Special Problems of Deep-Sea Oil and Gas Engineering

Huacan Fang , Menglan Duan , in Offshore Operation Facilities, 2014

4.4.4.2 Equipment Combinations for Subsea Production Systems

When we use subsea production system to explore deep-water oil fields, the exploration mode depends on whether there are surrounding facilities or we are in an independent development mode. No matter which solution is adopted, we can choose different solutions for combinations of equipment.

1.

Equipment combination schemes

Here several proposed equipment combinations refer to the subsea production system combination of SPS with surface production facilities. An existing subsea production system combined with equipment on the surface mainly has the following several of applications in deep water (Figure 4-72).

a.

SPS + SPAR

subsea production system + single column (independent) production platform

b.

SPS + TLP

subsea production system + tension leg platform

c.

SPS + FPSO

subsea production system + floating production, storage, and offloading tanker

d.

SPS + FPS

subsea production system + semi-submersible floating production platform

e.

SPS + (Fixed Platform)

subsea production systems + fixed oil platforms

2.

The distribution of several combinations in different years

The proportions for the choice of the five equipment combinations above in various regions of the world for different years is shown in Table 4-16 below.

Table 4-16. The Proportion of Different Combinations and Equipment in the Global Subsea Production System (Unit %)

3.

Subsea wellhead and equipment combinations trends

Figure 4-76 shows the development trends of the applications of deep-water subsea wellhead in the world. In Figures 4-75 and 4-76 and Table 4-16 we can see:

a.

The number of applications of subsea wellheads varies with each year and continues to increase in every major region of the globe, and the number of subsea wellheads used in deep-water oil field is also increasing, from about 17% since the 1990s to 33% in the early part of this century.

b.

Amongst subsea production system combinations, the FPSO vessel always occupies a large proportion through the years, as this advantageous scheme coincided with the growth in China's offshore oil field development.

c.

The combination with subsea production systems with floating semi-submersible platforms also occupies a large proportion and it is related to the semisubmersible platform's comparatively mature design and construction. In turn, the new tension leg platform and single (independent) pillar platforms occupy a small proportion, because they are not mature.

FIGURE 4-76. Subsea wellhead quantity increasing over time.
4.

The combination with a fixed jacket platform also occupies a considerable proportion and had a larger percentage in the 1990s, which indicates that it is mainly applied to shallow water.

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Offshore Platforms

James G. Speight , in Subsea and Deepwater Oil and Gas Science and Technology, 2015

3.3.6 Subsea Production Systems

Subsea production systems are wells located on the sea floor, as opposed to at the surface. Just as in a FPS, the petroleum is extracted at the seafloor, and then "tied-back" to an already existing production platform. The well is drilled by a moveable rig, and instead of building a production platform for that well, the extracted natural gas and oil are transported by riser or even by undersea pipeline to a nearby production platform. This allows one strategically placed production platform to service many wells over a reasonably large area. Subsea systems are typically in use at depths of 7,000 ft or more, and do not have the ability to drill, only to extract and transport.

Subsea systems comprise of the well system (includes the downhole completion system and the subsea tree), the production system (includes protective structures, manifolds, templates, intervention systems, and subsea processing systems), and the pipeline system (includes tie-ins, umbilicals, risers, injection pipelines, and production pipelines).

A subsea production system (FPS)—which is typically wells located on the sea floor in shallow or deep water—to extract petroleum can be associated with an already existing production platform or an onshore facility. The oil well is drilled by a movable rig and the extracted oil or natural gas is transported by pipeline under the sea and then to rise to a processing facility. The system ranges from a single subsea well producing to a nearby platform to multiple wells producing through a manifold and pipeline system to a distant production facility. These systems are being applied in water depths of at least 7,000 ft or more.

Subsea developments have been made possible by technologies such as subsea trees, risers, and umbilical lines. The production equipment is located on the seafloor rather than on a fixed or floating platform, subsea processing provides a less-expensive solution for myriad offshore environments. Originally conceived as a way to overcome the challenges of extremely deepwater situations, subsea processing has become a viable solution for fields located in harsh conditions where processing equipment on the water's surface might be at risk. Additionally, subsea processing is an emergent application to increase production from mature or marginal fields.

