Subsea Equipment Costs
Contents
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 are:
- 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.
Subsea Trees Cost
The cost of subsea trees in a subsea field development can simply be estimated by multiplying the unit price by the number of trees. Tree type and number are selected and estimated according to the field conditions such as water depth, reservoir characteristic, and production fluid type. The unit price can be provided by proven contractors and manufacturers.
Cost-Driving Factors
The following components are typically included while estimating the cost of trees:
- Tubing hanger assembly;
- ROV tree cap;
- EFAT testing.
The tree parameters should be selected and specified during the FEED, based on the information of oil/gas production, reservoir characteristics,
production rate, water depth and etc.,
- Main components of tree: tree body, tree valves, tree piping, protection frame, SCM, production choke, tree connector, ROV panel, etc.;
- Typical bore sizes: 5” and 7”;
- Standard pressure ratings: 5 ksi, 10 ksi, and 15 ksi;
The types of tree can be summarized into two categories: horizontal tree (HT) and vertical tree (VT). The main differences between HTs and VTs are the configuration, size, and weight. In a HT, the tubing hanger is in the tree body, whereas in a VT, the tubing hanger is in the wellhead. In addition, HT is usually smaller in the size than VT. The bore size is standardized to 5”, so the prices of the trees will not change too much for which bore size is 5” below. However, the trees with 7” or ever bigger bore sizes are still new technologies and the cost will changes largely. The pressure ratings for subsea Christmas trees are 5, 10, and 15 ksi, in accordance with API 17D and API 6A. Different pressure ratings are used at different water depths. The technology of 5- and 10-ksi trees is commonly used in water depths greater than 1000 m. The main difference in the cost is determined by the weight and size. Few companies can design and fabricate the 15-ksi tree, so costs are high because of market factors. The temperature ratings of subsea Christmas trees influence the sealing system, such as the sealing method and sealing equipment. API 6A temperature ratings are K, L, P, R, S, T, U, and V. Typical subsea Christmas tree ratings are LV, PU, U, and V. Many manufacturers supply the equipment with a wide range of temperature ratings so that they work in various types of conditions. The temperature ratings do not have too great influence on the total cost of a subsea Christmas tree.
Cost Estimation Model
The cost estimation of subsea Xmas tree is produced by taking the individual cost driving factors of the equipment, multiplying with the basic cost which is usually the normal cost range of a standard product on the market at that time. A correction must be made if some cases are different from those considered. The cost model of the subsea Xmas tree can be expressed as: C1 = C0 . f1 . f2 .f3.,,, + Ccorr
where
- f1, f2, f3 .: the cost driving factors for subsea Xmas trees, such as tree type, pressure rating and bore size;
- C1 : the cost of new subsea Xmas tree to be estimated;
- C0 : the basic cost of a subsea Xmas tree;
- Ccorr : the correction cost.
Tree types, pressure ratings, and bore sizes are the main cost driving factors of the cost estimation for a subsea Xmas tree. Following is an example of the cost estimation for a 5 inch 10 ksi vertical Xmas tree.
Subsea Manifolds Cost
Several concepts are applied to manifolds and associated equipment in a subsea field development. The installation of a subsea manifold from the moon-pool of the installation vessel. Some fields use templates instead of manifolds. Actually the templates have the functions of a manifold. PLET/PLEMs are subsea structures (simple manifolds) set at the end of a pipeline that are used to connect rigid pipelines with other subsea structures, such as a manifold or tree, through a jumper. This equipment is used to gather and distribute the production fluids between wells and flowlines. The costs of this type of equipment are mainly driven by the cost of the manifold, because it generally makes up about 30% to 70% of the total equipment cost, depending on the type and size of the field.
Cost-Driving Factors
The following components and issues should be included while estimating the cost of a subsea manifold or other subsea structures:
- Foundation of manifold;
- Controls of manifolds (e.g. SCM)
- Pressure and temperature;
- Pigging loop;
- EFAT testing.
