spec machine
1 month ago
Hmmmmmm, I missed this article
V-ger must have been offline
— Published April 2024 —
https://www.hgs.org/conversation-hgs-legend-john-seitz
A Conversation with HGS Legend John Seitz
John Seitz was named to the inaugural class of “HGS Legends in Wildcatting” in 2000, along with George Mitchell, Joe Foster, Marlan Downey and Gene Van Dyke. At that time, Seitz was nearly 25 years into his career and in senior leadership roles with Anadarko Petroleum, where he led successful exploration campaigns in Algeria and Nigeria, among others.
Seitz hasn’t slowed down in the twenty-four years since being named a Legend. He rose to the role of President and CEO of Anadarko before departing in 2003. Seitz then co-founded North Sea New Ventures that became Endeavor International, where he led key discoveries in the North Sea. In 2014, he co-founded GulfSlope Energy, where he is currently the President, CEO and COO.
Over his nearly 50-year career Seitz has learned key lessons about being a successful geologist: learning from mistakes, valuing commercial skills, and staying close to the technical work. These lessons, along with a passion for exploration, keep him going even when the commercial landscape for exploration is challenging.
Be willing to learn from mistakes
Seitz says one of the core lessons he learned at Anadarko was to make data-driven decisions and be willing to learn from mistakes. He describes that it is critical to document the basis for a decision and then to “thoroughly post-appraise” the outcome of the decision. Seitz stresses that the post-appraisal process is not intended to find a guilty party, but instead to understand whether decision-makers took unnecessary risk.
Good technical decisions are based good data. “You have to invest in science—the data, the people and tools. Not to invest is a mistake,” Seitz says. Once the data is gathered, the next step is to build a portfolio of opportunities. The third step is to balance the portfolio with a mix of risk v. reward probabilities. “Balance your gut feel with confidence from data,” he says. Seitz explains that with each success at Anadarko he was given more room “to run faster, run harder.”
Commercial skills are as essential as technical skills
“Early in my career, I was frustrated that my prospects weren’t getting funded,” says Seitz. He entered an MBA program at University of Houston in 1976 where he learned foundational economic and commercial skills. Although he didn’t complete the program, he says the skills he learned allowed him to view opportunities differently and bring forward prospects that had both technical and commercial potential. “The ability to speak the language of returns helped me to get into management,” he says.
In the past two decades, Seitz has been trying to get prospects funded by capital markets or private equity. He says the ability to raise risked capital is just as important has having good technical opportunities, but the skill sets are very different. Seitz notes that engineers have an advantage because they typically are involved more than geologists on economic evaluations.
Raising capital has a been challenge. “You earn your stripes well to well,” he says. While at Endeavor, Seitz had a 61% success rate of exploration and appraisal wells. Endeavor’s discoveries and appraisals included the 30 MBO Rochelle field. Another Endeavor appraisal well confirmed that the Cygnus discovery was one of the largest North Sea discoveries in recent history (AMEX_END_2008.pdf (annualreports.com). These successes, however, were not enough to keep investors motivated through the development phase and the company was closed in 2014.
When Seitz co-founded GulfSlope, he intended to raise capital for drilling prospects. However, GulfSlope’s launch was coincident with the 2014-15 shale boom and subsequent industry downturn. Seitz laments that today’s investors want to put their capital towards unconventionals or Energy Transition projects rather than exploration. “Sometimes it feels like butting my head against the wall,” says Seitz, “But we are still going.”
Stay close to the technical work
Seitz says that his last role at Anadarko was too far away from the people conducting the technical work. Similarly, he finds board roles weren’t sufficiently satisfying because he was too far removed from technical decisions. Seitz jokes that he prefers to be no more than “three offices away” from the landman and the geologist because it allows for efficient decision-making. “It’s all about the people, their creativity, and the small role I can play of having my ideas contribute to the process,” he says.
Similarly, it is critical to have a strong technical team whose skills complement one another. The days of the “sole contributor” are over, says Seitz. Specialized skills are needed to understand each aspect of the risk profile to make good decisions. While it is easier to learn those skills at a big company, it’s most important to work for a company that values learning, he says.
