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Has Gulf Of Mexico Production Peaked?

Offshore

Gulf of Mexico Production

Production for May by BOEM was 1673 kbpd and by EIA 1661, compared with 1661 and 1658 kbpd, respectively in April.

March looks like the peak, at least near term, for the basin, especially with Hurricane Cindy impacting the coming June figures.

(Click to enlarge)

The combined new fields added from late 2014 look to be peaking as well. Great White came back on line but xxx and yyy declined. In previous data I had omitted one big producing lease in Mars, which included the new Deimos field. With this added the production growth through 2017 is higher (and as shown later the decline in mature fields faster) than previously shown. There may be more increase to come: The Mars leases had three rigs operating through June, one dedicated for Deimos, which has now gone. The two platforms on the field each have a dedicated platform rig, so they can continue with in-fill drilling and workovers as they wish. The Kaikias development will be tied into the Olympus TLP on the Mars field in 2019, but it’s a subsea tie-back so would need a separate drilling rig. The facility has nominal capacity of 100 kbpd, but that might be limited by the platform wells and manifolds rather than production trains – if not then Shell must be expecting some decline before Kaikias comes on line.

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Stones start-up is still not looking good with an 8 kbpd fall – Shell are taking over the operation from SBM by buying the FPSO instead of leasing. Maybe this indicates poor operating performance (if so it’s something for ExxonMobil to be concerned with as they are following the same approach with SBM for Liza), or maybe just a convenient scapegoat. Julia, Cardamom, Stones, Jack and Lucius still have active drilling programs so may have opportunity for growth. Julia had plans for subsea multiphase pumping, I don’t know if that is operating or will be brought on as pressures fall.

Production from the South Santa Cruz and Barataria fields started in mid-June (actually part of Fourier and East Anstey fields by BOEM naming). The first Horn Mountain Deep well, for Anadarko, started production in April, a second well is due to be spudded this quarter. These are the only new fields announced for this year. Anadarko was the only company that had hinted they may develop something else (e.g. with Warrior and Phobos tie backs), but with them slashing budgets for 2017 after poor second quarter results that is now be unlikely: in their investor presentation, they indicated they expected flat production out 3 to 5 years, and didn’t sound particularly confident of that to me, and with no mention of Shenandoah so that might be on the way to full cancellation. One new lease in the Marmalard field (the last there) for LLOG was started in late May.

I’ve added natural gas production for the new fields here. Hadrian South and Otis are the only dedicated gas fields. Hadrian South production is a big proportion of the gas total from GoM now. It produces to the Lucius Spar, operated by Anadarko, and according to their investor presentation Hadrian South is supposed to finish by about 2021. I’m not sure if that can be correct, but if so it’s production should be declining significantly soon. Also on Lucius, its biggest producing lease, really part of Hadrian North field, started showing a sudden water cut increase in May, and dropped about 8 percent production (for some reason this does not show up in BOEMs list of qualified fields, but it is definitely tied in to Lucius). The first lease on the Lucius field has been killed in about two years with water break through; it’s not clear what their plans are for it (this is Anadarko as well).

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A couple of leases in Na Kika look like they have gone off line so production is down. Thunder Horse numbers were revised and now clearly show the impact from South Thunder Horse with about 35 kbpd increase. There have one rig still operating, but I think they will just maintain plateau now. Atlantis looks to be running about at nameplate capacity, so the coming North Atlantis development is likely only to be able to extend the plateau; there is one rig operating there now.

(Click to enlarge)

(Click to enlarge)

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For the Caesar/Tonga/Tahiti fields the Anadarko facility (Constitution Spar) went off line taking off 40 kbpd production (Ticonderoga and Constitution fields go there too). The turnaround was for 42 days so will reduce June figures too. The Constellation field is to be tied into the spar next year, the spar has nominal nameplate of 70 kbpd so another 25 or so (average) might be added to overall output.

(Click to enlarge)

For the Chevron fields in these leases it looks like production is limited by the gas handling capacity on Tahiti platform, at 70 mmscfd, which is pretty low given its oil capacity of 125 kbpd.

