Leismer is the first Statoil operated steam-assisted gravity drainage (SAGD) project in the Athabasca region of Alberta, Canada. Electrical submersible pumping systems (ESPs) are the standard artificial lift method for this project. A field trial was planned for newly developed ESPs rated to 250°C. The increased temperature rating allows operating SAGD chambers at higher pressures, thus providing more operational flexibility for increasing recovery and dealing with common exploitation problems. The field trial required reliable and comprehensive down-hole monitoring, so that thorough ESP performance analysis could be performed under real field conditions. Given the extreme conditions at which ESP systems operate in SAGD, fiber optic pressure and temperature sensors were selected for real-time down-hole monitoring. These sensors were placed at the pump intake, inside the motor and at the discharge. The fiber optic gauges’ performance is comparable to standard SAGD measurement devices, but without some of the disadvantages. The sensing system configuration, ESP interface and installation will be described. This paper will also present the value of real-time ESP monitoring. The pump operation is controlled by continuously history matching performance with well performance software and adjusting parameters to changing down-hole conditions. This ensures the ESPs are run near the best efficiency point. Pump intake sub-cool is controlled to minimize steam flashing occurrence. ESP motor temperature is monitored to boost reliability and run time. Finally, discharge pressure measurement has been used for history matching multiphase flow correlations. This improves ESP performance calculation accuracy in the field’s other wells. Integrating ESP advances with fiber optic measurement has allowed effective local technology qualification under real operating conditions. This project has provided abundant information and knowledge for field-wide production optimization.

As Permanent Magnet Motors (PMMs) become more widely used because of their many benefits, awareness of the potential safety hazards arising from their differences from Induction Motors (IMs) is important. Due to their construction, the magnetic field presence is always "on" with PMM – even when not under energized electrical energy. PMMs are AC generators when freely rotating forward or backward. Elevated safety consciousness is needed to avoid serious injury or fatality when working with PMMs. This paper presents operational procedures for installing, pulling, troubleshooting, and handling PMMs with a focus upon safety. Hazards have been identified, and some mitigations are recommended to eliminate the potential danger and bring awareness to the petroleum industry (and others) to ensure that all workers go home safely. The observations presented in this paper came directly from field experience with operators, equipment manufacturers, and service providers.

Objectives/Scope The performance of artificial lift systems on horizontal wells is greatly influenced by both the volume of gas produced and the tendency for gas slugging. With a sucker rod pump (SRP) system, this behaviour leads to gas interference at the pump, reducing system efficiency and equipment run life. With an electric submersible pump (ESP), gas slugs can cause cycling of the ESP, which may significantly shorten its run life. A trial project was launched to evaluate the performance of two tailpipe systems that could be applied to both forms of artificial lift to achieve the following goals: Methods, Procedures, Process Two tailpipe systems were tested in a number of wells using both SRPs and one ESP for lift. The systems differ in both separator design and packer location. The first uses a conventional packer-style gas separator with a reduced inner diameter (ID) tailpipe extending below the separator and past the KOP. The second uses a specialty cyclonic separator with a reduced ID tailpipe, and the packer is located at the lower end of the tailpipe. Some of these installations are outfitted with downhole gauges (DHGs) measuring pressure and temperature at several points along the tailpipe. The DHGs recorded pressure at the tailpipe inlet, tailpipe outlet, pump intake pressure, and pump discharge pressure. This surveillance package allowed for real-time monitoring of the performance of both the tailpipe and the artificial lift system, while also providing data for modelling the flow regime through the tailpipe. The modelling results were used to forecast long-term performance of the system as the well production declines over time. Results, Observations, Conclusions Results from the field trial show the performance of each system from a variety of standpoints: changes in flowing bottomhole pressure, flowing behaviour through the tailpipe, separation effectiveness, and changes in production. Challenges were noted, and potential solutions or courses of investigation are proposed. Conclusions were drawn regarding the overall effectiveness of the concept, as well as the relative effectiveness of the two systems. Novel/Additive Information We examined the differences between two tailpipe systems regarding the isolation location, whether at the top or bottom of the tailpipe, to aid us in designing future systems. A comparison of the two separators was attempted, and various operational challenges are discussed so as to improve the design, installation, startup, and operation of these systems.

Electric Submersible Pumps (ESPs) are severely affected by free gas entering into the pump, which can cause significant degradation in pump performance. Gas locking (i.e., a gas bubble blocking the fluid from passing through the impeller) results in frequent shutdowns and restarts, thereby increasing the risk of premature failure. The result is unstable production due to ESP shutdowns caused by underload or high motor temperature. Historically, the industry has used shrouds, reverse flow gas separators, dynamic gas separators, and more recently, multiphase pumps to handle the gas. Such multiphase gas handling technology adds cost and requires additional power. Recently Oxy Permian EOR installed a multiphase encapsulated production solution to separate the gas from the liquid in the wellbore. As produced fluids pass the pump at high velocity, the heavier liquid falls back into the shroud in a low-velocity area between the tubing and the top of the shroud, allowing the gas to continue to the surface. This system has proven to separate the gas from the liquid effectively, stabilizing operations within a certain operating window. In this paper, we share field examples showing the results achieved and how uptime improved over the last year. Twenty-four (24) systems have been installed in the Permian Basin with a 99% reduction in the number of shutdowns. All have had improved operational performance, with an average 30% improvement in drawdown and a 16% increase in total fluid production. These particular fields are constantly being injected with CO2, which presents even more challenging conditions for ESPs than merely solution gas. As the CO2 enters the wellbore, the liquid stream composition changes, as does the gas/liquid ratio (GLR), making it difficult to draw down and function consistently over time. Many different systems have been tried with varying degrees of success. This system has proved to be successful in attaining our objectives of higher drawdown, stable operations, and fewer failures.