Subsea Processing Systems Research Articles

Technology Focus: Subsea Systems (August 2023)

Emerging from the COVID-19 pandemic, and coupled with increasing activity for energy production, the latest focus on subsea systems indicates that the subsea industry is moving with the times, reflecting technology developments, and meeting overall society demands in terms of holistic energy supply. The papers reviewed and selected focus on key development areas—carbon capture, utilization, and storage (CCUS); renewable energy applications; and subsea storage. Implementing subsea systems to meet energy demands maintains the traditional emphasis on reviewing, refining, and incrementally improving the techniques and technology applications of today. Such efforts have a huge bearing on the direction of subsea engineering, and the overall efficiency and effectiveness of subsea operations cannot be underestimated in their contribution to the energy mix. It is worth noting that, with the current focus on greenhouse gas (GHG) emissions, subsea developments are among the lowest in terms of GHG footprint per barrel of oil equivalent, reflective of application improvements over many decades. While not a solution to the overall energy challenges themselves, this is a good marker for where future offshore industry efforts are positioned with regard to the energy transition. Specifically looking at the papers in review, we see carbon storage optimizing subsea development potential, adding to and incorporating existing technology as well as adapting it to optimize the massive potential of subsea CCUS storage, particularly in conjunction with near-shore CO2-production-intensive industries. In addition, with a nod toward the energy transition, the application of renewable energy to assist with reducing the GHG footprint of subsea operations is presented. Finally, from an efficiency point of view, as existing subsea systems approach all-electric operations, the parallel demand for increasing monitoring through improved sensing and communications is presented through analysis of all-optical subsea sensing capability with a potential effect on life-of-field efficiency. I hope these selections will spur thoughts and affect how we as subsea engineers approach future developments for both hydrocarbon and energy-transition requirements. Recommended additional reading at OnePetro: www.onepetro.org. SPE 210910 Innovative Industry Lead Project for Renewables for Subsea Power by Ian Roger Crossland, Mocean Energy, et al. SPE 205433 A Road Map for Renewable Energy Integration With Subsea Processing Systems by Juliano Pimentel, Aker Solutions, et al. OTC 31294 Subsea Liquid Energy Storage—The Bridge Between Oil and Energy/Hydrogen by Kristian Mikalsen, National Oilwell Varco OTC 32449 A New Subsea Station for Deep Gas Treatment Allowing Maximizationof Subsea Gas Fields Production by Paul Roland, Saipem, et al.

Reliability-based structural design of a vertical subsea separator for deep-water applications

This paper presents an integrated framework for the reliability-based design of deep-water vertical subsea separators using a novel collapse strength model. An analytical model for collapse strength prediction of a vertical subsea separator subjected to external pressure is proposed based on numerical simulations covering different geometries and imperfections. The proposed strength model is verified against experimental collapse pressure and other analytical models. The application of the presented methodology is demonstrated in a case study where uncertainties are systematically considered and the target reliability is used as a single design constraint. The First Order Reliability Method is adopted for the reliability-based design and probabilistic safety evaluation of the subsea separator and sensitivity and partial safety factors assessment. This framework is useful for the design of subsea processing systems as technology qualification and standardization of subsea separators are not fully available.

Bayesian framework for reliability prediction of subsea processing systems accounting for influencing factors uncertainty

A Bayesian network probabilistic framework is suggested for reliability prediction of two conceptual subsea processing systems. A suitable reliability prediction method for mechanical equipment is selected and then illustrated stepwise to estimate the total failure rate of the main subsea equipment from reliability data available for similar offshore topside equipment. First, a Failure Mode and Effects Analysis is conducted, then the main Reliability Influencing Factors on equipment failure are identified and the corresponding influence diagrams are developed. Bayesian network models are developed to describe the uncertainty on the Reliability Influencing Factors and to assess their effect on the equipment failure and subsequently on the reliability of the subsea processing systems. A sensitivity analysis is then conducted to evaluate the relative importance of Reliability Influencing Factors on the equipment and systems reliability. The paper contributes with a highly flexible approach that is suggested to model the uncertainty on the expert judgments when predicting the failure rates of new equipment operating in new scenarios, which can be updated as more information becomes available or more knowledge is provided by experts.

