Despite the increasing production and the possible export of oil and gas from shale plays, interest in the Gulf of Mexico (GOM) is still strong.
March’s lease sale of 329 GOM tracts covering some 1.71 million acres by the Department of Interior brought in over $872 million in high bids. The sales build on three previous sales held under the Obama administration’s Outer Continental Shelf Oil and Gas Leasing Program for 2012-2017 that offered more than 60 million acres for development and garnered $1.4 billion in bid revenues. The bids confirm a robust and continuing OSV market potential in the GOM.
Drilling activity on the GOM shelf has been stable, but deepwater exploration and appraisal drilling is robust.
Jez Averty, senior vice president for North America exploration for Statoil, said the prospects in the deepwater Gulf “rank highly in global prioritization” of the company’s portfolio. “It’s the value creation potential of this basin that drives us to explore.”
Statoil is not alone in its intensified focus on the deepwater Gulf. Almost all of the major international oil and gas operators are working there. The result is that while four to five jackups have been idled in the shallow water Gulf in the last few months, deepwater rig supply is on the increase. Currently, there are nearly 60 deepwater rigs (including platform rigs) working in the Gulf, with more expected as a number of newbuild rigs enter the sector over the next year.
All of these rigs will be needed to satisfy well permits issued through early March. Deepwater permits issued in February alone (approved, returned and pending) stood at 68 wells, including 21 new well permits, 28 revised new well permits, three bypass well permits, three revised bypass well permits and eight sidetrack permits. These permits add significantly to the number of planned and ongoing drilling programs in the deepwater Gulf.
DEEPWATER PROSPECTS
The robust GOM drilling activity has led to the appraisals of the development potential for a number of deepwater prospects.
Should these prospects appraise as expected, they will join a growing list of producing fields in the deepwater Gulf. While some will be fields tied back to existing deepwater production facilities — 73 existing facilities in water depths greater than 500' — others will require the installation of new production and export facilities, including SPARs, TLPs and FPSOs, in addition to gathering systems and export pipelines. Some examples are Chevron’s recently installed Jack/St. Malo semisubmersible and Shell’s ultradeepwater Stones floating production, storage and offloading (FPSO) vessel, scheduled for installation in 2016.
Crowley Maritime’s Ocean-class tugs successfully delivered the Jack/St. Malo semisubmersible production facility to its deepwater Gulf of Mexico location 280 miles south of New Orleans in March. Scheduled to begin producing oil and natural gas later this year, the Chevron facility will have a capacity of 170,000 bpd and 42.5 MMcfgd. It will act as a hub for the 43 subsea wells, including pumps and other equipment on the seafloor.
Shell’s ultradeepwater Stones project is expected to be the deepest production facility in the world. Fabrication of the FPSO and subsea infrastructure is underway. Stones is located in 9,500' of water, approximately 200 miles southwest of New Orleans. The project encompasses eight OCS lease blocks in the Gulf of Mexico’s Lower Tertiary geologic trend. Shell has been one of the pioneers in the Lower Tertiary, establishing first production in the play from its Perdido Development.
The Stones development will start with two subsea production wells tied back to the FPSO vessel, followed later by six additional production wells. This first phase of development is expected to have annual peak production of 50,000 bpd from more than 250 million bbls. of recoverable resources. The Stones field has significant upside potential and is estimated to contain more than two billion bbls. of oil, according to Shell.
The result of developments such as Jack/St. Malo and Stones is that, through last year, a growing percentage of U.S. Gulf of Mexico oil production came from deepwater.
With onshore shale oil production in the U.S. on the rise, some question whether deepwater prospects will continue to be developed and if the production ratio will be maintained. But because of the long life of deepwater wells, combined with an increasingly effective deepwater toolbox that helps reduce well costs and improve production and recovery, “deepwater still has the best economics,” said Jason Nye, senior vice president, U.S. offshore for Statoil. As an example, Nye pointed to the Shell-operated Vito field in which Statoil is a partner. The application of gas injection technology, an unusual approach for deepwater fields, is set to make the development a viable asset, producing some 125,000 bpd by 2020.
The deepwater Gulf of Mexico is a rapidly maturing province and, as a whole, the Gulf is high on the list of the most mature offshore provinces in the world. Since 1947, some 4,000 platforms and single well structures have been placed in the GOM. Many are now past their useful life and poor candidates for life-extension expenditures. These facilities, referred to as idle iron, are systematically being removed. Through the end of last year, 2,601 applications had been received to remove structures in the Gulf of Mexico, either through scrapping, reuse or under the Rigs-to-Reefs program. Of those, 2,086 had been removed. It’s expected that the increased demand for removal of idle iron will ensure a steady decommissioning and abandonment market in the Gulf of Mexico over the near to medium-term.
OSV DEMAND
The four Gulf of Mexico deepwater markets (drilling, facilities construction and installation, production and abandonment) should provide steady demand for the OSV fleet for at least a couple of years. The health of the market is reflected in deepwater day rates.
