EXECUTIVE SUMMARY

Welcome to this site where we give you key snippets from our position paper exploring the viability and ultimate potential of a hypothetical all-subsea solution – the ‘SuPPS’ (Subsea Production and Pipeline to Shore).

APPROACH
We ‘unpack’ the ‘SuPPS’ ...assessing the business case for each step as, one-by-one, we move the main components of our ‘benchmark’ (a conventional FPSO-based solution) from topside to subsea.

INSIGHTS
We conclude that while certain technologies are clearly enhancing (i.e., better value than other technologies) or even enabling (i.e., access to new resources), other parts of the all-subsea concept severely limit its current overall applicability.

EXECUTIVE SUMMARY


SuPPS vs FPSO

SuPPS
  • FPSO = Floating production, storage and offloading units
  • The chosen benchmark in our study is the cost-efficient turret moored converted VLCC concept, commonly used in Brazil and West Africa
  • FPSOs are currently the preferred development concept for water depths beyond 200m. The turret-moored option is the preferred benchmark in our study as it is suitable for harsher environments.
  • FPSOs operate in all water depths from shallow waters to the deepest fields at 2 500m, and in weather conditions ranging from benign to harsh.
  • For the cases where the SuPPS cannot compete with a turret-moored FPSO, it follows that it would not be able to compete with the cheaper spread-moored alternative.
  • SuPPS = Subsea Production and Pipeline to Shore
  • The definition of the all-subsea concept used in our study is: 'A pure subsea production and processing facility where hydrocarbons are processed to transport quality'.
  • The building blocks of our hypothetical SuPPS concept encompass processing, power, control, and safety systems, all of which are detailed below.
  • All-subsea field development concepts are gaining credence, and have been promoted by several oil companies and technology providers.
  • There are significant differences in how the all-subsea concept is viewed by different E&P companies; some have complete subsea developments as a vision or goal, whilst others focus only on specific parts to be used in combination with other development concepts.
SuPPS
  • FPSO = Floating production, storage and offloading units
  • The chosen benchmark in our study is the cost-efficient turret moored converted VLCC concept, commonly used in Brazil and West Africa
  • FPSOs are currently the preferred development concept for water depths beyond 200m. The turret-moored option is the preferred benchmark in our study as it is suitable for harsher environments.
  • FPSOs operate in all water depths from shallow waters to the deepest fields at 2 500m, and in weather conditions ranging from benign to harsh.
  • For the cases where the SuPPS cannot compete with a turret-moored FPSO, it follows that it would not be able to compete with the cheaper spread-moored alternative.
  • SuPPS = Subsea Production and Pipeline to Shore
  • The definition of the all-subsea concept used in our study is: 'A pure subsea production and processing facility where hydrocarbons are processed to transport quality'.
  • The building blocks of our hypothetical SuPPS concept encompass processing, power, control, and safety systems, all of which are detailed below.
  • All-subsea field development concepts are gaining credence, and have been promoted by several oil companies and technology providers.
  • There are significant differences in how the all-subsea concept is viewed by different E&P companies; some have complete subsea developments as a vision or goal, whilst others focus only on specific parts to be used in combination with other development concepts.

STEP 1
SUBSEA MULTIPHASE BOOSTING

The changes to the FPSO benchmark concept for this first step are extra subsea equipment – i.e. a subsea pump module with one or more compact helico-axial multiphase pumps (MPP). This design is chosen owing to its ability to handle a wide range of flow rates and compositions, including sand, and because it is the most used design subsea.

An MPP would trigger an extra topside power module with switchgear, transformers, variable speed drive (VSD), uninterrupted power supply (UPS), and an extra umbilical for power, control, chemicals, and combined barrier and lubrication oil supply. Adding power intensive equipment such as MPPs from field start-up means that the increased power must be accounted for in the dimensioning of power generation.

STEP 2
HEATING OF PIPELINES

Subsea equipment is insulated in order to keep the flows hot enough to avoid flow assurance problems such as waxing, hydrates, asphaltenes, and high viscosity oil clogging up pipelines. Chemicals, depressurization, and dead oil circulation are used to safeguard uninterrupted production, but an alternative approach is to heat up the pipeline to the required temperature, either continuously or during critical periods.