Going forward
Reflecting on the current push for renewables, Seitz says that the Energy Transition is not likely to happen quickly, and hydrocarbons will continue to play an important role going forward. He also reflects on the positive impact of hydrocarbons to economies around the world. “Oil means jobs and jobs mean stability,” explains Seitz.
Throughout his nearly fifty years in the Oil and Gas business, Seitz says he has learned to “stick to your guns.” Although he is currently looking for the right producing property to acquire, he plans to continue working to convince investors in the value of exploration and production and to seek like minded partners.
All the smoke points in a positive direction
Keep the faith
spec
Ebenezer3
1 month ago
Just so you know what you're dealing with, Tau-2 not Deepwater, but dealing with the same issues. What happened to Tau-1 wasn't a surprise, just the reality of oil exploration. Enjoy.
https://www.worldoil.com/magazine/2008/september-2008/special-focus/subsalt-exploration-risk-in-deep-water/
Subsalt exploration risk in deep water
September 2008
Subsalt exploration risk in deep water
The high rewards of finding hydrocarbon in subsalt plays make them very attractive for exploration. However, it is a challenging mission. Subsurface pressure uncertainty causes recurrent failure to reach the drilling targets. After the discovery of Mahogany Field in the GOM 15 years ago, special attention was directed to subsalt plays. That attention gradually shifted from the shelf to deep water (>1000-ft water depth), Fig. 1. Deepwater yearly production increased from 21 million bbl of oil and 33 Bcfg in 1985 to 339 million bbl of oil and 1.1 Tcfg in 2006, according to the US Minerals Management Service. Consequently, the cost of acquiring and testing prospects has increased due to the prospects’ location in deepwater salt mini-basins. The prospect’s risk results from intricate geopressure compartmentalization in a salt environment accompanied by a deep mud line, deep target depth and shallow sediment hazards.
The interaction between salt and sediment changes the geopressure relationships below salt, increasing drilling risk.
Selim Shaker, Geopressure Analysis Services, Inc.
The high rewards of finding hydrocarbon in subsalt plays make them very attractive for exploration. However, it is a challenging mission. Subsurface pressure uncertainty causes recurrent failure to reach the drilling targets.
After the discovery of Mahogany Field in the GOM 15 years ago, special attention was directed to subsalt plays. That attention gradually shifted from the shelf to deep water (>1000-ft water depth), Fig. 1. Deepwater yearly production increased from 21 million bbl of oil and 33 Bcfg in 1985 to 339 million bbl of oil and 1.1 Tcfg in 2006, according to the US Minerals Management Service. Consequently, the cost of acquiring and testing prospects has increased due to the prospects’ location in deepwater salt mini-basins. The prospect’s risk results from intricate geopressure compartmentalization in a salt environment accompanied by a deep mud line, deep target depth and shallow sediment hazards.
Fig. 1
Fig. 1. Deepwater GOM prospect risk results from intricate geopressure compartmentalization in a salt environment.
In the GOM’s Tertiary-Quaternary, geopressured sediments are caused by compaction disequilibrium. Lithology and maximum principal stress control this process. Salt’s unique petrophysical properties contribute to substantial changes in pore pressure gradients in the host sediments above and below the salt layer. Salt’s low density retards the overburden gradient below the salt, and enhances it above the salt. Its negligible permeability creates a perfect seal. Moreover, salt’s ductile nature generates a variety of structural styles that affect stress orientation and magnitude. Subsurface geopressure dictates sealing and retention capacities, and therefore affects oil- and gas-trapping capability in a specific structural closure. This article addresses salt-related risk assessment from a geopressure standpoint.
CONCEPTS DEFINITIONS
In extensional salt basins, the magnitude and direction of the principal stresses are controlled by sediment load, salt thickness and salt emplacement/displacement history. Therefore, the maximum Principal Stress (PS) is not necessarily represented by the vertical weight of the overburden. Salt buoyancy usually acts upward and has a tendency to accelerate and decelerate PS above and below the salt, respectively.
