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This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 133631, ’Henry Subsea Development - Challenges and Solutions,’ by Stephen Henzell, SPE, WorleyParsons Services Pty. Ltd., and Andrew Glucina, Santos Ltd., originally prepared for the 2010 SPE Asia Pacific Oil & Gas Conference and Exhibition, Brisbane, Australia, 18-20 October. The paper has not been peer reviewed. The Henry and Netherby gas fields are in Victorian waters in southeast Australia. They have been developed by extending the Casino production system which comprises two subsea wells in the Casino field producing by pipeline to an onshore gas plant. The entire development is subsea. During the Casino design, provisions were made for future extension of the production system. The full-length paper discusses the provisions made and their effectiveness during the expansion project. Introduction The Henry gas development has developed the reserves of the Henry and Netherby reservoirs by extending the existing Casino subsea-production system. The Casino, Henry, and Netherby gas fields are approximately 250 km southwest of Melbourne. The Casino reservoirs began production through two wells in January 2006. Henry and Netherby reservoirs began production in February 2010. Casino Production System The Casino production system currently comprises four subsea wells, Casino 4, Casino 5, Henry 2, and Netherby 1. The subsea wells are arranged in a daisy-chain configuration. Each subsea well ties into the pipeline through a short 150-mm-diameter flowline approximately 40 m in length at a tee in the pipeline. The pipeline is routed to pass near each well. The pipeline has provision for future wells along the pipeline route. The last 5 km of the pipeline extend beyond the Netherby-1 tee to the Pecten East field area. This section of the pipeline currently is suspended, waiting for successful drilling of an appraisal well. The 300-mm subsea pipeline is approximately 55 km in length, laid in two separate sections with a tie-in point between the two at the Casino-4 pipeline-end module (PLEM). The pipeline reaches landfall by a horizontally directionally drilled (HDD) section crossing the shoreline. The subsea pipeline is terminated onshore at the HDD exit in the mainline-valve (MLV) site. The 300-mm onshore pipeline continues approximately 12 km from the MLV site to the Iona gas plant (IGP), where raw gas is processed into export-quality gas and stabilized condensate.
- Oceania > Australia > Victoria > Bass Strait > Otway Basin > VIC/P44 > Block VIC/P44 > Casino Field > Waarre Formation (0.99)
- Oceania > Australia > Victoria > Bass Strait > Otway Basin > VIC/P44 > Block VIC/P44 > Casino Field > Cadna-Owie Formation (0.99)
- Oceania > Australia > Victoria > Bass Strait > Otway Basin > VIC/L24 > Block VIC/P44 > Casino Field > Waarre Formation (0.99)
- (4 more...)
This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 136648, ’The Medical Evacuation of Patients With Infectious Diseases From Developing Countries: Duty of Care,’ by R.L. Quigley, International SOS Assistance Inc., originally prepared for the 2010 SPE Middle East Health, Safety, Security, and Environment Conference and Exhibition, Manama, Bahrain, 4-6 October. The paper has not been peer reviewed. During the severe acute-respiratory-syndrome epidemic, innovative safety measures were developed to protect medical teams/flight crews from contamination during medical evacuation/transport. Those measures included the design, in accordance with international-health-authority guidelines [e.g., World Health Organization and Centers for Disease Control (CDC)], and implementation of a compact, portable isolation unit (PIU), ideal for regional ground/air travel. More recently, a disposable biological containment unit (BCU) has been developed that is designed for a Gulfstream III aircraft and is thus, ideal for transocean/continental travel. Introduction There are multiple factors to explain the continued prevalence of infectious diseases in the developing world. These include, but are not limited to, accessibility to medical care (vaccination/medicines), hygienic practices (drinking water), malnutrition, education, and pest control (vectors). Business travelers and expatriates alike, from developed nations, continue to visit/work in these under-privileged regions and may actually be immune to certain endemic infectious diseases through vaccination (e.g., measles) or prophylactic medicines (e.g., malaria). However, they are not immune to many of the other serious infectious diseases [e.g., Avian/Swine Flu, tuberculosis (TB), and viral hemorrhagic fevers] for which such proactive precautionary measures are irrelevant. Not only can these latter infections be lethal but they are highly contagious. With the lack of adequate healthcare facilities/resources, in many of these developing countries, transportation to the closest developed country for definitive care in a center of medical excellence (COME) may be the difference between life and death. Logistically speaking, such transportation invariably requires an air ambulance (AA) staffed by a team of medical experts. Even routine (universal) precautions (i.e., gown, cap, mask, eye wear, and gloves) frequently are not adequate to protect the transport team from the risk of contamination. To reduce the exposure risks of our medical-transport teams, a protocol has been developed and equipment has been designed to mitigate these infectious risks. The full-length paper presents the protocols, equipment, and reference data and outlines some of the logistical challenges that have been addressed in the medical evacuation of the highly contagious patient to the nearest COME. Furthermore, an enhanced biologic unit that will enable transcontinental travel is introduced. No doubt the development of such extreme measures has been catalyzed by the efforts of multiple organizations in the emergency-management industry to achieve compliance in their duty of care.
