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US GoM 2019 Summary: Part III – Production

US GoM 2019 Summary: Part III – Production thumbnail

Overall Annual Production

US Gulf of Mexico C&C production has had a series of peaks; firstly two from shallow oil, the middle acceleration probably caused by the mid seventies oil shock; followed by deep oil development and finally by ultra deep oil, with a dip in the middle from the Deep Horizon drilling hiatus. Most production has come from eastern and central (i.e. mainly Louisiana) with some, and falling, from the western section (Texas).

Natural gas production from shallow water (shelf) dry gas fields has been the largest single contributor to hydrocarbon production from the GoM, but it has now pretty much run its course. Two gas fields recently brought on-line in deep water were disappointments: Supertramp was a complete bust after the first month; Hadrian South (produced through Lucius) was produced hard for about eighteen months but was about only 70% as productive as expected. Infrastructure is being dismantled (i.e. offshore facilities, wells, pipelines, onshore gas plants) but some has to be kept to handle associated gas for the oil fields and can have impacts on production efficiency, such as the Enchilada pipeline and shutdown a couple of years ago.

Deep Water Details

Deep water (1000’ to 5000’ water) peaked in early 2000s but has recently been rising again, from brownfield work on two of the large basins (Mars-Ursa and Tahiti, which includes Caesar/Tonga), plus a couple of large, recent fields (Stampede, which is a stand alone floater and Kaikias, which is a fairly large field but is being produced as a tie-back to the Olympus platform in Mars-Ursa). Olympus was built to produce two fields, South Deimos and West Boreas but it appears that they peaked (maybe without achieving design rates) and declined fairly quickly (since 2014) so there was plenty of spare production capacity. PowerNap is another fairly large near field development that is due to be tied in there too, at 35 kbpd peak; Shell brought the start-up of this forward in late 2019 (maybe indicating Kaikias isn’t doing as well as expected, but that decision may now be reversed.

The ultra-deep developments (greater then 5000’ water depth) have been responsible for most growth recently. Initially several large fields were developed, Thunder Horse, Atlantis, Na Kika (a mixed oil and gas development), Mad Dog, Great White and Jack/St. Malo. Initially some of these had disappointing performance with reserve write-downs but a lot of brownfield development has kept them on long plateaus and increased estimated ultimate recoveries. After the 2014/2015 price collapse a series of smaller, fast declining tiebacks with fewer new surface facilities have been installed.

Now larger, stand-alone developments are coming on-line led by Appomatox, which is still ramping up. This was partly due to newer technology (e.g. 20 ksi drilling and wellhead equipment), partly in a fall of development costs along with the price drop and partly from an expectation, plus some fast tracked near field discoveries. In retrospect possibly misguided, in a recovery of prices. New on-going platform developments include Vito, Kings Quay, Anchor, and Mad Dog II, I don’t know how long these may be delayed  given the current size of impairments and CAPEX reductions being announced by E&P companies.

There appears to be fewer opportunities for tie-backs (Taggart and Oarse are due this year) and brown field expansion (Atlantis III is a large current development) probably because they were mostly used up after 2014 and will reappear when some newer areas have operating central hubs. There are a few other large discoveries under conceptual appraisal (Whale, North Platte, Ballymore) but I doubt if many FIDs or further appraisal drilling will be made this year.

Note that I am not very consistent in the way I group fields, for example Who Dat (Deep) is a processing facility for Longhorn and Apaloosa fields but I’ve showm Odd Job, Rigel (aka Neidermeyer), Son of Bluto 2, Marmalard and Otis (not named on chart) as individual fields processed through a twin facility: Delta House.

Recent Overall Production

It is maybe interesting that the production seems to follow a step pattern – flat for a couple of years then a step up over three to six months. This is not apparent from the smoothing in annual average number. It may be, after some struggle, this could be correlated to oil price at some previous period. It all seems to come from the larger fields and so, if nothing else, it’s likely indicative of the groupthink that pervades most majors (same models, same decision processes, same mindsets). It could also be to do with preferred maintenance and installation periods, though I don’t see it lining up like that – certainly not as much as it would in the North Sea, say.

