You have access to this full article to experience the outstanding content available to SPE members and JPT subscribers. To ensure continued access to JPT's content, please Sign In, JOIN SPE, or Subscribe to JPT Electrical-submersible-pump (ESP) technology is a proven artificial-lift method for shallow, low-pressure reservoirs such as those found in the West Sak viscous oil field in Alaska. However, the unconsolidated nature of the West Sak sands challenges the long-term lifting performance and reliability of conventional ESP systems. The case study in this paper includes the analysis of the two generations of rigless ESP systems, quantifying the success rate in varying conditions in more than 300 rigless ESP replacements in a high-sand, high-deviation environment on Alaska’s North Slope. In 1998, the operator developed through-tubing-conveyed (TTC) ESP (TTCESP)/TTC progressive-cavity-pump (PCP) (TTCPCP) technology to allow failed pumps (ESP or PCP) to be replaced quickly and economically using conventional equipment without a rig.
The development of a new low-carbon operation mode of artificial lift in high-water-cut oilfields, is significant for reducing energy consumption, improving operation efficiency and lowering production costs of oilfields. The annual electric consumption of the oilfield is increasing year by year. In 2016, the total electric consumption exceeded 35 billion kWh, of which the mechanical production system accounts for 57%.
The rodless artificial lift eliminates the use of the sucker rod, and reduces the installed motor power over 50%. The electric consumption is greatly decreased, while tremendous gain is seen in the system efficiency. Moreover, the application performance is especially good for low-production wells. Under such circumstances, the operation cost of the oilfield declines. The current rodless artificial lift is basically based on two types of pumps, namely submersible plunger pump and submersible direct-drive screw pump.
The submersible plunger pump lifts liquid via vertical reciprocation of the moving body driven by the motor, with daily electric consumption of an individual well decreasing by 46%, from 133.4 kWh to 72.5 kWh. The reduced annual electric cost per well is RMB 14,000, and the annual single-well carbon emission falls by 17.5 tons. As for the submersible direct-drive screw pump, the rotation of the pump is directly motivated by the downhole submersible motor, through which the downhole liquid is elevated to the surface. The daily electric consumption of an individual well decreases by 38.4%, from 224kWh to 138kWh, contributing to the annual electric cost reduction per well of RMB 13,600 and annual carbon emission decline per well of 17.1 tons.
The application of the two types of rodless artificial lift has taken initial shape. The submersible plunger pump has been applied to over 200 wells, and the submersible direct-drive screw pump, over 60 wells. The new low-carbon operation mode of artificial lift is critical for the energy saving, efficiency improvement and consequent cost reduction of oilfields, particularly in cases of the industry downturn triggered by low oil prices.
Artificial lift is a technique used to provide energy to the formation fluids in a production well when the pressure of the formation is not high enough for hydrocarbons to flow up the tubing string at an economic rate. Several types of artificial lift can be used to increase the production rate and maximize hydrocarbon recovery. The major artificial lift technologies are beam pumping/sucker rod pumps (rod lift), progressive cavity pumps, hydraulic submersible pumps, electric submersible pumps, and gas lift. Hydraulic submersible pumps (HSPs) (Fig.1) are hydraulic turbine-driven downhole pumps that were developed as an alternative to the more commonly used electric motor-driven submersible (centrifugal or progressive cavity) pumps (ESPs). ESPs are used extensively in oil lift applications--particularly offshore.
Operators generally want to reduce well downtime and repair/replacement costs by improving the reliability of their Artificial lift (AL) systems. In order to understand if actions taken to improve reliability are effective, one must track the AL system run-life. This paper discusses run-life measures commonly used in the AL industry and provides recommendations for when each run-life measure should be used. Synthetic data, generated using random runtime and failure data from known statistical distributions, is used to illustrate the effect of various factors, such as selecting equipment with higher inherent reliability, on the resulting measured run-life. This paper also presents several pitfalls that should be avoided when selecting run-life measures for comparing equipment or implementing operator-vendor alliance contracts.
