REDUCING THE COST OF DEEP WATER FIELD DEVELOPMENT
It may be considered surprising that operators avoid adopting the most appropriate technical approaches to the development of fields in deep water. Development tends to follow principles that have been proven in shallower water but with the engineering upgraded to accommodate the more extreme conditions. This ignores the fact that the economic factors governing deep water are very different and usually demand a different technical solution. The distances involved in transporting the recovered hydrocarbons from the well head mean that the most significant requirement is for the greater use of seabed equipment. This can be used for tasks such as injection, separation, booster pumping and the installation of HIPPs - all of which become more efficient the closer they are to the well head.
One reason given against this approach is the belief that all of the equipment required throughout the field’s life must be positioned on the seabed at the outset. This demands high initial capital expenditure (CAPEX) using large installation vessels during a lengthy commissioning window so that a sizeable “factory” can be created on the seabed before the field has started earning any revenue.
In deep water it is more logical to only deploy equipment on the seabed when it is needed. Incremental field development spreads capital expenditure over a longer period and also avoids an operator discovering later that, because the characteristics of the field have changed unexpectedly, expensive equipment installed earlier is not needed. By adopting an incremental approach a field can be developed in several stages with first oil being obtained shortly after the installation of the initial basic equipment. The net present value of the field is immediately maximised whilst capital expenditure is minimised.
This approach becomes possible by the use of a System-Modular installation known as an AlphaPRIME™ CPU (Central Processing Unit) which is located close to the wells on the seabed. Each installation consists of at least two identical operating System-Modules which contain all of the pumping and processing equipment needed for the efficient operation of the field. Each System-Module has a footprint of only 5 m by 4 m and weighs between 25 and 50 tonnes, depending upon the equipment to be accommodated and can be changed-out by relatively inexpensive, lightweight dive support vessels
Equipment failure in deep water is proportionally more expensive and time consuming for the operator to rectify and this can be made worse by having to shut-in the well while an individual component is being changed-out. This problem does not exist when System-Modules are used. If it becomes necessary to repair, reconfigure or overhaul any of the elements within the System-Module, the entire unit is recovered leaving the other on the seabed to maintain production. Because both System-Modules will have been operating in parallel, continued production is assured because the remaining unit can increase its capacity for a short time to compensate for the missing module while also avoiding problems associated with starting up “dormant” equipment.
The System-Modules can be reconfigured during field life, either in response to changing field characteristics, such as increasing water cut, or to introduce new technology when it becomes available (such as subsea gas compressors). In this way, equipment is provisioned and deployed only when it is needed, thereby reducing the initial capital expenditure budget.
The field operator gains numerous benefits from having the freedom and confidence to install equipment on the seabed as and when it is needed. An example of these can be seen in the solution it provides to the problems encountered with using long tie-backs. It is well known that in a long tieback pipeline, as the pressure drops, the gas breaks out of solution in the produced fluid. The resultant “slugs” can inhibit flow and require expensive multiphase pumping. Hydrate formation can also occur in multiphase pipelines and the best solution is to introduce first-stage gas and/or water separation on the seabed near the well heads. The separated phases can then be transported to the host by individual pipelines or, when water is present, used for re-injection.
Seabed separation and liquid boosting also increases overall yield in the early years, prolonging viable field life whilst reducing overall expenditure. Using Brent field data as a basis, it has been calculated that up to 75% extra production can be achieved by employing seabed separation and boosting in deep water, compared with conventional topside methods. Independent authorities have calculated that savings of $2 to $4 per barrel can be achieved in Gulf of Mexico or UKCS scenarios.
What surprises many people is that the technology used in the AlphaPRIME System-Modules is not new. They use existing, well proven products and processes that are simply reconfigured to provide the field operator with a more efficient and profitable way of operating in deep or shallow water.
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