A guest post by Bob Meltz
I’ll start with a brief overview of some northern offshore GOM production statistics, and then review what I see as the current state of Wilcox exploration and development projects and finish by discussing Wilcox production data. All production statistics are from BSEE/BOEM.
Cumulative production from the federal waters of the offshore Northern Gulf of Mexico (OCS) through 2020 is 22.7 BB (billion barrels) oil and 190 tcf gas. The first production was in 1947. Production from deepwater (defined by BOEM as water depths > 1000′) is 9.6 BB oil and 22.9 tcf gas. The first deepwater production was in 1979 from Shell’s Cognac platform in 1025′ of water.
The current annual peak in offshore oil production was in 2019. The average production was 1.9 mmbopd. 2020 production averaged about 1.64 mmbopd. So far from 2021 through October average oil production has been about 1.67. With the near term queue of Miocene projects set to come online in 2022 (Mad Dog 2, King’s Quay, and Vito), and the queue of Wilcox projects set to come online in 2024-2025 (Anchor, Whale, and perhaps North Platte), I believe we will see another peak in production in 2 to 6 years, and this could even exceed the 2019 peak.
The Wilcox, sometimes also called the Lower Tertiary, was thought by many to be the future hope for the offshore Gulf of Mexico, providing long-term production for years. As the shelf and flex trends played out, and as the deepwater Miocene fields started playing out, the Wilcox was going to pick up the slack and keep offshore production going.
I co-authored a paper with several Chevron colleagues in 2005 that led to some of this initial enthusiasm. Here is a link to that paper.
The article indicates potential from the play of 3 to 15 billion barrels of recoverable oil. The high-end estimate of 15 billion barrels of recoverable oil generated a lot of industry buzz at the time, but I’m glad we also included the low estimate of 3 billion barrels. As you will see later, I currently believe the ultimate recovery from Wilcox will be closer to that low estimate.
The oil industry has faced many challenges in pursuing Wilcox. Some include the technical challenges of drilling and completing these wells. In many cases, they are drilled through thick salt canopies onto total depths exceeding 30,000′. They are some of the deepest wells in the world, and often the top of the reservoirs are encountered below 25,000′. The deepest well in the GOM was a Wilcox test drilled by Chevron in 2013 to 35,935′ TVD_SS. Usually, the Wilcox reservoirs are quite thick, often over 1000′ of gross reservoir thickness and over 500′ of net oil pay. Successfully drilling and completing these wells is not for the faint of heart.
So, after 20 or so years of exploration and 11 years of production, how has Wilcox been performing?
First I’ll discuss the exploration story of the Wilcox.
Below is a simplified stratigraphic column showing the primary producing intervals of the offshore Gulf of Mexico.
Figure 1 – Simplified stratigraphic column for the offshore Gulf of Mexico
Historically, the Wilcox has been a prolific gas-producing interval onshore Texas and Louisiana. It wasn’t thought to be prospective in the deepwater Gulf of Mexico until the BAHA #2 well was drilled in 2001 in the outboard-of-salt portion of the Perdido Fold Belt. This well, classified as a dry hole, demonstrated both a working petroleum system (it did encounter 15′ of oil pay) and, surprisingly, thick Wilcox sands. This was followed in Perdido Fold Belt by the Trident discovery in 2001, and the Great White discovery in 2002.
Meanwhile, the initial test of the Wilcox section in the deepwater Central GOM was made by BHP at Cascade (2002). Interestingly, this well was not initially intended as a Wilcox test, but when the shallower Miocene section came in wet and very poorly developed, they deepened the well to test the Wilcox. The significance of this well is that it demonstrated both a working petroleum system in this portion of the GOM (the well was an oil discovery), and the existence of Wilcox sands over 200 miles east of those being found in the Perdido wells. That started to open up the potential for the Wilcox over the entire deepwater GOM. Subsequent discoveries included Chevron’s Jack and St. Malo.
A very good recent assessment of Wilcox exploration results can be found on pages 82-86 in the following BOEM document.
BOEM sites 21 discoveries out of 72 exploration tests, for a commercial success rate of 29%. 24 of the wells found non-commercial oil. (If the lease in which the well is drilled is still held by the operator, it is considered a commercial success. If the lease has been dropped, it is considered a non-commercial success. Of course, in both cases, at least some oil has to be encountered.)
The maps below from this document show the distribution of Wilcox exploration wells in the deepwater GOM. Producing assets are highlighted in green, and discoveries in red. (At least 3 discoveries are not included on the map or their statistics: 2 in the Perdido Fold Belt area to the west of Figure 2 to be briefly discussed later – Leopard, a few blocks south of the word Brontosaurus and Blacktip North, just north of Blacktip; and Constellation, a producing asset in Fig. 3. -a bit north of Turtle Lake.)
Figure 2 – West half of Figure 61 on page 86 of BOEM document referenced above, showing the distribution of Wilcox exploration wells in the deepwater Gulf of Mexico. Lease blocks are 3×3 miles. The underlying map is a rendering of bathymetry.
