Through 2021 the federal waters of the northern Gulf of Mexico (OCS) have cumulative production of 23.4 Bbo and 193 Tcf. The deepwater (water depths > 1000’ as defined by BOEM) has produced 10.2 Bbo and 23.5 Tcf while the shelf has produced 13.2 Bbo and 169.5 Tcf. From a BOE standpoint, the GOM has primarily been a gas province, and the bulk of that production has come from shelf fields. While the shelf has produced more cumulative oil than deepwater, over 90% of current oil production comes from deepwater fields.
First production from the OCS occurred in 1947. First deepwater production was in 1979 from Shell’s Cognac field in 1022’ of water. GOM oil production in December 2021 was 1.69 mmbopd as per BSEE. As Ovi says in his monthly updates, if GOM were a state, it would be the 2nd leading oil producing state in the US, only behind Texas.
Brief history of GOM gas production
GOM gas production peaked in 1997 at 14.4 bcf/day and has been declining ever since. Current gas production is about 2 bcf/day.
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Figure 1 – GOM gas production, with shelf and deepwater broken out. Data from BOEM.
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Figure 2 – US gas production (EIA data) with breakout of GOM (BSEE data) and Texas (EIA data).
One of the more significant seismic advances occurred in the late 70s-early 80s. This is when geophysicists recognized that a gas accumulation can often generate an anomalously high-amplitude seismic response, or a “bright spot”. Intentionally looking for bright spots, and high grading prospects based on bright spot quality was a big contributor to the abundance of gas produced in the 80s, 90s and 00s.
Also, 3D seismic became more and more common from the late 80s onward to where now almost the entire GOM is blanketed with 3D surveys. Any current drilling activity is supported by 3D.
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Table 1 – 30 largest gas fields in the GOM through 2019. Data from BOEM.
The table above shows the 30 largest gas fields in the GOM through 2019. 29 have cumulative gas production over 1 tcf. 27 are on the Louisiana shelf, 1 is on the Texas shelf and 2 are in deepwater. 24 are classified as gas fields and 6 as oil fields. The field with the largest remaining gas reserves as per BOEM is actually a deepwater oil field, Shell’s massive Mars-Ursa complex.
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Figure 3 – Map showing the distribution of the 30 largest gas fields in the GOM. Numbers refer to fields in Table 1. Many of the protraction areas are labeled. The shelf protraction areas all have “south additions” which are not labeled (e.g. Ship Shoal area, south addition is south of the labeled Ship Shoal protraction area.)
The map above shows the 30 largest GOM gas fields. Many of them are located on the Louisiana shelf. The thickest sediment accumulations in the GOM occur in this area. I suspect the burial depth of the source rocks has contributed to the gas abundance in this area – meaning the source rocks are buried deeper than the oil window, into the gas window. In addition, there also are numerous shallow biogenic gas accumulations that have been produced.
In conclusion regarding gas: Will current high natural gas prices cause a resurgence of gas drilling in the GOM? Maybe a bit, but nothing too substantial. I just don’t think the geology supports it. One interesting thing to consider though, is that there is a deep shelf gas exploration play that never really took off before prices crashed. Perhaps this will be revisited.
Update on GOM oil production
Figure 4 shows GOM oil production, with shelf and deepwater broken out. Deepwater production surpassed shelf production in 2000, and it has been dominant ever since. Based on these trends, I predict in 2027 or so deepwater cumulative oil production will exceed shelf cumulative oil production.
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Figure 4 – GOM oil production with shelf and deepwater broken out. Data from BOEM.
Table 2 shows the 30 largest cum oil fields in the GOM, with production through 2021. 12 of the fields are in the deepwater and 18 are on the shelf. Shell’s Mars-Ursa complex is by far the largest field, but it includes multiple fields. In BOEM’s accounting, they have combined a number of additional deepwater fields including Tahiti and Caesar-Tonga, and King and Horn Mountain.
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Table 2 – 30 largest GOM oil fields. Data from BOEM. Estimated reserves are mine – determined by subtracting 2020 and 2021 production from BOEM’s yearend 2019 reserves.
Figure 5 shows the distribution of the 30 biggest GOM oil fields. Note how a great number of the shelf fields are concentrated just offshore southeast Louisiana over to the Mississippi River delta. These fields are associated with, and adjacent to, the Terrebonne trough. This prolific oil trend continues into the onshore and state waters portions of southeast Louisiana and is one of the sweetest of sweet spots in the greater GOM basin. 12 of the 30 biggest GOM fields are in this trend with cumulative production of over 3.6 BBO, and this doesn’t include the onshore or state waters fields, or the numerous smaller fields. (Technically, the east edge of the Terrebonne trough is roughly the west edge of the Mississippi River delta. For this discussion I’m extending further east to include the Main Pass fields.)