Subsea production systems can range in complexity from a single satellite well with a flow line linked to a FP or an onshore installation, to several wells on a template or clustered around a manifold. Subsea production systems can be used to develop reservoirs, or parts of reservoirs, which require drilling of the wells from more than one location (Chapter 6). Deep water conditions, or even ultra-deep water conditions, can also inherently dictate development of a field by means of a subsea production system, since traditional surface facilities such as on a steel-piled jacket, might be either technically unfeasible or uneconomical due to the water depth, because the development of subsea crude oil and natural gas fields requires specialized equipment, which must be sufficiently reliable to safe guard the environment, and make the exploitation of the subsea hydrocarbons economically feasible. The deployment of such equipment requires specialized and expensive vessels, which need to be equipped with diving equipment for relatively shallow equipment work (i.e., a few hundred feet water depth maximum), and robotic equipment for deeper water depths. Any requirement to repair or intervene with installed subsea equipment is thus normally very expensive. This type of expense can result in economic failure of the subsea development.

Subsea processing can encompass a number of different processes to help reduce the cost and complexity of developing an offshore field. The main types of subsea processing include subsea water removal and reinjection or disposal, single-phase and multi-phase boosting of well fluids, sand and solid separation, gas/liquid separation and boosting, and gas treatment and compression. Subsea separation reduces the amount of production transferred from the seafloor to the surface of the water, debottlenecking the processing capacity of the development. Also, by separating unwanted components from the production on the seafloor, flow lines and risers are not lifting these ingredients to the facility on the surface but are used to direct unwanted ingredients them back to the seafloor for reinjection. Reinjection of produced gas, water, and waste increases pressure within the reservoir that has been depleted by production. Also, reinjection helps to decrease unwanted waste, such as flaring, by using the separated components to boost recovery.

On deepwater or ultra-deepwater fields, subsea boosting is needed to move the crude oil and natural gas from the seafloor to the facilities on the water's surface (Leffler et al., 2011). Subsea boosting negates backpressure that is applied to the wells, providing the pressure needed from the reservoir to transfer production to the sea surface. Even in mid-water developments, subsea boosting, or artificial lift, can create additional pressure and further increase recovery from wells, even when more traditional enhanced oil recovery methods are being employed.

Most subsea processing will increase the recovery from the field and, by enhancing the efficiency of flow lines and risers, subsea processing contributes to flow management and assurance and also enables development of challenging subsea fields. Furthermore, subsea processing converts marginal fields into economically viable developments. As a result, many offshore fields have included subsea processing into the development protocols. Whether the fields are mature and the subsea processing equipment has been installed to increase diminishing production, or the fields incorporated subsea processing from the initial development to overcome deepwater or environmental challenges, the subsea processing concept has enabled the fields to achieve higher rates of production.

For example, with the successful start-up of a full-field subsea separation, boosting and injection system on the Tordis field (StatoilHydro) in the North Sea in 2007, the mature Tordis oil field (StatoilHydro) increased recovery by an extra 35 million barrels of oil and extended the life of the field by 15–17 years. In addition, the Parque das Conchas (BC-10) project (offshore Brazil, Shell Oil Company) used gas/liquid separation and boosting and developed via 13 subsea wells, six subsea separators and boosters. Pazflor project (offshore West Africa, Total SA) is utilizing a gas/liquid separation system. Another example of a subsea system development is this to about 10,000 ft. A SPAR is located in the Mensa field located (Mississippi Canyon Blocks 686, 687, 730, and 731) (Shell Oil Company) which started producing in July 1997 in 5,376 ft of water, shattering the then depth-record for production. Consisting of a subsea completion system, the field is tied back through a 12-in. flow line to the shallow water platform West Delta 143. The 68-mile tieback has the world record for the longest tieback distance to a platform.

As offshore oil and gas regions mature, the focus of exploration and development shifts toward smaller hydrocarbon accumulations, which are in many cases better suited to subsea development solutions than to the more costly stand-alone platform developments.

Finally, there has been an increasing focus on deepwater prospects that have previously been out of reach. The use of floating production facilities and subsea technology has made exploitation of such fields possible, but a number of technical challenges remain.

