Maximizing the use of existing topside facilities is an attractive approach to reduce project CAPEX and therefore unlock new reserves. However, as the tieback length to the host increases, technical and economic challenges arise. These include flow assurance, and costs of the umbilical and flowlines which inherently increase with length. These aspects, together with others independent from the length, such as power and space availability, have a significant impact and could result in making the project unfeasible or uneconomical. Technologies developed in recent years, or in their final stage of qualification, play a significant role, not only in solving the technical challenges, but also in finding cost-effective configurations, either by reducing and/or staggering capital and operational expenditures or by extending reserves recoverability or also by reducing significantly the risks associated with a development. In order to appreciate these advantages, different configurations have been outlined starting from those allowed by the conventional technologies and comparing them to the ones enabled by the new technologies. Actual advantages of each technological "bricks", considered alone or in synergies, depend on the specific projects and can be identified in a timely manner thanks to early engagement of Contractor in the architecture and associated pricing of subsea tiebacks. The paper will present a platform of technologies, their maturity status and how they can be integrated in novel architectures in an economic manner. Such technologies include: Boosting Distributed and local heating Subsea water treatment and injection Subsea separation Subsea chemical storage and injection All electric control system Local power generation

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.

A new subsea-to-shore oil field architecture is presented where produced water is separated, treated and re-injected locally. This solution reduces the overall power consumption and the global CO2e footprint of the development compared to an architecture where the whole production is sent to shore. The paper will present the results of a study for the development of a 200 000 bpd oil field requiring 300 000 bpd water injection located 150 km from shore in 1500 m water depth and with a field life of 15 years. Preliminary design work performed covers flow assurance, subsea process, subsea equipment, subsea layout as well as CO2e footprint comparison with a scenario where all the production is sent to shore. The system incorporates a gravity-based liquid-liquid separator for bulk oil-water separation, produced water is then treated, mixed with desulfated seawater and re-injected. Oil, gas and residual produced water are sent to shore via a single wet insulated line with continuous injection of low-dosage hydrate inhibitors. This scenario has two main advantages compared to a subsea-to-shore without subsea processing. The first is that the power required to boost production is significantly reduced. The second is that the volume of produced water to be treated onshore is also significantly reduced, which is advantageous, not only in terms of cost, but also in terms of reducing the shore operations’ footprint. Particular focus will be made on the produced water treatment design which is a two-stage design using two different technologies for increased robustness in order to reach a specification of 30 ppm oil-in-water for injection water.

A new seawater laboratory pilot has been installed in order to evaluate the impact of the seawater quality on the performance of nanofiltration membranes and filters. The test program implemented was designed to produce the data required to optimize the design and operating parameters of a subsea sulfate removal plant, particularly with respect to the technology developed by Total, Saipem and Veolia, co-owners of the development. The equipment qualification plan is approaching completion with the development of subsea barrier-fluidless pumps, all-electric control systems, high-cycling valves operated by electric actuators and subsea water analyzers. This presented pilot laboratory study completes this plan. Nanofiltration membranes are commonly used to remove the sulfates found in seawater before the water is injected into wells. The principal advantages of relocating this equipment from topside to subsea are better reservoir sweep control, a substantial subsea water injection network reduction and savings on space and weight on the topsides deck. The move to subsea offers the opportunity to simplify the process due to improved deep water quality. This was previously demonstrated through a subsea test campaign. This new pilot study provides data both on the performance of a plant operating with different feed water quality and on the success of operating changes to further optimize the plant performance. The pilot has been installed at the Palavas-les-Flots site in France. Raw water collected from the basin was mixed with ultra-filtered water in order to calibrate the feed water quality. The pilot includes a two stage nanofiltration configuration and single stage nanofiltration unit. The two stage configuration was used to produce data for operation across an array of feed water quality and plant operating conditions. The single stage unit was used to produce data on membrane fouling over a long operating duration. Results from these tests and discussion on how this data relates to subsea plant performance shall be presented. This innovative approach enables a wide range of subsea water quality to be simulated and tested against different process configurations of the subsea unit. Indeed, for each industrial subsea application, the raw seawater quality is dependent on both the region and the depth of the seawater inlet. With this experimental data acquisition campaign and understanding of the seawater quality at inlet, the system design can be tailor-made for each future application case.

The offshore oil & gas industry is presently interested in exploring and developing ultra-deep gas fields for which the water depth is higher than 1,500 m. Considering the water depth and the characteristics of these reservoirs, the exploitation of such fields represents a challenge. To unlock these reserves, it is necessary to tackle obstacles like lack of available pressure, risk of solid deposits (hydrate, wax), and liquid accumulations in low points of the exports line(s). To cope with these issues when the field architecture is not sufficiently flexible (for example, if the number of export lines is limited), one solution is to remove the liquids before production in gas line. SUBGAS has been developed as a potential solution to these challenges and can be implemented over a wide range of application cases. SUBGAS is a subsea station that performs gas/liquid high performance low temperature separation (LTS), allowing gas dewpointing to be performed in subsea conditions. This subsea processing station performs a liquids and condensable components removal from the production gas coming from wells. The treated gas leaving the station is exported alone in the export line(s) while the liquids and condensable components are exported to shore via a dedicated line. Due to the dewpointing operation, the pressure drops in the export gas line(s) are reduced, hydrate and/or wax formation risk is avoided or significantly reduced, and the operability of the line is improved as there is no or a very low amount of liquid. Based on numerical studies, a technical comparison with typical gas/liquid (G/L) separation, subsea compression, and other dew-pointing technologies is presented to highlight advantages of the proposed solution. Then, the SUBGAS station process and design is highlighted through a specific study case. An assessment of the Technology Readiness Level (TRL), according to API 17N, of the solution has been also done showing a high level of maturity allowing a rapid time to market. By performing a gas treatment to remove liquids and condensable components, SUBGAS subsea station proposes an innovative solution to improve gas fields production via long subsea tie backs. Due to its simple process, high robustness, high maturity level, and considering the possibility to be used for brownfield long tie-back development, SUBGAS can be one of the keys allowing to maximize gas fields productions in the coming years.