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Abstract Following the installation in production fields of several tens of Two Phase Helico Axial Pumps, IFP and DBGP have recently launched a R&D program for the development of Two Phase Helico-Axial Turbines. These turbines may be used in many process applications in replacement of let down valves for energy recovery but also to increase the cooling duty or the liquid production. They may also be used in systems including a two phase separator with single phase expanders / turbines in view of reducing the number of equipment, space and weight. These turbines, suitable for all gas fractions, may find applications in the production of hydrocarbons (HP/HT wells, fractured reservoirs, oil stabilisation, electricity production in remote areas) but also in hydrocarbon treatment or in gas liquefaction. These applications cover a broad range in flow rate, pressure, temperature, gas fraction and fluid composition. A two phase helico-axial turbine prototype has been tested during the present year confirming the expected hydraulic performance. The hydraulic efficiency was found satisfactory to provide significant energy and liquid recoveries in many applications. Introduction Multiphase pumping is a long-established activity at IFP. First works were initiated in the seventies to extend the application of downhole electrical pumps. In the mid-eighties, multiphase pumping raised a renewed interest to transport the production of subsea satellite fields. At that time, subsea satellite developments were frequently substituted to stand-alone platforms in the North Sea to reduce offshore development costs. As tied-back distances to existing facilities were limited between 15 and 20 km due to the available natural reservoir pressure, multiphase pumps were a possible means of increasing these distances by adding energy to the liquid-gas mixture (Falcimaigne, 1992). After an extensive test programme on an IFP multiphase loop to investigate the hydraulic and mechanical behaviour in steady-state and slug flows, the P300 pump prototype was tested in 1991. This prototype is still in service in the IFP experimental loop, twelve years later, to boost multiphase mixtures. In 1994, first field applications of the Poseidon technology were characterised by relatively low flow rates and powers. Typical examples are the pump installed in the TotalFinaElf Pecorade field, in south of France, with a capacity of 360 m/hr and drive power of 600 kW (Figure 1.1 - Falcimaigne et al., 1994, Leporcher and Taiani, 1995), or the pump installed in the Statoil Gullfaks A Platform in the North Sea with a total capacity 200 m/hr and drive power of 750 kW (Vangen et al. 1995). A subsea helico-axial turbo-pump was also installed in 1994 at the Draugen field in the North Sea by Norske Shell. The progressive accumulation of field experience secured the oil operators to apply the technology on a larger scale. The power of recent Poseidon pumps reaches 4.5 MW for the TotalFinaElf Dunbar field in the North Sea and 6 MW for the Youkos Priobskoye oilfield in Siberia (total flowrate capacity : 3300 m/hr). At present, helico-axial pumps are the largest multiphase pumps in the world both in capacity and power, and also the deepest in the world for subsea applications (750 m water depth in Ceiba field, Gulf of Guinea).
- Europe > United Kingdom > North Sea (1.00)
- North America > United States (0.88)
- Europe > Norway > North Sea (0.84)
- (4 more...)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Alwyn Area > Block 3/9b > Alwyn Area > Alwyn South Field > Dunbar Field (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Alwyn Area > Block 3/8a > Alwyn Area > Alwyn South Field > Dunbar Field (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Alwyn Area > Block 3/14a > Alwyn Area > Alwyn South Field > Dunbar Field (0.99)
- (10 more...)
