BOEM has March 2018 production at 1696 kbpd, which is down 1 percent month-on-month and 4 percent year-on-year (March 2017 was the peak production month for GoM so far). EIA numbers were very similar, although last month’s were higher and haven’t been revised yet – typically EIA numbers end up almost exactly corresponding to the BOEM reported total qualified lease production, whereas BOEM can be a little higher, maybe including test wells or non-qualified leases. Natural gas production in the U.S. Federal Gulf of Mexico (GOM) has been declining for almost two decades.
EIA expects nine new natural gas production projects to start in 2018 and another seven to start in 2019. The major new project, Stampede, started in January, has no reported production numbers yet. BOEM and EIA estimate non-reported values and then retrospectively adjust their reports when actual numbers are available. The GOM marketed natural gas production has been mostly declining on an annual basis since 1997, when EIA first recorded this data. I don’t know how they estimate new production, but Stampede could produce around 60 kbpd with current plans, though likely a lot less initially as only one of two leases has been ramping up. I’ve assumed 20 and 40 kbpd for February and March respectively, which still might be high. Even allowing for that, and assuming other late numbers are the same as the previous month, since December EIA and BOEM both have estimates about 30 to 40 kbpd higher than the reported lease and well production numbers (which always match closely) would suggest.
Usually the difference is no more than ten. It is unlikely that the other late numbers, of which there are few, and none for all four months, will show such large, sudden and unexplained increases so either I’m missing something (maybe a lease not yet included in the numbers, but also not reported as starting up) or there could be some future downward adjustments. In 1997, production stood at 14.3 Bcfd, accounting for 26% of the United States’ total annual marketed natural gas production. Rigel and Otis are still off-line following the failure at a subsea manifold last October and are taking out about 22 kbpd plus some gas (Otis is a small gas field). Great White, Stones (for the full month) and Caesar/Tonga all had noticeable downtime in March taking about 90 kbpd off-stream.
By 2017, natural gas production in GOM declined to 2.9 Bcfd and accounted for only 4% of the total U.S. annual marketed production. The Kaikias Phase I development for Shell, a tie-back to the Ursa hub, was brought on line one year ahead of schedule in early June. It has an expected peak nameplate of 40 kboed (which may only be around 30 kpbd average oil) and will likely take a bit of time to ramp up to maximum. The number of producing natural gas wells in the GOM declined by 73% between 2001 and 2017—from 3,271 to 875. The technology and expertise required to produce oil and natural gas from the seabed is expensive and specialized, and costs of production platforms often exceed a billion dollars. Equally to accelerate production like this probably meant using a drill rig that was previously scheduled for alternative wells on Mars-Ursa, so there may be faster than previously planned decline on some of the other leases there.
In the second quarter there is likely to be downtime showing for Marlin, Horn Mountain and Holstein as they have planned turnarounds to prepare them for new production and, presumably, to allow normal maintenance; they should then come back online with higher overall flows. Marlin has one new Anadarko well planned, plus two from LLOGs Crown and Anchor field. Holstein has a platform rig and is developing four side-track wells this year and next. Horn Mountain has one more tie-back from Dorado field planned. With the growth in exploration and production activities in shale gas and tight oil formations, it became more economic to drill onshore in these basins. Atlantis has no drilling or work-over activity currently shown and in the past its wells have declined at around 20 percent year-on-year (see below), which may continue until the first Phase III wells come on line in 2020.