This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 140760, ’The Work of the UK Helicopter Task Group,’ by Jessica Burton, Oil & Gas UK, originally prepared for the 2011 SPE European Health, Safety, and En vironmental Conference in Oil and Gas Exploration and Production, Vienna, Austria, 22-24 February. The paper has not been peer reviewed. The Helicopter Task Group (HTG) was created by the UK oil and gas industry in April 2009 to address helicopter-safety issues, including those arising from the tragic helicopter crash off the northeast coast of Scotland on 1 April 2009. The task group included representatives from offshore operators and contractors, including those involved in the incident, as well as Oil & Gas UK, the offshore workforce, helicopter-operator companies, regulators, emergency-response organizations, and trade unions. Introduction The HTG was created to address cross-industry issues about helicopter safety, including those arising from the fatal helicopter crash off the northeast coast of Scotland on 1 April 2009. The purpose of the HTG was to act on behalf of the industry as a communications focal point for sharing information, advice, and learning across the industry and with other stakeholders on matters arising from this and other helicopter accidents, including assisting the implementation of any recommendations from the Air Accidents Investigation Branch (AAIB) inquiries. The group also defined possible policies and practices to be recommended to the Board of Oil & Gas UK for approval and consequent implementation on a pan-industry basis. In doing this, it was supported by existing industry workgroups and advisory teams. The group met every 4 weeks from April 2009 to June 2010. The full-length paper is designed to summarize the key issues that the task group was involved in over that period, some of which had been ongoing work for a number of years, and what changes have been made to the offshore industry and aviation safety as a result of the cooperation between the task group, wider aviation community, existing industry bodies, regulators, and emergency-response organizations. HTG Work Plan The HTG identified a number of key aviation-safety issues at its first meet-ing in April 2009, which would form the basis of its work plan. Although many potential projects could have been chosen, it was decided that—to ensure that the group could work effectively and deliver results in a manageable time frame—only a set number of priority items would be focused on. These work areas initially were linked to recommendations arising from the lessons learned in the two helicopter incidents that occurred in the UK continental shelf (UKCS) in early 2009. As the group progressed, other work areas were identified, including some linked to lessons learned in other incidents around the world. Summary of Key Work Areas and Progress Made The following is a summary of each of the key work areas or projects overseen by the task group, and the status of each by June 2010 when the group was closed formally and its work was handed over to a new group.
