UK-based Plexus Ocean Systems Ltd., a division of Plexus Holdings plc, is utilizing a patented technology that the company believes will improve wellhead design to prevent or minimize the impact of blowouts such as the April 2010 Macondo incident in the Gulf of Mexico and the 2009 Montara blowout offshore Australia.
The company's POS-GRIP technology, invented by the company's CEO and founder Ben Van Bilderbeek employs a method of elastically deflecting an outer wellhead body onto an inner casing or tubing hanger and locking them in place to support tubular weight and activate seals. In surface wellhead applications, the system is powered by reusable hydraulic devices, which are fitted temporarily to flanges on the outside of the wellhead.
An example of a POS-GRIP Rotary Surface Wellhead
Van Bilderbeek said he sees friction-grip technology as the best available and safest (BAST) method of engineering for wellheads for all applications, including:
POS-GRIP technology has been used for 12 years in the North Sea, particularly for high-pressure, high-temperature (HP/HT) wells, Van Bilderbeek told Rigzone.
The technology was initially introduced in the North Sea through an adjustable rental wellhead system for jackup drilling operations; later, POS-GRIP technology was developed for use in specialized HP/HT wellhead systems.
Plexus hopes to replicate the success of its HP/HT technology in the larger international production wellhead and subsea arenas as company officials see many applications in unconventional fields.
The company has had discussions with a number of companies to license POS-GRIP technology, and would like to enter the U.S. market with a partner, or potentially sell certain applications that don't fit perfectly with Plexus' business strategy.
"We ourselves are not interested in operating in the U.S. due to the risk factors that apply in U.S. waters," said Van Bilderbeek. There are lots of targets around the world with less risk."
POS-GRIP technology presents a number of advantages over existing spool-type and mandrel hanger wellhead technologies, depending on the application, including:
The technology also offers superior reliability, reduced life cycle cost and is tolerant to a contaminated environment.
The company's roster of customers includes: Apache Corp., BHP Billiton Ltd., BP Plc, ConocoPhillips Company, Maersk Oil, Lundin Petroleum AB, Newfield Exploration Company, Talisman Energy Inc., Statoil, Royal Dutch Shell Plc, Total S.A. and Wintershall Holding GmbH.
"Recent well control incidents around the world have highlighted the need for robust, high performance, subsea wellheads in oil and gas operations, particularly in extreme and hostile environments," said Van Bilderbeek in a June 19, 2012 statement.
"Specific functionality is required such as instant casing hanger lockdown, the ability to monitor sustained casing pressure and then enable remedial action and bleed off capability."
An example of how the POS-GRIP mechanism works
Wellheads to be 'Strong Link' in Well System; Industry Needs to Eliminate BOP Lifting Practice
The company has designed wellheads to be the strong link in the well system, Van Bilderbeek noted in a presentation for U.S. government officials in December 2012, and is pursuing a policy of preventing blowouts "by design". Achieving the goal of wellheads as the strong link includes matching wellhead standards to those for casing and tubing couplings, Van Bilderbeek noted.
To prevent blowouts, the company argues that the industry needs to eliminate the practice of lifting BOPs from the wellhead to set casing. Wellheads must be designed to be permanent safe platforms for well control devices, while maintaining dual barriers across the well bore and annular spaces adhered to at all times.
Additionally wellhead designs where possible should rely on rigid metal sealing for integrity beyond field life, and such standards should apply to all applications, rather than just for HP/HT wells.
Van Bilderbeek pointed out that current wellhead qualification test procedures are component based, whereas emerging standards require specific qualification tests treating seals as part of a system. Currently, standards for casing and tubing couplings are far more stringent than for wellheads.
Most blowouts occur when the BOPs are away from the wellhead, as American Petroleum Institute (API) spool type systems require removal of the BOPs to set casing.
One justification for continuing the century old habit of lifting BOPs is that this method eliminates to need to space out casing, avoiding the extra work of measuring pipe into ground.
"Further excuses include the need to tension casing, which is negated by the fact that this can be done with through BOP technology," Van Bilderbeek noted.
There is no longer any justification for ever designing wellheads that require the lifting of BOPs to be set casing, as without a BOP in place a well is left under the sole protection of single barriers for an extended period of time.
The Montara Commission of Inquiry Report links the design of pressure containing corrosion caps to the Montara incident, adding that removing abandonment caps from the well before a riser with a well control device on top is re-established clearly breaks the dual barrier rule, Van Bilderbeek noted.
The United States' forerunner agency to the Bureau of Ocean Energy Management and Bureau of Safety and Environmental Enforcement (BSEE), the U.S. Minerals Management Services had recognized the risk of lifting BOPs; they proposed a solution to improve cementing techniques, as seen in an incident that occurred in April 1997 at East Cameron Block 328. On that day, a serious blowout and fire occurred on Platform A. The U.S. Department of the Interior (DOI) concluded the probable cause of the incident was formation gas migrating through the cement between the 9-5/8-inch casing and the 13-3/8-inch casing.
DOI officials also concluded there was not enough wait-on-cement time prior to nippling down the BOP. A possible contributing cause was that, since the well had been drilled horizontal, the casing may not have been properly centralized, resulting in a non-uniform cement job.
Plexus' solution would be to require that the BOPs be left in place by using thru-BOP wellhead technology, which is available from all major suppliers. This allows an operator to control a well-kick during casing installation procedures.
