A new technology called local heating offers the possibility of significantly raising the temperature of the multiphase production fluid in order to improve flow assurance and consequently the economics of field developments. Heating the flowlines is a way to overcome the thermal constraints, mitigate hydrate & wax risks and provide operational flexibility. Indeed, in the case of long distance tie-backs, very deepwater applications or when the fluid temperature at the wellhead is too low, conventional flow assurance solutions might be very expensive or even not applicable. While other heating technologies such as DEH and Heat tracing are only used under transient operations (start-up, shutdown, preservation), local heating is a different solution, mainly to be used continuously during production and also during transient operations as long as there is fluid circulation in the flowline. The local heating device is a very simple and robust system integrated into a compact subsea module, installed in parallel of the main flowline and which can be retrieved for maintenance or relocated. The technology is compatible with any type of field architecture and can be implemented either on greenfields or brownfields. In the case of greenfields, the use of local heating is a way to mitigate uncertainties on production fluid temperature or solve an unexpected poor thermal performance of the design. The main principles of the local heating technology, as well as a preliminary design performed for a specific case provided by an operator, will be described in the paper. This solution is based on induction and is therefore able to provide very high-power levels (several MW) with a compact module. The temperature is continuously monitored throughout the heating module by means of fiber optic distributed sensors. The technology is fully compatible with preservation by flushing and allows pigging in the event of deposits. The paper will also present the qualification work performed by Saipem to date including heating performance tests performed mid-2018 on a small-scale submerged prototype operated under atmospheric conditions with multiphase fluid. The tests have confirmed the good electrical and thermal behaviour of the system. The next qualification step entails new tests to be performed on a medium scale prototype using crude oil as process fluid. The main objective is to qualify the heating performance tests and the fabrication method of the local heating module under representative conditions: representative process fluid and representative module geometry. The intention is to perform these tests on an existing Brazilian onshore test site in the frame of a JIP.

Subsea processing is becoming necessary for subsea production enhancement in deepwater. For brown fields, when water production is increasing, subsea oil/water separation with water re-injection into the reservoir is a relevant solution. When operated subsea, the produced water treatment will increase oil recovery from mature fields and generate spare topside capacity in order to tie back new wells. Indeed, this solution will provide process capacity for oil (reduction of total liquids) and capacity for injection water (reduction of seawater needs). Current oil/water separation units (Troll and Tordis operated both by Statoil in North Sea) are installed in relatively shallow waters and re-inject produced water into disposal wells. For deepwater applications, the large diameter vessels used on these two projects are not practical, due to the very thick wall required to sustain high pressure (either hydrostatic pressure or wellhead shut in pressure). Saipem is currently developing two bulk liquid separation systems to fit deepwater requirements, one based on gravity separation using several pipes working in parallel, and the second one based on cyclonic separation with compact equipment. After this first separation stage, if produced water is re-injected into injection wells, additional water treatment is then required to meet the stringent requirements of oil-in-water and solids-in-water contents. On this basis, Saipem and Veolia Water have partnered together to develop a series of solutions for deep water produced water treatment, targeting a water quality compliant with operators' requirements to inject produced water safely in existing or new injection wells. One of the developed solutions is based on the use of ceramic membranes which bring advantages compared to more conventional cyclonic systems, giving a much better water quality. This paper will present the global solutions developed for deepwater applications, from the first separation stage to the produced water treatment stage, giving the expected performances and the current maturity of the whole system. Introduction The production of a large number of deepwater fields requires water injection in order to sweep the oil to the production wells (water flooding) and/or to maintain the reservoir pressure by replacing the volume of the produced fluids. The injected water has conventionally been treated seawater while the water coming from the production stream is separated on topsides and disposed to the sea. As produced water cuts increase, produced water reinjection has become common, the oily water being treated on the topsides prior to injection. This paper addresses Subsea Produced Water Re-Injection (SPWRI) applied to mature deepwater fields producing a large amount of water. It consists of separating most of the produced water on the seabed and reinjecting it into the reservoir through water injection wells.