In several subsalt wells drilled in the mini-basins of the Mississippi Canyon, Green Canyon and Garden Banks areas (MC 211, 292, 619, 627, 674 and 714; GC 153 and 699; and GB 217), a distinctive shift of the Pore Pressure (PP) envelopes and normal compaction trends takes place across the salt body. A lower PP gradient has been observed below the salt and a higher gradient above the salt barrier. On a salt-rooted mini-basin scale, a higher gradient was also observed in areas where the salt was emplaced and a lower gradient where the salt withdrew.1
On the other hand, in a compressional system, the lateral stress generated by salt movement acts as the maximum PS, whereas overburden sediment load represents the minimum stress, i.e. Fracture Pressure (FP).
At the Sigsbee Escarpment, the salt mass’s toe is creeping down-dip near the mud line, creating thrust folds and faults out of the older underlying sediments. This has produced a potential new deepwater frontier, Fig. 2. Several Wilcox-equivalent (Lower Tertiary) discoveries have been announced recently in the Perdido Foldbelt and Walker Ridge.2 Chevron’s large discovery in Block WR 758, Jack No. 2, is along this trend. The well cost Chevron about $100 million and took three months to drill, according to a press release.
Fig. 2
Fig. 2. The Sigsbee Escarpment salt mass’s thrust folds and faults have produced a potential new deepwater frontier. Modified after Chowdhury and Lopez-Mora 2004.
Stress fields, in particular the maximum PS and FP, determine the pressure envelopes in the subsurface sedimentary column. PS dictates the progress (transgression and regression) of the PP, and FP represents the breaching limit, Fig. 3.
Fig. 3
Fig. 3. Stress fields determine pressure envelopes in the sedimentary column.
Terzaghi3 established the relationship between the PS and PP as:
PP = PS - ES (effective stress)
Therefore, PS is the driving mechanism of PP buildup. Sealing capacity is expressed by the transgression of the excess pressure in a specific compartment, whereas retention capacity represents the maximum capability of trapping a specific hydrocarbon column in a structural closure.4 The difference between FP and PP plays an essential role in dictating the retention capacity.
MODELS AND CASE HISTORY
The dynamic and emplacement history of allochthonous salt bodies is a complex issue to evaluate in this short article. Therefore, density difference between the salt and host sediments will be considered the main driving mechanism for PP development. The sediment above salt is subjected to a PS greater than the overburden stress as a result of salt buoyancy and consequently has a higher PP gradient.
This leads to a large reduction of the drilling tolerance window (FP to PP). These conditions require higher mud weight and multiple casing points to drill this upper section.
On the other hand, the PS on the rock column below the salt is reduced due to salt buoyancy effect. This leads to a higher retention capacity and the possibility of a thicker hydrocarbon section being trapped below salt. This also might reduce the sealing capacity (weaker seals) below the salt. The conceptual model in Fig. 4 exhibits this relationship. Moreover, it clearly shows the substantial drop of the PP and FP below the salt due to PS reduction. This leads to widespread, known drilling problems at the salt-sediment interface.
Fig. 4
Fig. 4. This conceptual geopressure model shows how the principal stress below the salt is reduced by salt’s buoyancy effect.
Crosby Field. This field was an exploration success and presently produces from a subsalt trap. It covers four blocks (Mississippi Canyon Blocks 898, 899, 941 and 942). MC 899 production peaked at 14.4 million bbl of oil and 19.1 Bcfg in 2002. In this block, Well No. 6 represents a key example of multiple pay zones below and above the salt. A thick gross oil and gas pay zone was trapped due to the large retention capacity, resulting from the subsalt PP regression. The measured PP at the ~18,000-ft pay zone was about 12,000 psi (pressure gradient of 0.66 psi/ft). The lower Pressure Gradient (PG) may be responsible for the relatively rapid production decline of this block. The well’s reported production in 2006 was 2.18 million bbl of oil and 3.16 Bcfg. High PS/PG in the suprasalt resulted in several kicks and water flow incidents and, therefore, seven casing points were needed to drill above the salt. Conversely, in the subsalt section, two casing strings from the base of the salt to TD (18,250-ft TVD) were set.
Several sidetracks were performed to reach the lower objectives below the salt due to several losses of circulation (low PS and low PG). Eventually, production will resume from the suprasalt pay zones.