Technology Focus: Offshore Facilities (September 2019)

Technology Focus I had the pleasure of reviewing 322 offshore-facilities papers submitted to SPE during the past year and selected three for inclusion in this issue as well as three for additional reading. This is my first assignment as a member of JPT’s Editorial Committee, and I am grateful. During my summer family vacation, I enjoyed reading all of the papers and considered a special theme related to today’s disruption of our oil and gas industry known as “Industry 4.0.” The first industrial revolutions were related to the commencement of electrification, followed by machinery. The third is the computer era, and the fourth (4.0) is the current age of machine learning, artificial intelligence, data analytics, and the Internet of things. Therefore, to start our discussion, let us ask the basic question: What is the definition of offshore-facilities project success in the context of Industry 4.0? Generally, cost (economic), time, and scope (quantity and quality, including safety) are the common project-success indicators. However, I believe we can expand these indicators to the social and environmental areas. So, for the oil and gas upstream industry, Industry 4.0 is the strategic positioning of technologies that can benefit production assets, business, and sustainability (social and environmental). The development of new subsea and offshore technologies, methods, processes, and monitoring should consider the tangible benefit of social and environmental effects. The selection of innovative subsea processing systems, platforms, real-time monitoring applications, automation, smart fields, intelligent wells, data analytics, and well/reservoir/facilities technologies and decommissioning should reflect an initiative to improve environmental performance. For instance, when a stakeholder selects a subsea processing and facilities technology scheme, it should optimize and accelerate the recovery of hydrocarbon, increasing its yield, extending the life of the field, reducing the floating production facilities while minimizing carbon footprint, and creating a positive social effect and low environmental impact. Let us consider another offshore-facilities project example. The world’s offshore liquefied-natural-gas (LNG) production concepts began in the 1970s but were only significantly enhanced in the mid-1990s. I was a finalist in the SPE Student Paper competition at the national level in 1997, and I wrote about the concept of floating liquefied natural gas (FLNG) facilities in Indonesia as a case study. The FLNG concept has been used because it has the capability to transport the LNG to nearly any location. However, we know that the design of FLNG facilities has many challenges, including floating design, process selection, equipment sizing, process safety, wind effects, metocean effects, and product transfer. Therefore, for FLNG, bigger is not always better and a sustainable business model is important. It took almost 25 years for engineers and experts to construct an FLNG facility. Now, the Prelude FLNG is the world’s largest FLNG facility as well as the largest offshore facility ever constructed. To derive the greatest benefit from Industry 4.0, we must develop strong and reliable data, lessons learned, experiences, and knowledge management. The three papers and recommended additional reading presented here reflect support for the implementation of Industry 4.0 such as innovation, digitalization (automation), low-cost facilities development, project flexibility, and facilities life extension. I hope you enjoy reading these papers as much as I did. Recommended additional reading at OnePetro: www.onepetro.org. OTC 28256 Standardization and Replication of Lean Wellhead Platform To Accelerate Hydrocarbon Maturation From Exploration to Production for Marginal-Field Development by H. Yong, Shell, et al. OTC 28276 Cost-Effective Riser Solutions for Deepwater Gas Developments: Steel Lazy Wave Riser and Tethered Catenary Riser by Stéphan Eyssautier, Subsea 7, et al. OTC 28340 Pragmatic and Consistent Approach to Life Extension of Floating Structures by Cedric Morandini, Bureau Veritas, et al.

How Will Subsea-Processing Technologies Enable Deepwater-Field Developments?

