Subsea Processing and Boosting - Technical Challenges and Opportunities

Subsea processing and boosting can be key enablers or optimization alternatives for challenging field developments and their benefits increase with water depth, flowrates and step-out. Petrobras has invested a lot on the development of such technologies, supported, among other pillars, on an aggressive R&D policy through its technological programs like PROCAP, and several subsea processing and boosting systems have successfully operated in Petrobras fields. Considering that, these technologies are being considered for application in potential Petrobras' scenarios including mature and green fields. This paper aims to give an overview of the systems developed and applied in Petrobras prospects during the last twenty years, such as the Vertical Annular Separation and Pumping System (VASPS), Boosting Systems with Electrical Submersible Pumps (Mudline ESP and MOBO), Subsea Multiphase Pumps, Subsea Raw Water Injection and Subsea Oil-Water Separation (SSAO). It also reports the new R&D initiatives related to subsea processing and boosting that are being developed within PROCAP - Future Vision technology program, showing the main motivations of these developments, the main benefits of using each technology, the technological challenges and typical application scenarios. Also, this paper illustrates the analysis and evaluations performed so far, for all of the new developments presented. Introduction Petrobras has developed and applied several technologies during the last 20 years, forming a very useful " toolbox" for subsea processing and boosting applications. After successful implementation of several technology-projects, on subsea boosting and processing, Petrobras and other operators have demonstrated that such technologies are definitely a very important field development tool, as predicted decades ago. In the beginning of the exploitation of oil&gas offshore fields, the main concern is related to the initial investment to construct the production units, to drill the wells and to install all the equipment necessary for the production. During this phase, there is a lack of information regarding the field, mainly about the reservoir behavior. Normally, the reservoir behavior is calibrated during the productive life of the field. Due to this, the operators usually adopt a conventional solution, not considering the use of new technologies as the first alternative. These are considered most when they are vital for a specific field development. For most fields in Campos Basin, Brazil, the main recovery mechanism for reservoirs, since the beginning of the production, is waterflooding. A typical curve of produced fluids starts with the predominance of oil, rising to the production plateau, until the water breakthrough occurs. At this point, the production presents increasing water content in the liquid stream. So, as it is necessary a massive water injection to keep the pressure of the reservoir, after a few years the watercut of the production increases a lot. Additionally to the two aspects described above, there is also a need to overcome the constraints of existing platforms. These motivations led Petrobras to start in the early 90's the development of subsea processing and boosting solutions. Technological Programs were created to support these developments. Several processing and boosting projects were installed since year 2001, when the VASPS was deployed in the Marimba Field (Campos Basin, Brazil). These projects will be described in a brief way in this paper, focusing their main technological aspects.

With ever increasing energy demands and the depletion of hydrocarbon resources, marginal fields play an important role in oil and gas exploitation. Flow assurance issues, including wax and hydrate formation, can be found in long distance tiebacks. Subsea processing, where processing equipment is installed on the seabed, can be used to solve these flow assurance issues in remote marginal fields. Subsea processing is the leading edge technology for unlocking production from reservoir under complex conditions. This paper demonstrates the opportunities in marginal field development, and analyses the implication of applying subsea processing in remote marginal fields. The marginal field case study concerns a development with an 80 km tieback, having reserves of 120 million barrels of oil and in water 3,000 m deep in the Gulf of Mexico. The technical and economic aspects of two field development options, one employing subsea separation and boosting, and the other, an electric trace heated pipe-in-pipe flowline and subsea boosting, are compared. Hydraulic analysis of three phase flow (oil, gas, and water) using state of the art simulation software (OLGA) is performed to demonstrate production fluid behavior inside the flowline. Life cycle cost, combining both economic (CAPEX and OPEX) and risk factors (RAM), are used as the selection criterion. Subsea separation with continuous hydrate inhibitor injection can prevent flowline blockage over the field life, while the electric trace heated pipe-in-pipe option may require subsea boosting to override the large pressure drop in late field life. In the analysis, subsea separation shows potential life cycle cost savings of up to 13% compared to electric trace heated pipe-in-pipe, indicating it may be the appropriate option when developing fields with these specific conditions. Improvement of subsea processing requires more compact designs for deepwater applications, which will help reduce both capital investment and intervention cost.