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Subsea Cost Estimation

Yong Bai , Qiang Bai , in Subsea Engineering Handbook (Second Edition), 2019

6.4.1 Overview of Subsea Production System

Subsea production system includes varies of subsea structures or equipment such as wellheads, trees, jumpers, manifolds, etc., which depends on the field architecture types and the topside equipment. Typical filed developments may utilize several wellheads and a cluster manifold located in the center of them. For marginal fields, it is more flexible and economic to use a satellite well tie-back. Typical components and equipment in subsea production system as shown in Figure 6-11 are:

Figure 6-11. Typical Subsea Production System [4].
•

Subsea wellhead: a structure used for supporting the casing strings in the well. It usually includes a guide base thus the wellhead is also used for guiding while install the tree;

•

Subsea Xmas tree: an assembly of piping and valves and associated controls, instrumentations that landing and locking on top of the subsea wellhead for controlling production fluid from the well;

•

Jumper: a connector or tie-in between the subsea structures, e.g., tree and manifold, manifold and PLET, PLET and PLET. Jumpers include flexible jumpers and rigid jumpers;

•

Manifold: equipment used for gathering the production fluid from trees/wellheads, and then transporting the production fluid to the floaters through subsea pipelines. A cluster manifold with 4, 6, 8 or 10 slots is the typical manifold;

•

Template: a subsea structure to support the subsea wells or the manifolds;

•

PLET: a subsea structure set at the end of pipeline to connect the pipeline with other subsea structures, such as manifolds or trees;

•

Subsea foundation: a component to support subsea structures on seabed. Mudmat, suction pile, and drilling pile are typical subsea foundations;

•

Subsea production control system (SPCS): components such as master control station (MCS), electrical power unit (EPU), hydraulic power unit (HPU) and etc.;

•

Umbilical termination assembly (UTA): the termination that mates with the umbilical flange for installation and pull-in of the umbilical to the required subsea structure;

•

Flying lead: a connector between UTA and other subsea equipment, it includes hydraulic flying leads (HFL), and electrical flying leads (EFL);

•

Subsea distribution unit (SDU): a connector with the subsea umbilical through the UTA, distributing hydraulic supplies, electrical power supplies, signals, and injection chemicals to the subsea facilities;

•

HIPPS: equipment designed to protect low-rated equipment against overpressure or abject flow accompanying the upset condition by either isolating or diverting the upset away from the low-rated equipment;

•

Umbilical: a component that contains two or more functional elements, e.g., thermoplastic hoses and/or metal tubes, electrical cables and optical fibres. Umbilical is the main medium for power and signal transmission between topside and subsea;

•

Chemical injection unit (CIU): equipment located on the topside platform to provide the chemical injection (e.g., the corrosion inhibitor) into subsea equipments;

•

Subsea control module (SCM), subsea control equipment normally located on subsea trees for transferring the data and signal from the topside to operate the valves or other mechanisms.

This book will focus on some typical and common equipment and introduce the cost estimation processes for them, instead of covering all subsea equipment costs.

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Economic Limit Factors

Mark J. Kaiser , in Decommissioning Forecasting and Operating Cost Estimation, 2019

4.5.2 Subsea Production System Design

In subsea production system design, a whole-system modeling approach is used to define the hardware requirements and operating strategies ( Kaczmarski and Lorimer, 2001; Arciero, 2017; Bomba et al., 2018). To optimize the system design, software models for each component are used to understand the trade-offs that result from balancing steady-state and transient operations with flow assurance management:

•

Steady-state thermal and hydraulic

•

Transient operations

−

Warm-up

−

Cooldown

−

Blowdown

−

Hot oil heating

•

Flow assurance management and remediation

−

Hydrate prediction and inhibition

−

Wax deposition

−

Asphaltene deposition

−

Scale prediction

−

Internal corrosion

−

Erosion

•

Corrosion

The flow assurance work process begins with the development of a thorough understanding of the fluid and reservoir properties (Joshi et al., 2017). A typical suite of analyses may include generation of hydrate stability curves, cloud-point and pour-point measurement, wax deposition patterns, asphaltene stability testing, and scale analysis based on water samples.