- Transportation > Air (1.00)
- Energy > Oil & Gas > Upstream (1.00)
This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 21712, ’Frigg Decommissioning - HSE,’ by Bjorn Oscar Tveteras, Total E&P Norge A/S, originally prepared for the 2011 Offshore Technology Conference, Houston, 2-5 May. The paper has not been peer reviewed. The decommissioning of large North Sea platforms gives rise to significant health, safety, and environmental (HSE) challenges. These include a high level of work activity, numerous lifting operations, and work in an exposed area, all of which take place on a platform where the layout rapidly changes from day to day. Hazardous materials, such as asbestos, scale, and mercury, need to be removed and must be handled in a safe manner. Introduction The Frigg and manifold-and-compression platform 01 (MCP01) Cessation Project is the largest decommissioning project undertaken in recent years and includes removal of six topsides, three steel jackets, and sealines, with a final disposed-of weight of 87 000 tonnes. Different methods have been applied, from single and module-based lifts to “piece small” dismantling and removal. The Frigg field was a gas field in the North Sea, on the border between Norway and the UK. The field was developed with three installations in the Norwegian sector, a drilling and production platform, a treatment and compression platform (TCP2), and an unused steel substructure damaged during installation in 1974. Three other installations were in the UK sector, a treatment platform (TP1), a concrete drilling platform (CDP1), and a living-quarters platform. The platforms were installed in the period 1974–77. The produced gas was transported to St. Fergus in Scotland, through the Frigg pipeline, passing through MCP01 at the midpoint of the pipeline. The Frigg field production was shut down in 2004, with decommissioning starting in 2005 after cleaning of the process equipment/utilities and removal of most loose hazardous wastes. The Frigg field was the first large field to be fully shut down and decommissioned in the Norwegian sector of the North Sea. Three Frigg field substructures (TCP2, TP1, and CDP1) were made of concrete while the other three substructures were steel jackets. MCP01 also was made with a concrete substructure. None of the substructures have been used for storing crude oil. The concrete substructures were not designed and built for removal, and the assessment of the alternatives for removal and onshore disposal, or partial removal through cutting of the substructure, revealed too high a risk and uncertainty.
This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 21578, ’Subsea Water Treatment Comes of Age,’ by David Pinchin, SPE, Well Processing A/S, originally prepared for the 2011 Offshore Technology Conference, Houston, 2-5 May. The paper has not been peer reviewed. This subsea seawater-treatment system has undergone several phases of development since its inception in 2002. It works by extracting water from the seabed area (where there are inherent advantages such as space, stable temperatures, lower degree of bacterial concentration, and distance from platform discharges). A combination of residence time within a “still room,” two steps of electrochemical disinfection, and chemical dosing are implemented to achieve disinfection and solids reduction. Introduction Water injection (waterflooding) is by far the most used method of increasing oil recovery from an oil reservoir. Water quality is an important factor for maximizing sweep efficiency (displacement of oil) during waterflooding and also preventing reservoir souring. Key objectives of seawater-treatment plants are therefore to minimize the blocking of reservoir pores (e.g., with solids, biomass, and scale) and to control reservoir souring. The full-length paper describes a subsea seawater-treatment system that is seen as filling the “missing link” to the already proven technology of “raw” seawater injection on the seabed by subsea pumps. To be accepted as a viable water-treatment process, it must be capable of providing at least the same level of reservoir protection as afforded by a topside seawater-treatment plant. Subsea Treatment System and Testing The subsea treatment unit comprises several equipment items assembled in such a way as to maximize solids removal and disinfection of the seawater. The process uses the seabed environment and makes use of its beneficial effects. A still room is used to isolate the water to be treated from external conditions (e.g., storms and tidal movements). The inlet compartment is designed to allow for a good degree of solids settling with sufficient density to drop out. The water then is chlorinated by electrolysis as it transfers to a second compartment where it is afforded a long residence time to allow the chlorine reaction to take place and to allow further solids settling. The water exiting the still room then flows through a hydroxyl-radical generator where a final oxidation process takes place. The treatment unit therefore generates its own treatment chemicals by electrolysis and requires only a combined power/control signal interface cable. For the testing, a submerged lift pump was used to induce flow through the subsea treatment unit and up to an onshore sampling/control container.