The case basis is an FPSO with a subsea production system and subsea multiphase boosting. The additional change is heating of flowlines. DEH is the most mature system for longer distances.

STEP 3
SUBSEA WATER INJECTION

Here, topside water injection equipment that is connected to the subsea wells with dedicated risers and flowlines is replaced with subsea water injection. The subsea water injection system has a water intake system that collects water from the water column above the seabed to limit particles being sucked into the system. Filters are nevertheless necessary, and can be backflushed to avoid clogging. The pump module has a barrier fluid system to protect the motor. A chemical injection system is for possible injection of antiscaling chemicals etc. into the injection water and well. The power requirements, components, and control topside are essentially common for both topside and subsea injection, but an umbilical from the topside to the pump module is added

STEP 4
SUBSEA SEPARATION

The case moves the entire separation system to the seafloor, and sends processed flows to the topside. Here oil is stored on board the FPSO before being shipped, and gas is exported via a pipeline using topside compressors. Water injection is already subsea, and produced water is reinjected.

Subsea separation installed to enable lifting of oil to a topside due to, for example, high viscosity oil combined with larger gas volumes, has a clear business case. The same goes for removing water to facilitate improved utilisation of the capacity of an existing topside. The business case is more opaque for a greenfield case …

STEP 5
SUBSEA COMPRESSION

Gas export compression is currently always installed topside. The compression case discussed here moves the compressor for pipeline export subsea, and thereby removes gas risers, leaving only oil risers, VOC return, and umbilicals/power cables between the FPSO/FSO and subsea facility. With separation in place, a dry gas compressor is used, including an anti-surge system for handling of transients….

Topside equipment is still VSD and switchgear. In order to increase the efficiency of the compressor, a cooler is located upstream of the liquid removal unit of the separation process. … As there is no pressurized gas on board the FPSO, the flare can be removed.

STEP 6
POWER TRANSMISSION FROM SHORE

Most FPSOs and other offshore facilities generate power … using multiple gas turbines. These are light, standardized, and feed of the produced gas which may be associated gas that otherwise is worthless unless the field’s gas volumes are large enough to warrant a gas export pipeline. Despite the advantages, gas turbines are maintenance-intensive, complex, rotating equipment, and represent a major proportion of the offshore oil & gas production emissions.

If the entire offshore facility is located subsea, as is the case for the SuPPS, a prerequisite is electric power to run large consumers like pumps, compressors, and heating, but also smaller consumers like UPS modules, actuators etc. To date, subsea electrification has been developed in two phases…

STEP 7
POWER SYSTEM – DISTRIBUTION & CONTROL

An FPSO may have power from shore, convert it to the correct voltage and frequency, and run as before. As described in the previous section, both the transformers and other power components linked to transmission, distribution, and control would be located topside. For a SuPPS these must be moved to the sea floor. Thus it is relevant to consider the effects and business case of this scenario.

STEP 8
OIL EXPORT BY PIPELINE & ELIMINIATING THE FPSO

The FPSO has by now been reduced to an FSO, which is essentially a VLCC with a turret, helideck, offloading equipment, utilities module and VOC handling system. The final step … is subsea oil export.

Oil export alternatives are either subsea storage, with surface offloading to an FPSO, or pipeline to shore. Subsea storage introduces additional subsea complexity … Pipeline transport is used whenever volumes, oil composition and onshore landing allows. Pipeline CAPEX increases with distance to shore, making shuttle tankers the preferred option for long distances and smaller volumes. At the same time, HVAC power transmission is limited to below 200 km.

Pipeline transport is assumed to be the most likely solution.

STEP 9
SUBSEA ON THE SHELF?

So far, the discussion has considered incremental steps, and the following main conclusions have been reached:

1. Multiphase boosting may provide, in addition to increased recovery and accelerated production, increased step-out distances of wells of 50 km and more as the pump differential pressure increases.

2. DEH together with MPPs may enable up to 100 km step-out distance.

3. Subsea seawater injection facilitates freedom regarding the location of injection wells relative to other subsea systems.

4. Subsea separation saves riser costs, especially deepwater, but can be simplified and optimal separation pressure is closer to the hydrostatic pressure in shallower waters.