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 27661, “How Will Subsea Processing and Pumping Technologies Enable Future Deepwater-Field Developments?,” by Phaneendra B. Kondapi, Texas A&M University, and Y. Doreen Chin, Ashesh Srivastava, and Zuying F. Yang, Subsea Engineering Technologies, prepared for the 2017 Offshore Technology Conference, Houston, 1–4 May. The paper has not been peer reviewed. Copyright 2017 Offshore Technology Conference. Reproduced by permission. This study examines how subsea processing (SSP) can develop into an important enabling technology for future ultradeepwater-field developments and long-distance tiebacks. The authors identify the gaps that need to be closed and describe the decision-making process during the field-development life cycle by considering the technical and economic constraints of various SSP technologies. Introduction A generalized definition of SSP is any active treatment of the produced fluids at or below the seabed to improve recovery factor of reservoirs. SSP technologies include multiphase pumping, subsea separation, gas compression, and raw-seawater injection. Subsea separation coupled with liquid boosting is effective in enabling production at very low flowing tubinghead pressures, even in deep water. This method also is well-suited for use where heavy, viscous oil or low reservoir pressure is the rule. Gas fields often are developed with subsea wells and multiphase transport to onshore facilities or to offshore processing platforms. Separation allows decreasing boosting-power requirements. Subsea-separation technology is progressing quickly because of its huge potential in minimizing topside water-handling requirements and separation of gas, oil, and water from the production fluid. Subsea gas-compression technology is one of the faster-growing technologies for large fields requiring pressure boosting (e.g., where subsea-to-beach development solutions result in long tie-back distances). It improves the production and recovery from the reservoir by reducing backpressure on the wells. As of this writing, more than 25 subsea boosting systems and six major subsea separation systems have been installed or awarded throughout the world. Given the growing number of greenfield and brownfield applications, some analysts anticipate the number of SSP systems installed globally to double by 2020. The complete paper contains a detailed discussion of the development of these technologies, from their origins to their current incarnations. Why SSP? SSP is typically considered for systems with a tieback to a host structure and can influence all phases of project life (start-up, plateau production, late life, and tail end). SSP can consist of the following: Use of single- or multiphase pumping systems to enhance the fluid-driving energy (subsea boosting) Subsea separation and disposal of the produced water (two-phase separation) Subsea separation of oil, gas, and water (three-phase separation)

Applying Subsea Fluid-Processing Technologies for Deepwater Operations

Summary Subsea processing is an evolving technology in response to ultradeepwater hydrocarbon development and has the potential to become one of the most attractive methods in the oil industry to economically unlock hydrocarbon resources. The objective of this paper is to examine the features of subsea fluid-processing technologies and capabilities, and compare the advantages and disadvantages of different facility types. The advantage of subsea processing systems is that they allow fluids to be boosted from longer tieback distances. Constraints associated with subsea processing systems include operation efficiency, produced-water and sand-handling capabilities, and the system’s ability to handle hydrates/scale. In this paper, we reviewed the application of subsea systems in 12 deepwater fields and discussed the significance of each. Furthermore, future subsea-technology development and anticipated challenges are outlined in this paper. The significance of this study is to summarize the lessons learned from current available uses so that future decisions regarding the application of these subsea processing technologies can be made appropriately and efficiently.

Finding New Ground in Subsea Integrity Management

The oil and gas industry has moved into more extreme territories in recent years, sanctioning an increasing number of ultradeepwater projects that require the use of remote and long-distance subsea tiebacks as well as subsea processing systems. With the push to deepwater development, production has become more reliant on the integrity of subsea, umbilical, riser, and flowline (SURF) systems. Operators have been seeking more cost-effective ways to define and implement the inspection and monitoring methods needed to assess and manage the integrity of SURF systems. An operator-only joint-industry project (JIP) was launched to help enable an integrated approach to the integrity management of SURF systems and develop best practices.