- Water & Waste Management > Water Management > Lifecycle > Treatment (1.00)
- Energy > Oil & Gas > Upstream (1.00)
This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 21210, ’Genesis Pipeline Crawlers: Pigging the Unpiggable,’ by Andy Kenney, Subsea Integrity, originally prepared for the 2011 Offshore Technology Conference, Houston, 2-5 May. The paper has not been peer reviewed. Many pipelines cannot be inspected internally because of reductions/changes in inside diameter (ID), extreme angles, 90º miter bends, T- and Y-junctions, or simply having access for pigs without a recovery point. A range of high-powered, tethered, brush-tractor crawlers are delivery systems for applications including internal inspection, cleaning, and repair. The brush-drive system copes with internal pipeline irregularities caused by corrosion, sedimentation, and changes in ID. Only one access point is needed for both insertion and recovery because crawlers can reverse. Introduction Conventional intelligent pigging of pipelines is usually a single-directional process (unless flow can be reversed) that requires sufficient product flow to drive the pig, a consistent bore size to allow the drive cups to efficiently occlude the pipeline, and a launch and receive trap at either end of the run. More than 50% of the global pipeline network (for various reasons) does not enable conventional pigging to be undertaken, and these pipelines are collectively identified under the heading of “unpiggable.” As ongoing development technology progresses to market-ready technology, additional capability becomes available to reduce the percentage of pipelines that cannot be inspected. One technology that falls into this category is high-power “brush-drive” pipeline crawlers. Pipeline crawlers that use reciprocating brushes as their source of grip and motive force have been in development for more than 10 years. Fully developed “tethered” production tools are now at the stage of field trials and early operations with a number of companies. Self powered and with high grip and high pull loads at the disposal of the crawler, they are capable of operating in a pipeline independently of most flow conditions, can operate in complex geometries, can be deployed and recovered from a single access point, and can be integrated with existing intelligent inspection tools and cleaning equipment. In essence, they are an enabling technology that can transport existing and established technology used in conventional pigging into an until-now unpiggable part of the pipeline network. Traversing Pipelines Propulsion. The crawler tool uses a free-running “brush drive” attached over the body of a reciprocating device, attached to a fixed-brush section. The brushes are designed to be larger than the pipe ID so they will bend to conform to the pipe bore. In this condition, the brushes possess a gripping force in one direction that is much larger than its sliding force in the opposite direction. When the brush drive is moved backward by the reciprocator (drive motor), the grip force of the brush moves the crawler tool along the pipe. When the brush drive is moved backward by the reciprocator, the fixed-brush grip force exceeds that of the drive brush and the drive brush moves forward. By repeating this process, a brush-driven crawler can travel forward.
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (3 more...)
This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 21705, ’Use of a Vertical Wind Turbine in an Offshore Floating Wind Farm,’ by Marc Cahay and Eric Luquiau, Technip, and Charles Smadja and Frederic Silvert, Nenuphar, originally prepared for the 2011 Offshore Technology Conference, Houston, 2-5 May. The paper has not been peer reviewed. With 2.0 GW already installed and more than 50.0 GW planned in Europe by 2020, as reported by the European Wind-Energy Association, the installation of bottom-mounted offshore wind turbines in very shallow water (less than 40 m) is now well established. The foundation and the offshore installation costs represent approximately 50% of the total development cost of an offshore wind farm, and this proportion increases with the water depth. Hence, floating wind turbines are the solution for deep offshore. Vertiwind Project Coming from a strong and complementary partnership of utilities, industrials, and academics, the Vertiwind project plans to build, install, and operate, in real offshore conditions, a full-scale floating vertical-axis wind turbine (VAWT) of 2 MW. This is a real step change in the technology compared with most offshore wind turbines with horizontal axes. The floater concept retained is of a semisubmersible design and is called “multifloater.” It skillfully combines an out-of-the-wave excitation response, a shallow draft to facilitate fabrication, and a very simple installation procedure requiring only one or two tugs. The VAWT is located in the center of the floater, ensuring that the center of gravity, the buoyancy, and the convergence point of the mooring lines are all on the same axis. This geometrical property highly reduces the sway and yaw response of the floater subject to noncolinearity or heading variation of wave and wind. Because of the architecture and underlying principles of this Darrieus turbine, the power production is not affected by the inclination of the turbine axis relative to the wind direction as a result of the floater motions. The turbine design is carried out in parallel with the floater. It integrates, at an early stage, all requirements of the offshore environment in terms of loads, accessibility, and ease of maintenance. The complete unit will be anchored to the seabed and linked to the network by a compliant subsea cable.
