In the current energy transition scenario, gas represents one of the main pillars for a greener energy mix. In 2015, we presented two promising schemes to produce a challenging notional gas field located 2500 meters water depth and 300 km from shore using only subsea processing [1]. The first scheme consists of subsea gas/liquid separation, gas compression and liquid boosting for multiphase export to shore; the second, developing a subsea high-pressure dehydration system for up to 300 Bara, using adsorption, to avoid the use of a monothylene glycol (MEG) loop and export dry gas directly from subsea. Performance of desiccants at such high pressure has not been studied thoroughly and qualification was necessary. This paper presents the proof-of-concept of a subsea dehydration technology at high pressure. Several criteria were used to evaluate the potential technologies: treatment performance, power consumption, production at varying pressure, sensitivity to feed contaminants, CAPEX, OPEX, weight & size, among others. The preferred solution was concluded to be temperature swing adsorption (TSA). Once TSA was selected as the most promising dehydration technology, different laboratory tests were performed and several parameters were identified to screen the potential desiccants: adsorbent working capacity, water/CH4 selectivity, water adsorption energy and regeneration temperature. Finally, a pilot was built and a test matrix was run in order to prove the concept. The adsorption, and specifically a TSA Process, was the technology selected in the first part of the study. The choice was based mainly on the energy efficiency and the technology readiness level. In the second part of this project, the feasibility of the process at high pressure (up to 300 Bara) and its application subsea were proven through experimental tests performed at a laboratory pilot. Characterization tests and water and methane adsorption/desorption isotherms are briefly presented. Based on these results, zeolite, alumina and activated carbon adsorbents were identified. Finally, complete adsorption/desorption cycles at different pressures and temperatures were performed, proving the concept and its potential. This is the first study proving experimentally the concept, and presenting the potential, of the TSA Process for subsea dehydration at high pressure. This is one of the subsea processing building blocks identified in many gas field architectures and it is especially required to produce remote and deep reservoirs at competitive costs.
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.
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.
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