Abstract Identifying and prioritizing reliability improvement opportunities for ESPs, requires proper consideration of hundreds of parameters that include equipment characteristics, operational conditions, and root cause analyses results (Brookbank, E. B., 1997). One of the main challenges is that this data typically resides in a variety of commercial software products used internally by ConocoPhillips Canada as well as various other repositories such as spreadsheets, PDFs and numerous other internal databases and usually needs to be manually integrated for analysis. A second challenge is how to easily and consistently data mine such an extensive dataset. This paper presents the approach taken, hurdles faced, and results obtained to effectively address both challenges above. First, a failure database was designed to automatically capture time continuous data flows from various data streams, many of them flowing from commercial software tools but also some via email. To address the second challenge, an advanced visualizations and data analytics layer was developed to mine the database, in order to estimate various reliability and optimization metrics, uncover trends and generate forecasts instantaneously. Our solution was to create a unique cradle to grave ESP tracking and visualization integrated system, supporting the complete ESP reliability engineering workflow. It includes vendor to operator ESP equipment data transfer, database and nomenclature structure, operational data capture during the life of the ESP and RCA results data capturing via a 3party low-code application development platform (LCADP). A visualization layer for data analytics and reliability metrics was seamlessly integrated through the use of a commercial software analytics and visualization platform (AVP). Results to date are very encouraging, both in terms of efficiency gains and quality of analysis and results. Consistent use of reliability metrics when used by different members of the production team have been achieved. Lessons learned during the development and specific examples on how the system is being used are presented, including AVP based trend visualization and failure forecast estimations. Key examples of the value captured with this Failure Database and Visualization Platform are also presented, including improved data quality, increased analytical capabilities and enhanced understanding of reliability improving options. The overall net benefit being optimized ESP life cycle costs. This development has the potential to be easily extended to other downhole production equipment such as fiber optic strings, liners, flow control devices, steam splitters and other artificial lift methods utilized in SAGD such as progressing cavity pumps.
Abstract The combination of well conditions such as high levels of carbon dioxide (CO2, an average of 15%), 85% water cuts (WC), sand production, and heavy viscous oil is one of the biggest challenges for any artificial lift system (ALS). Progressing cavity pumping (PCP) is the preferred method for sand and heavy oil production; however, CO2 presence in the form of carbonic acid, generates corrosion and pitting on the carbon-steel section of the Progressing Cavity stators. This condition results in short run life for PC pumps with standard materials historically installed. Taking advantage of the corrosion strength properties that Stainless Steel (SS) material has, a new SS PC pumps were manufactured to be installed in highly corrosive application and then determine the increase on run life for those wells previously affected by corrosion. This paper describes a section of the results from the flow assurance improvement plan obtained by the installation of PC pumps with SS technology in terms of workover (WO) intervention savings and extended run life in nine wells operating in Gabon, West Africa. This paper describes the methodology applied in the selection of the PCP models to be manufactured with Stainless Steel technology considering the dimensional restrictions the PCP would have due the casing size of the well completions where the PC pump would be installed, as well as the pump design requirements related to the expected flow rate in the wells historically affected by corrosion. In addition, the paper shows the screening done on the well candidates for the installation of SS PCP, based on historical well intervention data specifically associated to corrosion. Since the installation of the SS PCP technology, the client has performed several acid stimulations that have required pulling the PC pumps out of hole and re-running them multiple times. Throughout these operations, the PCPs have had no failures requiring intervention. The installation of SS technology has improved well run life across all nine candidates by 584% on average. The SS PCP technology continue to run in all nine wells with no corrosion-associated interventions. For an average of 326 days across all nine wells, there have been no WOs performed on the PCPs. The reduction in WOs has helped to avoid production losses, downtime, and associated costs. SS PCP has shown great results extending PC pump run life over 6 times compared to previous applications and has proven to be a good option for larger flow rates in 5.5 in casing completions.
