Surface BOP (SBOP) isn’t exactly a new technology; it’s been standard practice on jackups for decades. However, for floating rigs, the SBOP has been used only since the mid-1990s, and only sparingly at that. It has primarily been used in exploratory drilling since then, although Shell used the method while drilling development wells in its BC-10 field offshore Brazil. In other recent applications, SBOP has been used on riser systems for several floating drilling and production schemes.
A panel discussion during a general session at OTC on 6 May examined the state of surface BOP technology and future opportunities in deepwater.
An SBOP configuration includes a jackup-style BOP at the rig to contain the pressure in case of a kick or blowout. At the seafloor, operators began using a seabed isolation device (SID) that seals the wellbore and provides a release mechanism for the riser in case the rig cannot remain on the well. The SID is surface-controlled using an acoustic control system in combination with a MUX control to provide redundancy. This also eliminates control lines. A remotely operated vehicle (ROV) can also be used to operate the SID.
During Shell’s experience, the SID was used successfully four times: three times when moving a rig off location due to severe weather and once when a squall pushed a rig off location. In all instances, the riser was able to be reconnected.
Extending rig water depth, reducing costs
SBOP has proven to be a cost saver during exploration in deepwater for several reasons, according to Brian Tarr, senior engineer, well technology, Shell International E&P. “Using an SBOP can increase the rig’s water depth rating, resulting in a wider choice of rigs,” he said. Wells also can be drilled faster.
A smaller-diameter riser is key to increasing a rig’s water depth when using SBOP. The smaller diameter the riser, the less mud required to fill the riser and the less weight that has to be supported by the riser tensioners. The longer but smaller-diameter riser used with SBOP enables the rig’s riser tension system to handle the same weight as a typical larger-diameter riser, but its extra length means the rig can operate in deeper waters.
There is at least one caveat to using SBOP technology: “There must be sufficient number of wells planned in order to make use of SBOP’s economics,” Mr Tarr said.
In 2000, in mild metocean conditions, Shell drilled two wells with the Sedco 601 semisubmersible in a moored configuration without an SID. The following year, the company drilled three wells offshore Brunei and two wells offshore Malaysia with SBOP but without a SID. In 2003, Shell drilled its first BM-10 field well offshore Brazil in 9,473 ft of water in moderate metocean conditions. Later that year, Shell drilled three wells in about 8,000 ft of water off Egypt, also in moderate metocean. Both projects were drilled with the Stena Tay dynamically positioned semisubmersible. The use of SBOP on the Stena Tay enabled the rig’s water depth to be extended from 7,500 ft to 10,000 ft.
In 2008, to develop its BC-10 field offshore Brazil, Shell drilled a dozen development wells with SBOP in around 6,500 ft of water with the Transocean semisubmersible Arctic I. The rig’s water depth was extended from 3,000 ft to 7,500 ft with use of SBOP. These were the industry’s first development wells and completions to use an SBOP and SID. Shell used a 16-in. OD/ 14.5-in. ID riser designed around IADC’s SBOP guidelines for floating rigs developed in 2004.
The BC-10 SBOP components included a pressure test line, control system power and hydraulic supply in the umbilical, a purpose-built high-pressure (6,000-psi) riser with buoyancy and strakes, a 7 5/8-in. pipe ram in the SID for completion operations and a slim-bore wellhead.
While SBOP has been proven to be a cost-effective solution in certain cases and areas, there are some limitations to the technology, Mr Tarr noted. “There are few SBOP systems on the market,” he said, “and they are not suitable for deepwater rigs and overpressured wells.
“Also, SBOP is suitable only for a limited well depth below the mud line and is not suitable for metocean above moderate.”
Still, there is a future for SBOP, Mr Tarr emphasized. “SBOP systems for floating rigs are still relatively new,” he said, “while well intervention with an SBOP configuration is emerging technology.”
Floating deepwater host facilities using dry trees at the surface is considered a mature industry these days.
Quantitative risk analysis illustrates SBOP safety
David Bond, general manager, drilling, for Ophir Energy, answered the question whether SBOP is a safe operation. “Absolutely, provided they are engineered correctly and its limitations are understood,” he said. “SBOPs are potentially safer than conventional subsea BOPs, since the system is driven by having two BOPs (surface and SID).
“A SID is essential on a dynamically positioned vessel and recommended on a moored vessel,” Mr Bond explained.