Mackerel prospect. Wildcat Well 1 in Mississippi Canyon 619 was a disappointing subsalt exploration endeavor. The relationship between PS, overburden, PP and FP in the geopressure model applies. The pressure plot in pounds per gallon (ppg) vs. depth of MC 619-1 shows a steep increase of mud weight to drill the section above the salt, which led to setting five casing strings, Fig. 5. Moreover, the extrapolated FP trend from the Leak-Off Tests (LOT) and Formation Integrity Tests (FIT) exceeded the calculated overburden. This confirms the assumption that PS is higher than the overburden in the suprasalt section.
Fig. 5
Fig. 5. The pressure plot of MC 619-1 shows a steep mud weight increase above the salt which led to the operator setting five casing strings. Modified after Shaker and Smith 2002.
Below the salt’s PS and FP retreat, mud weight shows a minor increase of 0.5 ppg from the base of salt (12,000 ft) to the well’s 21,000-ft TD. This indicates a weak transgressive pressure envelope and, consequently, failed seal compartments, i.e. absence of sealing capacity.
Therefore, the targeted subsalt reservoirs are deemed water wet. Moreover, the timing of the salt emplacement in relation to the hydrocarbon migration to the prospect might explain the failure to find hydrocarbons in this well.5 In spite of high sealing capacity in the thin sediments (6,000 ft) above the salt, the prospective section is not economical to pursue.
SALT TOES AND FOLD BELTS
The new, deeper exploration fairway is associated with the creeping salt toe at the Segsbee Escarpment.6 As a result, the lateral stress has generated compressional fold/fault structural plays in the Wilcox-equivalent sediment below the salt. The fault plane in this structural setting usually yields high sealing capacity. Perdido, Walker Ridge and the Mississippi fold belts are the new exciting and promising exploration plays. Based on the released data from these frontier wells, a geopressure model has been proposed to explain some of the trapping mechanism and drilling challenges facing the industry, Fig. 6.
Fig. 6
Fig. 6. This proposed geopressure model explains some of the trapping mechanism and drilling challenges facing the industry in the new frontier exploration play.
In addition to the salt buoyancy effect on the sediment, below and above the salt, rafted sediment blocks embedded in the salt mass and gouges (furrows filled with transported and crumbled sediments) at the base of the salt impact the subsurface geopressure profile. If these older rafted blocks are cased with impermeable layers, PP will show a high gradient. In the case of older sediment plowed underneath the salt toe, the shear stress will substantially reduce the PP in this thin rubble layer underneath the moving salt. Subsalt gouges represent a drilling difficulty and hazard in frontier exploration plays. In addition, the salt buoyancy will accelerate and decelerate PP above and below the salt, respectively.
Atlantis Field. This field was an exploration success that tested a prospect below the salt toe. This probably will not be the general case in the frontier Lower Tertiary fairway, where the targeted traps are located down-dip from the tip of the toe.
The geopressure plot of the discovery well Green Canyon Block 699-1 ST2 shows the relationship between PS, overburden and FP, Fig. 7. Note that the FP is close to the calculated overburden above the salt, whereas PS far exceeds the overburden and FP in the subsalt. This leads to a wide retention capacity window and the presence of a thick column of oil, especially between 17,800 ft and 18,500 ft. On the other hand, the reduction of PS in the subsalt section led to a moderate PG of about 0.61 psi/ft at about 18,400-ft depth (MDT measurements). This can be attributed to the thick salt layer above (about 7,000 ft) and the water depth of the mud line (4,495 ft). Mud weight was increased to 10.5 ppg, and an extra casing point was set in the middle of the salt due to the presence of rafted sediments within the salt body. Moreover, the possible presence of the interface salt-sediment gouge, causing a sharp drop in the PP, was responsible for the sidetrack of the original hole.
Fig. 7
Fig. 7. The geopressure plot of the Green Canyon Block 699-1 ST2 discovery well shows that fracture pressure is close to the calculated overburden above the salt. Modified after Shaker and Smith 2002.