Typical manifolds are cluster type with 4, 6, 8, 10 slots. Cost of the manifold mainly depends on the slots, as each slot needs one set of valves and pipe works. This will increase not only the purchase cost but also the material cost. Besides, size and weight of the structures also influence the installation cost. Subsea structures such as manifolds and trees shall follow the standard pressure ratings specified as discussed in the article before. Pressure ratings mainly influence the piping design in the manifold, e.g. the wall thickness.
Cost Estimation Model
Cost estimation for subsea structures follows the method used in the cost model of subsea Xmas tree. The cost model of the subsea manifold can be expressed as below:
C1 = C0 . f1 . f2 . f3.,,, + Ccorr
where
- f1, f2, f3 .: the cost driving factors for subsea manifolds, such as slot number and pipe size;
- C1 : the cost of subsea manifold to be estimated;
- C0 : the basic cost of a subsea manifold;
- Ccorr : the correction cost.
PLEM is a type of manifold, which normally has 1 to 3 hubs. Structure of PLEM is similar to that of manifold. However, if there are only 2 wells, for example, a PLEM is much more flexible and economic to be installed and connected to the wells, comparing to a cluster manifold. Following is an example of the cost estimation for a subsea manifold.
Flowlines Cost
Flowlines are used to connect the wellbore to the surface facility and allow for any required service functions. They may transport oil or gas products, lift gas, injection water, or chemicals and can provide for well testing. Flowlines may be simple steel lines, individual flexible lines, or multiple lines bundled in a carrier pipe. All may need to be insulated to avoid problems associated with cooling of the production fluid as it travels along the seafloor. The cost of flowlines is usually calculated separately from the costs for other subsea equipment. The estimation can be simply arrived at by multiplying the length of the line and the unit cost.
Cost-Driving Factors
The main cost drivers for flowline procurement are:
- Type (flexible, rigid);
- Size (diameter and wall thickness, based on pressure rating and temperature rating);
- Material class;
- Coating;
- Length.
The steels applied in the offshore oil and gas industry vary from carbon steels (API standards Grade B to Grade X70 and higher) to exotic steels such as duplex. The higher grade steel obviously commands a higher price. However, as the costs of producing high-grade steels have been reduced, the general trend in the industry has been to use the higher grade steels, typically subsea flowline grades X70 and X80 for nonsour service and grades X65 and X70 with a wall thickness of up to 40 mm for sour service.
Flexible flowlines make the laying and connection operations relatively easy and fast. Material costs for flexible lines are considerably higher than that of conventional steel flowlines, but this may be offset by typically lower installation costs.
High-pressure ratings require high-grade pipe materials, thus the cost of steel increases for high-pressure projects. However, the increase in grade may permit a reduction of pipeline wall thickness. This results in an overall reduction of fabrication costs when using a high-grade steel compared with a low-grade steel.
The factor of pressure rating is combined into pipe size factor.
Cost Estimation Model
Subsea flowline cost is usually estimated by multiplying the unit price by the total length. The cost model of the flowline can be expressed as below:
C1 = Cu . L .f1.f2 . f3.,,, + Ccorr
where
- f1, f2, f3 .: the cost driving factors for subsea flowlines, such as pipeline OD and pipe wall thickness;
- C1: the cost of subsea flowline to be estimated;
- Cu: the unit cost of the flowline (per meter);
- L: the total length of the flowline;
- Ccorr: the correction costs for joints and coatings and etc.
Outside diameter (OD), wall thickness of flowline, pressure rating, and water depth are the main cost driving factors of the cost estimation for flowlines. Following is an example of the cost estimation for a subsea flowline.
Flexible pipe or composite pipe is different from rigid pipeline. A typical flexible pipeline contains several layers. However, if the base cost of the flexible pipe is available, the cost model for flexible flowline is still applicable for the cost estimation of the flowlines with different sizes.
References
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[7] American Petroleum Institute, Specification for Wellhead and Christmas Tree Equipment, nineteenth ed., API Specification 6A, 2004.
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