Innovative flow assurance solutions are required to make new field developments both technically and economically feasible. Indeed in the case of long distance tie-backs, very deepwater applications or when the fluid temperature at the wellhead is too low, conventional flow assurance solutions might not be applicable. In this case, heating the flowlines is a way to overcome the thermal constraints, mitigate hydrate and wax risks and provide operational flexibility. Existing heating solutions are based on distributed heating technologies (DEH and Heat tracing) and are mainly considered for hydrate management under transient operations (start-up, shutdown, preservation). Local heating is a different solution, intending to be used continuously during production. Local heating allows for the integration of the system into a compact subsea station, installed in parallel of the main flowline, which can be retrieved for maintenance or relocated to another location. The technology can be implemented either on new fields or for the extension of existing lines. The purpose of this paper is to present an overview of the local heating technology under qualification by Saipem. The heat is provided using induction. This solution is thus able to provide a very high power density leading to a very compact solution. The internal diameter of the line in the heating station remains unchanged from the main production line, which makes the solution fully compatible with preservation by flushing and allows to pig the system in case of deposits. The temperature is monitored throughout the heating module by means of a network of optical fibers. The paper will introduce the main features of the technology, the main scenarios for which this solution is particularly suitable as well as the impact on the field operations. Information will be based on the results of flow assurance studies performed for various types of oils and field configurations. Some preliminary designs of the subsea station will be given, going up to 3MW of thermal power delivered to the fluid. Finally the paper will present the qualification testing recently conducted on a reduced scale prototype, with a description of the prototype and the main results obtained.

New local subsea processing systems will need to be developed to allow remotely located satellite oil fields to be produced economically. One such system treats seawater for injection into the reservoir.As reservoir waters often contain elevated concentrations of barium or calcium, treatment systems need membranes to remove any sulfates that may form in the seawater before it is injected into the reservoir, in order to avoid severe scaling. SPRINGS (Subsea PRocess and INjection Gear for Seawater)is a collaboration project between Total, Saipem, Veolia Water and VWS Westgarth. It was initiated in 2007 and aims to provide robust solutions featuring the use of membranes for treating seawater on the sea bed in deepwater areas.SPRINGS has now reached qualification stage and a first industrial application is planned for 2015.This paper describes the SPRINGS development project, including an update on the latest progress to date. It presents a specific case study conducted in the Gulf of Guinea which illustrates the commercial and technological advantages, along with the limitations, of deploying this technology for future remote applications. It compares the conventional field architecture utilized in conjunction with water injection from FPSO topsides with the architecture required for a SPRINGS solution on the ocean floor.The information provided allows operators to consider an alternative development strategy for the application of membranes to water injection in remote satellite fields.

With most of the world’s largest and easiest-to-exploit deepwater oil reservoirs already under development or producing, the industry is now facing new deep offshore challenges: the production of smaller fields that often contain more difficult oils. The tie-back of new fields to existing facilities can be a viable method for developing such marginal offshore fields, which are often too small to be developed economically on their own. The use of subsea processing and innovative field architectures as development solutions is fast becoming a reality. Such challenges are already being addressed in the development of certain fields in the Gulf of Mexico (King, Perdido...), Brazil (Marlim, BC-10...) and the Gulf of Guinea (Pazflor). However, long subsea tie-backs come with inherent complications. The most demanding are the flow assurance issues arising from the different operating regimes, and these may be combined with more viscous fluids and/or reservoirs at low pressure or low temperature. This paper examines the advantages and limitations of various field architectures that may be considered for long satellite tie-back lengths in deep waters. The first part addresses production considerations such as turndown, preservation and restart management for each candidate architecture. The impact of tie-back length on operating modes is also evaluated. The second part examines the impact of these operating modes on the receiving facilities.