Operators can significantly improve hydrocarbon recovery from both Greenfield (new) and Brownfield (existing) reservoirs through the installation of subsea processing systems. Recent and ongoing systems designed for the Gulf of Mexico, West Africa, Brazil and North Sea have employed a variety of separator types and sizes. Designs using gravity based separation similar to surface separators and semi-compact separation techniques have been used. As the industry matures in to deeper and higher pressure applications, there is a need for further development of more advanced separation technologies that can provide enhanced performance with improved compactness, and reduced costs. Principles such as high g-forces, pipe separation technologies and electrostatic coalescence are examples of technologies that may enable the design of compact separators. This paper will describe conceptual designs and descriptions of the various subsea processing building blocks utilized to improve the economics of production. It will also give an overview of the fundamental phenomena providing the separation for the various technologies. References are made to various installations to demonstrate how the applied technologies and how field specific parameters can affect the selection of the separation solution. Additionally, sand handling philosophy is discussed and its affect on separation design. Introduction Subsea processing is one of the most attractive technologies currently being utilized and considered by the oil and gas industry. Treating the production flow at the seabed opens many opportunities to achieve more effective exploitation of oil reservoirs around the world. This is important as the oil industry is running out of the oil that has been " easy?? to produce, meaning that the focus now is placed on how to produce oil from offshore fields in deeper waters and in more remote areas cost efficiently. Subsea processing has been driven by the need to:Manage pressure issues related to producing heavy oil;Increase pressure and hydrocarbon output at fields with low reservoir pressures;Address hydrate formation risks;Combat declining oil production and associated increased water cut in brownfields; andReduce constraints topside facilities are faced with by performing functions on the seabed Produced water separation and re-injection is one of the first subsea processing concepts applied. In Norway both the Troll C Pilot and the Tordis SSBI projects have followed this approach. The advantages of this concept lay in the reduction in back pressure accorded by the reduction in fluid gradient. Not only does this result in increased production but also improved recovery. Additionaly this approach eliminates any need to increase produced water handling capacity on the host; retrofits of such expanded capacity are often highly expensive or impossible. The Tordis Subsea Separation and Boosting and Injection system was installed and started up in 2007. As the name implies, this version of the technology was designed to further improve the project economics by providing boost to the hydrocarbon stream; as well as water separation and disposal. The processing station has proven to work in accordance to design and generally has exceeded expectations. However, operating problems outside the processing station in the injection well has limited the use of the station. The Operator is currently investigating options to resolve this and the system should be returned to full operation in good time.