Llano, Cardamom and some of Baldpate/Salsa production came back on line following the partial repair of the Enchilada pipeline, adding around 45 kbpd, but there is some still off line, which I think has to be processed through the Enchilada platform and for which I’ve seen no expected restart news; however Anadarko have said it will be “later this year”, which I’d take to mean a few months yet. The BSEE deep-water activity report showing wells with drilling, completion, P&A or work-over activity currently shows 40 actions, this is down from around 50 at the beginning of the year and has been fairly steady for the past two months. In addition, most of the natural gas produced in the GOM is associated-dissolved (AD) natural gas produced from oil fields, and although older oil wells in the GOM tend to have higher natural gas content, newer wells are more oil-rich, resulting in less AD natural gas per well. Overall C&C looks to be continuing an overall slow decline started in the second half of last year, and if the unaccounted for 40 odd kbpd is revised out, then it is clearly accelerating. A lot will depend on downtime for turnarounds and hurricanes. So far this year these losses look higher than last (e.g. the early Tropical Storm Alberto took out about 7 kbpd for about a week, and also disrupted P&A activity on Lena and installation work at Appomattox) plus Mars-Ursa looks set for a partial shut down in April and the current Perdido / Great White turn around looks to be quite prolonged.
According EIA’s Natural Gas Annual, 59% of gross withdrawals of natural gas in the GOM were from oil wells in 2017. In 1997, however, only 13% of gross withdrawals were of AD gas co-produced with oil. Another major unplanned outage, like Enchilada or Delta House, is also possible. The Kaikias development by Shell has been advanced, but that may be countered by delays to Constellation, Hadrian North and some Delta House tie-backs. Natural gas production is in continuous decline. BOEM had March production at 2.59 bcfd, down 1 percent month-on-month but 21 percent year-on-year. The loss of 300 mmcfd from Hadrian South since last year and the losses from Baldpate / Salsa, one of the few other remaining significant gas fields, and Otis, because of the Delta House failure, meant last year showed accelerating decline which is unlikely to recover. Na Kika has a few gas leases, and a new long distance tie-back, Coulomb II, is due soon, but mostly the gas now is associated with the oil and will decline accordingly.
In 2016, all new projects in the GOM occurred in the Mississippi Canyon and Green Canyon protraction areas, located in the Central GOM planning area, and had an average depth of 4,283 ft and total resource level of 1,429 Bcf. Based on the data provided to the Bureau of Safety and Environmental Enforcement, no new GOM projects started up in 2017. Most of the fits came out reasonably well. Six of the largest fields are shown in detail below.
The overall (stacked) decline curves indicate the expected decline rate for all the wells remaining online, they are not predictions of future production. The fields where the fit was poor were either new projects that are still on plateau, have had fairly patchy start-ups, or have produced a lot of water (or all three) and include Lucius, Stones and Odd Job; or ones where there has been some sort of well rework, e.g. K2, which had gas lift added, and Mad Dog, which had various new measures including water injection added on some blocks. I didn’t include Na Kika as it is a collection of several different fields, some of them gas, and has a pretty uneven production history. The individual decline rates for each field are shown in parentheses after the name and run from 0 percent for fields on early plateau, up to 40 percent and with a pretty good spread between.
For 2018-2019, nine of the 16 projects are located in Mississippi Canyon and Green Canyon protraction areas. Three projects in Garden Banks, West Cameron, and Keathley Canyon are also part of the Central GOM planning area. The decline rate for the fields analyzed is likely to increase because of new projects coming off plateau, water breakthrough or acceleration (e.g. at Great White, Mad Dog, Lucius and Mars-Ursa might be the most likely) and a normal development feature that the best wells are drilled first; but overall that would likely be balanced by new projects reaching plateau. The overall average decline rate came out as 16 percent, which is maybe not surprising given that depletion rate for the whole GoM based on BOEM 2P numbers for 2016 (the latest available data) was also 16 percent.
With depletion and decline close it would imply there isn’t much being added to reserves on operating fields, or any that has been was quickly put on-line. Applying these decline rates to the 2017 field production rates gives an expected drop this year of 175 kbpd. Shallow fields are likely to decline 30 kbpd and the deep-water fields that I didn’t include about 45 kbpd. So total would be 250 kbpd; assuming 90 percent availability that would require 275 kbpd of additional nameplate capacity added to hold production steady. Average project depth is expected to be 4,544 ft in 2018 and 5,585 ft in 2019.