Developing Long-Distance Power-Distribution Systems

The vision of installing large subsea production facilities in remote offshore locations is today, simply not feasible. The problem is that subsea power systems are not designed to transmit high-voltage electricity to a production facility or pipeline tieback that may be under thousands of feet of water and 100 miles away from the nearest power plant. Today’s subsea power-distribution technology is largely based on alternating- current (AC) technology, which, because of its electrical characteristics, can only be efficiently transmitted across a distance of 90 miles. In most cases, however, the effective distance is much less. On average, subsea tiebacks receive power from a platform or vessel located not more than 10 miles away and, in the case of most subsea processing systems, even closer. In an AC-supplied system, the flow of electricity alternates back and forth across the transmission line and is the form of electricity most commonly used in homes and businesses around the world. When long distances are involved, AC power distribution becomes a complicated operation and requires a great amount of attention to detail because of the physics involved with voltage regulation. The search for an alternative to conventional AC systems has revealed the need for multiple technological advancements, from pressure compensated electrical switches to highly-conductive cables able to deliver power more efficiently. About 5 years ago, “We were looking at going to farther distances with alternating current instead of direct current (DC) because most of the equipment we have right now is AC powered,” said James Pappas, vice president of the Research Partnership to Secure Energy for America’s (RPSEA) ultradeepwater program. He said that, after studying the issue, however, it was determined that using AC power could result in a 35% power loss in a 100-mile-long cable because of resistivity and other factors. Not long after that conclusion was reached, General Electric (GE) approached RPSEA with a concept to transfer all the power to a deepwater field with DC and then use a subsea transformer module located within the field to convert some of the power to AC. With this system, the expected power loss over 100 miles could be as low as 25%. “So, if you have AC components, it can convert power to AC for those components, and if you need DC, then it has DC components,” Pappas said. “It all sounds pretty simple until you want to put it in a package and then set it down in 10,000 ft of salt water.”

Application of the All-Electric Subsea Production System

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 18819, "First Application of the All-Electric Subsea Production System - Implementation of a New Technology," by Laurent Bouquier and Jean Pierre Signoret, Total, and Robert Lopez, Cameron International, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May. Improvements have been made in equipment reliability, system availability, operational functionality, and environmental performance of all-electric subsea production systems (SPSs). This paper describes the process, decision criteria, and motivation that led to selecting the all-electric SPS for this North Sea application and outlines the objectives to implement the technology. Introduction Over the past decade, substantial gains have been realized in reliability and functionality of electrohydraulic multiplexed (EHM) control systems for subsea production. These systems use hydraulic-control technology dating back to the early days of subsea systems. The evolution of control-system technology has progressed from direct hydraulic to piloted and sequenced systems to provide improved response time and enable long-distance tiebacks. Today, most subsea developments use EHM control, which is a subsea computer/communication system of hydraulic directional-control valves. These electrically actuated valves allow stored pressure within subsea accumulators to be routed to individual hydraulic lines and onward to actuated gate valves and chokes on subsea production equipment. Generally, industry recognizes persistent weaknesses that are related to susceptibility of fluid cleanliness, materials compatibility, hydrostatic effects in deeper water, and limitations for long-distance tiebacks. Many reliability problems are attributable to hydraulic-component failure. Reliability issues occur during installation and during operations associated with high-pressure/high-fluid-volume hydraulic systems. Reliability studies initiated significant technology-development investigations to explore the potential of all-electric subsea controls. Technology Development and Evaluation In the early stages of the development, operators provided significant guidance and support through structured reliability and technical-assurance processes involving technical reviews, reliability and risk appraisals, and value assessments. The technology was viewed as promising for application to deepwater long-distance tiebacks. Reducing the size and weight of the surface units would enable tying fields back to congested existing facilities. There is potential use for subsea high-integrity pressure-protection systems. Synergies would exist with other electrically powered applications such as operation and maintenance of subsea-processing systems, heat-tracing systems, and resident remotely operated vehicles. A pilot project on a reduced-risk favorable field case was planned. Study results obtained from the single-well shallow-water case demonstrated a 31.8% reduction in lost-production days per year (including intervention and repair time) over a 20-year life. This reduction translated into a 26.7% decrease in the cost of deferred production in favor of the all-electric system. Production availability increased by 2% (from 94.4% for the EHM system to 96.4% for the all-electric SPS). Similarly, the results from the single-well ultradeepwater case showed a 27.8% reduction in lost-production days per year (20-year field life), with a corresponding 22.2% decrease in deferred-production costs.

