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Successful heavy oil reservoir management practices, are built on analyzing and accurately predicting the reservoir behavior over time. To enable these practices, the critical component that assures their success is a thorough understanding of reservoir physics. Given the complex nature of heavy oil reservoirs including geomechanical properties, fluid flow behavior, etc., there is a need to develop a repeatable technique that can account for these complexities within an acceptable margin of accuracy. The objective of this study is to conduct a comprehensive review of all the latest technologies and workflows developed for heavy oil reservoir management, so that, it can be used as a single source of reference for the industry. The latest technologies for heavy oil reservoir management, their underlying principles, along with the advantages and limitations for each of the methods in real-world applications, have been reviewed from different parts of the globe. Based on this review, conclusions have been drawn that help select the best criteria for using the latest heavy oil reservoir management techniques. The primary component of successfully applying heavy oil reservoir management methods, lies in accurately representing the reservoir physics. These components include petrophysical properties, fluid flow and geological properties of a given formation. In addition to outlining each of these components, an emphasis has been given to highlight the important criteria that enable the successful application of these methods to a given area. As such, the study will be an information repository catered to assist in developing robust reservoir management workflows for heavy oil reservoirs. While there are other reference, with examples, on heavy oil reservoir management; the uniqueness of this study lies in summarizing key lessons learned from real-field applications of these methods. Within a single source or reference, this study has given the specific focus on summarizing various aspects that are important to successful heavy oil reservoir management processes.
Successful heavy oil reservoir management practices, are built on analyzing and accurately predicting the reservoir behavior over time. To enable these practices, the critical component that assures their success is a thorough understanding of reservoir physics. Given the complex nature of heavy oil reservoirs including geomechanical properties, fluid flow behavior, etc., there is a need to develop a repeatable technique that can account for these complexities within an acceptable margin of accuracy. The objective of this study is to conduct a comprehensive review of all the latest technologies and workflows developed for heavy oil reservoir management, so that, it can be used as a single source of reference for the industry. The latest technologies for heavy oil reservoir management, their underlying principles, along with the advantages and limitations for each of the methods in real-world applications, have been reviewed from different parts of the globe. Based on this review, conclusions have been drawn that help select the best criteria for using the latest heavy oil reservoir management techniques. The primary component of successfully applying heavy oil reservoir management methods, lies in accurately representing the reservoir physics. These components include petrophysical properties, fluid flow and geological properties of a given formation. In addition to outlining each of these components, an emphasis has been given to highlight the important criteria that enable the successful application of these methods to a given area. As such, the study will be an information repository catered to assist in developing robust reservoir management workflows for heavy oil reservoirs. While there are other reference, with examples, on heavy oil reservoir management; the uniqueness of this study lies in summarizing key lessons learned from real-field applications of these methods. Within a single source or reference, this study has given the specific focus on summarizing various aspects that are important to successful heavy oil reservoir management processes.
The Ithaca-operated Captain field is located in Block 13/22a in the U.K. sector of the North Sea, 130 km northeast of Aberdeen, in a water depth of 360 ft. The Captain Field has an adverse mobility ratio across all the producing reservoirs and so has undergone improved oil recovery by polymer flooding since 2011 using Anionic polyacrylamide (HPAM) in liquid form. This paper presents recent offshore wellhead sampling from the Captain facility that confirms high polymer solution viscosity retention from a producing well, even after significant mechanical degradation through the Electrical Submersible Pumps (ESP), which is used for artificial lift. The continuing commercial success of the Captain Field polymer flood is underpinned by maintaining polymer viscosity throughout the system. High polymer returns, combined with declining oil rates, may result in the continued operation of these wells to be unattractive. This paper summarises the data used to shut-in mature wells that are producing polymer to the surface, to enable the polymer flood to continue displacing oil to offset production wells. Samples were collected from the wellhead in oxygen free conditions into pressurized cylinders. The measurements in laboratory were taken inside a glove box to avoid oxygen ingress. The absence of oxygen was confirmed through measurements of dissolved oxygen and redox potential. Viscosity of the solutions have been measured with Brookfield viscometer inside the glove box and the results were compared to the expected viscosity from fresh non-degraded polymer solution. The expected viscosity was determined using a concentration – viscosity curve of a fresh polymer in synthetic Captain brine. Polymer solution concentration is measured on-site using KemConnect™ EOR, a time resolved fluorescence method, the collected samples were subsequently confirmed with size exclusion chromatography (SEC) in the laboratory. The polymer concentrations measured from these wellhead samples with KemConnect™ EOR were in the region of 700-900 ppm. Previously collected downhole viscosity samples confirmed >70% viscosity retention prior to being produced through the ESP, while 50-80% of the original viscosity was found to be retained after production through the ESP to the surface facilities under anaerobic conditions for the range of concentrations sampled. These findings demonstrate the resilience of the polymer product to degradation in a real-world operational setting. It also provides data that may be used to estimate the expected downhole polymer solution viscosity from wellhead samples for defined operating conditions. The ability to estimate polymer solution downhole viscosity retention from wellhead samples provides a simpler and less expensive method of estimating viscosity retention than downhole sampling, which is especially useful for wells that do not have downhole access for sample collection.
It has been over 40 years since the publication of an early paper titled 'Polymer Flooding, Yesterday, Today, and Tomorrow' in the Journal of Petroleum Technology (Chang, 1978). Significant progress has been achieved since then, with successful commercial-scale applications in China (Daqing, Shengli, Xinjiang, Henan, and Bohai Bay offshore), Canada (Pelican Lake and Brintnell), India (Mangala), Oman (Marmul), the UK North Sea (Captain), and the USA (Yates, Vacuum, and Milne Point) since then. However, global polymer flooding (PF) production remains below expectations by the industry, particularly in the US (NPC, 1976 and 1984). The objective of this paper is to share our analyses and lessons learned to encourage more commercial-scale applications of PF worldwide. This paper reviews basic concepts, screening criteria, and mechanisms of polymer flooding and analyzes historical PF field activities from the early 1960s through 2023. It then presents reasons for the lower-than-forecast productions. Conventional wisdom holds that low crude oil prices are the roadblock to the commercialization of all chemical flooding. However, our analysis suggests that this is not the case, and there are other reasons for the lower-than-forecast results. Based on the progress made over the decades, we divide PF into three stages: the exploration stage from 1960 through 1980, the development stage from 1981 through 2000, and the commercialization stage from 2001 through 2023, including nine major commercial-scale polymer flooding projects worldwide. We analyzed key factors that impacted PF technology over the years, including the critical amount of polymer used, the impact of reservoir heterogeneity on-field performance, the issue of ineffective polymer recycling, the reversal of injection profile, injectivity and productivity problems, and difficulties in treating produced fluids. After these analyses, we propose a set of design criteria, including reservoir evaluation, polymer selection and slug design, laboratory and simulation studies, pre-commercial field tests, and surveillance/monitoring programs to ensure commercial success. We suggest areas for improvement in future operations, such as enhanced PF combined with other technologies. Future applications of polymer flooding in high-temperature and high-salinity, heavy oil, and carbonate reservoirs are also discussed.
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