This paper discusses technical challenges and technology development opportunities associated with developing and producing offshore heavy oil (OHO) reservoirs, with emphasis on projects in cold or deep waters. The paper addresses how the reservoir and fluid characteristics will impact reservoir characterization, development concept selection, well construction, reservoir performance, artificial lift requirements, flow assurance, and operations. The applicability of common onshore heavy oil practices to OHO developments will be discussed. Emerging technologies and technology development opportunities will also be discussed. The material presented in this paper will be of particular interest to technology development personnel and asset team personnel who are in the appraisal or concept selection stages of a project; however, additional information is provided which may also be valuable later in the project life.

Gas lift completions for steam-assisted gravity-drainage (SAGD)(1) producers are unique. Conventional gas lift valves and mandrels with a packer completion cannot be used because of the extreme temperatures of the downhole environment. Most lift gas enters the production stream downhole through open-ended tubing or nozzles, which if not properly sized can result in operational issues such as fluid/gas slugging and pressure instabilities that negatively impact the overall lift efficiency. In 2006, ConocoPhillips conducted a study to design a gas lift system for the Surmont SAGD development that would allow better control of lift gas into the production string. In late 2007, the wells completed with gas lift were placed on production. This paper covers the data-collection effort and analysis completed to determine the efficiency of the two types of gas lift nozzles used in the completions, the methodology for optimization of SAGD gas-lift systems, and recommendations for future improvement. Background Surmont, an in-situ oil-sands project, is located approximately 60 km southeast of Fort McMurray in the Athabasca oil sands (Figure 1). This multiphase SAGD project is a 50:50 joint venture between ConocoPhillips Canada Ltd. (CPC) and Total E&P Canada Ltd., with CPC as the operator. The Surmont pilot began injection of steam in 1997. The pilot comprises three SAGD well pairs that use a variety of artificial-lift methods. These wells have been tested to determine the preferred method of artificial lift for the first commercial phase. Steam injection, for Phase 1A of the commercial development, was initiated in mid-2007. Conversion to full SAGD production followed in late 2007. Phase 1A comprises 20 well pairs in which all the producers have been completed to produce through gas lift for the initial life of the well. Phase 1 (A, B, and C) has a capacity of 3,975 m3/d (25,000 B/D) and is expected to reach peak production in 2012. A second phase is slated for commercial startup before the middle of the next decade. Upon completion and full ramp-up, it is estimated to bring peak production from both phases to 15,899 m3/d (100,000 B/D). Additional phases at Surmont are also under study.

ConocoPhillips has been on a quest for a high-volume artificial lift system that will operate reliably in a 250°C (482°F) downhole environment. This paper will describe the testing and results of a high-temperature electric submersible pump (ESP) system in a flow loop built to validate downhole equipment for thermal applications, primarily for steam assisted gravity drainage (SAGD) developments. What makes this test program unique from previous tests is the longer duration (4+ weeks), the range of fluid temperatures (90°C to 245°C [194°F to 473°F]), and the type and volume of data collected. One of the key parameters monitored and documented was the internal motor winding temperature, which has been used to validate and calibrate a simulator for predicting motor performance in thermal environments. Background The group was tasked to find, select, and further support the development of artificial lift technology with the capability of handling fluid rates up to 1,000 m3/d at 250°C [6,290 B/D at 482°F] downhole conditions. The goal was not to just find and validate a single system, but to qualify several lift systems to provide the production engineers with a toolbox of solutions. This challenge was approached as two different projects: find, select, and further develop potential lift systems with the needed volumetric capability; and validate these systems through high-temperature testing. The latter was considered to be the bigger challenge. ConocoPhillips did not operate any fields with downhole temperatures close to 250°C [482°F], so validation via field trial was not possible. A more controlled test facility was preferred, so that a comprehensive suite of performance curves could be collected to define the full operating envelope for each lift candidate. A test facility that was not associated with a specific pump vendor was also preferred to avoid the legal and confidentiality issues with testing third-party equipment. It was decided that an existing high-temperature flow loop located at C-FER Technologies Ltd, in Edmonton, Alberta, Canada, was the best option for the artificial lift validation testing. The loop had been built as part of a joint industry project (JIP)1 in 2004, but needed to be upgraded for testing at 250°C [482°F]. ConocoPhillips contracted C-FER and funded the project entirely. Two lift systems have been tested to date in the flow loop after the high-temperature upgrade was completed in mid-2008. This paper focuses on the results of the second test program, which evaluated a Schlumberger high-temperature ESP system, developed for operation in thermal environments. Introduction In 2008, there were no commercially available ESP systems rated for 250°C [482°F] downhole environments. So, one of the existing systems was selected for testing to fully understand what would happen to the ESP components when the system was operated at or beyond the maximum temperature rating. The results would help determine how close the existing technology really is to reaching operation at the 250°C [482°F] target temperature, and, depending on the outcome, to help direct research funding into the appropriate places.

