber optic systems have utilized custom designed fiber optic bundles of multimode and single mode fibers, for distributed temperature sensing (DTS) and distributed acoustic sensing (DAS) respectively. Fiber optic systems were also installed in a steam injection test flow loop. All the optical fibers successfully acquired data in the wells and flow loop, measuring temperature and acoustic energy. A portfolio of algorithms and signal processing techniques were developed to interpret the DTS and DAS data for quantitative steam injection flow profiling. The heavily instrumented flow loop environment was utilized to characterize DTS and DAS response in a design of experiment matrix to improve the flow profiling algorithms. These algorithms are based on independent physical principles derived from multiphase flow, thermal hydraulic models, acoustic effects, large data array processing, and combinations of the foregoing methods for both transient and steady state steam flow. A high-confidence flow profile is computed based upon convergence of the algorithms. The flow profiling algorithm results were further validated utilizing a dozen short-offset, injector observation wells in the reservoir that confirmed steam movement near the injectors.
Summary Steam-conformance control in horizontal injectors is important for efficient reservoir-heat management in heavy-oil fields. Suboptimal conformance and nonuniform heating of the reservoir can substantially affect the economics of the field development and oil-production response and result in nonuniform steam breakthrough. To achieve the required control, it is essential to have an appropriate well-completion architecture and robust surveillance. Five fiber-optic systems, each with a unique steam-conformance-control-completion configuration, have been installed in two horizontal steam injectors to help mature steam-injection-flow profiling and conformance-control solutions. These fiber-optic systems have used custom-designed fiber-optic bundles of multimode and single-mode fibers for distributed-temperature sensing (DTS) and distributed-acoustic sensing (DAS), respectively. Fiber-optic systems were also installed in a steam-injection-test-flow loop. All the optical fibers successfully acquired data in the wells and flow loop, measuring temperature and acoustic energy. A portfolio of algorithms and signal-processing techniques was developed to interpret the DTS and DAS data for quantitative steam-injection-flow profiling. The heavily instrumented flow-loop environment was used to characterize DTS and DAS response in a design-of-experiment (DOE) matrix to improve the flow-profiling algorithms. These algorithms are dependent on independent physical principles derived from multiphase flow, thermal hydraulic models, acoustic effects, large-data-array processing, and combinations of these methods for both transient and steady-state steam flow. A high-confidence flow profile is computed using the convergence of the algorithms. The flow-profiling-algorithm results were further validated using 11 short-offset injector observation wells wells in the reservoir that confirmed steam movement near the injectors.
Horizontal steam injectors have a high-temperature, hostile wellbore environment which can result in sand influx, low cycle fatigue failures, packer failures, and liner hanger failures. This paper provides a case history analysis of five fiber optic installations in two wells that were used to evaluate, diagnose and address a variety of tubing-deployed equipment integrity and wellbore conditions. Distributed temperature sensing (DTS) and distributed acoustic sensing (DAS) were used to evaluate integrity of the liner and completion equipment performance in the horizontal section of the wellbore. Application of a robust fiber data analysis methodology is presented that is focused on determining if the completion equipment is performing consistent with the basis of design assumptions. Examples of basis of design assumptions includes determining : 1) are packers or liner hangers leaking, 2) are steam flow control devices providing both the design steam mass flow rates and uniform quality splitting of wet steam, and 3) is the liner intact and directing steam as expected. Steam flow in horizontal injectors is a complex two-phase system that cannot be readily predicted from simple multiphase flow models. Fiber optic surveillance provides important insights and understanding of the complex flow behavior in the annulus for tubing-deployed flow control devices (FCDs) in horizontal wells. Two-phase steam flow in horizontal injectors can create various flow regimes that can impact steam distribution and wellbore integrity (e.g. caustic and chloride stress corrosion and scale deposition). Flow diagnostic tools, the acoustic energy spectrum and steam flow regime models were used to understand nozzle sonic flow, packer integrity, tubing and liner integrity by visualizing the acoustic data in both time and frequency domains. Using advanced signal processing and separation techniques, the liquid and vapor zones were uniquely characterized within the wellbore. The reliability and integrity of the packers and the injection string were also evaluated utilizing DTS and DAS data in combination. The characterization of flow control devices and their performance at the down-hole condition is provided, including identification of slug flow regimes and water pooling in low spots in the horizontal section of the well.
A horizontal steam injection pilot project has been underway for the last four years in the Kern River heavy oil field located in the southern San Joaquin Valley of California. This pilot project was designed to address the following four prioritized learning objectives for horizontal steam injection in a mobile heavy oil reservoir, which were:What is the mechanical reliability and operability of horizontal steam injectors?Can acceptable steam conformance control along the horizontal section be achieved?Can steam conformance along the horizontal section be quantified with surveillance?What is the reservoir response and longer-term operability with horizontal steam injection? The 12-acre pilot area on the northwest flank of section 24 of the Kern River field was equipped with two horizontal steam injectors and nine vertical producing wells. The pilot area also had 12 vertical temperature observation wells (TOW) to understand steam conformance around each of the injectors and in the far-field reservoir. The TOWs were logged frequently to establish temperature trends. Based upon temperature trends steam identification and saturation logs were also acquired periodically. Five injector completions of increasing complexity were installed to understand the injectors' mechanical integrity, recovery of flow control devices, performance of isolation packers and fiber optic surveillance systems. A history-matched reservoir simulation model with coupled wellbore hydraulics was used for forecasting throughout the project life to conduct operational sensitivity analysis and to improve reservoir characterization. Fiber optic flow profiling methods were developed in the injectors that were validated with the observation wells and reservoir models. During each workover torque and drag measurements were acquired which were analyzed with both soft and stiff string analysis to understand wellbore mechanical conditions in the horizontal section. After each workover, all available reservoir and workover surveillance data, TOW logs and production and injection well information were used in a multidisciplinary review to understand progress against the four prioritized learning objectives. The performance of offsetting traditional, vertical steamflood developments were also evaluated.
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