Summary Gerotors are positive displacement pumps and potential artificial lift options in the oil and gas industry. This study presents the performance characteristics from physical testing of a unique one-stage, equal-walled gerotor pump design operating in oil and oil/air mixtures. The pump was tested at various rotational speeds in a flow loop. The performance results were obtained to ascertain potential design optimizations of the pump before embarking on manufacturing and testing of the field prototype pump. A physical prototype of a one-stage 400 series gerotor pump, suitable for application in a 5.5-in. casing, was designed, manufactured, assembled, and tested. Mineral oil and air were used as the operating media. For given pump outlet valve settings, the pump rotational speeds were set to 200, 250, 300, and 350 rev/min. Gas volume fractions (GVFs) at the pump inlet were varied from 0% to the maximum the current pump design could handle. For each test point, the corresponding pump parameters were measured. Dimensionless performance plots were established for obtaining pump performance at other flow conditions. The results showed that pump flow rate decreased with increasing differential pressure, typical of positive displacement pumps. At 200 and 350 rev/min, maximum pump delivery is approximately 190 and 330 B/D of oil, respectively, at zero differential pressure. The pump can supply flow against a differential pressure of up to approximately 5.5 psi at 200 rev/min and 15 psi at 350 rev/min. For the 200 to 350 rev/min speed range, volumetric efficiencies varied from 30 to 73%, whereas the electric power input varied from 145 to 191 W. When pumping oil/air mixtures, the current gerotor pump design can handle 15% GVF maximum, at 250, 300, and 350 rev/min. For certain pump outlet pressures, the total fluid flow rates decreased as the GVF increased to 15%. The volumetric efficiencies at 15% GVF varied from 32 to 53% for the 300 to 350 rev/min speed range, whereas the motor electric power input decreased with increasing GVF up to 15%. In conclusion, increasing the pump rotational speed improves the volumetric efficiency and gas-handling capability of the gerotor pump. These observations will aid in the required design optimization to enhance the performance of the future field prototype gerotor pump. This study presents the capabilities of gerotors as potential artificial lift alternatives to handle liquid and gas/liquid mixtures for boosting applications in oilfield operations. The technology with additional design optimization can be readily integrated into oilfield equipment architecture. The mechanical simplicity of gerotors and their compactness provides a promising artificial lift substitute that may be implemented for downhole or surface production of liquid or gas/liquid mixtures in the oil and gas industry.
For a low-pressure well with solids and/or heavy oil at a depth of less than approximately 6,000 ft and if the well temperature is not high (75 to 150 F typical, approximately 250 F or higher maximum), a PCP should be evaluated. Even if problems do not exist, a PCP might be a good choice to take advantage of its good power efficiency. If the application is offshore, or if pulling the well is very expensive and the well is most likely deviated, ESPCP should be considered so that rod/tubing wear is not excessive. There is an ESPCP option that allows wire lining out a failed pump from the well while leaving the seal section, gearbox, motor, and cable installed for continued use.
Artificial lift is a method used to lower the producing bottomhole pressure (BHP) on the formation to obtain a higher production rate from the well. This can be done with a positive-displacement downhole pump, such as a beam pump or a progressive cavity pump (PCP), to lower the flowing pressure at the pump intake. It also can be done with a downhole centrifugal pump, which could be a part of an electrical submersible pump (ESP) system. A lower bottomhole flowing pressure and higher flow rate can be achieved with gas lift in which the density of the fluid in the tubing is lowered and expanding gas helps to lift the fluids. Artificial lift can be used to generate flow from a well in which no flow is occurring or used to increase the flow from a well to produce at a higher rate.
Summary Linear network models are promisingly simple progressive cavity pump design tools. Current linear network models are difficult to use in the design process because they require calibration against experimental data or computationally intensive simulation. In this paper we present new approaches for implementing linear network progressive cavity pump models and provide new methods to accurately and quickly estimate the values of each resistor in the model from pump geometry for both laminar and turbulent flows. This paper also argues that sealing-line flow transitions from laminar to turbulent at orders of magnitude smaller Reynolds numbers than described in the literature thus far. We propose a new hypothesis for the point of transition to turbulent performance.