SuPPS TECHNOLOGY


THE SuPPS PROCESSING SYSTEM

Shown here is a system for both oil and gas wellstream processing to long-distance pipeline transport quality. Some elements are applied subsea today, while others (like produced water treatment, electrical coalescer and fine separation) are not yet operational. The system follows the wellstreams from subsea wellhead to shore. Following the conventional Christmas trees, manifolds, and infield flowlines, the gas and oil wellstreams have separate paths as in any topside system. Oil wellstreams include crude oil, associated gas, water and sand. Gas wellstreams include gas cap gas, associated condensate and water. Wellstream compositions and production rates vary between wells and over the field lifetime. Thus any processing system, subsea or topside, must be able to adapt to the changing needs.

Multiphase pump (MPP)

Extra boosting might be needed for the oil wellstreams depending on the reservoir pressure, wellstream properties and distance between wells and subsequent processing.

Direct heating (DEH)

To maximize the length of the multiphase flow, insulation and DEH are applied to the pipeline to avoid flow assurance problems during production and production shut-ins.

Sand removal

Sand causes problems for pipes, pumps, and other equipment. Thus, it is removed early in the process and reinjected via water injection wells, or brought to shore with the oil.

Gas removal

A polishing or fine separation unit to bring the gas-in-oil to a level at which the remaining flow can be considered one phase, e.g., under 5% gas volume fraction (GVF).

Electric coalescer

Ensures water droplet growth in the liquid flow by applying voltage and is assumed necessary to separate water from oil.

Water removal

Done where water in the oil has formed droplets to a sufficient extent. In a compact set-up, water needs to flow through all the upstream processing steps prior to removal.

Single-phase pump

Used for export through the oil export pipeline to shore as the oil stream has reached the required composition for the final transport leg

The gas wellstreams are illustrated to flow by reservoir energy alone to the subsea field centre.

The gas wellstreams are illustrated to flow by reservoir energy alone to the subsea field centre.

Slug catcher

Installed where the gas wellstreams enter the subsea field centre to prevent slugs entering the processing system.

Inlet cooler

Installed upstream of the compressor in order to increase the compressor efficiency and condense liquids in the gas.

Inlet cooler

Installed upstream of the compressor in order to increase the compressor efficiency and condense liquids in the gas.


THE SuPPS POWER SYSTEM

Operating the processing system described requires power, both for the processing equipment, like pumps and compressors, and for the low power and voltage control system. The SuPPS concept control system is assumed to be an all-electric design, thereby avoiding complicated pressurized hydraulic systems. Onshore facilities have not been indicated in the illustration. Power transmission can be high voltage AC (HVAC), high voltage DC (HVDC), or low frequency AC (LFAC). Includes onshore facilities, transmission cable and any equipment to convert the power to the right specifications. Power distribution includes all cables, umbilicals, switchgear, and other power equipment that distribute, transform, or otherwise control valves, motors etc. Can theoretically be AC, DC, or LFAC, but in the example, conventional AC is described.

Onshore terminal

The terminal/transformer transforms voltage to the required level for long-distance subsea transmission. HVAC runs the same frequency in the cable as the onshore grid.

Cable

The cable from shore is exemplified by a 132 kV nominal HVAC subsea cable, currently the most mature system.

Step-down transformer

Reduces transmission voltage to the subsea system voltage level. This is shown as a 3-winding transformer, as it is assumed that two outputs at different voltages would be required…

Substation

… with switchgear is the hub of the system. Load feeders to the individual components of the field centre branch from the main busbar with a series of circuit breakers.

Consumer modules

A series of power components linked to each of the large consumers; compressor, pumps, and heating. The main components of such modules are described in the remaining tabs.

Switchgear

Distributes power into the different systems through a busbar with filters and circuit breakers.

Transformers

Step down the voltage to the individual consumer’s requirements. The transformer for the MPPs will possibly work with different incoming voltage levels and at a higher hydrostatic pressure.

The Variable Speed Drive regulates the speed of electric motors. Converts input AC frequency via DC to the desired AC frequency.

The Variable Speed Drive regulates the speed of electric motors. Converts input AC frequency via DC to the desired AC frequency.

UPS

Uninterrupted Power Supply is needed for control systems and thus redundancy is built in. The system runs low voltage, (e.g., 400 V) and includes battery backup power where deemed necessary.

