Shallow water subsea systems can be an ideal solution for improving marginal field net present value. Jerry Streeter, Field Development Manager, for FMC Technologies, Inc., explains.
Very little has been published recently on shallow water subsea production systems (SWSPS) even though they were the foundation used to develop deepwater subsea systems. The large number of SWSPS in place worldwide and their many years of successful operation demonstrate the reliability that can be obtained with this equipment.
SWSPS are now being seriously considered and installed by operators of all sizes (fully integrated, independents, and national oil companies) to boost mature field production rates by exploiting the reserves in close proximity to existing infrastructure that were previously considered uneconomical.
In cases where the reserves are in less than 130m of water and located within 10km of the processing facility, subsea production systems specifically designed for shallow water could make the reserves economically attractive to develop. Shallow water systems, run on 11-7/8 or 16-in. high pressure drilling risers using mudline suspensions systems or 13-5/8-in. wellheads, are specifically designed for wells drilled from jackup drilling rigs. Their functionality and lower costs make them ideal for smaller, short-life fields.
To fully appreciate the impact that a shallow water subsea system can have on a field’s economics it is necessary to understand how a shallow water subsea system reduces costs and shortens time to first production.
Drilling and completion
The first option usually considered for developing stranded reserves is to drill additional wells from the existing platform. Often the challenge of this option is that the platform slots are full, so to drill a new well one of the producing wells would have to be plugged and the well sidetracked to the new target; taking this action lowers the net gain in production as the current production is now lost.
Image: FMC Technologies' JXT-3 shallow water subsea tree was installed on a two-slot template. Template and trees were installed by the drilling rig.
If the new target doesn’t produce as expected, reduced production could be the net result. A second option is to install a wellhead platform over the new well’s bottom hole location and drill a vertical well. A third option is to modify the platform to support new well conductors. These options avoid the lost revenue associated with abandoning a producing well, but they do incur the costs of building a new platform or modifying the existing platform and a delay in getting production on stream while the platform – or platform modifications, are designed, fabricated, and installed. Even if the platform has an open slot, reaching the stranded reserve could entail drilling an expensive highly deviated well, which could also be an extended reach well.
A fourth option is to use a shallow water subsea production system. As in the wellhead platform case the well’s surface location is directly over the bottom hole target location. This vertical, or slightly deviated well, reduces drilling time and expense, as well as the cost of modifying the platform, and eliminates the risk of taking a producing well out of production.
Shorter time to first production
While the period of time necessary to design, fabricate, install, and commission a well protector tripod platform will vary greatly around the world, 12-18 months, from contract placement to commissioning is a typical duration for these activities. In some cases, the wells can be pre-drilled; however, it isn’t unusual to wait for the platform to be installed before drilling the wells to minimize pre-investment. Producing a stranded reserve through a new wellhead platform potentially means production won’t start for 18-24 months after project sanction.
With no pre-investment, a shallow water subsea system can be installed and commissioned in as little as 9-12 months after project sanction. With minimal pre-investment, production can start as soon as six months after project sanction. FMC Technologies has implemented a stocking plan for long-lead equipment to reduce delivery times even further. With minimal preinvestment, an operator can drill and complete a well with a single mobilization of the jackup drilling rig.
Reduced installation costs
Installing a new wellhead structure entails mobilizing a derrick barge to the location for the installation work. Within the past year, IHS Petrodata reported the global average rate for a derrick barge is the range of US$300,000 to $350,000 per day. Shallow water subsea production systems are designed to be installed from the drilling rig, thus the cost of the derrick barge is eliminated from the capex. This is also true for decommissioning costs. The shallow water subsea system components are recovered by the drilling rig when the well is plugged and abandoned, eliminating the costs of the derrick barge to salvage the wellhead platform.
To achieve maximum cost benefit of using a shallow water subsea production system, the seabed architecture must be planned specifically for shallow water fields. A single well tie-back using direct hydraulic controls is the simplest form of subsea tie-back.
Image: FMC Technologies' JXT-3 shallow water subsea tree configured for a single well tie-back.
Direct hydraulic controls are an excellent, safe means of controlling the production tree for tie-backs to 8km (5mi.). Most applications include electrical conductors in the umbilical for instrumentation mounted on the tree. Chemical injection to prevent or remediate hydrate and wax issues is accomplished via one or more chemical tubes in the control umbilical.
Multiple well developments also hold the potential to achieve considerable cost savings using shallow water subsea systems, though it is imperative to keep the seabed architecture synergistic with jackup rig operations. When developing the seabed architecture, consideration must be given to the rigs being considered for drilling. Shallow water seabed architecture differs significantly from its deep water brethren as the shallow water seabed architecture must consider the time necessary to move a jackup from one location to another.
