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Multiphase transport systems are already commonly in use for short transport distances or "pleasant" fluids. Application of multiphase technology in field developments may result in 10-40% reduction of investment costs. An unmanned wellhead platform combined with multiphase transport platform combined with multiphase transport may be equally cost-effective as a subsea system, even in large water depths. The main technical problem areas are discussed and some conclusions are drawn as to the future use of multiphase technology.
The low and unstable oil price has spurred the offshore industry's interest for low cost field development concepts. The dream of avoiding large platforms by utilizing subsea multiphase technology has been closer investigated by a number of companies. In the North Sea the interest has been increased by the fact that the large fields developed some years ago already have left or shortly will leave their plateau production. The spare processing plateau production. The spare processing capacity can therefore be used to tie in other, smaller fields in the vicinity. A number of such fields have already been found throughout the North Sea. The distance to an existing platform will in most cases be less than 30 km. Some of these fields will only require a few wells to be drained, implying that the cost of a platform can not be accepted. platform can not be accepted. Multiphase transportation is no new experience to the oil industry. Multiphase flow occurs in every well and in the flowlines and risers from satellite wells. There also exist a number of larger diameter trunklines for two-phase or multiphase flow around the world. These examples involve either short distances or pleasant fluid properties. Longer distances and/or difficult fluids are beyond state-of-the-art technology.
FIELD DEVELOPMENT CONCEPTS
Fig. 1 shows the functions included in a conventional field development.
Since May 1991 a POSEIDON pump of the rotodynamic type has been running on the SIDI EL ITAYEM field in TUNISIA, logging more than 3500 operating hours (end of November 91) without a major problem. This pump is one of the practical results of the POSEIDON project, launched in 1984 by TOTAL, IFP and STATOIL, to develop the concept of multiphase pumping: the final target being a subsea multiphase boosting station.
Prior to the Tunisian test, this pump had been Prior to the Tunisian test, this pump had been tested satisfactorily on the two phase loop of IFP at SOLAIZE (FRANCE), and it was this which decided the partners to send the prototype, without any modification, to the real active field test rig specially prepared to accommodate multiphase equipment.
The choice of the multiphase pump type is the result of comprehensive knowledge and comparative studies of the different available or described pumping systems at commencement of the project pumping systems at commencement of the project The partners, not being bound to any particular pump manufacturer, only wished to select or to pump manufacturer, only wished to select or to improve a known product in order to have a tool available for their future subsea developments. In the following paper we will describe the different types of possible multiphase pumps and the reasons that lead the partners to the rotodynamic principle type. We will then present the POSEIDON pump, the tests performed on a diphasic loop to ascertain its behaviour with any composition of fluid, then the tests conducted in real field conditions at SIT and an intermediate conclusion about these operations that mark the end of the R and D phase.
2. MULTIPHASE PUMPS
With the current low price for produced oil and the increasing cost of offshore operations it makes sense to use the declining fields separation capacities to receive the effluent coming from the smaller or marginal fields which do not deserve a conventional development.
Also onshore fields located in remote areas or locations where it becomes more difficult to flare the produced gas or to build additional facilities are cases for using such pumps.
The basic requirement to develop any field is that the wellhead pressure, may be, assisted by secondary recuperation means - water injection, gas lift - is enough to transfer the multiphase effluent through a single, multiphase pipeline. Otherwise, a pump is needed. pump is needed. A line will be mainly characterised by the flow rate (bbl/d), the composition of the fluid i.e the gas fraction GLR [gas to liquid ratio expressed as a percentage by volume (%) or as a ratio (m3/m3) in percentage by volume (%) or as a ratio (m3/m3) in suction condition], the pressure at the pump inlet and the pressure rise needed to enter the first stage of the separator at the end of the line. Secondary data will be PVT parameters such as fluid density, temperature, viscosity, water cut etc...
Considering the above, the wide range of possible combinations must be emphasised, especially for the gas fraction that vary from zero in the case of a pure monophase fluid, to 95% for wells where a gas lift production is in use or if the produced gas has production is in use or if the produced gas has already reached high GOR, 100% being reached if there is severe slugging.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 165587, "Reassessment of Multiphase Pumps in Field-Case Studies for Marginal Deepwater Field Developments," by N. Abili, F. Kara, and I.J. Ohanyere, Cranfield University. This paper was peer reviewed and published in the February 2014 SPE Oil & Gas Facilities magazine, p. 56.
This paper focuses on the applicability of subsea-processing technology (SPT) using multiphase pumps (MPPs) to develop marginal fields commercially. A technology selection consisted of a comparison of performances of several SPTs for effective development of marginal fields and was evaluated further with an analytical hierarchical process, resulting in the most effective innovative SPT for marginal-field development. The findings of this process were validated further in their applications to real fields, reflected in specific field-case simulation studies.
