The oil and gas industry is flexing its muscles once again in the US Gulf of Mexico (GOM) with a surge of activity expected to support a robust level of deepwater development through the end of the decade.
While headlines worldwide have gone to onshore North American shale drilling, the GOM remains a premier objective for the world’s largest international companies. A single deepwater well can produce more than a large number of onshore shale wells combined, which translates to a lower capital cost per barrel for companies with the financial and technical wherewithal to develop deepwater resources.
The doubt cast over the future of GOM development in the aftermath of the fatal BP Macondo well blowout and oil spill in 2010, and the ensuing deepwater drilling moratorium, has receded.
Containment Advances
Two multicompany organizations, the Marine Well Containment Company and the Helix Well Containment Group, have now developed capping stack and spill recovery systems designed to contain a Macondo-sized blowout with equipment and resources permanently located in the GOM. The development and availability of sufficient containment technology was a necessary condition for the United States government’s decision to resume issuing deepwater drilling permits.
In addition, the government completed a major reorganization of its offshore regulatory system, strengthening offshore development oversight and the safety and environmental enforcement functions.
With the resumption of deepwater drilling permits and renewed acreage leasing, GOM activity has steadily increased over the past 2½ years.
As a final symbol of restored drilling and development momentum in the GOM, BP placed the high bids on 24 deepwater blocks in the federal lease sale for the central Gulf on March 19. Days earlier, the US Environmental Protection Agency (EPA) had lifted a suspension enacted after Macondo that barred BP from receiving new government contracts.
As a condition for regaining contract bidding rights, including bidding on government oil leases, BP agreed to retain an EPA-approved independent auditor to ensure that the company meets safety, ethics, and corporate governance standards.
Floating Rigs Increase
The number of floating drilling rigs that are active in the GOM—semisubmersibles and drillships that are designed for deepwater projects—has increased from 27 in October 2011 to 45 at the beginning of the year, according to data from IHS. Over the same period, the number of active jackup rigs—those rigs designed for shallow waters—fluctuated between 30 and 36 and at the start of the year stood at 31. The figures suggest the growing share of deepwater projects in total GOM activity.
“The deepwater drilling activity we are seeing appears to be sustainable as we look ahead to the next several years,” said Tom Kellock, head of offshore rig consulting at IHS.
In all, GOM production could grow by 180,000 B/D this year to 1.55 million B/D, according to the US Energy Information Administration. By 2016, Wood Mackenzie forecasts production is on track to surpass the GOM record of 1.8 million B/D set in 2009.
Two deepwater projects, the Shell-operated Mars B and the Murphy-operated Dalmatian developments, have already gone on-stream this year and five others are slated to start up by year-end. The seven projects were in various stages of planning before Macondo, most of them for several years. Each received its final investment decision (FID) after the 2010 incident.
Mars Operations Expanded
Mars B, which began production in February, is the first GOM deepwater project to expand an existing oil and gas field with significant new infrastructure. The Olympus tension-leg platform (TLP) installed at Mars B is the largest facility of its kind in the GOM with 24 well slots and a self-contained drilling rig. The initial production flowed from newly completed subsea wells in the West Boreas and South Deimos fields, which are tied back to the Olympus facility.
The TLP is situated in the Mississippi Canyon area in 3,100 ft of water. The Mars B project is developing Middle Miocene reservoirs at depths ranging from 10,000 to 22,000 ft beneath the seafloor, using the Olympus platform drilling rig and a floating rig. The planned development is expected to achieve peak production of 100,000 BOEPD from Mars B in 2016. The existing Mars field, which was discovered in 1989, went on-stream in 1996 and produced more than 60,000 BOEPD in 2013.
In addition to the Olympus facility and the subsea tieback wells, Mars B includes export pipelines and a shallow-water processing platform at West Delta Block 143. The Mars B development is projected to extend the life of the greater Mars basin to at least 2050. Shell holds a 71.5% interest in the Mars field with the remainder held by BP.
