Release Date: September 11, 2024
STEO Perspectives: EIA expects flat oil and natural gas production from the Gulf of Mexico after model update
We recently implemented a new model for forecasting crude oil and natural gas production from the U.S. Federal Offshore Gulf of Mexico (GOM) in the Short-Term Energy Outlook (STEO). Our new approach combines analysis of well-level historical production data with upcoming field developments to provide a more detailed outlook for the region.
Data values: U.S. Petroleum and Other Liquids Supply, Consumption, and Inventories and U.S. Natural Gas Supply, Consumption, and Inventories
Our shift to modeling production at the well level improved representation of production dynamics from both existing wells and new developments, improving assessment of infrastructure downtime on GOM production, and adding more robust analysis of factors that influence regional production trends. We first implemented these changes in our August 2024 forecast.
We also added new qualifiers that allow us to group the wells according to the floating production units (FPUs) associated with each well, field, block, and formation from which the wells will produce. The capability to group by well supports more granular analysis of production limitations such as platform-level production capacity and planned maintenance events. By characterizing production by formation, we can analyze production trends by formation and gain insight into the effects of future developments.
In our latest outlook, we forecast that 1.8 million barrels per day (b/d) of crude oil will be produced in the GOM in 2024 and 1.9 million b/d in 2025. We expect GOM natural gas production to average 1.8 billion cubic feet a day (Bcf/d) in both 2024 and 2025.
The Federal Offshore portion of the GOM accounts for about 97% of all U.S. Outer Continental Shelf (OCS) production, as some production in the GOM falls within state maritime boundaries. The crude oil and natural gas forecast volumes for the Federal Offshore GOM are in the Western and Central Planning Areas, as defined by the Bureau of Ocean Energy Management (BOEM).
As of September 2024, BOEM managed over 2,300 active oil and natural gas leases on approximately 12.5 million acres in the Federal Offshore GOM. Most active leases are in the Central Planning Area directly south of Louisiana, Mississippi, and Alabama.
About 94% of the GOM crude oil production and 80% of GOM natural gas production came from deepwater wells in 2023, according to BOEM. BOEM considers water depths greater than or equal to 1,000 feet to be deepwater.
Deepwater fields make up an increasing portion of Gulf of Mexico production
Data values: Deepwater Production Summary
Deepwater crude oil has accounted for most of total GOM production since 2000 and has been the main contributor in the rise of GOM crude oil production since the mid-1990s. Most deepwater fields are crude oil fields, as deepwater natural gas reservoirs have been uneconomic to develop.
As a result, deepwater natural gas production is predominantly associated natural gas production (production of natural gas from crude oil fields), which explains why natural gas production in the GOM has declined as production has shifted to deepwater fields.
Crude oil production is modeled using well-level historical production
We forecast GOM crude oil production from existing wells using automated decline curve analysis on all actively producing wells. Decline curve analysis is a method that forecasts future production from individual wells using data from existing wells.
Our model uses well-level historical production data from the Bureau of Safety and Environmental Enforcement (BSEE) for over 3,000 wells as well as each well’s expected decline. In contrast, our previous approach used field-level averages.
New expected fields incorporate facility capacity limits
We base our GOM crude oil production from newly developed fields and fields that have not begun producing on publicly available information from operators, including the anticipated timing and magnitude of production, ramp-up of production, and plateau rates. Operator information often includes FPU production capacity limits and expected resource recovery estimates.
Data values: Gulf of Mexico Permanent Deepwater Structures and EIA analysis of trade press reports
We expect 12 new fields to start production in the GOM during 2024 and 2025. Seven fields will be developed using subsea tiebacks, or underwater extensions to existing FPUs at the surface. Five fields will produce from four new FPUs, with one of the new FPUs (Salamanca FPU) targeting production from two fields. We expect that fields starting in 2024 will contribute 22,000 b/d of crude oil production in 2024 and fields that start production in 2024 or 2025 will contribute 231,000 b/d in 2025 as additional production comes online and ramps up.
Three new subsea tiebacks began producing earlier this year: the Rydberg field started producing in February as a tieback to the Appomattox platform, the Winterfell field started production in July as a tieback to the Heidelberg platform, and Pickerel started producing in July as a tieback to Tubular Bells. We expect these tiebacks combined will contribute an average of 11,000 b/d in 2024 and 42,000 b/d in 2025 after ramp-up.
A new FPU handling the production from the Anchor field, a deepwater high-pressure field located at a water depth of 5,000 feet with reservoir depths around 32,000 feet, started production in August. The Anchor FPU has a nameplate capacity to produce 75,000 b/d of crude oil and 28 million cubic feet per day (cf/d) of natural gas.
Technological advancements in high-pressure and high-temperature drilling and production equipment and the subsequent BSEE guidance and regulatory approval enabled the production of deepwater resources starting in 2019. These advancements aided the development of deepwater projects in formations in the Lower Tertiary/Paleogene and Upper Jurassic Norphlet play.
The largest field that is expected to come online at the end of 2024 is Whale, which will produce from a new FPU of the same name. Whale is expected to produce around 85,000 b/d, after ramp-up, in 8,600 feet of water. We expect other subsea tiebacks and facilities to enter production in late 2024 and 2025, with a combined production potential of more than 56,000 b/d in 2025, including Dover, Ballymore, Castille and Leon, Sunspear, Shenandoah, and Colt (Buckskin South).
Most of the natural gas production is associated gas
The natural gas produced in the GOM is predominantly associated gas, or natural gas that is produced from crude oil reservoirs. Therefore, our GOM natural gas production forecast is largely based on a ratio to crude oil production. For each well, the ratio of natural gas to crude oil produced (also known as the gas-oil ratio) remains relatively constant. We average the previous six months’ gas-oil ratio for each well and apply this average to the well’s crude oil forecast to determine natural gas production.
We expect the new fields of 2024 and 2025 will contribute about 15 million cf/d of natural gas production in 2024 and 173 million cf/d in 2025. The gas-oil ratio for total GOM production is expected to average about 1.0 million cubic feet of natural gas per thousand barrels of crude oil in 2024 and 2025.