Subsea Processing and Control System in the GASP Project: Testing of the Prototype System

Summary The subsea production and processing system developed under the Goodfellow Assocs. Subsea Production (GASP) project involved two stages of separation thatled to the production of exportable-quality crude oil production ofexportable-quality crude oil by pipeline. The produced gas is transported alonga separate line. This paper describes key elements of the subsea processsystem. A prototype system was developed during the second phase of theproject. The system was tested under dry and submerged conditions in a drydock. Key features of the proto type system and the tests carried out aredescribed. Prototype testing proved the viability of the GASP system and helpedidentify areas requiring particular attention and improvement for futureapplications. Introduction The main objective of the GASP project was to develop a subsea productionsystem suitable for the development of satellite marginal fields. This was ajoint industry project supported by the European Community project supported bythe European Community and eight major oil companies. An overview of the systemand the economics are addressed in a separate paper. This paper highlights somekey features of the process and control system and the extensive testing of theprototype system. The base case was a satellite field 30 km from the motherplatform. The field consists of four production wells and four water-injectionwells. A general view of the field scenario is shown in Ref. 1. Design Parameters. Table 1 summarizes the main parameters for the design ofthe system. The sensitivity case shows the range of values of interest to theparticipating oil companies and does not reflect the limits for future fieldapplications. The quality requirements for the processed crude oil were notnecessarily the processed crude oil were not necessarily the minimum or optimumfor the system but were set to a relatively more demanding level to allowexport of produced oil directly through an existing trunkline. The high exportpressure specified for the crude oil was to meet the operating pressurespecified for the trunkline. Options for simplifying the process system arediscussed later. process system are discussed later. Process Flow Diagram. Fig.1 shows the Process Flow Diagram. Fig. 1 shows the simplified process flowdiagram (PFD). Two identical production trains were adopted. Each train servestwo wells with an option to divert flow from one train to another through thetest-meter loop. Production testing of individual wells is achieved through abypass valve leading to the test header. The multiphase test meter enablessubsea measurement of individual wells without the need for a test line or aseparate test separator. The separator comprises two stages of gas/liquidseparation to meet the specified true vapor pressure (TVP) requirements. Thisleads to production of gas at different pressures (first- and second-stageseparators). pressures (first- and second-stage separators). An ejector is usedto commingle the gas products from the two sources for export products from thetwo sources for export through a single line. Oil and water are transportedalong separate lines for the base case. Separate booster pumps are used foreach train. This helps to keep the pump duty requirements within the range ofexisting pump designs and improves the availability pump designs and improvesthe availability of the system. A fiscal flowmetering system shown in the PFD, measures the crude oil rate for fiscal PFD, measures the crude oil rate forfiscal metering purposes as the product enter a common subsea trunkline. If theproduced oil is transported directly to the mother platform, this meter is notnecessary. The platform, this meter is not necessary. The first phase of thestudy established that designing a reliable subsea meter that met the desiredaccuracy, proving, and availability targets needed for fiscal metering wouldnot be easy and would require a novel approach. Adapting the existinggeneration of fiscal meters was feasible but would result in a cumbersome andtedious system requiring a costly maintenance and proving program. Process System Design. At the outset of Process System Design. At the outsetof work, the aim was to simplify the system as much as possible. Separation ofgas, oil, and water is a well-developed technology. For subsea application, however, the following points affect the design of the separator and may changeits features from those of topside units.Modularization to reduce size andweight if the unit is to be retrieved for maintenance purposes.Capacity tocope with the expected slug and plug flow conditions.Minimum use ofinternals to minimize maintenance requirements.Generous capacity to copewith flow functions, any slowness in control-valve responses, and possiblefoaming.Generous capacity to cope with slackness in the level monitoringand control and to avoid unnecessary system shutdown for minor equipmentmalfunctions.Capability to withstand pressures well above the operatingpressure, although it is feasible to include a pressure-relief system on theseparator to minimize the rating.

Modularization and Installation, Maintenance, and Repair Aspects of GASP Technology

This paper reports that the Goodfellow Assocs. Susbsea Processing (GASP) project addressed most of the major problem posed by the development of remote, small, marginal, or satellite oil and natural gas fields in deep waters. It considered a number of field development scenarios and , in particular, reviewed cases for fields situated up to 30 km from a platform- or shore-based processing facility. During the design of the resultant modularized GASP system, it was determined that an inspection, maintenance, and repair (IMR) philosophy needed to be developed. The number of field development scenarios involved, the different module dimensions and weights, and the remote driverless activities required in deeper waters resulted in a separate project, Maintenance and Retrieval Equipment (MARE).