The offshore oil and gas industry is developing subsea processing systems far away from the shore and in ultra-deepwater. These subsea systems are usually power intensive, and thus a reliable electrical transmission and distribution (T&D) system is desired. In this paper, the modular stacked direct current (MSDC) architecture is presented to meet the technical challenges of the ultra-deepwater subsea systems. Instead of using a bulky centralized high voltage direct current (HVDC) converter station, the high dc voltage is achieved by stacking a number of power converter building blocks in series on both the on-shore station and the seabed stations. The dc-link current is controlled to be constant, and the dc-link voltage will vary according to the loading condition. This architecture renders fault-tolerant capability and feasibility for field extension. The details for the system architecture, the control algorithm, the simulation and experimental results will be described. The test results and the studies show that the MSDC system is a very attractive solution for subsea applications. Introduction The diminishing conventional oil and gas reservoirs and the always growing energy consumption have been driving the efforts to explore the deep-sea water petroleum resources, as shown in the diagram in Fig. 1. These resources are usually in ultra-deepwater and far away from the shore, where subsea process is usually preferred for technical and/or economic reasons. Subsea processing is especially attractive for the locations with tough topside environment since the manned topside platform can be removed. However, in order to achieve subsea process, turbo machines, e.g., pumps and compressors, and other processing equipment need to be deployed on the seabed. Accordingly various electrical equipment, including variable speed drives, power supplies, motors, connectors, switch gears, etc., are required to drive the machinery loads subsea. The overall power requirement ranges from tens of kW to tens of MW. As the scale and power consumption of the subsea process continue to grow, there is a clear need for a reliable power transmission and distribution system to power the subsea equipment over long step-out. Long step out distances and the ultra-deepwater environments have brought significant technical challenges to the electrical system. In ultra-deepwater and long step-out situation, accessibility of any equipment deployed in the subsea field is extremely limited. Subsea operation and maintenance is dependent on availability of vessels with remotely operated vehicles (ROV) and sufficient lifting/installation capacity, hence unplanned stops due to failures will cause large losses in production due to lost time. The cost of the vessel and offshore operation is also significant. Therefore, other than being designed for installation in ultra-deepwater, the electrical system must be very reliable and require minimum regular maintenance in its lifetime. The electrical system should also be as compact as possible and modularized, so that they can be installed and retrieved without heavy vessels and lifts which have very limited availability. In addition, the electrical system should be flexible and easy to be reconfigured since the power requirement, the tie-back length, and the number of loads will vary from site to site. And it should also have the flexibility for future expansion since additional field might be found in the adjacent area. In order to meet the above mentioned challenges and requirements, the MSDC architecture has been developed for the subsea power transmission and distribution with long step-out. This paper compares different technology options for subsea transmission and distribution (T&D), presents the MSDC architecture, describes the details of the system operation, and discusses the results of the field case simulation and the lab demo.

The Parque das Conchas (BC-10) development located in the deepwater BC-10 block offshore Brazil - comprises of relatively low-energy, low-API reservoirs (Ostra, Argonauta B-West) and one high-GOR field (Abalone) - tied back subsea 9 to 34 km to an FPSO. To enhance production and maximize recovery, an innovative subsea separation and boosting technology has been employed, consisting of a shallow well conductor that contains a caisson where liquid and gas are separated prior to transport to the surface. In the case of Ostra/Abalone, separated gas flows naturally to the FPSO via a dedicated, un-insulated gas flowline. Separated single phase fluids at the bottom of the Caisson are boosted via an electrical submersible pump (ESP) located within the caisson, and transported to the FPSO in a wet insulated flowline. The heavier B-West fluid is separated and recombined in the caisson and pumped as a multi-phase mixture. The addition of the Caisson/ESP (C-ESP) subsea separator and pumping system has significantly reshaped the flow assurance challenges and analysis processes typically applied to deepwater subsea tieback developments. For instance, several of the traditional flow assurance concerns - such as hydrate control, slug management, sand handling, and emulsion/foam tendency - will now involve a different set of design and operability requirements. Additionally, " ensuring the flow?? in the C-ESP system itself involves several unique design and operability challenges, associated with separator design and control and mitigation of separation inefficiencies. This paper describes some of the new challenges and analysis tools to be encompassed by flow assurance engineering, as this new area of subsea processing emerges in deepwater developments. The role of the flow assurance engineer will expand to include subsea " process systems engineering?? - i.e. the application and extension of traditional process engineering approaches to the design and operability of subsea separation and artificial lift systems. Introduction The Parque das Conchas development is located in block BC-10, approximately 74.5 mile South West of the coast at the city of Vitoria in Brazil in water depths about 5,900 ft. Shell is the operator with a 50% working interest, in a joint venture with Petrobras (35%) and ONGC (15%). Phase 1 of the development includes three fields - Ostra, Abalone and Argonauta B-West, each with different fluid properties. Argonauta O-North is currently in planning for development in Phase 2. Ostra and Abalone fields use the concept of subsea separation and boosting. B-West uses a novel non-separated boosting system in which the multiphase fluids from the well are separated and then recombined and boosted using a conventional ESP. The Ostra field will be produced via six horizontal wells. The oil has an API of 24 and a GOR of 274 scf/sbbl. Abalone has an API of 44 and a GOR of 3,800 scf/sbbl and behaves like a gas condensate. B-West has a heavier oil with an API of 16 and a GOR of 194 scf/sbbl. An additional challenge at B-West is the unusually high viscosity of the fluids, especially below the bubble-point.