Results of fluid and reservoir analyses are combined with thermal-hydraulic modeling of the system to assess the flow assurance risks. The formation processes for the solids of concern (e.g., hydrates, wax, asphaltenes, and scale) are all driven by a combination of temperature and pressure, hence the need for accurate thermal-hydraulic modeling of system performance in steady-state operations and during transient operations such as start-up and shutdown. Corrosion, erosion, slugging, and emulsion formation are often included in the flow assurance analysis since they are also driven by a combination of temperature and pressure, flow rate, and flow regime.

The results of the flow assurance work process are expressed in the form of flow assurance strategies that combine elements of the system design, system operational strategy, and chemical treating requirements. Strategies vary greatly among projects because each development has a different set of driving factors of cost, project life, reliability targets, and environmental restraints. As a result, flow assurance must be integrated into the overall subsea systems engineering effort, not only to ensure that the analyses are performed at the correct time and desired accuracy, but also to integrate flow assurance with equipment selection and development of operational guidelines in a way that optimizes the final result for the project.

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Flow Assurance Issues

Mark J. Kaiser , in The Offshore Pipeline Construction Industry, 2020

2.2 Design Issues

The primary flow assurance issues for subsea systems are hydrate, wax, asphaltene, scale, and corrosion. Each of these components may occur at different places and at different times during the life cycle of production, and therefore, anticipating their occurrence and designing systems to mitigate, reduce, or remediate is the key element of flow assurance strategies.

Hydrate, wax, and asphaltenes are the main threats and may arise downhole in the production tubing of the well, at the wellhead or manifold on the seabed, in the connecting jumpers or flowlines, at the riser at the base of the host, and in the equipment and piping topsides. They may occur early or late in life and during different operating states from normal production, shutdown, start-up, and remediation. Start-up/warm-up and shutdown/cooldown are transient conditions where flowing temperatures change and may enter regions of hydrate risk and wax appearance. Systems must be robust and flexible to handle dynamic and changing conditions.

Early in production, flow rates and temperatures are high, but later in life, flow rates and temperatures will decline. If systems are not designed for these changing conditions operational problems may occur. Early in production, fluid quality (viscosity, gas-oil ratio, water cut) is similar to the fluid samples obtained during well testing, but later in life, as reservoir pressures decline, fluid quality changes which may cause operational problems if unable to manage.

In subsea production system design, a whole system modeling approach is used to define the hardware requirements and operating strategies ( Arciero, 2017; Bomba et al., 2018; Kaczmarski and Lorimer, 2001). To optimize the system design, software models for each component are used to understand the tradeoffs that result from balancing steady-state and transient operations with flow assurance management:

•

Steady-state thermal and hydraulic conditions

•

Transient operations

•

Warm-up

•

Cooldown

•

Blowdown

•

Hot oil heating

•

Flow assurance management and remediation

•

Hydrate prediction and inhibition

•

Wax deposition

•

Asphaltene deposition

•

Scale prediction

•

Corrosion internal

•

Erosion

•

Corrosion

The flow assurance work process begins with the development of a thorough understanding of the fluid and reservoir properties (Ellison et al., 2000; Joshi et al., 2017). A typical suite of analyses may include generation of hydrate stability curves, cloud point and pour point measurement, wax deposition patterns, asphaltene stability testing, and scale analysis based on water samples.

Results of fluid and reservoir analyses are combined with thermal-hydraulic modeling of the system to assess the flow assurance risks. The formation processes for the solids of concern (e.g., hydrates, wax, asphaltenes, and scale) are all driven by a combination of temperature and pressure, hence the need for accurate thermal-hydraulic modeling of system performance in steady-state operations and during transient operations such as start-up and shutdown. Corrosion, erosion, slugging, and emulsion formation are often included in the flow assurance analysis since they are also driven by a combination of temperature and pressure, flow rate, and flow regime.

The results of the flow assurance work process are expressed in the form of flow assurance strategies that combine elements of the system design, system operational strategy, and chemical treating requirements. Strategies vary greatly among projects because each development has a different set of driving factors of cost, project life, reliability targets, and environmental restraints. As a result, flow assurance must be integrated into the overall subsea systems engineering effort, not only to ensure that the analyses are performed at the correct time and desired accuracy, but also to integrate flow assurance with equipment selection and development of operational guidelines in a way that optimizes the project.

