Compared to the modern day, technologies used and survey techniques were primitive and well locations were defined by bathymetry and the utilisation of jack-up rigs rather optimising subsurface intersection. Now with Bahamas Petroleum Company’s tenure, modern technologies are being employed in an attempt to finally fully realize the potential of these waters.
Mid to late Forties
Early exploratory activities in the mid to late Forties comprising small, local gravity and magnetic surveys were performed on contract for such companies as Gulf Oil, Standard Oil (Chevron), Superior Oil and Shell. This early activity was designed to highlight basin architecture rather than define specific structures or targets but did result in the drilling of the first Bahamian well (Andros Island #1), drilled onshore on Andros Island designed to a target depth (“T.D.”) of 14583 feet. The well was plugged and abandoned with no significant hydrocarbon shows reported.
1948 to 1955
From 1948 to 1955, the region experienced only limited exploratory activity, though Gulf, in 1948 and 1950, did attempt the first experimental underwater seismic and gravity surveys. Regionally, the Gulf 826-Y well was drilled west of Key West, Florida, notable as the well flowed 18 barrels of 22-24API gravity crude oil from an interval of anhydrite and carbonate (below 10,000ft) similar to those anticipated within the Bahamas Petroleum Company southern licences.
In 1956, Bahamas California Co. (Chevron) and Bahamas Exploration Co. (Gulf) performed a detailed seismic and engineering survey of the Cay Sal Bank area culminating in the second exploration well conducted in The Bahamas, the Cay Sal #1 (T.D. 18906 feet). The well was a joint test by the two companies drilled in 1959 encountering “live oil shows” from 12682 feet to T.D., but with no commercial quantities of hydrocarbons tested.
1959 to 1968
From 1959 to 1968, up to eight companies held the entire Bahamas region under concession. Gulf and Chevron led the majority of the exploratory activity by completing many experimental marine seismic programs (including the use of dynamite as an energy source). The lack of success in the acquisition of this primitive poor quality marine seismic data in the bank regions did not encourage well tests during this period.
In 1970, Gulf, Chevron and Mobil drilled a joint test, the Long Island #1 well (T.D. 17,577 feet), though this well was plugged and abandoned after having encountered live hydrocarbon shows at a depth of approximately 15,900 feet. The rig was then moved to the Great Isaac Bank where the Great Isaac #1 well was drilled by Chevron to a total depth of 17,847 feet. This well did encounter live hydrocarbon shows in the 16,900 feet to 17,700 feet depth interval with an over pressured reservoir containing gassy water at 17,436 to 17,495 feet depth interval. However, no commercial quantities of hydrocarbons were reported on tests.
1970 to 1983
From 1970 to 1983, industry exploratory activity involved new digitally-based seismic, gravity and magnetic surveys. Academic institutions and the Deep Sea Drilling Project were actively involved in attempting to understand the nature of the carbonate bank of The Bahamas through the acquisition of subsea and subsurface samples as well as new seismic and potential field data.
During the early 1980s a number of companies vied for competitive licence positions in Bahamian waters such that by 1984 the companies strongly represented included Esso, Amoco, Tenneco, Texaco, Arco, Breoco and Shell. In 1985, industry exploratory activity included the completion of then state-of-the-art seismic surveys, gravity and magnetic surveys, surface and subsea geochemical surveys, and geotechnical site surveys. Tenneco Oil Company was the leader in employing the greatest amount and variety of exploratory surveys. Further, during this time the international scientific Ocean Drilling Program drilled a series of tests to gather shallow subsurface data.
By late 1986, Tenneco had decided to spud the Doubloon Saxon #1 well; the deepest test drilled in The Bahamas to date and located within the current day Donaldson licence area. The well was successfully drilled to 21,740 feet, T.D’ing in the early Cretaceous above the regional Jurassic source rock intervals. The well encountered a number of live oil shows over a thick interval but did not report commercial quantities of hydrocarbons. Through the Cretaceous, and especially below the Aptian level, sequences of carbonates, fractured dolomites and anhydrites were encountered in multiple potential, reservoir sequences. These units, with around 20 in number where log quality allowed evaluation,, represented repeating units generally over 200′ thick. The well was drilled using a shallower water jack-up rig. Our reexamination of the targeted structure has concluded that whilst a successful drilling operation was conducted the well did not target a valid trap.