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
- Health, Safety, Environment & Sustainability > Environment (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems (1.00)
- Facilities Design, Construction and Operation > Facilities and Construction Project Management > Offshore projects planning and execution (1.00)
This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 143066, ’Optimization of Completions in Unconventional Reservoirs for Ultimate Recovery - Case Studies,’ by Daniel J. Snyder, SPE, and Rocky Seale, SPE, Packers Plus Energy Services, originally prepared for the 2011 SPE EUROPEC/EAGE Annual Conference and Exhibition, Vienna, Austria, 23-26 May. The paper has not been peer reviewed. Over the last decade, an industry-wide shift to unconventional plays has been made possible by advances in technology, allowing the recovery of previously uneconomic reserves. The primary objective of completions in these unconventional reservoirs is to increase the effective surface area of the well to maximize reservoir contact. The full-length paper provides an introduction to unconventional reservoirs, describes the main methods of horizontal multistage completions, and discusses how the choice of method can affect good fracturing practices as well as long-term production. Introduction Unconventional Reservoirs. Over the last decade, an industrywide shift to unconventional plays has occurred as a result of the depletion of mature conventional reservoirs, increased demand, and advances in technology. Unconventional reservoirs have been defined as formations that cannot be produced at economic flow rates or that do not produce economic volumes of oil and gas without stimulation treatments or special recovery processes and technologies (Fig. 1). Types of unconventional reservoirs include those with poor fluid-flow characteristics because of small inter-pore connections and/or with stacked pay units. The primary objective of completions in these unconventional reservoirs is to increase the effective surface area of the well to maximize reservoir contact. Horizontal drilling and multistage fracturing are two technologies that accomplish this. The two main methods of horizontal multistage completions currently used in unconventional reservoirs are cemented liner “plug and perf” and openhole multistage-fracturing systems. Although both methods have the same goal of increasing access to the reservoir by the induction of fractures along the entire length of the horizontal wellbore, they differ significantly from an operational perspective. Cemented-Liner Multistage-Fracturing Method. This type of completion involves cementing production casing in the horizontal wellbore and plug-and-perf stimulation. Mechanical isolation in the liner is accomplished by setting bridge plugs using pump-down wireline or coiled tubing (CT), followed by perforating and then fracturing the well to provide access to the reservoir. The cement provides the mechanical diversion in the annulus, while the bridge plug provides the mechanical diversion inside the liner. This process then is repeated for the number of stimulations desired for the horizontal wellbore. After all stages have been completed, CT is used to drill out the composite plugs, thus re-establishing access to the toe of the horizontal wellbore. Although an effective method of creating diversion along the horizontal section for discrete-stage stimulation, the inherent cost of multiple interventions with CT, perforating guns, and deployment of fracturing equipment needed for each stage is extremely high, not to mention being very inefficient and time consuming. Production using this method also can be limiting because cementing the wellbore closes many of the natural fractures and fissures that would otherwise contribute to overall production.
- Europe > Austria > Vienna (0.55)
- North America > United States > Texas (0.48)
- Geology > Petroleum Play Type > Unconventional Play (0.55)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.34)
- North America > United States > Texas > Anadarko Basin > Cleveland Formation (0.99)
- North America > United States > Texas > East Texas Salt Basin > East Texas Field > Woodbine Formation (0.97)
This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 133299, ’Prediction of Uncertainty in Exploration of Unconventional Gas Reservoirs,’ by Mohan Kelkar, SPE, Kyle Bonney, SPE, and Phillip Bonney, SPE, University of Tulsa, originally prepared for the 2010 SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September. The paper has not been peer reviewed. Once a new unconventional play is identified, companies start acquiring sizable land holdings within the same play. Before making acquisitions, the companies would like to know how much to pay for the bonus, what the strategy is to initiate the drilling program, and how to determine the uncertainty related to estimated ultimate recovery (EUR) from these wells. Most companies use the data from existing wells within the same play or a similar play to estimate what type of production to expect from the land to be acquired. Introduction Shale-gas plays are becoming increasingly important in the world. Shale-gas plays possess some unique characteristics, which