Shallow C&C and total natural gas production have been steadily declining but both recovered a bit in 2019. The more mature small and medium deep fields where falling fast with a step down when the Enchilada went off-line but grew significantly in 2018 and 2019, but now seems to be showing accelerating decline.  The major IOCs tend to operate the larger deep fields, the more mature of theses have been holding steady. Most of the growth has come from recent start-ups (more details below).

Note that the obvious recent declines they are not quite as dramatic as shown as some numbers are delayed especially on recent start-ups (this may amount to 100 kbpd for April, but much less for earlier months).

Drilling Activity

BOEM reports active and inactive drilling and work-overs by well each month. I’m not sure how this is done – e.g. if it’s a snapshot of activity on a particular day as Baker-Hughes does, but if so active drilling number should approximately equal the total number of rigs, whereas it is actually less than a quarter. Nevertheless the total numbers have been falling generally in-line with each other. The numbers show a rapid decline recently but they are usually revised upwards in later reports so will not be quite as dramatic as shown.

Baker-Hughes rig count fell dramatically through 2014 and 2015, all from a net loss of shallow wells, but then held fairly steady, at around twenty to thirty, until this year when the pandemic has halved the number, with shallow drilling down to only a couple of rigs and no gas drilling at all.

Currently, by the BSEE deep-water weekly activity report, there are nineteen rigs operating, nine are for Shell, three for BP and two for Chevron. I think the majority of these are on fields that are ramping up (Appomatox and Big Foot) and/or where there is a platform rig rather than MODUs (e.g. Mars-Ursa has three operating). There are still three exploration wells (for Shell, Total and LLOG) and at least one appraisal well (for Galapagos with BP).

C&C Production Details

Mars-Ursa is a large basin with three major production platforms (Mars, Ursa and Olympus), which were originally. It is shown here because Olympus was started in 2014 serving two new fields: South Deimos and West Boreas; it is difficult to separate it’s production from earlier fields. The other fields shown that were already flowing in 2014 had significant new fields or in-fill drilling added.

Gunflint, Big Bend and Dantzler are tied back to the Thunder Hawk platform; Rigel, Marmalard, Son of Bluto 2, Otis, Odd Job, Blue Wing Olive, Red Zinger and Nearly Headless Nick to the Delta House FPS; Dalmatian to Petronius Tower; Julia to Jack; Barataria and South Santa Cruz to Blind Faith; Crown & Anchor to Marlin; Hadrian South and Buckskin to Lucius; Kaikias to Ursa; Constellation to Constitution Spar; and Stonefly to Ram-Powell.

The larger platforms (usually run by major IOCs) has have held a combined plateau, may now be under accelerating decline although Atlantis III which  is due soon, may hold it a bit longer – this is really a false conclusion because it is a new (deeper) discovery rather than brownfield developments of growth in original reserves. There have been some significant brownfield projects, e.g. Thunder Horse South and water injection, Tahiti Vertical Extension and Caesar/Tonga Phase II.

The mature deep fields (only the larger are named on the chart) have been in decline but recovered in the last couple of years. Partly due a bounce back after the Enchilada restart, but the decline appears to be accelerating now.

Shallow production has been generally declining but was held on a plateau for the last couple of years, I suspect mostly from in-fill drilling but possibly also through control of the water cut. The decline now seems to be accelerating again (as is usual when production is accelerated through brown field work).

Production by Field Size

Most of the production and almost all of recent growth has come from the larger fields (based on size of the original reserves in equivalent oil barrels shown in mmbbls o.e.). Even as the C&C production has increased the proportion from ultra deep-water wells has been increasing faster.

Off Topic Finish: Canadian Drilling

Canadian rig counts have been steadily declining over the last decade for all months through the year. Much of this is because of the rise of long life cycle oil sands projects and the decline of faster declining conventional onshore wells. The price crash in 2015 produced a bigger step down and this year the Covid-19 lockdown has meant there has been no post frost thaw recovery.

The frost thaw period has got noticeably earlier by one or two weeks, presumably because of the accelerated warming especially in the permafrost regions. I’d have thought the thaw pause would have ended earlier too, but it seems to be getting longer, maybe because of the overall drop in drilling or because the area for drilling has been changing (presumably moving north). Alternatively the warming may mean the frost heave penetrates deeper and lasts longer.

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