Figure 3 – East half of Figure 61 on page 86 of BOEM document referenced above, showing the distribution of Wilcox exploration wells in the deepwater Gulf of Mexico.
One of the biggest challenges presented by Wilcox is how to handle discovery. After drilling an exploration well where you have encountered oil, it isn’t always apparent that you’ve drilled a commercial discovery. Most of these Wilcox wells are subsalt where seismic data can be difficult to interpret, and your ability to determine how extensive an oil accumulation is can be quite challenging. As a result, no final Wilcox development decisions are made based on the results of the first exploration well (unless you decide to walk away from the project). An appraisal is a very big deal, and sometimes appraisal well results are disappointing, and the operator decides to not pursue development, and drop the leases. This results in a non-commercial oil well.
If the appraisal results are successful, and this could include multiple appraisal wells, the operator will often have enough confidence that they will be able to produce economic volumes of oil and will sanction the project, sometimes called FID or Final Investment Decision. The development may involve the fabrication of a new facility, a commitment to drill additional development wells, and installation of all of the subsea facilities to bring the oil and gas to market (it’s different if you decide on an FPSO where the oil is stored on the facility, and then offloaded to a tanker). Project costs can vary from as little as a few hundreds of millions of dollars (for a small well tieback to an existing facility) to multiple billion-dollar projects.
Recently, the Perdido Fold Belt area (located on the west half of Figure 2) has been a focus of exploration. A number of significant discoveries have been made by Shell and partners in the subsalt to a mostly subsalt portion of the Perdido Fold Belt in the Alaminos Canyon protraction area. These include Whale (2018), Black Tip (2019), Leopard (2021), and Black Tip North (2021).
The lease map below, Figure 4, courtesy of Shell with a few of my edits, shows the locations of these recent discoveries. It also shows the location of the Perdido host production facility. Note the proximity to the U.S. / Mexico international boundary. At one time there were rumblings that the Mexican government was convinced Shell would be draining oil reserves that extended into Mexican waters. This is definitely not the case. These are bright spot-associated reservoirs that are very well imaged on seismic, and the bright spots clearly stay in US waters, and abundant well control confirms this.
Below is a link to a 2007 article about this.
The Perdido fold belt extends south into Mexican waters. The trend has been moderately explored in Mexican waters with BHP’s Trion discovery being the most significant and one that is very likely to be developed. The Trion discovery was made in 2012 and the first oil is expected in 2026 and non-op partner Pemex’s estimate of the gross estimated recoverable resource is 485 mmboe.
Figure 4 – Lease map of the Perdido Fold Belt area showing key Shell leases and recent discoveries. The map is courtesy of Shell with a few edits. The underlying map is a rendering of bathymetry.
Next, the production side: The first Wilcox production occurred in 2010 when Shell brought the Perdido project online, (see the location of Perdido Host in Fig 4). At the time it came online, it was producing from the deepest water in the world, with the Perdido host facility in 7835′ of water. The main producing reservoirs at Great White are at about 17,000′, about 9000′ below the mud line. The Great White Wilcox is unusual in that it has quite favorable rock properties because it is fairly shallow – porosities in the low 20% range, and permeabilities in the 100 mD range or so. This differentiates it from the other producing fields where the Wilcox is deeper, porosities are in the 10-20% range and permeabilities are in the 10s of mDs. It is also outboard of salt and, consequently, doesn’t suffer from the seismic data quality issues seen in the subsalt areas.
Soon after, in 2012, Petrobras brought on Cascade and Chinook in Walker Ridge. They are located in the eastern portion of Figure 3 above. These fields are producing to a centrally located FPSO, the first of its kind in the GOM.
There are currently 9 fields producing from the Wilcox. The chart below shows annual production from these fields through 2020 compared to total GOM oil production. To date, peak Wilcox production was 304 kbopd in 2019. This was 16% of total GOM production in 2019. Total GOM production was down slightly in 2020 because of Covid, while the Wilcox contribution increased to 17%.
Figure 5 – Annual Gulf of Mexico oil production with Wilcox breakout
Cumulative Wilcox production through 2020 is 614 mmbo, with the per field breakout in table 1. BOEM’s latest reserve updates are through 2019, so I just subtracted each field’s 2020 production from BOEM’s 2019 reserves to get an estimate of remaining reserves at the end of 2020.
(I’ve included a column showing cumulative gas production for these fields through 2020. With the exception of Great White, these are all low GOR oils.)
Table 1 – Key information on the current Gulf of Mexico deepwater fields producing from the Wilcox.
Chinook stands out as having negative reserves at the end of 2020, meaning Murphy (the current operator) produced more oil in 2020 than BOEM’s reserves were at the end of 2019, and it has produced more than 2 mmbo through 9 months in 2021. So you can at least change that -4 to a +2.
Then it starts getting to be a question of what the most likely total recovery will be from these fields, or, how much additional recovery will these fields achieve beyond the sum of current cumulative production and my estimate of BOEM’s reserves at the end of 2020. I’m going to go with an estimate of 1.6 +/- .3 BBO as the EUR range for these fields. That captures the current cum plus reserves of 1.3 BBO (614 + 677 = 1.291 =~ 1.3 BBO) on the downside and allows for a fair bit of upside. 2 things that I can see leading to that upside are further developments at Great White and Buckskin and there certainly could be others.