Abstract The field is a very mature field. 30 years after its production start-up, it is now producing with an average water-cut of 84 %. This paper presents the continuous adaptation efforts deployed throughout the years to further valorise resources, in response to the growing maturity of the field. Well activation started very early, first through ESP's, then by full field gas-lift implementation. As an answer to an important depletion of some reservoirs, a water injection scheme has been implemented as early as 1979. In 1997, a major field revamping campaign was performed to implement an EOR technique which proved to be very efficient: tertiary gas injection after water flooding. After the first horizontal wells, drilled in 1994, ever increasing well architecture complexity allows now to target more and more precisely heterogeneities, to produce residual oil pockets, and to develop tight reservoirs. A 3D seismic acquired in 1995 has opened the path for quadruple and quintuple multilateral wells. At the current maturity level, field management appears as the next challenge. The complex gas scheme, which comprises at the same time gas production, gas lift, gas injection, gas recompression and gas export, needs constant arbitration between activation gain and tertiary recovery. In parallel, a global water management policy must be set up, as the water disposal network is more and more heavily loaded. A water management study is currently under the way, to review long term fluid production predictions, surface facilities limitations, and long term reliability of disposal well, and to screen for solutions, ranging from reservoir and well control to surface facilities de-bottlenecking. Introduction In 1972, one year after the creation of the UAE Federation, Total was granted a concession to develop a field offshore Abu Dhabi. At that time, the life span of the field was estimated to 15 to 20 years. Today, 30 years later, oil is still being produced, and will continue for many years to come. In order to achieve such a result, extensive and continuous efforts have been deployed throughout the years to further develop resources, in response to the growing maturity of the field. A remarkably large variety of means and techniques has been deployed all along its development to curb the production decline and extend the life of its installations, such as phased development, secondary reservoirs development, well activation, production mechanism optimisation, use of emerging technologies, understanding of heterogeneities, field management, equipment replacement and upgrading. Background The field is a large NE-SW anticline, affected by NW-SE trending faults. The stratigraphic sequence encountered comprises a thick calcareous platform succession from Permian to recent. Depositional environments range from shallow marine to supratidal. Limestone, dolomite, anhydrite and shale are the most common lithologies encountered. The field comprises 2 main reservoirs of Upper Jurassic Age, respectively called Upper and Lower reservoirs, one secondary reservoir of Lower Cretaceaous age, and one marginal, Middle Jurassic, reservoir.
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.71)
- North America > United States > Texas (0.48)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.55)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.34)
- Geophysics > Seismic Surveying (0.69)
- Geophysics > Borehole Geophysics (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.57)
- Oceania > Australia > Victoria > Bass Strait > Gippsland Basin (0.99)
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Abu Al Bukhoosh Field > Arab Formation (0.98)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.97)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.97)
Abstract Kuwait's production to date is characterized by large, massive reservoirs undergoing natural depletion with the help of strong natural aquifer drives. In a few fields, natural aquifer support is supplemented by pattern or peripheral waterflood. However, there has been no systematic attempt to define the Improved Oil Recovery (IOR) potential within the country. This study is a first attempt to assess this potential. The study considered 10 IOR displacement processes, suitable for long-term implementation within Kuwait. These processes included waterflood (including chemical floods), gas injection processes, and thermal methods. The study did not consider techniques based purely on well stimulation or infill drilling (e.g. cyclic steam injection, or horizontal well development); the potential for these techniques is already well understood and considerable data already exists for planning around these options. The study focused on screening reservoirs and identifying IOR processes for further study. The screening was in two parts. The first part was an evaluation of process suitability for all reservoirs. The second part was a ranking of IOR opportunities by reservoir. In total, over 800 process/reservoir combinations were evaluated. The evaluation process made use of various industry criteria; however, these were modified to better reflect conditions within Kuwait. After screening for suitability, the reservoirs were ranked in importance for future study. This ranking included: incremental oil recovery, crude quality cost per barrel and urgency (timing). This ranking will be used to direct resources at particular projects for further study and, if positive, future implementation. Key technical contributions of this work include: data evaluation techniques, consistent ranking of reservoirs with varying degrees of risk, development of scoping economic models for preliminary project assessment. Introduction Improved Oil Recovery (IOR) methods, as defined for this study, consist of processes in which an injection fluid is used to improve the recovery of oil from a hydrocarbon reservoir. In other words, IOR includes the following processes: Waterflood, Miscible Gasflood with Hydrocarbon, Carbon Dioxide, or Nitrogen as an injecting, Immiscible Gasflood (Hydrocarbon), Enhanced Waterfloods (Surfactant, Polymer, or Alkaline), Steamflood (including Steam Assisted Gravity Drainage) and In-Situ Combustion. Most Kuwait reservoirs are currently under primary depletion, with no IOR. This is due to a variety of reasons, primarily because of strong natural aquifers and the relatively early stage of depletion. A few reservoirs in North Kuwait are in the process of implementing a sea-water injection process, and a few in West Kuwait are making use of dump-flooding to enhance the natural aquifers. It is expected that many reservoirs would eventually benefit from the application of IOR methods to increase oil production/reserves and extend field life. This work was undertaken to help focus attention on those fields and IOR methods, which look most promising and warrant further study.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.54)
- Asia > Middle East > Iraq > Basra Governorate > Arabian Basin > Widyan Basin > Mesopotamian Basin > Zubair Field > Zubair Formation (0.97)
- Asia > Middle East > Iraq > Basra Governorate > Arabian Basin > Widyan Basin > Mesopotamian Basin > Zubair Field > Mishrif Formation (0.97)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Minagish Field > Marrat Formation > Upper Marrat Formation > Sargelu Formation (0.94)
- (21 more...)