Artificial lift is a critical technology used to keep wells producing when they are incapable of providing enough energy--in the form of pressure--to produce liquids to surface at economic rates. Most development plays throughout the world would be uneconomic without artificial lift. JPT Features Editor Joel Parshall, in his March 2013 JPT article titled, "Challenges, Opportunities Abound for Artificial Lift," writes There is no global repository of artificial lift statistics; however, industry observers estimate that 90% to 95% of the world's producing wells currently use artificial lift, said Bill Lane, vice president of artificial lift systems emerging technologies at Weatherford. "It is trending more toward 95% than 90%, and probably 100% of producing wells would use artificial lift at some point in their lives, except for wells shut in prematurely because of economic factors." The 2014 SPE Artificial Lift Conference and Exhibition for North America, held in Houston 6–8 October, ...
The A East Haradh formation contains a 200-m-thick oil column of highly viscous oil, with viscosity ranging from 200 to 400,000 cp. Because of the high viscosity, first production was considered possible only by the use of thermal enhanced-oil-recovery techniques, starting with cyclic steam stimulation (CSS). This paper presents key learnings derived during this initial-operations phase of CSS in the A East Field, including key trial results on different well completions and artificial-lift systems. In light of the results of a new geochemical characterization study of the crude extracted from a core, cold production was deemed feasible in the crestal area of the field. Viscosities at the top of the Haradh were estimated at 200 cp, lower than previously thought, and progressing cavity pumps (PCPs) were installed in 32 wells to start a cold-production phase.
Artificial intelligence (AI) has captivated the imagination of science-fiction movie audiences for many years and has been used in the upstream oil and gas industry for more than a decade (Mohaghegh 2005, 2011). But few industries evolve more quickly than those from Silicon Valley, and it accordingly follows that the technology has grown and changed considerably since this discussion began. The oil and gas industry, therefore, is at a point where it would be prudent to take stock of what has been achieved with AI in the sector, to provide a sober assessment of what has delivered value and what has not among the myriad implementations made so far, and to figure out how best to leverage this technology in the future in light of these learnings. When one looks at the long arc of AI in the oil and gas industry, a few important truths emerge. First among these is the fact that not all AI is the same. There is a spectrum of technological sophistication. Hollywood and the media have always been fascinated by the idea of artificial superintelligence and general intelligence systems capable of mimicking the actions and behaviors of real people. Those kinds of systems would have the ability to learn, perceive, understand, and function in human-like ways (Joshi 2019). As alluring as these types of AI are, however, they bear little resemblance to what actually has been delivered to the upstream industry. Instead, we mostly have seen much less ambitious “narrow AI” applications that very capably handle a specific task, such as quickly digesting thousands of pages of historical reports (Kimbleton and Matson 2018), detecting potential failures in progressive cavity pumps (Jacobs 2018), predicting oil and gas exports (Windarto et al. 2017), offering improvements for reservoir models (Mohaghegh 2011), or estimating oil-recovery factors (Mahmoud et al. 2019). But let’s face it: As impressive and commendable as these applications have been, they fall far short of the ambitious vision of highly autonomous systems that are capable of thinking about things outside of the narrow range of tasks explicitly handed to them. What is more, many of these narrow AI applications have tended to be modified versions of fairly generic solutions that were originally designed for other industries and that were then usefully extended to the oil and gas industry with a modest amount of tailoring. In other words, relatively little AI has been occurring in a way that had the oil and gas sector in mind from the outset. The second important truth is that human judgment still matters. What some technology vendors have referred to as “augmented intelligence” (Kimbleton and Matson 2018), whereby AI supplements human judgment rather than sup-plants it, is not merely an alternative way of approaching AI; rather, it is coming into focus that this is probably the most sensible way forward for this technology.
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. In this first-generation rigless ESP system, a rig deploys conventionally, on tubing, the electric cable, motor, and seal sections, with a special latching device that allows the pump (only the pump, not the motor or seal) to be pulled and replaced by use of slickline (SL) or coiled tubing (CT), without a rig.