Several wet, sand-rich sections below the pay zone, which started at 18,500 ft to TD (19,500-ft TVD) and concurred with a mud weight increase to 12.4 ppg (overbalanced), led to thick mud cake, stuck pipe, plugback and sidetrack. BP plans to put Atlantis Field on line in 2009. Projected daily production is estimated at 250,000 bopd and 180 MMcfd.
Jack prospect. The Jack prospect is a part of the emerging Wilcox-equivalent salt toe belt at the Sigsbee Escarpment in the Gulf of Mexico deep water. It is located in the Walker Ridge Blocks 758, 759 and 678. Applying the same geopressured model to the salt toe can explain the drilling hurdles of Walker Ridge 759-1 ST 00BP00 (OCS-G-17016), which increased drilling cost to over $100 million. These challenges were:
Lost return at the base of the salt (19,653 ft)
Pump LCM sweep of 13.5 ppg
Inability to stop losses
Sidetrack
Set casing at the salt mass (13,507 ft), possibly due to a rafted sediment block.
CONCLUSION
Exploration in deepwater mini-salt basins and frontier fold belts has yielded and is expected to produce substantial reserves, but it is also very challenging.
Subsalt prospects have many positive qualities. Salt enhances the retention capacity of the reservoirs beneath the salt and the sealing capacity in suprasalt formations. Large reserves are trapped by less-faulted structural closures as a result of salt swells in a mini-basin’s area. There is high sealing capacity of the thrust-faulted system in the fold belt fairways. Reservoirs generate high flowrates due to the high permeability of the younger sediments (Plio-Pleistocene), particularly above the salt. In addition, drilling does not require high mud density to reach objective targets.
These positive attributes can only yield substatial reserves when salt’s challenges are met. While drilling, it is common to encounter problems (kicks, shallow water flows) above the salt due the high principal stress and the pressure gradient. Several casing points may be needed to drill through this zone. Drilling hurdles, especially lost circulation, are common at the salt-sediment interface at the base of the salt, especially in the gouge zone. Drilling bypasses and sidetracks to divert borehole trajectory, to overcome troubles in this zone, sharply increase drilling costs. The moderate to weak pressure gradient and sealing capacity below the salt can be a substantial cause of seal failure and weak water drive in the production phase. There are low-permeability reservoirs in the older Wilcox-equivalent sediments (Eocene-Paleocene). Finally, there is a need to improve subsalt seismic imaging quality and accuracy. WO
ACKNOWEDGEMENTS
The author is greatly indebted to Dr. Colin Sayers for his review of this manuscript and valuable technical advice.
LITERATURE CITED
1 Shaker, S. and M. Smith, “Pore pressure prediction in the challenging supra/subsalt exploration plays in deep water, GOM,” Extended abstract, AAPG Convention, 2002.
2 Berman, A. and J. Rosenfeld, “A new depositional model for the deep water Wilcox-equivalent whopper sand-Changing the paradigm,” World Oil, June, 2007.
3 Terzaghi, K., Theoretical Soil Mechanics, John Wiley and Sons, Inc., New York, 1943.
4 Shaker, S. “Geopressure compartmentalization in Keathley Canyon, deepwater of GOM,” GCAGS Transactions, 2001
5 Shaker, S. “Trapping vs. breaching seals in salt basins: A case history of Macaroni and Mt. Massive, Aluger Basin, GOM,” presented at the GCAGS Annual Convention, San Antonio, Texas, 2004.
6 Chowdhury, A. and S. Lopez-Mora, “Regional geology of deep water salt architecture, offshore GOM,” GCAGS and GCSSEPM, 2004.
THE AUTHOR
Shaker
Dr. Selim S. Shaker has over 30 years of oil industry experience in Egypt, northwest Australia, Algeria, Libya, the North Sea and China. His specialty is prospect risk assessment from an exploration and drilling standpoint. Shaker’s recent work has been in the GOM’s deepwater salt mini-basins and the high-pressure/high-temperature environment of the GOM shelf. He is an active member of AAPG, AADE, SEG, HGS, GSH and GMSH. Shaker is Director and Consulting Geologist for Geopressure Analysis Services, Inc. He may be reached at email: geopressureinc@verizon.net.