Richard Sanchez, marine editor at IHS Petrodata, Houston, said the deepwater market is especially strong for larger (3,000 dwt–6,000 dwt) vessels with advanced DP capability. These vessels can attract day rates of “$35,000 to $45,000 for short term contracts, and $37,000 to $48,000 for longer-term contracts,” he said.
However, the market still contains some softness, said Matthew Rigdon, chief operating officer for Jackson Offshore Operators, New Orleans. But he said the softness is only a temporary function of delivery delays for new rigs in the Gulf of Mexico due primarily to “extended shakedown periods that may take nine months rather than the anticipated 90 to 180 days.” This is compounded by the projected arrival of a number of newbuild OSVs in the Gulf.
Rigdon does not see the softness continuing past the first quarter of 2015 due in part to the way oil and gas companies are changing the OSV market dynamics by expanding the vessel-to-rig ratio. While “pretty bullish” on the deepwater market, he believes that the deepwater vessel fleet in the Gulf should not expand anymore until at least the first quarter of 2016.
As a result of the increasing OSV vessel size for deepwater deployment, Sanchez predicts that smaller vessels (2,000 dwt and less) will suffer significant attrition in the Gulf of Mexico. That scenario is playing out in day rates, which have fallen by $500 to $1,500 per day for smaller DP0 and DP1 boats. He notes that the new larger boats with larger capacities “are likely to change the equation of three-and-a-half boats per platform.” But that, he said, will be up to the operators who hire the vessels.
Rigdon, who believes that the market may not need a lot of new 5,000-dwt to 6,000-dwt vessels, agreed that the market is being driven by the oil and gas companies who want increased vessel capacities, especially in drilling operations in the wake of the Macondo incident.
Overall, Sanchez said, if you are a large OSV operator, the world looks good, and you should see “four to five quarters of good revenues” for your fleet. While Rigdon is less bullish, he is optimistic for the medium term. Both agree that if you have long-term contracts locked in, things will be smoother. A possible market contraction in 2016–2017 could hurt a bit but the big boats will still do well.
Rigdon and Sanchez said that small boat operators should be a bit more concerned.
The LNG debate heats up
There’s been a lot of talk lately about liquefied natural gas (LNG) as a marine fuel. The LNG debate revolves around dual-fuel (diesel and LNG) operations. The debate is still playing out in the U.S., as Harvey Gulf International Marine builds six dual-fuel, 302' OSVs. The first three STX SV310DF OSVs have been chartered by Shell.
There are strong arguments on both sides. A big pro is fuel cost. As traditional diesel fuel costs rise with increasing oil prices, OSV owners and oil and gas operators are increasingly considering LNG as a fuel to reduce operating costs. Depending on usage, Harvey Gulf estimates that LNG could potentially lower vessel operating expenses by as much as $2.4 million per vessel per year. This, the company says, will more than cover the 20% price premium to build LNG vessels versus similar diesel-powered OSVs. LNG-fueled vessels will also be an environmental win. When running in gas mode, the environmental impact is minimized. Nitrogen oxide (NOx) emissions are reduced by about 85% compared to diesel emissions. Sulphur oxide (SOx) emissions are completely eliminated, and emissions of CO2 are lowered substantially. Oil and gas operators are likely to tolerate higher day rates for dual-fuel vessels in line with their stated commitments to environmental stewardship.
A big negative is also fuel cost. While the actual fuel cost is not the issue, outfitting a vessel for dual-fuel operation is. Essentially, redundant systems with tankage and piping are required, driving prices higher. Also, bunkering a cryogenic liquid for storage at -260°F requires careful design and planning.
A related concern is the loss of liquid cargo space below deck. Dual fuel means lost capacity. Many say that a 300' dual-fuel vessel has the below-deck capacity of a 250' OSV due to the extra storage requirements for LNG. With oil and gas operators demanding larger and larger boats for deepwater work, the loss of cargo capacity could be a serious consideration.
A third big argument against LNG and dual-fueled vessels is the lack of bunkering facilities. As consultant Mike Corkhill noted recently in a BIMCO presentation, “in a classic case of the chicken-and-egg dilemma, investors have been reluctant to sanction the provision of an LNG bunkering network in the absence of sufficient gas-powered ships.”
It is too early to predict the outcome of the dual-fuel debate in the U.S. Increasing supplies of domestic LNG, with a large, looming U.S. LNG export potential, argue for its widespread adoption. Globally, notes John Dane, president and CEO, Gulf Coast Shipyard Group, DNV forecasts call for “50% of newbuild OSVs to burn LNG by 2020, with 10% of the world’s fleet dual fueled by 2016.”
However, fleet conversion costs, capacity issues and the lack of bunkering infrastructure have to be overcome to convince most OSV owners to take the plunge. — B. Pike