Dalmatian Starts Production
In March, first production flowed from the initial well of Murphy’s Dalmatian field in the De Soto Canyon area, with a second producer slated to follow in the third quarter. The project is a subsea development of Middle Miocene sands, with production being tied back to the Chevron-operated Petronius field in Viosca Knoll Block 786.
A peak production of 7,000 B/D at Dalmatian is anticipated in the fourth quarter. The field lies in 5,875 ft of water. Murphy holds a 70% interest in Dalmatian, with Ecopetrol holding the remaining share.
Cardamom Deep Limits Footprint
Shell’s Cardamom Deep project in Garden Banks Block 427 is expected to come on-stream in the second half of the year. Five subsea wells are being tied back to the Shell-operated Auger TLP on Garden Banks Block 426, enabling Shell to limit the project’s offshore footprint. The wells, in more than 2,700 ft of water, will produce from a Miocene zone approximately 26,000 ft beneath the seafloor. The host facility has undergone retrofitting and upgrading to handle the new development.
“Cardamom is a great example of using existing infrastructure to increase oil and gas production in a less capital intensive way,” said John Hollowell, executive vice president for deep water at Shell Upstream Americas.
When drilled from the Auger TLP 3½ years ago, the Cardamom discovery well set records for subsurface length and depth, achieving a measured depth of 31,634 ft, a horizontal reach of more than 15,000 ft, and a vertical depth of more than 25,000 ft. The discovery well has produced from Auger since December 2010. Cardamom, owned 100% by Shell, is expected to produce 50,000 BOEPD at peak output from the subsea system and direct vertical access wells drilled from Auger.
Lucius Creates Hub
Also in the second half of the year, Anadarko plans to start production at its major Lucius project, a USD 2.8 billion development in the Keathley Canyon area. A floating truss spar facility measuring 605 ft by 110 ft has been installed in 7,100 ft of water at Keathley Canyon Block 875.
The facility, with a combined hull and topsides weight of 38,000 tonnes, will produce from subsea wells completed in subsalt Pliocene and Miocene sands. It has a capacity of 80,000 B/D of oil and 450 MMcf/D of gas. The Lucius reserves are estimated at 300 million BOE.
Anadarko has a 35% working interest in the field. As operator, the company has signed a unitization agreement covering the Lucius reservoirs with project co-owners Freeport McMoRan (23.3%), ExxonMobil (15%), Apache (11.7%), Petrobras (9.6%), and Eni (5.4%).
Hadrian South To Tie Back
On Keathley Canyon Block 964, ExxonMobil will bring its Hadrian South subsea project on-stream through tiebacks to Lucius, starting gas production simultaneously with the Anadarko project.
By an agreement signed between the Lucius and Hadrian South partners, Lucius will process gas from the ExxonMobil development in exchange for handling fees and facility upgrade reimbursement. Terms have not been disclosed, but it is expected that payments from Hadrian South will cover most of the Lucius operating costs. Anadarko has described Lucius as one of its most economically efficient projects.
Similar to Lucius, the planned Hadrian South production will come from Pliocene sands. Both projects also originated with discoveries in 2009, setting them up to be among the fastest projects to move through development in the deepwater GOM. ExxonMobil holds a 50% working interest in Hadrian South, with Petrobras and Eni each having a 25% interest. Hadrian South is slated to undergo further exploration.
Tubular Bells Eyes Subsea Production
Another development slated for 2014 startup is Tubular Bells, a Hess-operated deep Miocene project in the Mississippi Canyon area at water depths of 4,300 to 4,600 ft. The immediate plans are to develop three subsea production and two subsea water injection wells. The well arrangement calls for two seafloor drill centers, the first with two producers and an injector, the second with a producer and an injector.
The drill centers will be tied back to Gulfstar, a floating production system (FPS) based on a spar concept that was recently installed at Mississippi Canyon Block 768. Gulfstar, owned by Williams Partners, is the first spar-based FPS to have its major components built entirely in the US.
In the tiebacks, production pipelines leading from the drill centers will be connected to the Gulfstar hull through a steel catenary riser system. Tubular Bells is expected to produce between 40,000 and 45,000 BOEPD from recoverable resources estimated at 120 million BOE.
