With increasing water depth, purely mechanical systems quickly became impractical, and the industry turned to hydraulic or electrohydraulic systems to operate subsea equipment. But there were problems. The inherent drawbacks of hydraulic systems experienced exponential growth with increasing water depth, step-out distance and seawater temperature. System reliability, actuation response time, hydrostatic effects and the risk of environmental incidents should the hydraulic fluid leak or spill into the sea were factors that drove the search for a new solution.
Interestingly, the principle driver for development of a new subsea production control system was not safety ― at least not directly. Operational reliability, command sensitivity and actuation response time were the critical factors that required improvement, and a good business case could be made on these merits alone.
Figure 1. CameronDC all-electric subsea production system for K5F field development. (Images courtesy of Cameron) |
At the same time, the industry had reached an economic frontier of sorts. Deep and ultradeepwater developments required huge elephantine fields to make a feasible economic case, and there simply were not enough of these to keep up with demand. First in the North Sea and later in the Gulf of Mexico,
As early as 1999, Cameron recognized the need for a better subsea production control system, and started work on what was to be
Figure 2. Subsea gate valve with electric actuator and failsafe spring. |
A comparison of response-time contrasts the DC system to its hydraulic counterpart. Not only is response smoother and faster, but the operator gets real/time feedback regarding system performance and instantaneous valve status.
A look at the bottom line
Economics always play a role when new systems are introduced. The DC Tree was deliberately made compatible with the company’s popular Spool Tree design so it could be used both on new installations and for upgrades or retrofits to existing subsea production systems.
Figure 3. Subsea choke module with electric actuator. |
A study performed jointly by BP, Cameron and Cranfield University in the United Kingdom, did some life-of-the-field modeling to estimate the economic impact of the DC production system. Using a base-case consisting of a four-well field in 5,000 ft (1,524 m) of water, 12.5 miles (20 km) from the production facility and flowing 100,000 b/d of oil, the study calculated the number of necessary intervention days using the DC system vs. an hydraulic system over a 12-year field life. Results were impressive.
· 40% reduced intervention time the first year, followed by 20% reduction in subsequent years;
· 20% reduction in single-well failures over the life of the field; and
· 15% reduction in system downtime over the life of the field.
Using very conservative US $25/bbl of oil and $3.50/MMcf of gas commodity prices and a 10% discount rate, the model calculated a $129 million improvement in net present value over the life of the field.
Testing the concept
In assessing the viability of the DC production control system, Total engineers did a rigorous analysis of all data acquired over several years of component testing, as well as two significant system tests. Field trials were conducted with the cooperation of BP on its Magnus field in the UK North Sea. (Prior to that, a 22-day “shakedown” test was conducted in the fjord near
The test system consisted of a representative number of valves and chokes, all equipped with DC electric actuators:
· 5 1/8-in. 5,000 psi FLS gate valve;
· 2 1/16-in. 5,000 psi FLS gate valve;
· 5 1/8-in. 5,000 psi insert choke;
· 3/4-in. 5,000 psi chemical injection valve;
· Pressure transmitters on supply and return lines; and
· Hydraulic accumulator to provide bore test pressure and flow.
In addition, a 6.25 mile (10 km) power and control cable bundle was spooled on top of the test tree to simulate step-out distance and quantify its effect on power and data transmissibility.
Figure 4. A subsea electric control module. |
The choke with electric actuator was subjected to the equivalent of 1 million steps on a hydraulic stepping choke.
Contributing to the success of the field testing was the fact that the all-electric system has much fewer moving parts and seals than its hydraulic counterpart. The average electro-hydraulic control module alone has more than 500 moving parts and seals, whereas the all-electric version has none. And hydraulic systems require full power at all times to maintain status. Electrical systems maintain status at low power (the equivalent of a standard light bulb) and only consume high power (equivalent to a standard household appliance) during actuation.
A unique design
Each module is based on field-proven, reliable valve designs, in fact the electrical actuator conforms exactly to the interface previously used for the Cameron hydraulic actuator. A mechanical failsafe spring will close the valve in the event of an emergency. Three basic actuator sizes will cover the
Subsea choke actuators followed a similar design philosophy, except there was no requirement for a failsafe mechanism. Chokes were designed to be infinitely variable with fast response and low power consumption. Reliability was assured by equipping the chokes with redundant motors and position sensors. Like the valves, the choke interfaces are interchangeable with previous hydraulic versions to enable upgrading of existing trees (Figure 3).
Figure 5. Power regulation/ communications module. |
The “brains” of the system is the electrical control system which consists of a surface module and two subsea modules: the power regulator and
A world’s first
When they are installed in 2007, the first two all-electric subsea systems will enable production control from Total’s K5F gas field located about 68 miles (110 km) northwest of Den Helder, and will tie-in to a new 6.2 mile (10 km) pipeline to the existing K-6 satellite platform and treatment facility. Production is expected to reach 99 MMcfg/d (2.5 MMcm/d). The option exists to add two additional DC production control systems in the field at a later date. The
Recommended Reading
Seadrill Sells Three Jackups for $338MM to Gulf Drilling International
2024-05-17 - Seadrill Ltd. is also selling its 50% equity interest in the joint venture that operates the rigs offshore Qatar.
Could Crescent, SilverBow Buy More in South Texas After $2.1B Deal?
2024-05-17 - The combination of Crescent Energy and SilverBow Resources will yield one of the Eagle Ford’s top producers—and the pro forma E&P could look to gobble up more acreage in South Texas after closing.
Permian Powerhouse: Apache Doubles Down on Core Assets After Callon Acquisition
2024-05-16 - Apache CEO John Christmann detailed plans for the Permian Basin and Suriname during the SUPER DUG Conference & Expo.
Crescent Energy to Buy Eagle Ford’s SilverBow for $2.1 Billion
2024-05-16 - Crescent Energy’s acquisition of SilverBow Resources will create the second largest Eagle Ford Shale E&P with production of about 250,000 boe/d, the companies said.
Exclusive: Is TG Natural Resources Looking to Snap Up More?
2024-03-27 - At Hart Energy's DUG Gas+ Conference and Expo in Shreveport, Louisiana, TG Natural Resources' President and CEO Craig Jarchow said the integration of the Rockcliff Energy acquisition is well underway and that "being acquisitive is certainly" in the company's future.