To surpass the main challenges established by deep water, high gas-oil flowratios, flow assurance and constant increases in produced water, Petrobras is developing, within PROCAP Technology Program - Future Vision, several projects in the subsea processing area, such as: Compact Oil-Water and Gas-Liquid Separation Systems, Multiphase Pump with High Differential Pressure and Gas Compression System. The main applications of these projects are in fields with high fraction of gas and water, in fields/discoveries located far away from Production Units and to increase the reservoir recovery factor. Furthermore, the application of these technologies may have great benefits, such as: production anticipation, reduction of process system footprint on the Production Unit, decrease in CAPEX/OPEX and especially an increase of the topside oil processing capacity. This paper aims to present an overview of those technologies being developed in PROCAP - Future Vision. Also, this article shows the main motivations of these developments, the main benefits of using each technology, the technological challenges and gaps, typical application scenarios and results of the evaluations performed so far. Major petroleum companies are searching for new technical solutions that fulfill their needs of reducing both CAPEX and OPEX while increasing oil and gas production. The development of new subsea processing technologies, as stated above, will enable, and in some cases reinforce, the use of these technologies for deepwater and/or subsea to shore scenarios. Introduction Subsea processing is a key enabler for challenging field developments, and their benefits increase with water depth, flowrates and step-out. Regarding subsea separation, these advantages are maximized when employing subsea compact separation technologies. Also, subsea processing brings HSE benefits related to reduction of waste disposal to sea, an environmental contribution of subsea oil-water separation systems, and the possibility of using smaller platforms - or none at all - due to the use of processing equipment on the seabed instead of topside, reducing operational risks. In terms of compact separation technology development, Petrobras has been conducting several R&D initiatives for the last ten years. Firstly, these R&D initiatives were developed for topside and onshore applications, but always keeping on mind the subsea employment. In order to evaluate these technologies several tests have been performed. More recently, the Marlim SSAO 3-Phase Subsea Separation System is a very significative example of compact subsea technology employment, for a single producer well application. Multiphase boosting is always considered as a good alternative to develop oilfields, mainly for remote areas. Petrobras invested a lot on the development of twin screw and helicoaxial concepts for multiphase pumps, targeting applications with required differential pressures up to 60 bar. Recently, analysis has indicated that High Differential Pressure Subsea Boosting (up to 150 bar) is economically and technically attractive to various Petrobras scenarios and, because of that, many R&D efforts are being done to develop such technology.