are not typical for conventional gas reservoirs. One of the relevant characteristics is the areal extent. Unlike conventional reservoirs, whose areal extent is limited and discontinuous (e.g., fluvial channels can appear and disappear), shale plays extend over many square miles. Drilling a well is almost guaranteed to be successful in penetrating a particular shale formation, but this does not mean the well will be successful. Other intrinsic parameters of the shale such as mineralogy, presence of natural fractures, brittleness, and stress anisotropy can play an important role in determining the success of fracturing in the shale. In addition, external parameters also have played an important role. Many operators believe that with the correct fracturing technique and well configuration, areas that are not successful today can become successful tomorrow. Because of this belief, the acquisition of shale properties and further evaluation are performed very differently than in most conventional plays. Companies acquire large swaths of acreage (thousands of acres) without worrying about small variations of physical properties within the play and base their estimates of reserves on average characteristics. Two specific questions addressed in the full-length paper are the following. 1. If a company is interested in acquiring new acreage in a shale play, how would a company evaluate that acreage? If analogous data are available from an adjacent area, which has been developed, how can they be used effectively to quantify potential uncertainties in the acquisition? Is there a way that the variation in potential EURs can be determined correctly? 2. Assuming that acreage is acquired, can a company track its success by comparing the observed values with the expected results? For example, if the company has an initial 10 well drilling program, what is the accepted variation for the observed results before a company can say that the observed results fall within the bounds of predicted uncertainties?
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play (1.00)
This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 136407, ’Best Practices & Innovations for Improved ESP Performance; Mature Field Case History; TNK-BP Company, Russian Federation,’ by D.C. Borling, SPE, BP, and S.V. Sviderskiy, SPE, and, S.F. Gorlanov, SPE, TNK-BP, originally prepared for the 2010 SPE Russian Oil & Gas Technical Conference and Exhibition, Moscow, 26-28 October. The paper has not been peer reviewed. Leadership, teamwork, and technical ingenuity were critical strategy elements that resulted in an 82% run-life improvement for electrical-submersible-pump (ESP) systems in the TNK-BP company. During the past 4 years, the 12-month rolling mean time between failure (MTBF) steadily improved from 295 days during January 2006 to the current 541 days in July 2010. This 246-day improvement was achieved across more than 14,250 ESPs and achieved USD 307 million value to date. Introduction TNK-BP is a privately owned oil and gas joint venture. The company was formed in 2003 and for the past 7 years its upstream producing operations were located primarily in West Siberia (Khanty-Mansiysk and Yamalo-Nenets Autonomous Districts, Tyumen Region), East Siberia (Irkutsk Region), and Volga-Urals (Orenburg Region). As of July 2010, the company operated more than 200 hydrocarbon-bearing fields with approximately 15,700 active producing oil wells. More than 98% of these wells used artificial lift. In TNK-BP, ESP systems refer to both surface and downhole equipment components. Surface components include transformer, switchboard (and/or variable-speed motor controller), and a relatively short surface power cable. Downhole components include pump intake (and/or gas separator), seal element, motor, and a long downhole cable (used to transfer power from the surface to the motor). Operating Conditions Each of the company’s 14 regional business locations has unique operating conditions. By mid-2010, more than 50 different types of ESP equipment were deployed across the company to lift a wide range of produced-fluid rates and gas and solid content. Approximately 92% of all deployed ESP equipment was manufactured within the Russian Federation. The remaining 8% was imported for use in complicated well conditions and harsh downhole operating environments. TNK-BP deployed ESP equipment in almost every type of downhole condition imaginable. Harshest conditions included a mixture of high temperature, abrasive solids, scaling, asphaltene, paraffin, high free-gas content, and corrosive fluids. Teamwork Without good teamwork on a massive scale across five business segments and 14 regional businesses, the TNK-BP ESP-MTBF-improvement initiative would not have achieved the intended results. A best practice was the method used to align ESP MTBF key performance indicators and work plans at the start of each year. While this alignment was a big undertaking, it proved itself to be worth the effort each year.
- Europe > Russia > Volga Federal District > Orenburg Oblast > Orenburg (0.25)
- Europe > Russia > Central Federal District > Moscow Oblast > Moscow (0.25)
- Asia > Russia > Ural Federal District > Tyumen Oblast > Tyumen (0.25)
- (2 more...)