Most of the world’s exploration-and-production companies have a significant number of unconventional and remote fields in their portfolios. Recent industrial effort has been focused on the accelerated development of SPT. One of the innovative solutions is the handling and treatment of produced oil and gas at or below the seabed for transport to topside facilities, to mitigate flow-assurance issues.
Some of the notable benefits of subsea processing include mitigation of hydrate formation and management of pressure-related issues resulting from the production of heavy oil, increase in wellhead pressure, and increased hydrocarbon production from fields with low pressure profiles. In ultradeepwater and deepwater fields, subsea processing is the most effective solution because such fields are beyond human intervention (divers), and it is used to boost hydrocarbon production from green fields or brownfields, reducing production cost and the need for topside processing.
This paper explores subsea processing in the development of offshore fields. From the concept selection, an optimal or near-optimal solution of SPT was then applied to an offshore-field development. The application of the optimal solution is simulated with a transient-multiphase-flow dynamic-model program, and the production profiles obtained from the simulation are compared with the reservoir’s production profile. The present paper considers results presented on subsea MPPs as a possible solution to develop marginal offshore fields commercially.
Results and Analysis of Field-Case Study
The simulation covers an 8-year production period simulated over two isolated cases (see the complete paper for discussions of four such cases) with varying water cuts and productivity index (PI). This simulation compared the most-innovative and -effective SPT found through analysis, which is multiphase pumping. The base case is modeled in a transient-multiphase-flow program without any form of subsea processing or gas or water injection. Field A is a typical example, and the current production profile uses an electrical submersible pump (ESP) to boost production; however, this is not modeled here because of the difficulty in handling free gas at suction conditions, because this reduces the efficiency of the pump and creates difficulty in modeling an advanced gas handler or gas separator for an ESP in the transient-multiphase-flow program.
Hence, for each of the cases in the 8-year period, we ran concurrent simulations for different field-development profiles. The field-development profiles were simulated for two production cases:
Field A. The field is located in the North Sea, at a water depth of more than 180 m and a seabed temperature of 4°C. A 26 000-m length of pipeline at an uneven seabed is expected to create slugs in the flowline. The well that was considered was a deviated well with a vertical depth of 1848 m from the seabed and a horizontal distance of 800 m from the wellhead. This is a high-pressure field, with reservoir pressure in excess of 200 bar and temperature in excess of 70°C. Production is through water injection, tied back to a floating production, storage, and offloading vessel.Field B is discussed in detail in the complete paper. Two field-case studies from Field A will be outlined here; please see the complete paper for the results of two field-case studies from Field B.
The emerging subsea processing systems described in this abstract/work, describes the development of the real wet gas compression system. With challenges related to deeper water, longer tiebacks, Reservoir uncertainties, Flow assurance challenges, less productive reservoirs, Low pressure, Maturing assets/ brownfields, Low recovery factors and development costs.
This system integrates several production technologies to optimize performance, lower operating costs and support reliable and safe operation. New technologies in this system are the Multiphase Compressor and subsea coolers.
By putting a Subsea Multiphase Compression system close to the reservoir, you will extend plateau, increase rates, reach an ultimate recovery and improve flow assurance.
Subsea Wet Gas Compression is the compression of unprocessed well stream from a field, different kinds of flow regimes.
In 2009 OneSubsea started the development of the Gullfaks Multiphase Compression system together with Statoil. This was a qualification program of technology and system for the world first real multiphase compression system. OneSubsea started a technology qualification program of the WGC4000 in 2007 to 2011, which has a capacity of 6000 Am3/h, differential pressure of 32 bar and a shaft power rating of 5000 kW. The wet gas compressor was qualified in a submerged test loop arrangement and test medium was live hydrocarbons from the Gullfaks field. Statoil approved the multiphase compressor in 2011.
In 2015 the world’s first subsea multiphase compression system was installed on the seabed and the two WGC units were started up at the Gullfaks later the same year. Utilization of the system will show an enhancement in the gas recovery in the range of 20% for this field.
As the world’s need for energy is increasing, several major gas field developments have taken place on a global scale. One example is the Snohvit project, which went into production in 2006. Another development is the Ormen Lange, which is located some 120 km offshore Kristiansund on the west coast of Norway, at a water depth in the range of 800 – 1,100 m (Bjerkreim, 2004). The fields development was based entirely by the use of subsea technology, with tiebacks to onshore process terminals, hence eliminating the need for offshore production facilities.