Abstract In mature fields, operators are confronted with wells producing high water cut at low pressure with consequently very high gas volume fraction (GVF). Under these conditions, the net oil flow rate is low and therefore, permanent or periodic testing becomes critical to determine profitability and manage the field production. To optimize and monitor the oil production under these conditions, operators are looking to utilize multiphase flowmetering technologies. Accuracies achievable by inline multiphase flowmeters have greatly improved in recent years, but liquid and water-cut measurement accuracies decrease when the GVF is very high. At low pressure to reduce the GVF, it is necessary to separate a large portion of the gas upstream of the multiphase flowmeter, thus enabling optimum measurement of the liquid and water cut under lower-GVF conditions. Market drivers generally dictated by operator requirements have resulted in the formation of an project team with specific Middle East focus to deliver an operational prototype for a production well testing campaign on a fast track basis. The package comprises a partial separation unit and a dual-energy gamma ray/Venturi meter. The selection of a partial separation design was based on a review of the commercially available solutions capable of handling the large operating range required for use in periodic well testing applications in terms of flow rates and pressure rating. The design comprises gas liquid cylindrical cyclone with tangential inlet. The capacity of each device to ensure a dry gas phase with minimum pressure loss over the complete required operating range was critical in the selection process. This paper presents test results validating that a gas liquid cylindrical cyclone located upstream of a dual-energy gamma ray/Venturi meter is an effective partial separation system. With an inlet GVF of 99% and 90% of the inlet gas extracted by the partial separation system, the GVF at the multiphase flowmeter condition is below 90%, and accurate measurement of the 3 phases is achieved. Introduction In the Middle East, there are a number of mature oil fields that produce either close to or below the bubblepoint and are pressure maintained using water and/or gas injection. These reservoirs are commonly produced with the assistance of artificial lift systems such as gas lift or electrical submersible pumps. Under these production methods, the effluents at surface are often characterized by low pressure, very high GVF, and high water cut. It is not uncommon to have wells producing with a net oil flow rate of less than 10% of the total flow rate (10% oil volume fraction). The revenue to the operator is derived mainly from the oil production, and quantifying to a high degree of confidence the oil flow rate is an important piece of information that can determine whether a well is economically viable, especially in environments in which injection gas allocation is critical. To optimize and monitor the oil production under these conditions, operators are looking to utilize multiphase flowmetering technologies. Inline multiphase flowmeters in very high-GVF environments show an increased uncertainty in the accuracy of the water cut measurement, which is required to obtain the water and oil flow rate from the measured total liquid flow rate. A number of multiphase flowmeters have been tested to assess meter performances against stated requirements and the number of meters qualified was limited. One of the qualified meters uses a partial separation device upstream of the multiphase flow measurement and many in the industry have adopted the approach of partial separation upstream of a multiphase flowmeter. The presence of the partial separation reduces the GVF at the multiphase flowmeter conditions and therefore improves the accuracy of the water cut, hence of the net oil. It does however introduce other drawbacks. To achieve the objective of minimizing the net oil uncertainty under very high GVF and high water cut, a study was initiated to determine which gas extraction technology combined with a dual-energy gamma ray/Venturi multiphase flowmeter best suits the operational requirements and metering needs for this production well testing application.
- Europe (1.00)
- North America > United States > Texas (0.94)
- Asia > Middle East (0.67)
- Africa > Middle East (0.66)