The U.S. Gulf of Mexico might best be dubbed ‘Old Reliable’.
It’s been churning out hydrocarbons since 1947 when the first well drilled from a fixed platform out of sight of land marked the debut of the offshore oil and gas industry.
Derided as the “Dead Sea” a number of years ago during one of the industry’s infamous bleak periods, diminished activity at the time eventually did a “180” and just keeps on going even today.
The region’s crude oil production is estimated to increase to record high levels in 2017 despite record low prices, according to the U.S. Energy Information Administration’s Short-Term Energy Outlook, February 2016.
The numbers are impressive.
The government agency projects that federal GOM production will average 1.63 MMbpd in 2016 and 1.79 MMbpd in 2017, reaching 1.91 MMbpd in December 2017. In all, the area’s production is expected to account for 18 percent and 21 percent of total forecast U.S. crude oil production in 2016 and 2017, respectively.
Offshore GOM production has little in common with its onshore counterpart.
In the Lower Tertiary deepwater activity, for example, both water and reservoir depths are a considerable challenge to drilling and production.
Look at Chevron’s Jack/St. Malo program where the tension-leg platform is positioned in 7,000 feet of water with some target reservoirs sitting many thousands of feet beneath the seafloor.
This is a typical scenario for the region, a testament to why such projects move at a virtual snail’s pace, often spanning several years between discovery and production.
Over the course of evaluating, planning and constructing these massive, high cost, long term projects, short term oil price gyrations are relegated to the back burner, as opposed to onshore, where producers must keep a wary eye on such price movements.
Even so, the EIA noted that current decreasing profit margins and lowered expectations for a quick oil price recovery have convinced many GOM operators to scale back on future deepwater exploration spending, reduce their active rig fleet by scrapping and stacking older rigs, and either restructure or delay drilling rig contracts.
As a result of these actions, there is increased uncertainty relative to the timeliness of a number of GOM projects. Those in the early stages of development are at the greatest risk of delay or cancellation.
The EIA noted that eight fields came online in the GOM during 2015. All except one was developed as a subsea well tied back to production facilities nearby. Using subsea tiebacks, producers can reduce project costs as well as start-up time.
The lone exception was Anadarko’s Lucius field, which spans several blocks in the Keathley Canyon area in 7,168 feet of water about 180 miles off the Louisiana coast.
Lucius produces oil via a truss spar, which is a type of floating production platform that supports drilling, production and storage operations. Designed to provide increased stability in harsh offshore circumstances, this spar is the largest in the Anadarko fleet.
The company’s Heidelberg field in 5,271 feet of water started production in January 2016, producing at a spar using the same design as the Lucius, according to the Environmental Protection Agency. Heidelberg is in the Green Canyon Block 159, about 140 miles offshore Louisiana.
In contrast to Lucius and Heidelberg, production at Shell Oil Co.’s Stones field in 9,556 feet of water in the Walker Ridge area about 250 miles southwest of New Orleans will utilize the first floating production, storage and offload (FPSO) vessel in the GOM, the EIA noted.
FPSOs enable development of complex fields with unique reservoir properties and no existing infrastructure.
Crude produced at the Stones complex will be transferred to tankers for transport to some of the myriad U.S. Gulf Coast refineries.
Two additional fields anticipated to begin producing in the deep waters of the GOM in 2016 are subsea tiebacks as well as a couple of fields slated to begin producing in 2017.