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Collaborating Authors
Results
Offshore ESP Selection Criteria: An Industry Study
Romer, Michael C. (ExxonMobil Production Company) | Johnson, Mark E. (ExxonMobil Production Company) | Underwood, Pat C. (ExxonMobil Production Company) | Albers, Amanda L. (ExxonMobil Production Company) | Bacon, Russ M. (R.M. Bacon Engineering Ltd)
Abstract Most offshore wells that require artificial lift are gas lifted, as gas typically is readily available and compared to other lift systems, gas lifting is relatively inexpensive and low maintenance. However, electric submersible pumps (ESPs) can efficiently and economically increase oil production and reserves recovery under the appropriate operating conditions. This may translate to a lower abandonment pressure in the long termโpossibly reducing the total number of wells required to deplete an asset. Since few ESPs currently are installed in offshore wells, an ESP screening "Rules of Thumb" was created as a simple guide for prioritizing offshore ESP candidates. The selection criteria focus on feasibility of installation, operability conditions and operating practices to maximize run life, and economic considerations. ExxonMobilโ and industry experience from North America, South America, West Africa, Asia, Australia, the Middle East, and the North Sea provided the basis for the study.
- Asia > Middle East > Qatar (0.68)
- North America > United States > Texas (0.49)
- Europe > United Kingdom > North Sea (0.48)
- North America > United States > California (0.46)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Block BM-C-7 > Peregrino Heavy Field (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Block BM-C-47 > Peregrino Heavy Field (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Dampier Basin > WA-191-P > Block WA-27-L > Mutineer-Exeter Field > Exeter Field > Angel Formation (0.99)
- (10 more...)
- Production and Well Operations > Artificial Lift Systems > Gas lift (1.00)
- Production and Well Operations > Artificial Lift Systems > Electric submersible pumps (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (0.93)
Abstract The plans for many of the upcoming deepwater projects involve the use of highpower Electrical Submersible Pump (ESP) Systems for Artificial Lift. However, the perception in the industry is that the average run-life currentlyachievable with such high power ESP Systems is much shorter than what would bedictated by robust project economics, given that intervention costs in theseapplications can be very high, in the US$50MM - 75MM range. Therefore, theconsensus among operators is that there is a need to try and improve thereliability of these systems. In response to this industry need, DeepStarยฎ recently commissioned a gap studytowards identifying the barriers that may be preventing ESP Systems fromachieving the desired reliability as well as the additional R&D effort thatmay be required for the industry to close the existing gap. DeeepStarยฎ providesa forum for deepwater technology development, while leveraging the financialand technical resources of the industry (). This paper presents a summary of the results of this study, including:the Mean Time To Failure (MTTF) that people believe is currently achievable (i.e.with current technology); the biggest differences about these applications, which introduce additional uncertainty to the ability of the system to performreliably; the main sources of uncertainty regarding each of the major ESPSystem component's reliability; and the tentative plan that was outlined aspart of the project, to address the gaps that were identified. The Gap Analysis was based on phone interviews conducted with recognizedindustry experts, on discussions that took place with members of a TechnicalCommittee (TC) that was put in place for the project, and on a broader industrysurvey conducted through the internet. The proposed go-forward plan consists oftwo follow-up projects: one focused on improved system design and operationalpractices, including system monitoring (or surveillance) and control; and onefocused on validating the design of key components of concern, for thespecifics of these applications, through laboratory testing. The proposednear-future R&D effort has the support of major operators, but still needsto be fine-tuned, with input from the industry, before the actual work canproceed with buy-in and financial support from all of the partiesinvolved. Introduction The Oil and Gas industry continues to move towards more challengingexploitation environments offshore: deeper water (over 10,000 ft), longertie-backs, deeper reservoirs (up to 20,000 ft below the mud line), and/or withhigher viscosity oil. The plans for many of the major projects currentlyunderway in such offshore environments involve the use of relatively high powerElectrical Submersible Pump (ESP) Systems for Artificial Lift. These include, for instance: Shell's " Parque das Conchas" and Petrobras' " Parque das Baleias" in Brazil's Campos Basin, as well as Shell's Perdido, Petrobras' Cascade andChinook, and a few other projects in deep waters in the US' Gulf of Mexico(GOM) such as Chevron's Big Foot. Operating in these extreme environments will likely require deploying newproduction systems (e.g. with subsea boosting) and/or new generations of ESPequipment. While individual well production rates can exceed 20,000 bpd of oil, understanding of well performance is usually only marginal at the time ofsystem design and installation. Intervention costs in these scenarios can bevery high, sometimes in the US$50MM - 75MM range (per intervention). Productionlosses following an equipment failure can also be quite significant, especiallyfor wells with higher production rates. Therefore, the economic success ofthese projects is closely linked to the ability to minimize the number ofinterventions for equipment repair and maximize production uptime. Thisrequires not only using highly inherently reliable equipment but also havingthe best possible design and operational practices in place, in order to beable to actually realize the whole reliability potential of the equipment. Astated goal by some operators is to have 95% confidence that a 5 year run-lifecan be obtained from the ESP System, despite this very challenging operatingenvironment.