ConocoPhillips has been on a quest to find a high volume artificial lift system that will operate reliably in a 250°C (482oF) downhole environment, which exists in certain SAGD applications. This presented two problems:there were no commercially available technologies for such a high temperature; andthere were no facilities capable of testing these systems. This paper describes the complexity of building and operating a high temperature flow loop rated for 250°C, and the lessons learned while upgrading an existing flow loop, from the initial design through the final commissioning phases. The paper also describes the issues encountered with the first artificial lift system tested at 250°C, which was a metallic stator progressing cavity pump system, rated for 1100 m3/d (6919 bpd) at 500 rpm. In the end, the test program not only served to validate and define the pump's performance, but also provided valuable lessons on the completion configuration and operational procedures. Introduction The ConocoPhillips technology group was tasked to find, select, and further develop artificial lift technology with the capability of handling fluid rates up to 1000 m3/d at 250°C (6290 bpd at 482oF) downhole conditions. The goal was not to just find and validate a single system, but to qualify several lift systems, in order to provide the production engineers with a "toolbox" of solutions. This challenge was divided and approached as two different projects:find, select and further develop potential lift systems with the needed volumetric capability; andvalidate these systems through high temperature testing. The latter was considered to be the bigger challenge of the two. ConocoPhillips did not operate any fields with downhole temperatures close to 250°C, so validation via field trial was not possible. A more controlled test facility (whether a well or flow loop) was also preferred, so that a comprehensive suite of performance curves could be collected to define the full operating envelope for each lift candidate. A test facility which was not associated with a specific pump vendor was also preferred, to avoid the legal and confidentiality issues with testing third party equipment. ConocoPhillips decided that an existing high temperature flow loop located at C-FER Technologies Ltd, in Edmonton, Alberta, Canada was the best option for the artificial lift validation testing. The loop had been built as part of a Joint Industry Project (JIP)1 in 2004, but needed to be upgraded to allow for testing at 250°C. This was a costly endeavor, and ConocoPhillips and C-FER contacted other Canadian SAGD operators to see if the upgrade could be completed as a JIP, thus sharing the capital cost among several interested parties. However, no other operators were interested in upgrading the loop at the time, so ConocoPhillips proceeded to fund the project entirely.

Providing a stable production stream with minimal GLR fluctuations to surface is a critical factor when designing gas-lift systems for subsea applications. As well intervention methods are very costly, the sub-surface gaslift equipment must be designed for the life of the well and the unloading and operating procedures must be tailored to minimize erosion of the gaslift valves and orifice.For the Angola Kuito Development, dynamic modelling was used to determine the optimum orifice size for long term operability over a given range of injection rates, water cuts, and productivity indexes. The dynamic model also aided in the development of start-up procedures that minimized erosional effects on the downhole orifice and helped to answer questions regarding cyclic production pressures at the subsea wellhead. Through a variety of charts and graphs, this paper will describe the methodology used for this detailed design process. Results of the study led to the purchase of different downhole and FPSO (floating production storage and offloading vessel) components for the gas injection system than originally planned and greatly modified the well completion and start-up procedures.Using dynamic modeling for gas lift design is relatively new to the oil and gas industry. Dynamic modelling is a powerful tool, that when used properly, leads to better gas lift designs and increases confidence levels in the reliability and performance of the system.The field was placed on production late 1999 and the gas lift system is expected to start-up February 2000.