Addressing Horizontal Steam Injection Completions Challenges with Chevron's Horizontal Steam Test Facility
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Events such as hydraulic gradients in the horizontal completion, geologic and fluid variations in the reservoir and well placement issues can produce very poor steam conformance in the Steam Assisted Gravity Drainage (SAGD) process. Operators have implemented many strategies in an effort to address the issue. Simultaneous injection in inner tubing and annulus space or dual-tubing completions are commonly used in SAGD wells to provide controllable injection and production from the heel and toe regions of the horizontal well pair but this does not guarantee both uniform and efficient performance. This paper presents a study of a hybrid of two technologies to improve both conformance and economics of this thermal process. Recent work suggests that using Proportional-Integral-Derivative (PID) feedback to control the steam injection can lead to improvements in SAGD performance and conformance. The feedback control is applied to each steam injection point in the horizontal well pair. Injection at these control points is regulated by a PID feedback controller monitoring temperature differences between injected and produced fluids in order to both enforce a specified subcool and to achieve uniform production along the entire length of the producer. PID feedback control can be practically and inexpensively implemented in the field with current technology. Inflow or injection control devices (ICDs) can also improve SAGD performance. ICDs (or FCDs) can be incorporated in the horizontal completion as restrictive elements to modify the pressure distribution along the length of the wellbore. Among other benefits, properly sized and distributed ICDs can create a more uniform flow profile along the horizontal section of the well, regardless of permeability, formation damage and wellbore location. Furthermore, ICDs on the producer can provide a self-regulating effect to prevent live steam from entering the sand control screen. This paper examines detailed wellbore simulations of a SAGD process in which wells are equipped with a combination of ICD completions and feedback control in order to (i) determine the physical mechanisms (including the dynamic flow paths inside the well and in the near wellbore region), and (ii) outline practical procedures to determine an improved ICD completion and feedback control design. A novel aspect of this work is the inclusion of a revised flow-regime-independent multiphase flow correlation that can predict the pressure drop in horizontal and near-horizontal wells. Results presented in this paper should aid reservoir simulation engineers in both the design and optimization of steam injection in a SAGD well pair.
Events such as hydraulic gradients in the horizontal completion, geologic and fluid variations in the reservoir and well placement issues can produce very poor steam conformance in the Steam Assisted Gravity Drainage (SAGD) process. Operators have implemented many strategies in an effort to address the issue. Simultaneous injection in inner tubing and annulus space or dual-tubing completions are commonly used in SAGD wells to provide controllable injection and production from the heel and toe regions of the horizontal well pair but this does not guarantee both uniform and efficient performance. This paper presents a study of a hybrid of two technologies to improve both conformance and economics of this thermal process. Recent work suggests that using Proportional-Integral-Derivative (PID) feedback to control the steam injection can lead to improvements in SAGD performance and conformance. The feedback control is applied to each steam injection point in the horizontal well pair. Injection at these control points is regulated by a PID feedback controller monitoring temperature differences between injected and produced fluids in order to both enforce a specified subcool and to achieve uniform production along the entire length of the producer. PID feedback control can be practically and inexpensively implemented in the field with current technology. Inflow or injection control devices (ICDs) can also improve SAGD performance. ICDs (or FCDs) can be incorporated in the horizontal completion as restrictive elements to modify the pressure distribution along the length of the wellbore. Among other benefits, properly sized and distributed ICDs can create a more uniform flow profile along the horizontal section of the well, regardless of permeability, formation damage and wellbore location. Furthermore, ICDs on the producer can provide a self-regulating effect to prevent live steam from entering the sand control screen. This paper examines detailed wellbore simulations of a SAGD process in which wells are equipped with a combination of ICD completions and feedback control in order to (i) determine the physical mechanisms (including the dynamic flow paths inside the well and in the near wellbore region), and (ii) outline practical procedures to determine an improved ICD completion and feedback control design. A novel aspect of this work is the inclusion of a revised flow-regime-independent multiphase flow correlation that can predict the pressure drop in horizontal and near-horizontal wells. Results presented in this paper should aid reservoir simulation engineers in both the design and optimization of steam injection in a SAGD well pair.
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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