The use of subsea technologies and innovative field architectures as development solutions for oil and gas fields is fast becoming a reality. In the last ten years more than half of new global oil and gas reserves have been discovered offshore, especially in deepwater. This paper shows the selection path followed systematically for the proper technical and economical solution selection, passing through concept screening and case-specific conceptual studies. A typical case study will be presented in this paper, showing the advantages to be gained in using the proposed selection exercise, including flow assurance strategies, for the development of challenging new upcoming reserves deepwater. The values presented are for a generic offshore development. The purpose is to pinpoint the limits of existing technologies, identify new subsea architectures implementing upcoming subsea processing solutions and compare and illustrate the performances of several configurations for a development in about 1000 m of water, through a case study. A problematic oil will be considered, having a density in the range of 20–30 °API, a GOR in the range of 200–400 scf/bbl, wax and hydrate formation risk. Total liquid flowrate in the example is around 50,000 bbl/d, selected in order to be out of giant project frame. Conventional loop, single production line, electrical heating, gas/liquid separation, subsea liquid or multiphase boosting are the scrutinized solutions, applied considering on site or long distance topside facilities and upward or downward production line path. The analysis reported in this paper evidences the technical feasibility and when benefits are obtainable implementing subsea processing technology on offshore oil and gas fields. The principles described could be the base to perform a multi-parameters study for real case technology selection. This paper examines the drawbacks, limitations and advantages of various field architectures and technology solutions, that may be considered for deepwater oil development. It covers the different production phases, from start-up to tail production, without forgetting flow assurance issues, typical of long satellite tie-back lengths in deep waters. INTRODUCTION In the last ten years more than half of new global oil and gas reserves were discovered offshore, especially in deepwater [1]. Usually such hydrocarbons reservoirs are located in remote areas, far from existing facilities. Traditional development solutions to exploit this kind of reserves are no longer applicable, due to both technical and economical constraints. Technologically advanced solutions are needed in order to efficiently produce oil and gas from satellite fields to overcome technical and economical difficulties. Especially for marginal fields, containing relatively small amounts of reserves in place, increasing the overall recovery factor is crucial to make the field economically sustainable. Marginal fields means too small to support the investment required for a conventional standalone development or too depth and far from existing facilities to be produced by means of conventional surface production technologies. Therefore marginal fields are more challenging to exploit in a cost-effective manner. The only way to unlock these reserves is to minimize the investment for facilities that will extract and process the hydrocarbons.

In the current energy shortage and transition context, gas represents an alternative to provide an affordable, reliable and less GHG emissions issuing energy than other available fossil energies. Flow Assurance studies have been launched for a series of gas fields to identify optimal subsea processing functional requirements for a subsea to shore export. The objective is to confirm the robustness of subsea processing architectures identified in previous studies and to evaluate their sensibility towards water depth, step-out, fluid composition and bathymetry. First, real gas fields were selected, the portfolio was completed with notional cases constructed on analogs to reach a good mapping in depth and distance to shore. For each case, bathymetries and PVT models were established. Ledaflow® was used to construct flow models and define the necessary pipeline size based on early and late life flowrates (based upon Erosion Velocity Ratio, Turn down and hydrate risk). When the multiphase export required several pipelines in parallel, an alternative architecture was studied consisting of multiphase pipeline at early life and then gas/liquid separation plus single phases export (separated gas pipeline and liquid pipeline) for late life. Compression and boosting requirement were evaluated. More than one configuration is technically possible. The solution of "multiple multiphase export pipelines" is usually in competition with a "single multiphase pipeline at early life coupled with a subsea separation at late life". The first configuration favors operational flexibility, while the second one favors reduced installation time and cost and allows decreasing the well head back pressure to increase reserves. However, this last solution still requires the installation of a liquid line at late life. Regarding boosting requirements, each configuration has compression needs at late life. The first architecture allows to optimize the compression requirements and increase the process efficiency, while the second one present the drawback of high boosting requirements for the liquid line for great depth and longer step out. For the multiphase export, and a field with very low CGR, the governing parameter for the pressure loss and the compression requirements is the step-out, not the water depth, while, for the subsea separation scheme, the water depth becomes detrimental for the boosting requirements of the liquid line for the great water depths. This large study confirms the feasibility of subsea to shore architectures for gas fields and allows identifying the limitations of the existing technologies and anticipating future technological developments.

