Gulf of Mexico production is expected to surpass pre-pandemic levels and hit record highs in the coming years as operators bring pandemic-delayed projects on-line while focusing on lean development and lower emissions intensity.
Shell PLC, bp PLC, and Chevron Corp., among the most prolific US Gulf of Mexico producers, have each made moves to decarbonize business units in recent years. Shell said its global oil production peaked in 2019. In 2020, bp outlined an effort to decrease its worldwide oil and gas production by 40% by 2030. Last year, Chevron said it would lower the carbon intensity of its operations.
These commitments, however, do not necessitate moves away from the Gulf of Mexico, according to experts.
Ben van Beurden, Shell’s chief executive officer, made a point to mention in the company’s second-quarter 2022 report that its Gulf of Mexico emissions intensity is among the lowest in the company’s global portfolio. Shell and other companies can cut higher-emissions production elsewhere but keep production growth in the Gulf of Mexico.
“Companies are referencing Gulf of Mexico more frequently in their investor communications as a basin providing high-margin oil production at a very low emissions cost,” said Scott Nance, research analyst, US Gulf of Mexico upstream, Wood Mackenzie.
Further, Nance told OGJ, “the emissions intensity for offshore Gulf of Mexico production is one of the lowest globally, so we expect that will factor more prominently in investment decisions going forward.”
The US Gulf of Mexico registers below average Scope 1 CO2 intensity when compared to other regions, according to Rystad Energy analysis. The company estimates 13-14 kg CO2 emitted per boe produced compared to a global average of about 18 kg CO2/boe, said Sonya Boodoo, vice-president, upstream research, Rystad Energy. “The strong performance is particularly driven by newer deepwater developments which produce lower emissions from extraction and flaring operations relative to their legacy counterparts,” she told OGJ.
Barring divestments, Shell, bp, and Chevron are expected to continue to dominate the US Gulf of Mexico production landscape for the next decade, Boodoo said. These companies alone are expected to contribute roughly 50% of production in that timeframe, she said.
For Shell and bp, Boodoo continued, “divestments of oil and gas assets are likely in order for them to achieve their net-zero Scope 3 targets, but US Gulf of Mexico is an unlikely region for divesting due to its competitive performance both on costs and emissions.”
Rising production
Supply chain issues show signs of easing, but bottlenecks continue to impact the oil and gas industry, and inflationary pressures deepen the trend.
“Cost increases are hitting every category with double-digit inflation, from labor to subsea kit to production infrastructure. Drilling rigs are seeing the most dramatic increases in the US Gulf of Mexico, with average rig rates 50% higher in 2022 than 2020,” said Justin Rostant, principal analyst, US Gulf of Mexico upstream, Wood Mackenzie. The most dramatic increase, he told OGJ, was in pricing for the Aquadrill Offshore-owned Vela (formerly West Vela) drillship, with a 130% increase from 2020.
Despite these pressures, however, production from the US Gulf of Mexico appears steady and is expected to hit all-time highs over the next few years.
At this writing, 2022 year-to-date Gulf of Mexico production was 1.7-1.8 million b/d, about 100,000 b/d below 2019’s pre-pandemic levels and accounting for about 15% of total domestic oil production.
Driven in part by the April startup of the Murphy Oil Corp.-operated King’s Quay semisubmersible floating production system (Murphy 50%, Ridgewood Energy Corp. 50%) in Green Canyon Block 433 at 1,100-m water depths—designed to process 85,000 b/d of oil and 100 MMcfd of gas—2022 was a big year for new production.
Two projects that were also expected to boost 2022 production, the Shell-operated Vito (Shell 63%, Equinor 37%) and bp’s giant Argos semi-submersible floating production platform—to be used to develop Mad Dog Phase 2—are now expected to come online end-2022 at the earliest following startup delays, Wood Mackenzie’s Rostant noted. Argos, bp’s fifth platform in the Gulf of Mexico and the first new platform since Thunder Horse began production in 2008, will provide the operator with an estimated 25% increase in regional production. The platform, about 190 miles south of New Orleans in water depths of 4,500 ft, will operate through a subsea production system from 14 production wells.
“With the ability to produce at 100,000 b/d and 140,000 b/d, [Vito and Argos] respectively, we can expect 2023 production to exceed pre-pandemic levels and even hit a record high for deepwater production,” Rostant said.
These projects, together with others currently under development but not yet producing, will help maintain Gulf of Mexico production in the near term. The project pipeline also remains robust over the medium term, said Colin White, a Rystad Energy consultant and co-author of a recent Rystad Energy Gulf of Mexico report with Boodoo. “Over the next 3 years, Rystad anticipates at least one hub-scale investment, and more than 10 tieback developments will reach final investment decision [FID]. Production from these fields will help to arrest decline from legacy fields towards the 2030s,” he told OGJ.
Development
US Gulf of Mexico operators are leaning on subsea tiebacks and continually evaluating platform design, from a special-case repurposing to standardization and simplification.
“Frontier exploration has largely taken a back seat as hub-scale investments are largely seen as providing a low internal rate of return, being vulnerable to volatile price environments, and requiring extremely high capital commitments. Smaller tiebacks promise to reduce operators’ overall carbon footprints, fill existing infrastructure at risk of underutilization, and reduce overall capex tied to increasing oil and gas production; all persistent challenges for majors operating in the region,” White said.