Example: Flow assurance strategy at Stones

Stones is a phased development that began producing in September 2016 from two subsea wells tied back to an FPSO in the Walker Ridge area in 9576   ft water depth. The development consists of a turret moored FSPO with a disconnectable buoy, which allows the FPSO to weather vane in normal operating conditions and be released in the event of a tropical storm or hurricane.

Full field development includes six additional wells from two connected drill centers, and a subsea boosting system. With reservoirs located at depths of more than 29,000 ft, subsea boosting was identified in the original development plan as a means to enhance recovery due to rapidly decreasing reservoir pressures (Hagland et al., 2019). The project is characterized by high-pressure high-temperature reservoirs with low permeability, as well as by fluids with low gas-oil ratio, lower API grade and higher viscosity than typical Gulf of Mexico oil (Hoffman et al., 2017).

Major flow assurance risks at Stones are mitigated as shown in Table 2.1.

•

Wax is mitigated by insulation, commingled hot oil, and paraffin inhibitor injection.

•

Corrosion is mitigated by corrosion-resistant alloys and inhibitor injection.

•

Hydrates are mitigated by heat retention and dead oil displacement for shutdowns.

•

Scale is mitigated by downhole scale inhibitor injection and backup injection at the tree.

Table 2.1. Flow Assurance Strategies at the Stones Development

Risk Operation Wellbore Tree/Jumpers Flowline/Risers
Hydrates Production (>5 kbpd/FL) None None None
Unplanned shutdown MeOH bullheading MeOH flush Dead oil
Planned shutdown MeOH bullheading MeOH flush Dead oil
Cold start-up Overrun hydrates Inject MeOH Hot oiling
Wax Production (>8 kbpd/FL) None None None
Production (<8 kbpd/FL) None None Hot oiling
Unplanned shutdown None None None
Planned shutdown None None None
Cold start-up None None Hot oiling
Other Asphaltenes (remediation) None None None
Scale (production) SI inhibition None None
Corrosion (production) None None CI inhibition
Erosion (production) None None None
Emulsion (production) None None None

From Hoffman, J., Clausing, K., Robinson, S., Subramanian, P., Zummo, A. 2017. The Stones project: subsea, umbilical, riser and flowline systems. In: OTC 27569. Offshore Technology Conference. Houston, TX, May 1–4.

Emulsion and viscosity were deemed low to medium risks. Slugging, pour point, erosion, and asphaltenes precipitation/deposition were deemed low risks. Due to a lack of good fluid sample, a conservative approach was employed for hydrate and scale management.

Pipelines that transport crude may become fouled with organic scale, and the paraffins, asphaltenes, and naphthenates contained within the oil may precipitate and adhere to the pipeline walls. Corrosion may occur underneath these organic deposits. Pipelines that transport gaseous products may form organic-scale deposits from the condensed hydrocarbon fluids. If moisture is present in a sour environment, sulfide scales may form. More complicated issues may arise from mercury, arsenic, zinc, or other scales (Wylde and Slayer, 2010). Scales can be compacted and adhere to the walls of the pipeline, necessitating the addition of surfactant-based chemicals to assist in the breakup, softening, and transportation of these deposits (Cordell and Vanzant, 2003).

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Overview of Subsea Engineering

Yong Bai , Qiang Bai , in Subsea Engineering Handbook (Second Edition), 2019

1.2.4 Installation and Vessels

The development of subsea production systems requires specialized subsea equipment. The deployment of such equipment requires specialized and expensive vessels, which need to be equipped with diving equipment for relatively shallow equipment work, and robotic equipment for deeper water depths. Subsea installation refers to the installation of subsea equipment and structures in an offshore environment for the subsea production system. Installation in an offshore environment is a dangerous activity, and heavy lifting is avoided as much as possible. This is achieved fully by subsea equipment and structures that are transmitted to the installation site by installation vessels.