With a processing capacity of 60,000 B/D of oil and 200 MMscf/D of gas, Gulfstar is designed to be a hub for additional tiebacks. Williams and Noble Energy have already signed an agreement for the tieback of Noble’s nearby Gunflint project, which will come on-stream in 2016. Hess has a 57% interest in the Tubular Bells project with the remainder held by Chevron.
Jack/St. Malo: Year’s Largest Startup
The largest project slated to come on-stream in 2014 is Chevron’s Jack and St. Malo development in Walker Ridge blocks 758, 759, and 678, expected to start production late this year. The estimated peak production of the project’s first phase is 97,500 BOEPD, which will include some third-party tiebacks. The full project has a designed production capacity of 177,000 BOEPD.
The Jack and St. Malo fields lie 25 miles apart in 7,000 ft of water. A massive semisubmersible facility weighing about 75,000 tonnes has been installed between them and will produce the resources of both fields. The Lower Tertiary reservoirs of both fields are estimated to hold more than 500 million BOE.
Phase 1 development calls for four subsea wells to be drilled from Jack and six from St. Malo, with the wells tied back to the production facility. Its capital investment is estimated at more than USD 7.5 billion.
Located about 280 miles south of New Orleans, the production facility is intended to serve as a hub for 43 subsea wells planned for subsequent phases of development. Front-end engineering and design is already under way for Phase 2, comprising two wells each from Jack and St. Malo, with an FID expected in 2015.
Chevron holds a 50% interest in Jack, with Statoil and Maersk each holding a 25% share. Chevron’s interest in St. Malo is 51%, with the remaining interests held by Petrobras (25%), Statoil (21.5%), ExxonMobil (1.25%), and Eni (1.25%).
A Look Ahead
Looking beyond this year, GOM production should continue to grow. “As far as future development projects, there are going to be quite a few coming online in the next 5 to 7 years,” said Justin Devery, exploration and production researcher for deepwater GOM at IHS. “There are some big, giant fields out there.”
Two of the biggest are ExxonMobil’s Julia project and Shell’s Stones project. Both have received FIDs and will develop Lower Tertiary discoveries in the Walker Ridge area.
Phase 1 of Julia is scheduled to come on-stream in 2016 as a six-well subsea tieback to the Jack/St. Malo floating production unit. First-phase production is expected to peak at 34,000 B/D. Appraisal well results have suggested that Julia could hold as much as 6 billion bbl of recoverable resources and have a field life of more than 40 years.
At Stones, Shell will develop subsea wells in 9,500 ft of water and tie them to a floating production, storage, and offloading system. Phase 1, slated for 2016 startup, will include two wells that will produce 50,000 BOEPD at peak output. Later plans call for adding six wells with multiphase pumping. Stones is estimated to hold resources of more than 2 billion BOE in place.
Other developments that have yet to receive FIDs and probably await later execution include Anadarko’s Shenandoah project and BP’s Tiber project.
Drilling at Shenandoah in Walker Ridge has encountered more than 1,000 ft of net pay in high-quality Lower Tertiary reservoirs.
At Tiber in Keathley Canyon, BP drilled a 2009 discovery that could hold more than 3 billion bbl of oil. The well was drilled to 35,000 ft beneath the seafloor, which creates large development challenges from the high pressures and temperatures in the reservoir.
GOM Opportunities Beckon
While the GOM will continue to present many challenges to companies worldwide that seek to find and develop its deepwater resources, the region will continue to attract those companies—and probably some newcomers—with opportunities to discover billion-barrel fields and develop them in a stable political environment with high fiscal and regulatory transparency.
The deepwater GOM affords economies of scale not only because of big targets, but because of extensive existing development. That and new facilities being installed at the water’s surface create increasing opportunities for subsea tiebacks and other development strategies that integrate with existing infrastructure. This reduces development costs for many new projects, while typically generating fee and tariff income for the owners of host facilities—adding value for both parties. All indications are that these opportunities will remain abundant.