Even though the downturn has changed many operator’s initial plans, subsea tiebacks have emerged as the economical way to develop many Gulf of Mexico fields. Karen Boman reports.
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The North Ocean 105 lay vessel. Images from McDermott International. |
The global oil price downturn prompted oil and gas operators to delay or cancel plans for offshore field development in the Gulf of Mexico (GoM), including subsea tiebacks.
As a result of the downturn, Rystad Energy expects only nine dedicated subsea tiebacks to start production from 2017-2021, down from 31 dedicated subsea tiebacks to existing fields that came online from 2012-2016. During that time, 43 tiebacks for both existing fields and greenfield floater projects came online, says Fredrik Folmer Ellekjær, project manager, Rystad Energy.
“Capital expenditures for both floaters and tiebacks in the US Gulf of Mexico also declined from 2012-2015 levels of approximately US$20 billion per year to $16 billion in 2016,” Ellekjær says. He expects this spending to fall to around $12 billion, then flatten towards 2021.
“We expect spend to increase post 2021 with higher activity levels due to renewed sanctioning activity picking up from 2018 and onwards,” Ellekjær adds.
Rystad expects 15 dedicated tieback projects to come online from 2022-2025. However, the commerciality for these projects is more uncertain than those starting production from 2017-2021. Many of these projects have already been sanctioned by operators, Ellekjaer explains.
Subsea tiebacks economics
Going forward, GoM operators will primarily use subsea tiebacks to bring new production online as industry seeks profitability in the “lower for longer” oil price environment. With the exception of the Lower Tertiary play, Wood Mackenzie estimates breakeven prices for GoM subsea tiebacks in the high $20s-$30/bbl (Brent crude). On the other hand, the breakeven price for a standalone facility could range from a high $40/bbl (Brent) to the low $50/bbl range, says Imran Khan, senior manager for Wood Mackenzie’s deepwater Gulf of Mexico team.
Subsea tiebacks will comprise 27%, or $2.4 billion, of total GoM capex ($8.7 billion) this year. For 2018, Wood Mackenzie anticipates approximately $2.7 billion in subsea tieback spending out of $11.1 billion in GoM spending. However, Wood Mackenzie expects overall capex spending and subsea tieback spending in the region to decline through 2020 to $10.4 billion and $899 million, respectively. This capex data includes commercial fields only, not fields that might be fast-tracked into development or non-commercial fields that are reclassified as commercial.
Investment is pulled back for many reasons, Khan stated.
“Lower oil prices can make it hard to justify a multi-billion dollar deepwater project when compared to a low-cost onshore project,” he explains. “The short lead time also factors into the decision making process in the current environment. Deepwater projects take much longer to develop than onshore projects and in the current environment, short lead times are very important for generating a positive return on investment.”
What’s next?
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An aerial view of McDermott’s Gulfport, Mississippi, spoolbase, which opened in 2015. |
Over the next two years, Wood Mackenzie expects three major subsea tieback projects to take place in the GoM. These projects include Shell’s Kaikias field, which the supermajor said in late February that it would develop via six subsea wells to Shell’s Ursa production hub. Greater efficiencies in Shell’s drilling strategy will enable a two-year timeline from sanctioning of Kaikias’ first phase to first oil in 2019, and also save the company millions, Khan says.
“What Wood Mackenzie is starting to see now is operators drilling wells with the belief that hydrocarbons will be encountered, and designing the appraisal well so it can be turned into a development well,” says Omar Garza, research associate with Wood Mackenzie’s deepwater Gulf of Mexico team. “Before even announcing the sanction, Shell already has been drilling development wells and plans to convert appraisal wells to producers. This involves more of a parallel process than seen in the past, when operators drilled a well, then went back to the drawing board to see what kind of development plan made sense.”
Anadarko Petroleum’s Constellation field is another widely anticipated GoM subsea tieback project. BP, the former operator of Constellation, still maintains an interest in the field. At 50 MMboe, Constellation – formerly called Hopkins – would be too small for BP to develop as an operator.
“But, cash flow remains king [in the oil and gas industry] and everybody needs it,” Khan says. “Given the project’s relative cheapness, it makes sense for BP to maintain an interest.”
In its Q4 2016 earnings report, Anadarko said that it would likely tieback its Warrior exploration well to its Marco Polo facility. Additionally, the company may tieback the Phobos appraisal well to its Lucius facility.
LLOG Exploration’s subsea tieback of the Lower Tertiary discovery Buckskin, to what Wood Mackenzie believes will be the Lucius platform, will be another subsea tieback project that industry will follow closely. One reason is that the Lower Tertiary is viewed as a major growth region for the deepwater GoM, but little production data is available for the play. Even as subsea tiebacks, these wells will be pricey, with breakeven prices estimated at around $40/bbl (Brent). The other reason is that LLOG had previously focused on smaller subsea tiebacks or other plays such as the Miocene and Pliocene.
“The industry is interested to see how LLOG, someone with a proven track record in other areas, will fare in the play,” Khan says.
To economically justify a standalone development, a field would have to contain around 200 MMboe, Khan says. But, proximity to existing facilities and available processing capacity also would factor into the decision. However, Wood Mackenzie expects facilities to become cheaper due to falling costs and available capacity in fabrication yards. Lower costs could make 150-200 MMboe fields economic now compared with three years ago, Garza says.
Prior to the oil price downturn, operators were talking about pursuing prospects longer from existing infrastructure and in increasingly deeper waters. The trends of longer and deeper subsea tiebacks have halted with the oil price collapse, and Rystad does not anticipate deeper field developments to come online that have not been discovered yet, Ellekjær says.
“We’re not going to push the technical boundaries in the next five years in terms of tieback length in the US Gulf of Mexico,” Ellekjær says.
The industry’s focus on keeping costs low is allowing new subsea production to move forward. In January, BP brought online the Thunder Horse South expansion project 11 months ahead of schedule and $150 million under budget. BP was able to complete the new subsea production system – located approximately 2mi south of the existing Thunder Horse platform – by relying on proven standardized equipment and technology rather than building customized components, the company said in January.
BP also recently sanctioned the second phase of its Mad Dog field development project in the GoM. According to Rystad’s estimates, Mad Dog 2 was sanctioned at a breakeven oil price right above $50/bbl. Shenandoah and Vito, the two next floater developments in line in the GoM, are also expected to have breakevens lower than $60/boe.
McDermott International also is seeing majors and smaller independents pursuing a few smaller subsea tieback existing infrastructure projects in the GoM, says Scott Munro, vice president of McDermott’s Americas, Europe and Africa division. In late 2015, the engineering, procurement and construction firm opened a new spoolbase facility at Gulfport, Mississippi, to support its flex-lay, rigid pipelay vessel North Ocean (LVNO) 105.
The LVNO 105 has worked on smaller subsea tieback projects such as LLOG’s Otis field and Anadarko’s Caesar/Tonga Phase 2, Munro says.
McDermott’s flex lay vessel North Ocean 102 has worked on several subsea tieback projects in the deepwater GoM, including ExxonMobil’s Julia project and Chevron’s Jack/St. Malo project. McDermott’s Derrick Barge 50 also has installed equipment packages on existing Gulf facility topsides to accommodate subsea tiebacks, Munro says.
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