©2024 World Oil, © 2024
Ebenezer3
1 month ago
Just something to wet your appetite:
In honor of Dwight "Clint " Moore
https://www.offshore-mag.com/geosciences/article/16760671/subsalt-exploration-us-gulf-subsalt-evolves-into-successful-play
GEOSCIENCES
SUBSALT EXPLORATION US Gulf subsalt evolves into successful play
Jan. 1, 1997
Dwight "Clint" Moore Anadarko Petroleum Corporation Robert O. Brooks (retired) TGS/Calibre Geophysical Company Significant discoveries in Gulf of Mexico subsalt exploration trend. The Mahogany platform being set. Offshore explorers will continue to pursue the US Gulf of Mexico subsalt exploration play because of the enormous profit potential, given the size of discovered and potential oil and gas reserves, the presence of existing infrastructure, advancing geoscientific technology, and
5701salt
Over 40 subsalt wells allow detailed geoscience integration; multiple commercial discoveries now under development
Dwight "Clint" Moore
Anadarko Petroleum Corporation
Robert O. Brooks (retired)
TGS/Calibre Geophysical Company
Significant discoveries in Gulf of Mexico subsalt exploration trend.
5701salt
The Mahogany platform being set.
Offshore explorers will continue to pursue the US Gulf of Mexico subsalt exploration play because of the enormous profit potential, given the size of discovered and potential oil and gas reserves, the presence of existing infrastructure, advancing geoscientific technology, and economically attractive water depths.
Subsalt sandstone reservoir quality has been repeatedly found to be of high porosity, high permeability, and high pressure. These reservoir components set the stage for tremendous production capacity from future discoveries. Thick sequences of primarily Pliocene, Miocene, and even Pleistocene, clastic sandstone sections have revealed subsalt deepwater paleoenvironments, and continue to confirm deepwater depositional models.
Additionally, industry is discovering there is an important stratigraphic interval just below salt. The first 500-1,000 ft below salt is a less competent, shaley section referred to by some drillers as a "gumbo zone", or more accurately, a "non-competent" zone. As a result, over a dozen of the historical subsalt penetrations did not drill deep enough to see beneath this section.
Explorers should remember that future subsalt wells ought to be drilled roughly 4,000-5,000 ft below the base of this zone, so that adequate reservoir sandstone opportunities can be encountered through the predictive cycles of sequence stratigraphy.
It seems clear, that as advanced seismic acquisition and processing techniques provide improvements in seismic image resolution, and subsalt well control continues to refine geologic concepts, geoscientific integration should lead to giant discoveries in multiple style traps beneath the horizontal salt sheets.
Plio-Pleistocene leads to play
As is the case with many new plays, the geotechnical leads for today's subsalt play were hidden in the wells of the 1970-80 Plio-Pleistocene Play, in the same offshore Louisiana and southeast Texas region.
For many years, explorers had drilled to depths from 5,000-10,000 ft looking for oil and gas sands above salt, as the Plio-Pleistocene Play exploded across these south additions of the Outer Continental Shelf. In more than one hundred of these wellbores, drilling was stopped when salt was encountered at the bottom of the hole. Explorers also drilled around the flanks of these prominent salt structures targeting bright spots, or hydrocarbon indicators (HCI), that sometimes also proved to be salt.
Although these occurrences were economically disappointing, they provided geoscientists with many useful data points to better seismically image the depths and geometries of these underlying salt structures.
Beginning of play
Beginning in 1983, and extending throughout the 1980s, nearly one well a year was drilled through salt sheets in the US Gulf of Mexico. Between 1985 and the present, over 40 wells were drilled through or into varying thicknesses of salt, and a significant number of the early wells were unintentional subsalt tests.
Interestingly, Gulf Oil, in 1983, appears to have been the first operator to actively implement an organized effort to pursue subsalt and subweld reserves in the Gulf of Mexico. Two wells, both spudded in late 1983, were drilled without success, and after the company was acquired by another operator, the remaining prospect acreage was allowed to expire without further exploration. Other operators have actually leased some of this acreage in the lease sales of the 1990's, and have since drilled several wells with at least one reported discovery at South Timbalier 260/259.