Subsea installation can be divided into two parts: installation of subsea equipment and installation of subsea pipelines and subsea risers. Installation of subsea equipment such as trees and templates can be done by a conventional floating drilling rig, whereas subsea pipelines and subsea risers are installed by an installation barge using S-lay, J-lay, or reel lay. The objective of Chapter 5 is to review existing vessels used for the installation of subsea equipment such as trees, manifolds, flowlines, and umbilicals. This includes special vessels that can run the trees and rigless installation. Subsea equipment to be installed is categorized based on weight, shapes (volume versus line type), dimensions, and water depth (deep versus shallow).

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Advancements in Cathodic Protection of offshore structures

Jim Britton , Matthew L. Taylor , in Trends in Oil and Gas Corrosion Research and Technologies, 2017

25.5.1 History—how was it done?

The development of subsea production systems really started to gain momentum from the mid-1980s. Technological developments in subsea equipment have made deep water and ultradeep water exploration and production a reality. These subsea systems can be extremely complex, combining subsea Christmas trees, flowlines, manifolds, pipeline connection skids, and more recently subsea separation and process skids. From a corrosion control perspective this means a lot of mixed materials, a wide range of operating temperatures, coated and uncoated systems, and many mechanical connections and joints. All these systems normally provided by a number of different suppliers. The challenge is to make all the corrosion control systems compatible; this has not been very well accomplished to date and as a result many early in situ repairs and anode supplements are required. The major recurring problems that we have seen on these types of systems are as follows:

Electrical continuity issues. All the bolted connections, coated fasteners, and heavy epoxy-based coating systems used can result in some components being isolated from the CP system. This can be very difficult to correct when the system is sitting in 3000   m of seawater. The solution is to provide multiredundant continuity paths with jumper cables between components. Use coated fasteners carefully and if the coating is dielectric, provide methods to endure continuity such as serrated (star) washers under nuts. Most importantly, check continuity with a milliohm meter between all components and the part of the structure where the anodes are located. These checks should be conducted as part of system integration testing, and as factory acceptance, but should also be rechecked immediately prior to load out offshore as road transportation vibration can cause problems.

Mismatched anodes. Sacrificial anodes are the only viable alternative to cathodically protect these assets. However, when designing sacrificial anode systems, there are a few basic rules, which must be followed, but which are routinely ignored by many operators on subsea systems.

Cardinal rule is not to mix anodes of different cross-sections on a common structure. A fact that is commonly overlooked by system designers is that when a flowline is connected to a subsea tree there is no electrical isolation between the two elements, so by default they become a "common structure". Small cross-section bracelet type anodes are usually connected to the flowline and bulky block anodes are attached to the tree structure or end connection skid. The anodes (being merely unintelligent castings) do not realize that they are supposed to only protect the element to which they are attached. They rather follow the basic laws of physics and all deliver protective current basically in accordance with ohms law. If the anodes are all of the same basic chemistry, this means that the smaller cross-section anodes will deplete first, rather than them all depleting through the design life as intended by the designers.

Rule number 2 is to ensure that all anodes are of the same chemistry. This is very difficult to achieve in reality if different foundries, in different countries, produce the anodes. The chemical composition range may be to a common specification but foundry practice, anode size, and rate of cooling can produce anodes that exhibit a range of driving voltages. Obviously, anodes with a higher driving voltage will take on a disproportionate amount of the CP task, leaving others virtually untouched.

Another rule is to distribute anodes evenly across the structure; this is important for several reasons. The main reason is to ensure adequate current distribution. Second, it is not good to crowd anodes as they will interfere with one another reducing current output and causing uneven consumption that can lead to significant efficiency reduction.

Location of anodes should also consider the proximity of elements that are possibly susceptible to hydrogen embrittlement, such as cold bends in duplex stainless steel control tubing. It is common for anode corrosion products to remain and build up on the anodes in deep water because there is no current to disperse them. Significant build-up of these products may be detrimental if allowed to build into a dense packed mass and engulf uncoated materials.