Phase conversion

From 3 to 1 phase is necessary for DEH. Connect one of the phase to the system would cause asymmetric loads and therefore an electronic conversion is preferred.

Phase conversion

From 3 to 1 phase is necessary for DEH. Connect one of the phase to the system would cause asymmetric loads and therefore an electronic conversion is preferred.


THE SuPPS CONTROL SYSTEM

Operating a hydrocarbon processing facility remotely in a safe and optimized manner is demanding, owing to the distance itself, but also due to the complexity of the SuPPS, and the need to be able to prevent, detect, and isolate faults. A control system that allows for high bandwidth and reliable communication across the various processing equipment and power systems in order to maintain safe and reliable operation is the third level of the SuPPS concept.

Onshore control

Onshore continuous control will receive and process data from all parts of the SuPPS, giving operators access to expert teams and large computing power in case of unforeseen events.

Sensors

Extensively deployed not only to control, but also for fault detection, locating and isolation with sufficient redundancy. E.g. multiphase and single-phase flow meters, temperature sensors, pressure sensors, and accelerometers.

Fibre optic

Cables from shore, bundled in umbilicals, can handle the required amounts of data to be transmitted.

Infield grid

An infield fibre optic grid using loops, will facilitate large data traffic and redundancy, as opposed to a radial grid. Using mesh technology ensures communication through the easiest available route.

Control modules

Subsea Control Modules (SCM) for every part of the systems will handle speed, independence, autonomy and redundancy, at a completely different level than conventional subsea control systems.

Actuators

Assumed to be of an all-electric design, as opposed to hydraulically powered.


THE SuPPS SAFETY SYSTEM

Safety systems are considered a separate layer of the SuPPS. These systems intersect with processing, power and control, but have their own dedicated tasks and independence solely for the purpose of maintaining safety. Safety concerns for the SuPPS: Occupational risk is not considered relevant as there is no immediate risk to personnel involved in daily operations. Environmental risk, as in the risk of acute pollution resulting from a possible hydrocarbon release to the environment, is the focus of the safety systems. Major accident risk is related to large discharges to sea and is a subset of the environmental risk in this specific context. maintaining safety.

HAZOP

This illustration serves only as an example. A safety system is the result of a complete and specific hazard and operability study (HAZOP), subsequent analyses and risk acceptance criteria

Preventive barriers

Prevent loss of containment and loss of well control. Including the Process Shut Down (PSD), Downhole Safety Valve (DHSV) Production Master Valve (PMV) in the Christmas tree.

HIPPS

A High Integrity Pressure Protection System (HIPPS) is used to protect the SuPPS including pipelines against overpressurization.

Mitigating barriers

React based on an event that has occurred in order to mitigate consequences and prevent escalation.

Leak detection

Together with temperature and pressure sensors, this is essential to reduce leak duration through short response time of other safety systems.

ESD

Emergency shut-down (ESD) shuts down the system and isolates the different areas immediately following an incident that is likely to or has caused a loss of containment

BUSINESS CASE


How can all the subsea concept become a viable business case

GENERAL CONCLUSIONS

  • Subsea processing is now a real alternative to conventional solutions.

  • The different technologies are enhancing or even enabling under certain circumstances.

  • Still, there are limits to its widespread adoption at present.

  • Subsea equipment has different capabilities relative to topside equipment.

  • Eliminating riser cost is a major part of the SuPPS business case.

  • Net contributing technologies can also be applied to FPSO-based concepts.

BROWNFIELD APPLICATIONS

  • Subsea processing and power applications are already here, and are here to stay.

  • Subsea technologies enable additional volumes

  • Business case driven by existing facilities’ limitations.

THE ALL-INCLUSIVE SuPPS

  • Few possible applications as the concept requires large oil and gas volumes.

  • Deepwater business case more likely when significant parts of the processing can be performed in shallower waters.

THE OIL SuPPS

  • Suited for limited-depth developments in mature areas.

  • Business case driven by reduced cost.

  • Access to pipeline infrastructure and existing onshore processing is vital.

THE GAS SuPPS

  • Proof-of-concept in 2015.

  • Additional tie-ins to existing infrastructure or LNG liquefaction.

  • For large, stand-alone LNG development projects, FLNG is becoming the preferred solution.


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