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 19083, "The New Deepwater Oil and Gas Province in Brazil: Flow Assurance and Artificial Lift: Innovations for Jubarte Heavy Oil," by Giovani Colodette, Carlos A.G. Pereira, Cezar A.M. Siqueira, Geraldo A.S.M. Ribeiro, Roberto Rodrigues, Joao S. de Matos, and Marcos P. Ribeiro, Petrobras, originally prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed. The full-length paper presents a review of the artificial-lift (AL) and flow-assurance challenges faced in the exploitation of Jubarte heavy oil, starting from the features of the Pilot Phase. The challenges posed and innovations proposed and implemented for Phase 1 field development, as well as expectations for the subsequent Phase 2, are detailed. Introduction The Jubarte field is in the north part of the Campos basin, approximately 80 km offshore from the state of Espírito Santo, at a water depth between 3,280 and 4,922 ft. The field discovery occurred in January 2001, when an interval containing 17°API oil was identified in sandstones of Maastrichtian age. During the evaluation phase, a study based on the concept of value information supported the decision to drill a horizontal appraisal well. In February 2002, the well was drilled, with a 3,510-ft horizontal length, and was completed with an openhole gravel pack. The result was a well productivity index (PI) 13 times greater than the PI obtained with the vertical well. An extended well test (EWT) was proposed and approved. In the EWT, which started in October 2002, Petrobras made use of the floating production, storage, and offloading (FPSO) vessel Seillean, a dynamically positioned vessel with a rig capable of performing light workover operations. The well was connected to the FPSO through a 5 5/8-in.-inside-diameter drillpipe riser. Using an innovative solution, a 900-hp, 25,000-B/D-capacity electrical submersible pump (ESP) was installed above the wet tree. In case of ESP failure, the drillpipe riser could be recovered by the FPSO for pump retrieval and replacement. The good results obtained in the EWT led to its continuation in a Pilot Phase, which lasted until January 2006. After the Pilot Phase, the Jubarte Phase 1 production was started with the FPSO P-34. This new development phase comprises four production wells, and a 60,000-B/D oil-production rate is expected. One of the wells represents an innovative installation of the ESP on the seabed, another well has a downhole ESP installed, and the remaining two wells produce with gas lift (GL). GL backup can be used in the ESP wells while awaiting repair in case of pump failure. The ultimate Jubarte production system (Phase 2), to be implemented in 2011, will comprise 11 new wells plus the four wells from Phase1, and seven water-injection wells, connected to the FPSO P-57. During this production phase, all production wells will run ESPs installed on the seabed as the main AL method, with GL as backup.

The article provides an analysis of shale oil production and artificial lift equipment world market for choosing the optimal method for oil production from the Bazhenov formation. The result of the analysis is the identification of prospective complexes of artificial lift (wellhead and downhole) equipment that meet the following conditions:
 • artificial lift equipment is used in operating conditions that are similar to those, which planned for the Bazhenov formation development: for wells with a long horizontal wellbore and multi-stage hydraulic fracturing; conditions similar to the Bazhenov formation in terms of the depth of the deposit, production volumes (production curve, initial flow rates, gas-oil ratio (GOR), reservoir temperature, etc ).;
 • the properties of the produced fluid are similar to the Bazhenov formation reservoir fluid (light oil, GOR increase over production time, water cut drop over time, etc.
 Analysis includes wellhead equipment, downhole equipment, and control stations for wellhead and downhole equipment.
 Based on the analysis results, the main selection criteria are given, a comparative analysis of the main types of artificial lift equipment is carried out, and promising types of artificial lift for oil production from the Bazhenov formation are identified.

A 2-layer non-hydrostatic model with improved dispersive behaviour is presented. Due to the assumption of a constant non-hydrostatic pressure distribution in the lower layer, the dispersive behaviour is improved without much additional computational time. A comparison with linear wave theory showed that this 2-layer model gives a better result for the dispersion relation and shoaling of waves in intermediate water. This means that the 2-layer model is applicable in shallow and intermediate water depths (up to relative depths kh equals 4), whereas the 1-layer model is only applicable in shallow water depths (kh smaller than 1). Three laboratory experiments, including a fringing reef and a barred beach, were used to validate the presented mode for different hydrodynamic conditions. Based on these results, it can be concluded that the 2-layer model can be applied to accurately simulate the bulk wave height and spectral properties. The low frequency wave height, the setup and in particular the second order statistics contain more scatter, but the model accurately captured the general trend. Furthermore, the model showed good results for complex bathymetries in shallow to intermediate water.