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Subsea Power Supply

Yong Bai , Qiang Bai , in Subsea Engineering Handbook (Second Edition), 2019

Abstract

The power supply for a subsea production system is designed according to the subsea control system. Different control system types require different power system designs. However, basically two types of power systems are used: an electrical power system or a hydraulic power system. The power system supplies either electrical or hydraulic power to the subsea equipment: valves and actuators on subsea trees/manifolds, transducers and sensors, SCM, SEM, pumps, motor, etc. The power sources can come from either an onshore factory or from the site. The electrical power system is a typical subsea production system that provides power generation, power distribution, power transmission, and electricity from electric motors. The power is either generated on site or onshore. To ensure continuous production from a subsea field, it is of utmost importance that the subsea system's associated electrical power system be designed adequately. Various organizations have developed many electrical codes and standards that are accepted by industries throughout the world. These codes and standards specify the rules and guidelines for the design and installation of electrical systems.

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Design Codes for Risers and Subsea Systems

Yong Bai , Qiang Bai , in Subsea Pipelines and Risers, 2005

23.6 Regulations and Standards for Subsea Production Systems

One of the first steps in designing a subsea production system should be to determine the regulatory rules applying to the specific situation. Every oil-producing nation has a set of regulations governing the exploration and extraction of its natural resources.

The origin of standardization in the petroleum industry has its roots in the United States, whereby the industry have been dominated by American solutions. This has reflected on the developed standards and specifications, where many of the fundamental standards have been developed by the American Petroleum Institute (API), an organization consisting of American companies involved in petroleum exploration, production, transportation, and refining. As American companies started exploration in other parts of the world they brought the American solutions and standards, due to the lack of similar standards in the applicable countries. The American standards were, as time progressed, adapted to fit the individual countries whereby new national and industry standards were developed.

The choice of standards, which a subsea development is to be designed according to, is the choice of the operator assigned to develop and operate the field. The operator is obliged to follow the applicable country's regulations, and can choose which (if any) standards shall be the basis for design and operation. In practice a field development is always developed according to a number of standards or recommendations, which can be any kind of national, international, industrial, or company specific standards. In order to ensure the security of their investments, shareholders in a development will usually demand the designs and constructions of the development classified by an independent third party classification society, as will the operator with any sub-contractors. The classification society will review and verify the design and construction to ensure compliance with the predefined regulations, standards, rules, and guidelines.

As the use and demand of subsea production systems increased so did the need for separate standards, the first being the API 17 series covering the following areas:

•

RP 17A, Design and Operation of Subsea Production Systems;

•

RP 17B, Flexible Pipe;

•

RP 17C, TFL (Through Flowline) Systems;

•

Spec 17D, Subsea Wellhead and Christmas Tree Equipment;

•

Spec 17E, Subsea Production Control Umbilicals;

•

RP 17G, Design and Operation of Completion/Workover Riser Systems;

•

RP 17I, Installation of Subsea Umbilicals;

•

Spec 17J, Unbonded Flexible Pipe;

•

Spec 17K, Bonded Flexible Pipe.

In 1999 the international organization for standardization (ISO) published the fist standard in the ISO 13628 series, Design and operation of subsea production systems, was published. To date the following ISO 13628 standards have been published:

•

ISO 13628–1: General requirements and recommendations;

•

ISO 13628–2: Flexible pipe systems for subsea and marine applications;

•

ISO 13628–4: Subsea wellhead and tree equipment;

•

ISO 13628–3: Through flowline (TFL) systems;

•

ISO 13628–5: Subsea control umbilicals;

•

ISO 13628–6: Subsea production control systems;

•

ISO 13628–7: Workover/completion riser systems;

•

ISO 13628–8: Remotely Operated Vehicle (ROV) interfaces on subsea production systems;

•

ISO 13628–9: Remotely Operated Tool (ROT) intervention systems.

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All-electrical subsea systems and actuation

Karan Sotoodeh , in Prevention of Actuator Emissions in the Oil and Gas Industry, 2021

Abstract

This chapter provides a short review on subsea production systems such as wellhead, Christmas trees, manifolds, subsea distribution system (SDU), etc. for understanding the subsea systems better. All-electrical subsea actuators and systems are known as the future of subsea industry due to many benefits such as environment saving, cost reduction, reliability, flexibility, etc. All benefits of subsea electrical systems are explained in this chapter. In addition, subsea electrical and hydraulic actuators are compared in this chapter. A design review on an electrical actuator has been performed and at the end effect of adding electrical actuator on subsea valves inside a manifold in terms of safety and changing the type of valves is discussed.

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