Subsea

Offshore, subsea satellite development may be a viable alternative to ERD wells. 

In preparation for a field wide quick look correlation, all well logs need to be corrected for borehole inclination. This is done routinely with software which uses the measured depth below the derrick floor ( alonghole depth below derrick floor AHBDFor measured depth , MD) and the acquired directional surveys to calculate the true vertical depth subsea (TVSS). This is the vertical distance of a point below a common reference level, for instance chart datum (CD) or mean sea level (MSL). Figure 5.41 shows the relationship between the different depth measurements. 

Subsea production systems are an alternative development option for an offshore field. They are often a very cost effective means of exploiting small fields which are situated close to existing infrastructure, such as production platforms and pipelines. They may also be used in combination with floating production systems. 

Figure 10.34 Typical Subsea Field Development Options...

Typically, a Subsea Field Development or Subsea Satellite Development would consist of a cluster of special subsea trees positioned on the seabed with produced fluids piped to the host facility. Water injection, as well as lift gas, can be provided from the host facility. Control of subsea facilities is maintained from the host facility via control umbilicals and subsea control modules. 

Subsea production systems provide for large savings in manpower as they are unmanned facilities. However, these systems can be subject to very high opex from the well servicing and subsea intervention point of view as expensive vessels have to be mobilised to perform the work. As subsea systems become more reliable this opex will be reduced. 

In 1986 when the oil price crashed to 10 a barrel, operators began to look very hard at the requirements for offshore developments and novel slimline, reduced facilities platforms began to be considered. The reduced capital outlay and early production start up capability, coupled with the added flexibility, ensured that all companies now consider subsea systems as an important field development technique. Although the interest and investment in subsea systems increased dramatically, subsea systems still had to compete with the new generation of platforms, which were becoming lighter and cheaper. 

However, in recent years the trend has been turning towards developing much smaller fields, making use of the existing field infrastructure. This, in combination with advances in subsea completion technology and the introduction of new production equipment has further stimulated the application of subsea technology. 

Various types of subsea production systems are being used and their versatility and practicality is being demonstrated in both major and marginal fields throughout the world. 

The most basic subsea satellite is a single Subsea Wellhead with Subsea Tree, connected to a production facility by a series of pipelines and umbilicals. A control module, usually situated on the subsea tree, allows the production platform to remotely operate the subsea facility (i.e. valves, chokes). 

An exploration or appraisal well, if successful, can be converted to a subsea producer if hydrocarbons are discovered. In this case the initial well design would have to allow for any proposed conversion. 

The Subsea Production Template is generally recommended for use with six or more wells. It is commonly used when an operator has a firm idea of the number of wells that... 

As the first well is being drilled the template is connected to the host facility with flowlines, umbilicals and risers. A Chemical Injection Umbilical will also typically be laid to the template or subsea facility and connected to a distribution manifold. 

As soon as the subsea tree on the first well has been commissioned, production can commence. The rig will then move to another template slot and start drilling the next well. 

If one or more clusters of single wells are required then an Underwater Manifold System can be deployed and used as a subsea focal point to connect each well. The subsea trees sit on the seabed around the main manifold (compared to the template). 

The manifold is typically a tubular steel structure (similar to a template) which is host to a series of remotely operated valves and chokes. It is common for subsea tree control systems to be mounted on the manifold and not on the individual trees. A complex manifold will generally have its own set of dedicated subsea control modules (for controlling manifold valves and monitoring flowline sensors). 

As subsea production systems are remote from the host production facility there must be some type of system in place which allows personnel on the host facility to control and monitor the operation of the unmanned subsea system. 

Modern subsea trees, manifolds, (EH), etc., are commonly controlled via a complex Electro-Hydraulic System. Electricity is used to power the control system and to allow for communication or command signalling between surface and subsea. Signals sent back to surface will include, for example, subsea valve status and pressure/ temperature sensor outputs. Hydraulics are used to operate valves on the subsea facilities (e.g. subsea tree and manifold valves). The majority of the subsea valves are operated by hydraulically powered actuator units mounted on the valve bodies. 

With the electro-hydraulic system the signals, power and hydraulic supplies are sent from a Master Control Station (or MCS) on the host facility down Control Umbilicals (Fig 10.36) to individual Junction Boxes on the seabed or subsea structure. 

Sensors on the tree allow the control module to transmit data such as tubing head pressure, tubing head temperature, annulus pressure and production choke setting. Data from the downhole gauge is also received by the control module. With current subsea systems more and more data is being recorded and transmitted to the host facility. This allows operations staff to continuously monitor the performance of the subsea system. 

Whether on land or offshore, the principle of satellite development is the same. A new field is accessed with wells, and an export link is installed to the existing (host) facility. Development is not always easier on land, as environmental restrictions mean that some onshore fields have to be developed using directional drilling techniques (originally associated with offshore developments). A vertical well can be drilled offshore away from the host facility, and the well completed using a subsea wellhead. 

All pipelines will be circulated clean and those that are buried, or on the seabed, left filled with water or cement. Surface piping will normally be cut up and removed. Flexible subsea pipelines may be reeled-in onto a lay barge and disposed of onshore. 

Subsea facilities are easily decommissioned as they are relatively small and easy to lift. However, subsea manifolds and templates can weigh in excess of 1,000 tons and will require heavy lift barges for removal. 

In many applieations, eg. within the nuclear, offshore and subsea fields it has been required to have a small unit, that could be placed unattended, close to the scanning object and operated from a remote operation unit. 

GoodfeUow Associates Ltd., Applications of Subsea Systems, PeimWeU Books, 1990. 

V. E. McKelvey and co-workers. Subsea Mineral Resources, Bulletin 1689-A, U.S. Geological Survey, Woods Hole, Mass., 1986. 

The procedure for calculating methanol usage can best be explained by an example. Given a flowing temperature for one well of our example field of 65°F (as could occur with a remote well and subsea flow line), calculate the methanol required to prevent hydrates from forming. Assume that at the high flowing pressure there is no free water, but the gas is saturated. 

Figure 4-35. Tension members of subsea handling equipment [10].

The most fundamental difference found between onshore and offshore drilling occurs when the wellhead is located at the seafloor. This configuration makes communication with the well more complex. A marine riser provides communication and circulation capability between the surface and the seafloor, and is used at some point during most offshore drilling. The riser consists of large-diameter (17-20) in.) steel pipe joints of approximately 50-ft lengths, with quick-connect couplings. The riser can be connected at the seafloor to a wellhead or to a subsea blowout preventer stack. A diverter system is usually attached at the... 

Offshore, well control equipment and associated operations present some differences from that seen and used onshore. In some instances onshore equipment can be employed, but the offshore environment generally dictates a modification of equipment and procedures. There are several different well configurations used offshore, often on the same well at different drilling intervals, and each configuration has specific well control procedures that should be followed. A well may be equipped with a surface blowout preventer stack a subsea blowout preventer stack, riser and diverter system a riser and diverter system with no blowout preventer a diverter only or a riserless system with no well control equipment. 

The high driving voltage may, however, result in overprotection. Combined with relatively poor capacity (1 230Ah/kg) and high unit cost these disadvantages mean that magnesium rarely finds application in subsea environments where alternatives are available. Despite this, Mg-Al-Zn anodes have been used in seabed mud and for rapid polarisation of structures (in ribbon form). 

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