Buckskin is an interesting case study. Chevron (CVX) and partners drilled the discovery in 2008 and followed it up with some appraisal drilling. After not seeing a clear path to economic development, LLOG acquired Chevron’s interest, drilled and completed 2 development wells, and brought the project online as a tieback to Anadarko’s nearby Lucius platform in 2019. Buckskin is in the southwest portion of Figure 3.
The queue for near-term future developments is quite attractive. They are shown below in Table 2. These are all projects that have either FIDed or where the operator has shown a very strong commitment to FID. Note that 3 of them will be 20 k projects – meaning the drilling and production equipment needs to be able to handle the ultra-high pressures (up to 20,000 psi) associated with these Wilcox reservoirs.
Table 2 – Gulf of Mexico Deepwater Wilcox projects that have been FIDed, or are very likely to FID within the next year or so.
The Shenandoah development has a somewhat similar history to Buckskin. Anadarko and others drilled numerous wells at Shenandoah and nearby prospects, with the first discovery drilled in 2009, but were never able to come up with a path to economic development. The project languished, but Beacon has come in and is planning a phased development approach. Shenandoah and offsets, Yucatan, Coronado, and Monument, are in the central part of Figure 3.
There also are a number of projects that are likely to be developed but have not been FIDed and are, therefore, a little further out in the future. They include 3 of the recent Shell discoveries in the Perdido Fold Belt area – Blacktip and Blacktip North and Leopard. Another project is a potential co-development of Leon and Moccasin (Leon is in the southeast portion of Figure 3 and Moccasin is to its east. The Moccasin label is cut off by the edge of the map.)
It’s harder to put a reserve range on these because of a lack of information from operators, but, when that’s the case, I find that the best practice is to make the range-wide. So, I’m going to put the range from .7 +/- .4 BBO.
What about undiscovered prospects? It’s my view that exploration for the Wilcox is fairly mature in the GOM, so I put this range at .5 BBO +/- .5 BBO. (A high side estimate of only 1 BBO may be too conservative?) The chart below, Figure 6, from the BOEM report referenced earlier, shows how the number Wilcox exploration wells have been steadily decreasing over the last 8 years or so. This, to me, speaks to the overall maturity of the basin. Some, though, may disagree and say this is related to low oil prices.
Figure 6 – Number of deepwater Wilcox (Lower Tertiary) exploration wells since 1996. From BOEM document referenced above. No wells were drilled in 2010 because of the BP oil spill.
One source of prospects could be for operators to revisit some of the remaining discoveries that have been made but don’t appear to be on a path to development. A good example here is the Guadalupe-Tiber area in the middle of Figure 2. I could see this area getting revisited in a similar way that Beacon is moving ahead in the Shenandoah area.
Table 3 below is my EUR ranges for all of these projects, broken out by status, in mmbo.
Table 3 – EUR ranges for Wilcox projects of varying status in the GOM.
So, after 20 years of exploration, and 11 years of production, my EUR range for the Wilcox is between 2.6 and 5.5 BBO, with a most likely EUR of about 4 BBO, pretty close to our low-end estimate of 3 BBO from 2005.
You might ask how did we ever get to that upside estimate of 15 billion barrels of recoverable oil? At that time, only 13 exploration wells had been drilled, and 9 were classified as discoveries, and about 12 BBO of original oil in place had been discovered. That results in a discovery rate of 9/13 = 69%. If you assume a similar success rate for future Wilcox wells and assume a total of 65 prospects, that results in 45 discoveries. If you also assume a similar OOIP per future discovery as existing discoveries, the total OOIP goes to 60 BBO. (I’m just multiplying things by 5.) Then, if you assume 25% recovery, you get 15 BBO. The biggest “miss” here is the recovery factor. Because of the low perm nature of most of the Wilcox reservoirs, 25% recovery is very unlikely. 10-15% recoveries are probably closer to what operators are going to achieve. Great White is an exception to this because the main reservoir is shallower than others and has better rock properties. In fact, a fairly successful waterflood is being done in this reservoir and the expected recovery factor could be 40-50% of OOIP.
Another “miss” is around the number of discoveries that have ended up being non-commercial, and unlikely to get developed.
Interestingly and in conclusion, using the BOEM data mentioned earlier plus the 3 additional discoveries that I mentioned, you get 75 total exploration wells, 24 discoveries, and 24 wells with non-commercial oil. 48 out of 75 wells found oil, resulting in a discovery rate of 64%, not too far from the early discovery rate of 69%. The commercial discovery rate, though, is 24/75 = 32%. As mentioned earlier, it is these wells that end up being non-commercial discoveries that can become real appraisal challenges. (Actually, even some of the commercial discoveries end up being appraisal challenges, but I will leave it there.)
Editor’s Note: The summary bullets for this article were chosen by Seeking Alpha editors.