“Projects are largely dominated by subsea tieback developments which are becoming the obvious choice among Gulf of Mexico operators as priorities have shifted to focus on leaner projects with smaller capital commitments and faster lead times, a trend that was already under way prior to the onset of the pandemic,” he continued. With a swath of under-utilized infrastructure across the deepwater Gulf of Mexico, “operators have chosen to employ an infrastructure-led exploration strategy focused on smaller prospects within a 30-mile tieback radius to their existing hubs,” he said.
In March, Shell started production from the PowerNap subsea development in the Mars corridor of Mississippi Canyon, about 150 miles from New Orleans. The oil and gas field is tied back to the Shell-operated Olympus tension leg platform (71.5%) in about 4,200 ft of water. Estimated peak production from the field is 20,000 boe/d.
In June, LLOG Exploration Co. LLC began producing from Spruance field, Ewing Bank (EW) Blocks 877 and 921. A two-well subsea development is producing about 16,000 b/d and 13 MMcfd gas via a 14-mile subsea tieback to the EnVen Energy Co.-operated Lobster platform in EW 873.
In May, Chevron sanctioned its operated Ballymore deepwater project (Chevron 60%, TotalEnergies 40%), which also lies in the Norphlet trend of Mississippi Canyon. With design capacity of 75,000 b/d of crude oil, Ballymore will be developed as a 3-mile subsea tieback to the existing Chevron-operated Blind Faith platform. First oil from the $1.6-billion project, which involves three production wells tied back via one flowline, is expected in 2025.
In September, Shell confirmed to Energy Intelligence it took FID to develop its Norphlet trend Rydberg discovery in Mississippi Canyon as a two-well subsea tieback to its Appomattox floating platform. With first oil expected in second-half 2023, the operator expects peak production of 16,000 boe/d.
With an eye toward hub development, LLOG is repurposing the decommissioned Independence Hub floating production unit (now Salamanca). The column-stabilized Salamanca FPS will sit in Keathley Canyon Block 689 in 6,400 ft of water to tap the Lower Tertiary Leon and Castile discoveries, LLOG said in a May release. The platform will have processing capacity of 60,000 b/d of oil, 25,000 b/d of water, and 40 MMscfd of natural gas. Three initial development wells are planned, two on Leon field and one on Castile field. Initial production from the joint development is expected mid-2025.
“LLOG was able to make an opportunistic acquisition of Independence Hub, re-christening it as Salamanca at an estimated cost of $600 million,” Wood Mackenzie’s Nance noted. “Though the topsides will have to be completely rebuilt, the cost savings will be considerable versus commissioning an entirely new 46,000-ton hull.”
LLOG points to standardization as one of its advantages, utilizing similar equipment, design, and procedures across multiple projects.
Looking at the entirety of the project and reviewing the decommissioned infrastructure, Eric Zimmermann, LLOG’s chief operating officer, told OGJ that the company “realized the location, water depth, and capacity were all good fits for a co-development of Leon and Castile.”
In an August release, the privately held company said the hull, topside truss, cranes, and lifeboats will be reused with minor modifications and that all other topside equipment, including piping, instrumentation, and electrical systems, will be new and fit-for-purpose.
Overall, the repurposing “positively impacts economics through a reduction of costs and diminishes the time to bring discoveries online,” Zimmermann told OGJ, and just as important, he said, is the “significant positive ESG impact through the reduction of emissions compared to the construction of a new platform.”
Both White and Nance note the refurbishing may be a one-off case. Another recently decommissioned hub meeting anticipated specification requirements conveniently docked at the original hull fabricator’s Texas Gulf Coast facility is…unlikely, said White.
And, unlike much of the Gulf of Mexico infrastructure, the Independence Hub’s production tenure was a short 9 years, ceasing production in 2015, White said, noting “many large operators are likely unwilling to bet on a decommissioned facility given inherent risks surrounding safety of aging equipment and modifications necessary to meet new regulatory requirements.”
Wood Mackenzie’s Nance also noted the lack of idle infrastructure for repurposing and pointed instead to moves by operators over the years towards more focused, purpose-built platforms. “While independents like LLOG have been operating in a cost-effective space for some time, Shell has also made substantial progress on this front with their extensive Vito redesign,” Nance said.
As part the project’s downsizing effort that began in 2015, Shell reduced Vito into the 39,000-tonne structure that exists today and realized a 70% cost reduction from the platform’s original concept. Then, last year, in announcing FID on the Whale deepwater development (Shell 60%, Chevron 40%), the operator outlined a plan to replicate nearly 80% of Vito’s four-column semisubmersible platform design. Scheduled to come online in 2024, Whale is expected to reach peak production of 100,000 boe/d.
Vito and Whale lie in contrast to Appomattox, the largest floating production system Shell ever built (Shell, 79%, CNOOC 21%). In water depth of 7,400 ft, the infrastructure consists of a semi-submersible, four-column production host platform, a subsea system featuring six drill centers, 15 producing wells, and five water injection wells. Weighing 125,000 tonnes, it’s larger than an aircraft carrier.
Standardized platform design is increasingly commonplace, with Murphy’s King’s Quay and LLOG’s Shenandoah project both utilizing an Exmar Offshore semi-submersible design previously used for the Who Dat and Delta House platforms, White said. The practice reduces front-end engineering and design and infrastructure capital expenditure commitments.
The steady pace of Gulf of Mexico projects coming online, while due in part to projects delayed by pandemic-related issues, is poised to continue, said Wood Mackenzie’s Nance. Exploration still lags, but companies continue to invest, innovate, and advance projects and many remain optimistic about the region.