The objective of this study is to describe the complete transport chain of CO2 between capture and storage including a ship transport. This last one is composed by the following steps: Shore terminal including the liquefaction, temporary storage and CO2 loading, Ship with a capacity of 30,000 m 3 , On or off shore terminal including an unloading system, temporary storage and export towards the final storage. Between all the possible thermodynamic states, the liquid one is most relevant two options are compared in the study (-50°C, 7 bar) and (-30°C, 15 bar). The ship has an autonomy of 6 days, is able to cover 1,000 km with a cargo of 2.5 Mt/year. Several scenarios are studied varying the geographical position of the CO2 source, the number of harbours and the way the CO2 is finally stored. Depending on the option, the transport cost varies from 24 to 32 €/tCO2. This study confirms the conclusion of a previous study supported by ADEME, the cost transport is not negligible regarding the capture one when ships are considered. Transport by ship becomes a more economical option compared with an off shore pipeline when the distance exceeds 350 km and with an onshore pipeline when it exceeds 1,100 km .

Today, Subsea processing is recognized to be an efficient way for oil production enhancement, especially for fields having challenging reservoir characteristics or laying in very deepwater. These marginal fields must be developed with cost efficient solutions and innovative technologies to allow the economical recovering of the in place hydrocarbons as the conventional solutions are not viable in such cases. The subsea gas/liquid separation associated with the boosting of produced liquids is one of the possible configurations for the depletion of the marginal fields, as the reduced back pressure at the wellhead can allow a larger recovery of the in place hydrocarbons and simplify the hydrate preservation strategy of the production flowlines during shut down. Being installed in deepwater, the subsea processing systems shall address the mechanical and functional constraints that are imposed by the deepwater installation and operation along with the obvious reliability requirements. In order to provide a solution to this challenge, Saipem has developed a subsea gas/liquid separation and boosting station integrating a gravity separator made of pipes, specifically designed for the deepwater environment: the Vertical Multi-Pipe Separator is composed of an array of vertical pipes that provide the required separation and liquid hold up volume. The reduced diameter and wall thickness of the vertical pipes, as compared with the equivalent single separation vessel, is particularly suited in deep and ultra-deep water applications and/or high pressure services. Furthermore, the system relies on the gravity separation whose efficiency is less prone to the input flow rate and the un-steady regimes than dynamic separation processes. To demonstrate the reliability and effectiveness of the multi-pipe separator, an extensive and in depth qualification and testing program has been performed for the validation of the concept and for the confirmation of anticipated performances. In particular, the validation of the separation performances was carried out, within the framework of a JIP sponsored by BP and Total, in a pressurized multiphase loop handling crude oil, natural gas and water. Introduction The Operators are more and more interested in the development of reservoirs laying in ultra deep waters, or in the tie back of remote or marginal fields to existing production facilities. In particular, the maturation of the Oil Industry's experience in the deep water technology was traditionally made on Oligocene reservoirs characterised by high pressure light oil able to grant large production flow rates in natural depletion. However large Miocene reserves remain available for depletion but characterised by heavy viscous oil in low pressure reservoirs. In all the above cases, the subsea boosting of the produced liquid is required to allow the economical development of the fields with acceptable level of oil recovery. The subsea separation of the associated gas and the subsea boosting of the liquid through pumps is one of the most interesting solution in deep and ultra deep water, allowing longer tie back distances. The installation of a subsea separator is also beneficial in the management of the slugs that may be generated in the subsea flowline network and in certain flowing conditions. The capability of handling large slug volumes is in many cases the sizing criteria for the subsea separators that shall also provide the needed residential time to the gas and liquid phase to separate. The combination of large volume and diameter separators in deep water is always associated to very thick wall thickness of the separator shell that shall resist to the collapse when operating in low pressure or in depressurised condition. The present paper introduces a novel approach to the deep water separation with the aim of avoiding costly and long lead pressure vessels and of making use of line pipes to provide the required separation and slug handling volumes.

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.