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Figure 5 – Map showing the distribution of the 30 largest oil fields in the GOM. Numbers refer to fields in table 2.
Gulf of Mexico oil producing sweet spots
As one can see from the 2 maps above, there are some patterns to the distribution of both the biggest gas fields, and the biggest oil fields. They are not uniformly distributed around the offshore GOM basin. I define a Tier 1 oil sweet spot in the offshore Gulf of Mexico as an area that can be described geologically as having numerous petroleum system element similarities (such as similar structural styles, similar age reservoirs and probably a common source rock) and where the cumulative oil production, or anticipated cumulative oil production, has exceeded, or can be reasonably expected to exceed, 2 billion barrels. A Tier 2 sweet spot can be expected to have cumulative production between 1 and 2 billion barrels of oil
The previously discussed Terrebonne trough is a Tier 1 sweet spot. Cumulative production from just the biggest fields is over 3 billion barrels. It is very mature and future production will be, in my opinion, negligible. 12 of the 30 biggest fields are in this trend, and they have estimated remaining reserves of 44 MMBO. Many of these fields are salt dome related, reservoirs range in age from shallow Pleistocene to deep Miocene, and most of the pay is normally pressured. Production from this trend began in the 1940s.
The remaining Tier 1 sweet spots are in deepwater. One is the subsalt Miocene trend of southeast Green Canyon. Cumulative production from this trend is 1.9 Bbo. Production from this trend started in 2005 when Mad Dog and K2 came on line. BOEM’s remaining reserves for these fields is 692 MMBO. Four of the biggest GOM fields – Tahiti-Caesar/Tonga, Atlantis, Shenzi and Mad Dog – are in this trend. The most significant remaining project to come on line will be Mad Dog 2 where first oil is expected in late 2022. (I place Murphy’s recent King’s Quay project just to the north of this sweet spot.) These fields are all either completely, or at least mostly, subsalt. The reservoirs are all Middle to Lower Miocene deepwater channels or fans and the structures are either large faulted 4-way closures or 3-way closures against salt. I expect the ultimate cumulative oil production from this trend to be close to 3 billion barrels.
Another Tier 1 sweet spot is the greater Mars-Ursa Basin. BOEM lumps Mars, Ursa and a few nearby fields into one entity, which has cumulative production of 1.6 BBO and is clearly the biggest field in the GOM. If you include the nearby fields – Crosby, Europa, and Kaikias – cumulative production to date from the greater Mars-Ursa basin is 1.8 BBO. Production from this trend started when Mars came online in 1996. Remaining reserves for this trend are 843 mmbo, with most of those reserves split between Mars-Ursa and Vito. The most significant remaining project to come online in this trend is Shell’s Vito where first oil is expected in late 2022.
The remaining Tier 1 sweet spot is the Wilcox in Keathley Canyon, Walker Ridge and Green Canyon. Even though this sweet spot covers a pretty large area, the prospects share petroleum system elements such as similar reservoirs and source rocks. This trend includes the Wilcox producing fields outside of the greater Perdido Fold Belt area, and a number of developments set to come on line within the next few years. While cumulative production to date for this sweet spot is only 468 mmbo, I expect the midcase EUR to be 2-3 Bbo.
For those interested, below is a link to a recent Wilcox update I did.
Update on the Wilcox in the Offshore Northern Gulf of Mexico – Peak Oil Barrel
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Figure 6 – My interpretation of Tier 1 and Tier 2 oil sweet spots. Tier 1 – ultimate cum oil > 2 Bbo. Tier 2 – ultimate cum oil 1-2 Bbo
The Greater Perdido fold belt area in Alaminos will become, I believe, a Tier 2 sweet spot. Cumulative production to date is 260 mmbo, from Shell’s Perdido’s host facility, but there are 3-4 future projects with most likely recovery in the 800 mmbo to 1.2 bbo range. Those include Whale, Blacktip, Leopard and Blacktip North.
I’m currently not convinced that the Norphlet trend will ultimately become a Tier 2 sweet spot, although this is subject to change. This trend would be just south of field 11 on Figure 6 above. As per an assessment done by Talos Energy, as of 2019 23 Norphlet exploration wells had been drilled and 9 were classified as discoveries. Since then, only Shell’s Appomattox and Vicksburg discoveries have come on line via production to a new facility, (with cumulative production through 2021 of 71 mmbo) and Chevron’s Ballymore will get developed via a tieback to nearby Blind Faith. No development plans have been announced for any of the other discoveries, which were all made by Shell. If some of these do end up getting sanctioned, then I think the cumulative production from the Norphlet can exceed a billion barrels.