Van Bilderbeek believes the industry would benefit from a wider acceptance of the simple and obvious BAST rule -- never lift BOPs unless absolutely necessary.
When a POS-GRIP wellhead is activated, multiple metal seals interact over a long interface between the wellhead bore and casing hanger. Conventional annular seal are no longer required, and movement between parts is eliminated for integrity beyond field life. Qualification has taken place under simulated and extended field life testing conditions, Plexus officials noted.
Technical Solutions to Lock and Seal Casing, Tubing Annuli 'Problematic'
In subsea wellhead applications, the technical solutions available to lock and seal casing and tubing annuli have been problematic. As a direct consequence, the industry has adopted a procedure of installing lock-down sleeves to fix casing hangers in the well bore at the end of the drilling program.
These devices, which are time consuming and can cost between an estimated $2 million and $5 million to install, are used because of the problems associated with using remotely activated lock-ring devices in the contaminated environment of a subsea well.
To be functional, a lockdown sleeve needs to be set with downward load on the casing hangers. The length of the weight string of pipe hanging from below a lockdown sleeve can dictate the setting depth for the cement plug, depending on the chosen installation sequence, van Bilderbeek noted.
If mud is replaced with seawater prior to setting of the cement plug, its setting depth can contribute to under-balancing of the well, which suggests that the use of a lockdown sleeve to secure casing hangers in a subsea wellhead, because conventional lockdown devices are problematic, can lead to well control incidents.
"Conversely, on surface wellhead applications, all casing hangers are individually locked down as soon as casing is cemented, and this is done for good reason," Van Bilderbeek noted, and the same logic and safety disciplines should apply subsea for the protection of personnel and the environment.
Van Bilderbeek noted that DOI's May 2010 report advising that all casing hangers should be instantly locked down following cementing is correct.
Van Bilderbeek, who met with U.S. government officials in early December 2012 as part of a teaching mission on technology available for wellhead design, and to highlight the conflict which comes into play when a technology is both BAST and proprietary, notes that no justification exists for ever leaving casing hangers unlocked in a subsea wellhead at any time during drilling or production.
Van Bilderbeek commented that Shell has issued revised qualification guidelines which require that the lockdown capacity for subsea casing hangers during drilling is proven to a level equivalent to the requirement for production casing hangers in the field, Van Bilderbeek noted.
A POS-GRIP HG Platform Wellhead System
JIP Formed to Develop New Class of Subsea Wellhead System
In October 2010, a joint industry project (JIP) was formed by Plexus to focus on development of a new class of subsea wellhead system, the POS-GRIP HGSS subsea wellhead, with particular focus on addressing systemic deficiencies of current technology. The JIP's primary target is to design a wellhead system in which all casing hangers can achieve rigid lockdown following cementing, while remaining releasable if it becomes necessary to recover casing.
The JIP's member rosters now include ENI, Oil States Industries, Maersk Oil subsidiary Maersk Oil North Sea UK, Shell Plc subsidiary Shell International Exploration and Production, Wintershall Holdings GmbH subsidiary Wintershall Noordzee, Total S.A., and Tullow Oil Plc. The project is expected to take between 18 and 24 months from the February 2012 launch date at a cost of approximately $2.3 million to $3.1 million (GBP 1.5 million to GBP 2 million). Any intellectual property created through the JIP will be owned by Plexus.
Key features that Plexus hopes to incorporate into its new POS-GRIP HGSS subsea wellhead design include:
The wellhead standards utilized by the Plexus JIP will be more stringent than those proposed by API for similar technology, Van Bilderbeek commented.
The Plexus wellhead standard will be pitched to match the standards required of premium casing and tubing couplings. Van Bilderbeek noted that this is not the approach that API currently takes by allowing a single sample test, and unlimited number of attempts.
The Plexus JIP also requires make and break testing, test to failure, simulate field conditions, and test under loading, Van Bilderbeek noted.
BSEE has identified the need for development work on 20,000 psi extreme HP/HT subsea drilling equipment and well design. However, Van Bilderbeek pointed out that a recent BSEE report fails to address systemic shortcomings of conventional 15,000 psi and below applications, focusing only on work to be done in the 20,000 psi and above category.
The BSEE has reported that additional developments and qualified work will be required before 20,000 psi systems are commercially available for subsea applications. For 20,000 psi drilling equipment, the current direction is the development of custom products. Wellhead systems with working pressures in excess of 15,000 psi are under development and not expected to be ready for use for a number of years.
Van Bilderbeek reported that the HGSS wellhead technology design work is underway, based on qualified hanger designs used on 20,000 psi surface drilling operations in the North Sea.
Testing on the HGSS JIP to adapt POS-GRIP technology for subsea applications is well advanced, and a POS-GRIP HP/HT tie-back connector designed to allow operators to pre-drill HP/HT production wells is now available.
Plexus believes POS-GRIP's potential in its HP/HT tieback application is one of the most far reaching developments in many years. According to Plexus, HP/HT and ultra high-pressure/high-temperature (XHP/XHT) wells could be safely tied back at a future date, negating the disposable nature of these wells.
Potential savings for the operator is the entire cost of the well, which Plexus estimates is between $75 million to $450 million per HP/HT well, and the well can begin to generate revenues at a much earlier date. HP/HT wells in a proven field could be pre-drilled and abandoned ready for completion while the platform was being designed and construction.
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