This paper presents the Technical and Organizational Challenges SOFRESID ENGINEERING have met to extensively engineer the modification and upgrade of GIRASSOL FPSO to accommodate the production of a new oil field : ROSA offshore Angola. Technical challenges came from the drastic limitation in additional weight, stability and available space of such an existing floating vessel, as well as operational constraints such as reducing shut down time, hook up operation and the need of a complete revamping of the Control and Safety System. Organizational challenges came from the limitation of lifting and installation means that drove the design optimization, the need of an extensive and accurate knowledge of the as built facilities. They were increased by the overall market situation leading to long procurement lead time and scarcity of Engineering resources. The main objective of this paper is to describe these challenges and the way SOFRESID ENGINEERING and TOTAL E&P ANGOLA have worked together under a new contracting strategy to overcome them by developing innovative solutions such as an intelligent 3D modeling coupled Laser Survey, continuous module design optimization, advanced lifting frame arrangement, and a proactive multi-center engineering organization. Introduction The ROSA field located in block 17 offshore Angola will be developed through the existing Floating Production Storage and Offloading (FPSO) GIRASSOL which needs modifications and additional facilities to accommodate such additional production. GIRASSOL is the first very large FPSO ever installed:Production capacity : 220,000 bod,Storage capacity : 2,000,000 barrels,Water depth: 1,350 m,FPSO size: 300 m × 59 m × 30 m,FPSO weight: 350,000 t,Topside equipment: 25,000 t dry,Gas compression and reinjection at 350 bars (25 MW). Capacity increase will be significant, with a stream capacity which will jump up to 270,000 bod and water treatment facilities from 180,000 to 300,000 bwd to be injected in the field at 275 bars. SOFRESID ENGINEERING has been awarded by TOTAL E&P ANGOLA a comprehensive Engineering, Procurement services and ICSS supply contract to engineer the first ever done upgrade of a new built FPSO under operation. This contract is made of several elements such as Lump Sum for the Supply, Target cost for Engineering services, full Reimbursable for Vendor and Contractor Follow up and several Bonus / Malus clauses forming an innovating incentive scheme regarding Project Cost, Weight and Shutdown time. During this large Engineering work all provision have been taken for the execution of the project considering that construction, installation, hook up and commissioning on the FPSO will be accomplished in a SIMOPS mode (Simultaneous Operations and construction). Objectives given by TOTAL E&P ANGOLA and shared by SOFRESID during all the project duration have been:to secure Safety of People and integrity of the Installation,to minimize Shut-down duration on GIRASSOL FPSO,to simplify offshore Hook Up operation,to ensure Operability of installation,to optimize Cost, Weight and Schedule.

As most of the light and easy oil fields have been produced or are nearing their end-life, the emulsion stability is enhanced and water cut is increasing in produced fluid which have brought challenges to oil–water separation in onshore and offshore production trains. The conventional solution to these challenges includes a combination of higher chemical dosages, larger vessels and more separation stages, which often demands increased energy consumption, higher operating costs and larger space for the production facility. It is not always feasible to address the issues by conventional means, especially for the separation process on offshore platforms. Electrostatic coalescence is an effective method to achieve demulsification and accelerate the oil–water separation process. In this paper, a novel compact electrostatic coalescer with helical electrodes was developed and its performance on treatment of water-in-oil emulsions was investigated by experiments. Focused beam reflectance measurement (FBRM) was used to make real-time online measurements of water droplet sizes in the emulsion. The average water droplet diameters and number of droplets within a certain size range are set as indicators for evaluating the effect of coalescence. We investigated the effect of electric field strength, frequency, water content and fluid velocity on the performance of coalescence. The experimental results showed that increasing the electric field strength could obviously contribute to the growth of small water droplets and coalescence. The extreme value of electric field strength achieved in the high-frequency electric field was much higher than that in the power-frequency (50 Hz) electric field, which can better promote the growth of water droplets. The initial average diameters of water droplets increase with higher water content. The rate of increment in the electric field was also increased. Its performance was compared with that of the plate electrodes to further verify the advantages of enhancing electrostatic coalescence and demulsification with helical electrodes. The research results can provide guidance for the optimization and performance improvement of a compact electrocoalescer.