A study to assess the safety of an SBOP system was performed based on the Deep Venture drillship. Among the factors in the study was stationkeeping to confirm the rig’s capability, a riser analysis to ensure no riser failure, a quantitative risk analysis (QRA), equipment running capabilities and procedures, and pore pressure studies.
The QRA examined the failure path leading to a blowout and describes the logic leading to the failure. It also applies probabilities and frequencies to each failure point, with the results indicating the likelihood of a failure. The riser analysis focused on likely fatigue and to understand if vortex-induced vibration (VIV) suppression was required on the riser, as well as other wave loading issues. The conclusion was that the 13 3/8-in. top section of the riser with a premium connection had an 8-year fatigue life.
The QRA examined several blowout mechanisms: There is a kick and the BOP fails; there is a kick and the BOP closed too late; there is a riser failure and the BOP fails; there is a kick and a shoe failure (underground blowout); or there is a choke and kill failure and a kick.
DrillSlim SBOP and riser system
Gavin Humphreys, new business and technology manager for Stena Drilling, outlined enhancements to SBOP to facilitate new drilling and well intervention technologies for the company’s DrillSlim concept. “Current SBOP systems generally do not have the same pressure integrity in the riser and throughout the entire BOP system,” Mr Humphreys said, “and the system generally does not have kill and choke lines.
“Also, the SBOP systems are not specifically designed to incorporate a rotating control head or Blafro flanges to facilitate managed pressure drilling (MPD) or underbalanced drilling (UBD) technology in slim-hole drilling or in thru-tubing rotating device (TTRD) mode.”
The above is important, according to Mr Humphreys, because slim wells can be drilled in deepwater where the subsurface pressures are relatively mild with expandable and MPD technologies that can improve drilling performance and ultimate recovery at a much reduced well cost. “Use of MPD or UBD drilling technology in deepwater could improve drilling performance and/or reservoir characterization and make reservoirs deemed noncommercial due to their reservoir properties commercial again,” he explained.
“Drilling in UBD mode would facilitate use of the riser as a lubricator, eliminating subsurface valve controlled from the surface via control line,” Mr Humphreys continued.
During interventions, where TTRD changes the “drainage point” in a reservoir in order to increase the ultimate recovery, “MPD or UBD can eliminate all drilling problems caused through convergence of pore pressure and fracture pressure due to depletion of the reservoir pressure,” he explained.
The well control equipment consists of a subsea lower BOP including a lower marine riser (LMR) and emergency disconnect (LBOP), and an upper BOP (UBOP) and a diverter system. The LBOP consists of one hang-off ram, two blind shear rams and an LRP with a hydraulic disconnect package
The 13 5/8-in. UBOP consists of three sets of rams (two variable bore rams and one set of 9 5/8-in. casing rams and a 13 5/8-in. annular preventer on which a rotating circulating device (RCD) can be installed to facilitate MPD or UBD.
The riser consists of 7,500 ft of 16 ¾-in., 10,000-psi high-pressure riser with one kill/choke line, one booster line and two hydraulic lines.
The subsea package is controlled by a multiplex system with acoustic back up.
Operational flexibility of SBOP
John Kozicz, technology manager for Transocean, provided a brief update on the operational flexibility of SBOP. He noted that, while SBOP can significantly extend the water depth of a semisubmersible or drillship, as noted in several examples earlier, surface BOP can improve shallow-water operating efficiency by mitigating challenges to jackup exploration operations in areas prone to the risks of punch-throughs.
(Chevron used the Sedco 602 semisubmersible in Bohai Bay offshore China due to the soft seabed that resulted in deep jackup leg penetration, requiring several days in some cases to pull the legs from the soft seafloor.)
Shallow-water SBOP projects are assessed on a case-by-case basis, he noted, with risers designed in accordance with the requirements of API RP 16Q and API RP 2RD. Stationkeeping/mooring design are in accordance with API RP 2SK. Metocean considerations include calm or moderate winds and sea state, with minimal currents.
“Shallow-water surface BOP exploration drilling (with a floating rig) in many instances can be a viable alternative to jackup drilling,” Mr Kozicz said,” and is particularly suited to areas with challenging soil conditions.
“It can improve drilling operations efficiency and productivity,” he continued, “and can also provide a minimum commitment opportunity to gain SBOP operations experience.”