The greater Thunderhorse area, fields 9 and 19 in figure 6, is another area that I’m not convinced yet is going to have cumulative production over a billion barrels. BP’s Thunderhorse and Thunderhorse North have cumulative production to date of 583 mmbo, and BOEM’s remaining reserves are 211 mmbo. Current production from the Thunderhorse fields is about 100 kbopd, and BP anticipates production increasing to about 200 kbopd over the next few years as the Thunderhorse South project comes on line, but I believe the reserves for that project are already included in BOEM’s assessment.
One could argue that numerous shelf protraction areas outside of the Terrebonne trough fields could be classified as Tier 2 sweet spots. For example, the Eugene Island fields have the largest oil cum of any shelf protraction area of 1.7 Bbo. I have decided to not include that area, for example, because the fields don’t share enough petroleum systems elements to warrant being classified as a sweet spot. Also, since my focus here is more on future GOM production and ultimate EURs, the shelf protractions are long past their peak in oil production and won’t, in my opinion, be contributing much in the years to come.
How much of a difference will offshore lease sales make?
Some have argued that the lack of offshore lease sales will have a big impact on future GOM production. For example, the National Offshore Industries Association has said GOM production could be reduced by 50% by 2040 if the offshore lease sale ban continues. I’m not quite as pessimistic. Oil production could be reduced 50% by 2040, but, if that happens, it will be due to geology as much as due to a lack of lease sales. It’s a question to me of how many substantial prospects are there out there that industry has missed. The Gulf of Mexico has had annual area-wide lease sales for most of the years going back to 1983. (Before 1983, leases had to be nominated by industry prior to a sale to be considered in a lease sale. Far fewer leases were available for industry to bid on in these pre-1983 lease sales.) That’s almost 40 years of area-wide annual lease sales. How many bites at the apple does industry need? Many of the leases that have been getting picked up by industry in recent sales have already been leased at least one time, and then they have been dropped because either a dry hole, or non-commercial discovery was drilled, the prospect on the lease didn’t stack up against the inventory of prospects the operator had at the time, or it was picked up as protection acreage. These clearly aren’t, and never were, the most prospective leases in the Gulf. The exceptions to this are that new play concepts and advances in seismic imaging technologies can make non-prospective leases prospective. I believe this has resulted in, for example, the recent discoveries Shell has made in the subsalt portions of the Perdido fold belt. I haven’t seen evidence of any more examples of this. And these prospects are all going to be deep, difficult to appraise, and expensive to develop.
Now one could argue that the industry hasn’t had the technology to drill and produce from the deepest high temperature and high pressure plays for the last 40 years. Fair enough – those technologies have been developed over the last 10-15 years or so, and, in fact, the first HT-HP field is yet to come on line, notably Chevron’s Anchor. But again, if there are prospects like that still out there, they will be deep, difficult to appraise, and expensive to develop. Another HP-HT field that was thought to get sanctioned, TotalEnergie’s North Platte, was recently deferred because it didn’t stack up against their queue of other global projects.
Also, most oil companies have enough undrilled leases in their current inventories that they can continue drilling exploration wells for at least 2-3 years. After that, industry will probably start running out of exploration prospects, but the question is: Are there still attractive undrilled prospects out there, after 40 years of lease sales, that industry has just over-looked?
(In my review of recent GOM discoveries, I found that the most recent lease sale where a block was acquired, and a recent significant discovery was made was the August-2017 sale. Shell acquired Alaminos Canyon 336 in that sale, and in early 2021 made the Blacktip North discovery on that lease. Since then, there have been 6 sales – 2 in 2018, 2 in 2019 and 2 in 2020. I’m not aware of any discoveries that have been made on any of the leases picked up in these sales. The one in November 2021 was the on-again/off-again sale. My point here is that industry has had ample opportunities to pick up leases.)
Of late, industry has been focused on near-field exploration because of quick turn-around. A discovery made near existing infrastructure can be tied back and brought on-line much more quickly than a frontierish type of discovery that needs a new facility. Almost always these near field discoveries are small. If those same volumes were discovered in an area lacking infrastructure, it would be called a non-commercial discovery. There still are, probably, a queue of these types of discoveries remaining to be made, but, this queue is also getting smaller and smaller.
In my projections of future GOM oil production, I don’t make any specific considerations about whether future lease sales happen or not, although in my high side estimates, future lease sales are baked in (and the related new discoveries of mostly small but some decent sized reserve ranges), while in my low side estimates, there are no future lease sales, or, at least, no significant discoveries if lease sales continue.
Now if the entire eastern GOM were made available for leasing, this story changes. But there are no signs of that happening.
Estimate of future production and EUR ranges from the GOM
The queue of high impact projects set to come on line in the GOM over the few years is quite attractive and includes King’s Quay (just came on line), Mad Dog 2 (2022 first oil), Vito (2022), Anchor (2024) and Whale(2024). All 5 projects have dedicated new facilities with capacities ranging from 75 to 140 kbopd. Table 3 shows those these 5, plus 2 other projects, that should come on line before 2025 with most likely reserves of at least 100 mmbo. 6 of these developments include new facilities. The last, Thunderhorse South, will be tied into BP’s Thunderhorse facility. Note that the total new facility capacity is over 700 kbopd.