SPRINGS® (Subsea PRocessing and INjection Gear for Seawater) is a qualified process for subsea water treatment and injection. It uses membrane technology for water desulfation upstream of water injection wells to prevent sulfate scaling on the production side (nearwell bore, well and production equipment). It moves the water treatment from topside to subsea locations close to the injection wells with only power and communication tie-backs to existing topside facilities. Qualification of the process was achieved through both onshore and offshore trials. In advance of deploying the first industrial application, an industrialisation programme was undertaken in order to ensure that every component necessary for the subsea process implementation was available and had a sufficient technology readiness level to be safely installed and operated within the subsea plant. The existing and available technologies were reviewed vis-À-vis the requirements arising from both the process and the business strategy. Several industrial partners were engaged to determine the elements of novelty that needed to be brought to each technology or component to satisfy such requirements. The new technologies included: Subsea barrier-fluidless pumps Open framework all-electric control systems High-cycling electric actuators and valves Subsea water analyser Subsea storage and injection units for chemicals The design basis for the development of each technology, which in most cases included the realisation of a prototype and relevant qualification testing, was set up to consider a range of possible applications with differing environmental conditions, process data and/or IMR scenarios. The most challenging conditions were selected for each development to determine the relevant required performance. Where available, specific standards, such as API 17F (ref. [8]) for subsea electronics, were followed to determine the qualification plans. In those cases where no dedicated specific standard was available, the evaluation of the proposed solution was performed in conjunction with the technology provider through the risk based approach stated in API 17N (ref. [9]) and DNV A203 (ref. [10]). Failure Modes, Effects and Criticality Analyses (FMECAs) as well as technology readiness assessments were performed in order to develop the technology qualification plans. Most of the key equipment qualification plans will be completed by mid-2019, establishing an industrial platform for the deployment of the subsea water treatment and injection technology in a completely all-electric configuration, i.e. connected to the surface only through a communication and power cable. Such an industrial platform will also contain the building blocks for other subsea processes. The presentation and paper will introduce the elements of technological novelty and will describe the process, the challenges and the results of the relevant qualifications.

This paper presents Computational Fluid Dynamics (CFD)-based simulations of the hydrodynamic behaviors of a floating barge in shallow waters on an inclined seabed near shore. The hull hydrodynamic behaviors with respect to water depth are quantified by evaluation of the hydrodynamic coefficients, i.e., added mass, viscous damping coefficients, and current drag coefficients, which are required for the prediction of hull motion responses and mooring loads of the barge. CFD simulations are performed to predict the hull hydrodynamic coefficients with consideration of the actual seabed conditions, including water depth and varying bathymetry. Added mass and viscous damping coefficients are calculated using forced harmonic oscillations, while current drag coefficient is obtained using steady current flow simulation. These hydrodynamic coefficients are calculated for three of the six degrees of freedom (DOFs), i.e., surge, sway, and yaw of the hull. By considering three different nearshore water depths with a flat seabed and two inclined seabeds, the hull added mass, viscous damping, and current drag coefficients are quantified and compared against the coefficients in deepwater conditions. The hydrodynamic coefficients are found to be significantly affected by shallow water depths. Overall trends show exponential increase of added mass and viscous damping coefficients as water depth reduces. There is a further linear increase in the coefficients when the seabed bathymetry changes from flat to inclined, particularly when the water depth to hull draft ratio is less than 4.50. Similarly, current drag coefficients increase with decreasing water depths for flat seabed conditions, while for inclined seabed conditions, they may increase or decrease depending on the directions with respect to the shore and the current heading. This paper demonstrates the efficiency of CFD simulations in predicting a floating barge’s hydrodynamic behaviors in shallow water conditions, including varying nearshore bathymetry and viscous effects. The CFD simulation methodologies presented may be extended for the hydrodynamic behavior assessments of other nearshore floating structures such as Floating Offshore Liquefied Gas Terminals (FLGTs), Floating Storage and Regasification Units (FSRUs), and floating wind turbine structures.