In fields drilled with a floating rig, the rig can easily and quickly move a few hundred meters to keep the well’s surface location directly above the bottom hole location. As a result, the favored seabed layout is a central manifold with production trees and injection trees spaced around the manifold. Flowline jumpers and umbilical flying leads connect the tree to the manifold and control system distribution skid.
A dual or single flowline transports production from all wells to the processing platform, with subsea chokes mounted on the trees to balance production flowing pressure and rates from each well in the flowline. Jackups aren’t able to easily and quickly move a few hundred meters to a new well, so drilling templates are used to cluster wells into drill centers under the rig’s cantilever deck to avoid moving the rig to a different location for each well.
Care must be taken that the center point of each well is within the working envelope of the cantilevered drilling and Texas decks of the proposed drilling rig. Two-, three-, and four-well templates are quite common; some rig cantilever deck windows and template layouts can accommodate as many as six wells.
In addition to wellhead locations and geometry, another important consideration is the method of connecting flowlines and pipelines. The common default practice for subsea systems is to use diverless hydraulic connectors, such as FMC Technologies’ U-Con connection system, for connecting flowlines, jumpers, and spools to the subsea hardware.
For the shallow water system discussed, saturation diving techniques allow these connections to be made using conventional pipeline flanges; swivel flanges and mis-align ball flanges; studs; and nuts installed with nut-tensioning equipment at great cost savings. Before selecting the optimum approach, the total installed cost, availability of divers in the region of the installation, and client safety requirements must be considered for each project.
A single well tie-back using direct hydraulic controls is the lowest cost option for a subsea production system. Sometimes it is advantageous to apply this principle to multi-well developments. One seabed architecture that has been used several times to simplify operations and reduce CAPEX is one in which the trees are placed on a template, then each tree is connected to the host facility with a discrete umbilical and discrete flowline.
The higher cost of multiple flowlines and a control umbilical can be offset by the cost savings of a direct hydraulic control system over a multiplex control system, as well as the elimination of the subsea control module and the subsea choke. The number of wells, offset distance, and flowline diameters ultimately determine if this approach is cost effective.
We can use a very typical three-well brownfield development to demonstrate the NPV improvement that can be realized by using shallow water subsea production systems. The shallow water field development team at FMC Technologies was asked to evaluate and recommend the most economically attractive method of producing a set of wells.
The client had previously installed tripod wellhead platforms in a similar water depth in another district and wanted to determine if a shallow water subsea approach would be economically attractive in this field. Therefore, the base case was to install three tripod wellhead platforms and produce the wells to an existing host facility in the vicinity. FMC Technologies was asked to develop capex budgets and schedule estimates for this base case, as well as a subsea alternate, so an economic evaluation could be completed.
The following table summarizes the capex estimates and forecast NPV for each option. The base case assumes drilling starts in month 1 of the development process and all the wells are drilled with the same rig consecutively. Wellhead platform and pipeline procurement begins after drilling and first production occurs in month 34. The subsea case uses the same timeline and cost assumptions for drilling.
Procurement of the subsea system also starts after drilling, but due to the shorter delivery time of the subsea equipment first production occurs in month 16. Both cases use $20,000 per well per month for opex. The subsea case has an higher total opex because production starts earlier and the model stops production in month 239, in both cases rather than extending the analysis for 240 months, from the time each well comes on production.
Well intervention occurs after ten years of production and both cases assume a drilling rig will perform the intervention. In this case, the subsea option had a lower capex and, due to the shorter time to first production, produced a significant improvement to NPV.
In many cases, shallow water subsea production systems can deliver a robust, cost-effective solution for marginal oil and stranded gas reserves. If operators attempt to offset declining production rates in mature fields by producing untapped reserves in the vicinity of their existing production facility but find conventional methods uneconomical, they should consider contacting a shallow water expert.
Companies like FMC Technologies have teams of experienced field development specialists dedicated to assisting operators develop their marginal oil and stranded gas reserves located in less than 130m of water. OE
Jerry Streeter is a Marine Technology Society Fellow, and a past president and a former chair of the Offshore Technology Conference Program Committee. His involvement in offshore pipeline and subsea field developments projects began 35 years ago. Innovative application of technologies has been a mainstay of his career. His recent project work includes leading technical teams to conceptualize development plans for shallow water oil and gas fields and prove their commercial viability. Previously, he has led conceptual, FEED, and detail design efforts for the KivuWatt Gas Extraction Facility in Lake Kivu, Rwanda. This project combined oil and gas production technologies with gas-processing technology and the logistics of design for a facility to be constructed on a lake 1300km from the nearest port.