As early as 1985, some of the subsalt wells were beginning to reveal some significant rock properties. Diamond Shamrock's well on South Marsh Island 200 hit a 990-ft thick salt sheet while in pursuit of a bright spot target. After deciding to drill through the unexpected salt sheet, high pressure shales were encountered directly beneath the salt base. Additional casing had to be run, and the operator even drilled ahead toward the original 13,500-ft intended depth, as they quickly evolved their play concept.
Nearly 2,000-ft below the salt base, a 1,000-ft thick, highly porous and permeable, wet Pleistocene-aged sand was encountered, and thus the significant reservoir potential of subsalt sand was confirmed beneath the salt sheets of the Gulf.
For the next four years, only limited drilling occurred, with no success. Some operators found high permeability and porosity in subsalt sands while others, disappointed at encountering salt sections unintentionally, did not drill deep enough below the salt base to evaluate subsalt sediments at all. Not surprisingly, the absence of a commercial strike pushed the subsalt play into later years.
Decade of discovery
1990 truly proved to be the beginning of the decade of discovery for the subsalt play. Exxon's Mississippi Canyon 211 Mickey prospect, which was drilled that spring, was announced as a 100-200 million bbl discovery, and became the first significant subsalt discovery. Although to date, a decision on its commerciality has not been announced.
The drilling pace began to pick up soon thereafter, and several operators, armed with 3D seismic depth images and better depositional models of the subsalt and suprasalt sediments, began to drill their prospects.
Drilling thick, salt sections was no longer considered a difficult task, as proven in late 1991. Chevron drilled through a 6,950-ft thick salt sheet and then 5,200-ft of subsalt sediments in 724 ft of water at Garden Banks 165, proving that very thick salt sheets could be easily penetrated and even drilled to substantial depths below the salt base.
However, the presence of non-competent shales immediately beneath the salt have presented a far greater challenge to drillers than the salt sheets themselves. The differential between frac gradient and pore pressure can be fairly narrow in this zone, thus complicating drillers decisions involving optimal mudweight selection to control pore pressures and prevent lost circulation.
Play hits commerciality
These efforts all set the stage for the first major strike on the continental shelf in subsalt sediments. Operator Phillips Petroleum Co., and its partners Anadarko Petroleum Corp. and Amoco Production Co., drilled the Mahogany #1 well on Ship Shoal 349 in 1993, testing flows up to 7,256 b/d oil and 9.9 MMcf/d gas on a 32/64-in choke at 7,063# FTP, from its 180-ft thick "P" oil sand. The Mahogany # 2 well was announced as a successful appraisal well in late 1994 with flows from another sand at 4,366 b/d oil and 5.315 MMcf/d gas on a 20/64-in. choke at 6,287# FTP.
In April of 1995, encouraged by a third successful well at Mahogany, Phillips announced the commerciality of the Mahogany Field. A fourth well has also been announced as a successful test appraisal, and a fifth well has been partially drilled to the top of salt, but suspended for installation of the platform this past summer.
First production from this significant new field was expected by yearend 1996, and is projected to reach 22,000 b/d oil and 30 MMcf/d gas in 1997. The platform production is expected to rise as more wells are drilled, and it has the capacity to produce 45,000 b/d oil and 100 MMcf/d gas from up to 20 wells. A new chapter in the prolific history of offshore Gulf of Mexico production is about to begin.
During the drilling of the second Mahogany well, Phillips and Anadarko announced their Teak discovery on South Timbalier 260. Although not indicated as commercial, this second discovery on the shelf, with its combined flow tests of 4,431 b/d oil and 7.7 MMcf/d gas from three zones, flowed from the third zone at 3,743 b/d oil and 5.988 MMcf/d gas on a 22/64-in. choke at 7,220# FTP. Encouraged by the news, other operators spudded several of their subsalt prospects toward the latter part of 1994.
Soon thereafter, 1995 saw the announcement of the second commercial subsalt discovery. Shell Oil, with partners Pennzoil and Amerada Hess, announced the commerciality of their Enchilada prospect, which includes Garden Banks blocks 128, 127, & 172.
When combined with supra-salt discoveries that they had made on adjoining blocks in blocks 83 & 84, reserve estimates of 400 bcf gas and 25 million barrels oil/condensate were indicated. Anticipated flow rates could ultimately reach 300 MMcf/d gas and 40,000 b/d oil & condensate, Shell reported.
