Excessive solids production and liner issues are familiar complications in maturing SAGD operations, potentially causing well integrity concerns. There are several factors that can occur, in isolation or in combination, to cause excessive solids production and/or liner failures in SAGD wells. Reservoir characteristics, well construction and known downhole conditions contribute to production results and potential liner degradation over time. The production strategy typically considers fluid mechanics, metallurgy, and thermal cycling to limit steam breakthrough, channeling, and/or low sub-cool events. Even with the best construction and production practices, the gradual accumulation of solids in a production well can limit optimal productivity. SAGD Operators may choose a downhole intervention to mitigate the potential of a future failure or require an intervention to prepare for liner remediation. The paper begins by outlining common cleanout methods used in SAGD wells. Then, it discusses a SAGD downhole intervention in three stages: (1) a jetting venturi cleanout, (2) a gauge mill run, and (3) installation of a remedial liner system. The jetting venturi cleanout is comprised of concentric coiled tubing coupled with an engineered jet pump. It is designed to artificially lift wellbore materials, cleaning the SAGD wellbore while recording the volume of solids returned from a specific location. The gauge mill run confirms an acceptable diameter for smooth liner installation. These first two stages ensure seamless installation of the remedial liner system to mitigate detrimental mechanisms that limit production or impact well integrity. Two case studies, in two heavy oil formations from two Operators, support the effectiveness of the SAGD liner intervention. The case summaries and results demonstrate the success of the SAGD liner intervention, corroborate its consistent and repeatable use and show its compatibility with remedial techniques in SAGD operations. The paper establishes the importance of effectively cleaning and clearing a SAGD wellbore in preparation for liner remediation and to provide insight into future well integrity operations.
This paper describes the steps taken in the planning, design, and field implementation of an enhanced artificial lift system to address the common challenges of conventional ESP installations. A set of case studies, in two basins, reviews the field installations and sequential optimization to achieve an improvement in ESP performance. Unconventional horizontal wells have the complexity of depth, temperature, fluid composition, and rapidly declining production rates. Most artificial lift systems struggle and inadequately cope with inconsistent slug flows from a horizontal wellbore, foamy fluids, damaging solids and gas interference. In ESPs, gas interference frequently overheats the motor resulting in excessive shut downs and/or premature failures. The root cause of gas interference is flow from the horizontal wellbore that tends to be sluggy with inconsistent mixtures of gas and liquid. A downhole flow conditioning artificial lift technology designed to smoothen and suppress slug flows prior to the ESP dramatically improved ESP performance. Field implementation revealed that the technology conditioned the flow and successfully reduced slug flow behaviour showing consistent rates and pump intake pressures. With the slug flow issue resolved, this revealed an unaddressed problem not previously noted with conventional ESP installations caused by liquid lifting in the small annular space adjacent the pump. With high enough gas rates, liquid lifting past the ESP can occur, starving the pump of liquid, overheating the motor, resulting in shutdowns. In initial field trials, this problem limited the ability to drawdown past 800 psi intake pressure. Subsequent field trials solved the problem by manipulating pump intake pressure or reducing equipment size for higher gas rate wells resulting in significantly lower pump intake pressures and improved ESP reliability. The paper describes consecutive cases that implement stepchange modifications to resolve both slug flows to the ESP and annular liquid lifting past ESPs. The optimized design resulted in an extended range of pump operability, improved reliability and enhanced control and reservoir management.
Plunger lift is a popular low operating and capital cost lift method for high gas-liquid ratio (GLR) wells that cannot unload naturally, particularly in deep, liquids-rich gas, horizontal plays common today. Plunger lift is challenged by lengthy plunger travel time, greatly increased GLR requirements, and liquid loading effects in the build section of the well. This paper explores the implementation of an artificial lift technology designed to enhance the performance of artificial lifts systems and for cost-effective artificial lift transitions over the life of a well. It will extrapolate upon the challenges associated with developing a total life-cycle artificial lift strategy for today's unconventional plays in the Permian Basin. Discussion begins with an overview of the theoretical challenges of designing a life cycle artificial lift strategy with a conventional system in the face of sluggy flow and high decline rates from the horizontal. The paper then proposes an artificial lift approach to suit this challenge. The paper then presents an overview of plunger lift optimization challenges experienced in horizontal well production strategy from frac-flowback to abandonment. It explores the characteristics unique to plunger lift and demonstrates the connection between slug flow mitigation and improved plunger lift efficiency. The result is a discussion of a new, slickline swappable, artificial lift technology for plunger lift systems that mitigates slug flow, thereby enabling efficient plunger lifting at considerably lower GLRs, through the life of the well. Case studies and field trials in the Permian field illustrate implementation and results of the artificial lift technology to cost effectively transition from natural flow to plunger lift and on to rod pumping, with optionality to provide low cost and safe frac-hit protection from offsetting wells. Results demonstrate production increases with reduced CAPEX and OPEX.
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