The Society of Petroleum Engineers (SPE) bestowed technical awards on members whose outstanding contributions to SPE and the petroleum industry merited special distinction. Recipients of the 2013 SPE international awards were recognized at the SPE Annual Reception and Banquet held Tuesday, 1 October at the 2013 Annual Technical Conference & Exhibition in New Orleans, Louisiana. Alhanati, managing director at C-FER Technologies, in Edmonton, Canada, began his career in 1983 as a petroleum engineer at Petrobras. The author or coauthor of 16 SPE papers and coauthor of a chapter in the SPE Handbook on PCP (progressing cavity pump) Systems, he also served as an SPE DL during 2008–09. He served as chair of the SPE Brazil Section during 1993–94, served on various SPE committees and subcommittees, and taught several courses throughout the world on PCP and ESP (electric submersible pump) systems.
Talk to the experts and see the full interactive circle of technologies and competencies in Booth #22. The system can reliably pass through buildup rates up to 25 per 100 ft. Call us or visit BakerHughes.com/CENesisCurve Dear Colleagues, On behalf of the program committee, we are pleased to welcome you to the SPE Artificial Lift Conference--Latin America and Caribbean. You will have the opportunity to explore ideas about the cost-effectiveness, safety, and technology of lift and flow systems in some of the most challenging and promising offshore fields in the world.
Horizontal wells are known to have production challenges as a result of inconsistent slug-fluid flow, damaging solids, and excessive gas interference. Production Plus Energy Services introduced the retrievable Horizontal Enhanced Artificial Lift (HEAL) Slickline System, which provides greater access to the wellbore, easier installation, simpler integrity testing, and an economical protection solution for damaging offset interwellbore communication. With no moving parts, the system easily joins to the horizontal as part of a standard well completion and is designed to perform for the life of the well. The system is part of a set of configurations that offers producers increased efficiency, more cost options, and the flexibility to enhance the performance of any artificial system, including electrical submersible pumps, rod pumping, progressive cavity pumping, and plunger lift through the life of a horizontal well. The products in the HEAL suite are designed to benefit a horizontal well’s entire producing life—controlling fracturing flowback, extending the natural flow period, simplifying transitions between artificial-lift phases, lowering operating expenses, and eliminating costly intermediate artificial lift.
Horizontal wells are known to have production challenges as a result of inconsistent slug-fluid flow, damaging solids, and excessive gas interference. Production through the life cycle of these wells often requires complex and expensive artificial-lift strategies. Production Plus Energy Services introduced the retrievable Horizontal Enhanced Artificial Lift (HEAL) Slickline System, which provides greater access to the wellbore, easier installation, simpler integrity testing, and an economical protection solution for damaging offset interwellbore communication. With no moving parts, the system easily joins to the horizontal as part of a standard well completion and is designed to perform for the life of the well. The system is part of a set of configurations that offers producers increased efficiency, more cost options, and the flexibility to enhance the performance of any artificial system, including electrical submersible pumps, rod pumping, progressive cavity pumping, and plunger lift through the life of a horizontal well.
Like all production companies Occidental Petroleum (Oxy) is continually searching for new and creative ways to increase production and lower operating costs. Artificial Lift is a major focus due to the large annual expenditures on equipment and electrical power consumption. Oxy faces unique challenges in its Enhanced Oil Recovery (EOR) operations in the Permian Basin where miscible carbon dioxide (CO2) and water flooding are utilized resulting in wells with high gas to liquid ratios (GLR) that challenge the gas handling capabilities of electrical submersible pumps (ESP's). While initially designed for high temperature steam flood applications Geared Centrifugal Pumps (GCP's) have several design advantages that make them attractive to use as an alternative lift option. A GCP is an artificial lift system which utilizes a Progressing Cavity Pump (PCP) drive head and rod string to drive an ESP style centrifugal pump through a downhole speed increasing transmission. The GCP design has the rate capacity of an ESP, but eliminates a downhole motor and power cable. By eliminating the downhole motor the GCP design delivers the ability to run a dip tube below the pump without a shroud through the perforations which should improve natural downhole gas separation. In order to test the performance of the GCP system Oxy chose to conduct a trial in three Permian Basin wells in one of its miscible CO2 floods. The key objective of the trial was to compare the performance of the GCP system with the previously installed lift methods to confirm if there is an opportunity to increase drawdown, increase daily up time, improve system efficiency, and increase run life. As of the writing of this paper two GCP systems have been installed as part of the trial with one of the installations still being in operation. This paper will present the details of the trial and the results that have been obtained thus far as well as challenges and lessons learned.