1996 yields discoveries
1996 yielded three more announced discoveries, with the most significant perhaps being the Texaco/Chevron Gemini discovery. Located in Mississippi Canyon 292 in 3,393-ft of water, Texaco announced in June that the discovery, actually drilled in 1995, was now considered commercial, after conducting testing operations in the spring of 1996.
The well reportedly flowed from two intervals at a combined rate of 54 MMcf/d gas and 4,405 b/d condensate, from below a salt sheet reported to be 2,908-ft thick. The first interval flowed at 22 MMcf/d gas and 3,778 b/d condensate on a 36/64-in. choke at 3,892# FTP, but is estimated to be producible at rates up to 50 MMcf/d gas and 7,700 b/d condensate, and was restricted by test capacity limitations.
The second interval flowed at 32 MMcf/d gas and 627 b/d condensate on a 48/64-in. choke at 2,225# FTP, but is also estimated to be producible at higher rates, up to 80 MMcf/d gas and 1,500 b/d condensate. An appraisal drilling program is underway, and Texaco has stated that first production might be anticipated in the 1999-2000 time frame.
Meanwhile, Phillips and its partner Anadarko announced another new discovery in the play at the Ship Shoal 361 # 1 Agate well. Tested from two separate zones in the same sand, the well yielded a combined flow of 4,125 b/d oil and 24 MMcf/d gas. The first zone tested at 2,738 b/d oil and 14.4 million cf/d gas on a 17/64-in. choke at 6,773#FTP, and the second zone flowed at 1,388 b/d oil and 9.67 MMcf/d gas on a 18/64-in. choke at 7,038# FTP. Plans for development have not been announced to date.
At the end of 1996, Anadarko, and its partners Phillips and BHP Petroleum, announced another subsalt discovery in Vermilion 375. The Monazite #1 well encountered multiple hydrocarbon bearing sands which were confirmed by well logs, core analyses, and production testing. All tested intervals flowed oil, but data obtained were largely inconclusive due to various problems encountered during test operations, including extensive sand production. Due to wellbore conditions, this well has been plugged and abandoned. Future appraisal drilling will be necessary to determine commerciality of the Monazite discovery.
Again and again, subsalt wells are turning up good reservoir properties, especially high permeability, porosity, and pressures, and strong oil/gas producing zones. While the prospectivity of the play has gained momentum in the months following the Mahogany platform announcement, much less information is available from recent subsalt/subweld wells drilled by other operators, because the US Minerals Management Service maintains confidentiality of results for a period of two full years.
Four wells underway
As this article went to press at the end of 1996, at least four subsalt wildcat wells were underway, two of which were being drilled in water depths over 600 ft. This demonstrates the very large projected reserve potential of the subsalt play as it appears capable of justifying the significantly higher costs of deepwater development.
This is reflective of a fundamental fact of the geology: that the play will be pursued both on and seaward of the outer continental shelf, since the large horizontal salt sheets extend off the shelf into the deepwater areas of the slope, as well.'
Authors' Note:
This article summarizes and updates a technical paper entitled "The Evolving Exploration of the Subsalt Play in the Offshore Gulf of Mexico", by Dwight "Clint" Moore and Robert O. Brooks, presented as a keynote address to the Gulf Coast Association of Geological Societies in Baton Rouge, Louisiana, in October, 1995.
AUTHORS
Dwight "Clint" Moore is Offshore Exploration Geological Supervisor for Anadarko Petroleum. He is a recent past President of the Houston Geological Society, current Chairman of the AAPG Government Affairs Committee, and is chief editor of the text entitled "Productive Low Resistivity Well Logs of the Offshore Gulf of Mexico." He holds degrees with honors in geology and business administration from Southern Methodist University.
Robert O. Brooks recently retired from TGS-Calibre Geophysical, after 37 years of geophysical interpretation experience. He has recently been involved in regional interpretation of stratigraphy, salt style, and salt distribution. He holds a degree in geology from Southern Methodist University.
Copyright 1997 Offshore. All Rights Reserved.
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