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Table 3 – 7 projects with at least 100 mmbo of most likely reserve potential that will be developed in the deepwater GOM with first oil before 2025,
The new production coming from the projects above will result in a new annual peak in GOM oil production between now and 2030 or so, and it is possible this peak will exceed 2019 peak of 1.9 mmbopd.
After these projects, the remaining significant identified projects are in Table 4.
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Table 4 – Remaining significant identified projects in deepwater GOM. FIDed projects will get developed. Development decisions have not been made on the others. Note that TotalEnergies recently withdrew from North Platte.
I believe the era of significant deepwater megaprojects is nearly over in the GOM. After the projects referenced above come on line, I don’t see much more megaproject activity in the GOM. The link below is to a recent SPE article by Blake Wright on this topic.
Is It Twilight for Deepwater US Gulf Megaprojects? (spe.org)
As mentioned in the article above, part of the reason for this is because of the lack of significant discoveries. My Figure 7 below, from Wood Mackenzie, and also referenced as Figure 3 in Wright’s article, shows how discovered volumes in the GOM have been dropping over the last 4-5 years. Some would argue this is because of low oil prices, and that discovered volumes are low because of fewer exploration wells. I disagree – I think it’s primarily because of geology. But, with the current high oil prices, let’s see if operators start making more significant discoveries. If industry starts seeing year after year of 1 Bbo+ in discovered reserves (or even 500 mmbo per year), then I will have been proven wrong. (But what about the lack of lease sales discussed above? If the lack of discoveries is due to the lack of drilling because of low prices, as some think, then companies should have a good queue of undrilled exploration prospects to drill now with high oil prices.)
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Figure 7 – from Wright SPE article referenced above.
Figure 8 shows my low-mid-high range of predictions of future production from the GOM. I have also included a recently released EIA estimate of GOM production out to 2050, from their March 2022 Annual Long Term Energy Outlook. The EIA estimate stopped at 2050, so I started decreasing their production at the annual rate of 100 kbopd until I got down to 0 production.
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Figure 8 – GOM oil production from 1980 to 2021 and my projections out to 2080 in mmbopd. Included is my edited EIA estimate, which takes their projection to 2050, and then reduces it by 100 kbopd per year til 2064.
In all cases, I see production increasing to a new peak. This new peak ranges from 1.7 to 2.18 mmbopd (EIA estimate), and in both my high side case and the EIA case, the previous peak from 2019 is exceeded.
EURs ranges are 31, 36 and 42 Bbo in my low-mid-high cases, and the edited EIA EUR is 46 Bbo. Among other things, the low side outcome assumes either lack of future lease sales, or lack of material discoveries from future lease sales. The upside case assumes numerous significant discoveries from either industry’s current lease inventories, or from leases picked up in future sales.
BOEM’s UTRR (Undiscovered Technically Recoverable Resources) from their 2021 update for the entire GOM is 29.6 Bbo (from Jan. 1, 2019 data). This is down from about 48 Bbo in the 2016 assessment. Significant discoveries since then include Blacktip, Leopard, Monument and Blacktip North. Any other announced developments are from discoveries made prior to Jan 1 2019. If you include just the Central and Western GOM, their UTRR drops to 24.7 Bbo. 24.7 Bbo plus the 21.4 Bbo cum at the end of 2018 give a total EUR for the GOM of 46.1 Bbo. That is, in my opinion, pretty high, even for a high side estimate, but it is in line with my edited EIA EUR.
For those interested, comparison to my 2016 GOM production post.
This post is an update to one that I did as SouthLaGeo back in 2016. Below is a link to that post. I initially promised Dennis I would do this update in 2018, but,,, oh well. If I keep this pace up, my next update would be in 2028. Given the divergence in the production profiles in 2028, that would be a very interesting update. Even a 2025 update would be interesting.
Overview of the Northern Deepwater Gulf of Mexico – Peak Oil Barrel
I include this primarily to show how my EURs and production profiles compare, but for those interested, there is more geology in the 2016 post. Below is a chart showing my low case, mid case and high case projections from 2016 included with the data from the chart above. I know the chart is busy. Hopefully you can see through everything.
My 2016 EUR ranges were: low case 30 Bbo, mid case 37 Bbo, high case 47 Bbo. Interestingly, my mid and low EUR ranges have not changed too much, but my high side has come down a fair bit. The profiles in all cases certainly have changed. I clearly under-predicted future production, and my current profiles show production dropping off more quickly.
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Figure 9 – Production profiles from my 2016 posting as SouthLaGeo compared to 2022 profiles.