- South America > Brazil (1.00)
- North America > United States > Texas > Harris County > Houston (0.15)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > South America Government > Brazil Government (0.45)
- South America > Brazil > Campos Basin (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Dampier Basin > WA-191-P > Block WA-27-L > Mutineer-Exeter Field > Exeter Field > Angel Formation (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Beagle Basin > Dampier Basin > WA-191-P > Block WA-27-L > Mutineer-Exeter Field > Exeter Field > Angel Formation (0.99)
- (6 more...)
From Operations to Desktop Analysis to Field Implementation: Well and ESP Optimization for Production Enhancement in the Cliff Head Field
Dholkawala, Z.F.. F. (Advanced Well Technologies Pty. Ltd.) | Daniel, S.. (Advanced Well Technologies Pty. Ltd.) | Billingsley, B.. (Advanced Well Technologies Pty. Ltd.)
Summary Understanding the integrated performance of complex artificially lifted wells on not normally manned (NNM), offshore platforms without invasive techniques represents a challenge not only to minimizing operating costs but also to optimizing production and thereby maximizing value. Often the analysis of such problems is hindered by the complex interactions between identified production constraints and by a lack of operating data. The Cliff Head oil field (offshore Western Australia) is developed with an innovative coiled-tubing deployed-electrical-submersible-pump (CT-ESP) artificial-lift system. This paper describes the process by which ESP and well data, in conjunction with a well-performance-modeling software, have been used as a powerful tool to diagnose well-performance issues and optimize production. Production trends were created on the basis of real-time production data to understand ESP performance. Individual-well models were created to identify potential causes of declining performanceโin this case, the use of an ESP performance-limiting factor (PLF) indicating deteriorating ESP performance because of solids buildup. On the basis of the model results, chemical soaks were implemented on two production wells to remove flow restrictions within and around the ESPs. The treatments increased the oil-production rates by 17 to 48%. Following a debottlenecking study, reservoir simulation in combination with detailed ESP-performance analysis concluded that total-field-production improvements of up to 50% were possible. Consequently, the next phase of field development will install larger-capacity ESPs. This paper outlines how field data and desktop tools were combined successfully to monitor and diagnose well-performance issues to deliver material production enhancements.
- Oceania > Australia > Western Australia > Perth Basin > Carynginia Shale Formation (0.99)
- Oceania > Australia > Western Australia > Indian Ocean > Perth Basin > Abrolhos Basin > Block WA-325-P > Cliff Head Field (0.99)
- Africa > Middle East > Algeria > Ouargla Province > Hassi Messaoud > Oued Mya Basin > Hassi Messaoud Field (0.99)
- (2 more...)
Summary The selection criteria for multiphase boosting options remain somewhat subjective and are frequently influenced by the vendors? data, which may mask potential limitations of this emerging technology. Existing literature on multiphase pumping tends to focus on a certain pump type for a specific field application, but does not provide more-generalized criteria for the selection of multiphase boosting solutions from among those available in the market. A comprehensive literature review into the working principles of the major pump types identified the intrinsic advantages and limitations of each technology for subsea and downhole applications. The survey showed that, for subsea application, both the twin-screw pump (TSP) and the helicoaxial pump (HAP) can handle high suction gas volume fraction (GVF) with a fluid recycling system, or flow mixer. Thus, GVF is not a discriminating factor. The positive-displacement principle allows TSPs to work with very low suction pressure, but limits their operating range because of the dependency of flow rate on their relatively low speed. However, these pumps can handle highly viscous fluid. The rotodynamic concept enables the differential pressure of HAPs to self-adjust to any instantaneous change in suction GVF, and to achieve higher flow rate if sufficient suction pressure is maintained. Because HAPs usually run at higher speed, they offer a wider operating range. For subsea application, HAPs appear to be a better option than TSPs because they offer higher operation flexibility and have a better installation track record. For downhole applications, the electrical submersible pump (ESP) and the progressing-cavity pump (PCP) are the outstanding favorites, with the latter being preferred for lifting streams that are viscous or with high sand content. For GVF up to 70%, the rotodynamic pump (RDP) is becoming a popular solution. Although it is claimed that the downhole TSP (DTSP) can handle up to 98% GVF, it is not yet widely accepted in the field.
- North America > United States (1.00)
- Europe (1.00)
- Africa (1.00)
- Asia > Middle East (0.68)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Dampier Basin > WA-191-P > Block WA-27-L > Mutineer-Exeter Field > Exeter Field > Angel Formation (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Beagle Basin > Dampier Basin > WA-191-P > Block WA-27-L > Mutineer-Exeter Field > Exeter Field > Angel Formation (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Mississippi Canyon > Block 764 > King Field (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 3/02 > Lyell Field (0.99)
- Production and Well Operations > Artificial Lift Systems > Progressing cavity pumps (1.00)
- Production and Well Operations > Artificial Lift Systems > Hydraulic and jet pumps (1.00)
- Production and Well Operations > Artificial Lift Systems > Electric submersible pumps (1.00)