(Click to enlarge)

After a bit of a plateau from some brownfield work and new tie backs the decline in the larger mature fields looks like starting up again; the drop in gas is particularly noticeable, but is mostly due to Baldpate turn around. Overall water cut looks like it might be rising as well. Thunder Hawk has two new rigs operating, but I haven’t seen any announcement for new developments there. The smaller mature fields (not included in the charts) seem to be holding up quite well, I will try to get some individual lease data for these next month.

(Click to enlarge)

(Click to enlarge)

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For the GoM activity report from the last week in July, there were 28 rigs drilling, twelve running tools and two in plug and abandon operation. I think the report can mean there is dual activity on a single well (e.g. wire line and drilling). Two rigs are predrilling on Stampede, one on Appomattox and one on Mad Dog II. For the newer fields, there is development drilling on Lucius, Cardamom, Mars (two rigs), Stones, Julia, Jack / St. Malo, plus new wells for recently added or due production on Horn Mountain Deep and South Santa Cruz/Barataria. Atlantis also has a new rig, which may be for development of the Atlantis North discovery – it’s noticeable how any reasonable discovery is immediately fast tracked, the North Sea is similar. The Dorado field (operator Anadarko, discovery in 2014) is also being drilled; I think it is one of the last of wells for small fields (King, Dorado, Holstien Deep) being tied back to Marlin, there’s probably one more for King and a couple of others possible. Only Phobos has appraisal drilling.

Five rigs are drilling on unnamed fields, so presumably exploration – four of these are in Green Canyon, which means they are near field, and probably smaller, prospects; the other one is for Shell, in Walker Ridge, and probably a frontier wildcat. With all the predrilling on new fields, most new fields reaching plateau or decline periods, and few exploration wells (and fewer still in frontier regions) it seems likely that the drilling numbers will tend to decline over the next few years as unused well slots and tie back locations on the facilities are exhausted, even with an increase in oil price.

In the past few months as production rose the EIA STEO showed a new production forecast which had the same shape but was just raised to start on the new production number. They didn’t do the reverse as the production fell but instead kept the June STEO forecast with a single dip down for April. The August STEO, showing May data, is due next week.

Gulf of Mexico Lease Sales

As further support that the current decline in exploration is not just a function of price, the chart below shows the acreage of GoM leases that have been successfully auctioned, plus the percentage of offerings that were taken up (charts are stacked according to BOEM designated production areas to the give total). The numbers before about 1976 are listed against states (FL, LA, TX) and I think are inshore shallow leases, although it might be they just changed naming convention. After about 1990 areas were split from just GOM to east, central and west. The percentage bought calculation only considers the area auctioned after 1990. It is marked how the amount bought and the percentage bought both peaked and rapidly dropped off, even in the high price years through to 2014. However, there were obvious impacts from earlier price collapses in the late nineties and 2008.

(Click to enlarge) Related: The Secret Behind Better Oil Major Earnings

It’s possible to read too much into these charts but generally it looks like, on average, discoveries follow three or four years behind the lease sales and production about the same length after that. But the recent production rise isn’t in that pattern – maybe disrupted by the 2008 recession and 2010 drilling hiatus, or maybe the high oil prices after 2011 allowed some difficult and expensive long-term discoveries to become commercial.

(Click to enlarge)

The number of open, undeveloped leases is relatively few, and declining. The chart below shows the number of leases discovered (and not terminated without development), producing or in development, and those still undeveloped. The open bars show my guesses for some larger fields that seem likely to be approved soon (e.g. Vito, Anchor). Most of the undeveloped leases (in yellow) are associated with existing, fairly recent, fields on production (e.g. St. Malo, Tubular Bells (and are likely to be poorer wells, waiting on surface facility capacity to become available before being tied in. There are two new field discoveries this year: Mormont and Khaleesi, by LLOG in Green Canyon (they have switched from Animal House to Game of Thrones naming convention) and are likely to be smaller reserves similar to their Delta House developments.

(Click to enlarge)

There is one area that might be expanding: deep shelf pre-salt. These are deep or ultra-deep wells but in shallow water (this is a rare combination and hence one problem is that there aren’t many rigs – jack-ups – that are suitable). W&T brought on Mahogany field this year, in an already producing lease (one well at 5000 boed with up to three others due, although the production data suggests it wasn’t as great as expected) and there may be more to come. The production is high pressure and high temperature, and in places can be too high for the available technology or commercial development, and mostly gas prone.

By George Kaplan via Peak Oil Barrel

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