Following this significant exploratory test, licence interests remained with Tenneco and Shell (Shell having acquired Arco’s position). Subsequently additional post-drilling seismic surveys were performed by Tenneco and Shell during 1986 and 1987 but all licences were allowed to expire in 1988 so as to avoid incurring a significant work obligation for 1989 of $250m, and due to the then prevailing low oil prices (<$20/bbl).
Overall, the well results indicate the presence of a active petroleum systems, based on the presence, especially in the pre-mid Cretaceous sections, of oil shows of varying quality, abundant reservoirs and seals, indications of source rocks, and hydrocarbon saturations from log interpretation. Carbonates, the major component rocks of this region, globally contain 60% of the world’s oil but are not often encountered by nor best understood by many of todays major and independent oil companies. So now, into the modern era of new 3D technologies, deeper water drilling equipment becoming commonplace and sustained demand, Bahamas Petroleum Company has the opportunity to complete the exploration of this exciting potential hydrocarbon province.
The Company was awarded its licences in 2007. Once awarded, the Company sought to collect all available historical, geological and geophysical data from oil exploration projects in The Bahamas. This led to a three-year international search and purchase of historical materials from various oil companies, universities and research institutions. As a result, the Company developed an extensive database including well cores, logs, rock samples and thin sections (from three of the five deep oil exploration wells previously drilled in The Bahamas), approximately 8,000 line kilometres of regional 2D seismic data (of varying quality), and magnetic and gravity data. This data was evaluated using a combination of modern technologies and interpretative techniques, providing encouragement to invest in the acquisition of new data (seismic and further studies), so as to better define the petroleum system elements and the resource potential within the Company’s licences.
In 2010, the Company recorded the first modern offshore seismic survey in the southern Bahamas since the 1980s. Interpretation of this 2D seismic acquisition programme confirmed the presence of several large structures, providing the basis for an independent Competent Person’s Report (“CPR”) completed by Ryder Scott in July 2011. The CPR included the Bain, Cooper and Donaldson licensed areas, highlighting the existence of multiple fold and fault structures and an estimated mean 2 – 3 billion barrels unrisked recoverable oil resources from several different stacked reservoir intervals (with a high case of 7 billion barrels unrisked recoverable oil resources).
Subsequently, in 2011, the Company completed a 3D seismic survey of 3,076 km2 within the Southern Licence area using the latest CGG BroadSeis acquisition technology. This 3D seismic survey firmed up the previously identified structures mapped from the 2D seismic survey, confirming the petroleum resource potential in The Bahamas within multiple, large-scale structural prospects. The high quality of the 3D seismic and extensive other data allowed for several integrated studies by various consulting companies and university departments, so as to continue to reduce the prospect uncertainty. This work included seismic stratigraphy to determine facies classification and distribution, seismic attribute analysis, basin modelling and regional structural reconstruction to determine the timing of crucial petroleum system events such as trap formation and hydrocarbon generation and migration.
An optimal well location was chosen on the crest of the most prospective structure. In 2012 the Company completed a Front End Engineering Design (“FEED”) study for the well design, being consistent with discharging the licence obligation to drill an exploratory well targeting the shallowest prospective horizons and with drilling equipment capable of reaching depths of at least 18,000 feet. To all intents and purposes this meant that, having completed a significant amount of preparatory work, the Company regarded the prospect as ‘drill-ready’. However various ‘above ground’ issues (as detailed further in Section 4 Regulatory Backdrop, below) resulted in a delay to the implementation of these plans.
During the period of this delay, the Company invested considerable additional efforts into a range of technical work focused on the Southern Licences. This work further established the presence and robustness of the petroleum systems, and assessed and sought to mitigate individually source rock interval and maturity, trap formation, oil migration, reservoir and seal risks. This work included analysis of fluid inclusion and oils collected from the region, determining multiple pulses of oil migration from differing source rock intervals, all determined to be in the oil window; an analysis of seal facies and distribution linked to vertical seismic anomalies to determine trap / seal integrity across the prospective structures; seismic inversion to aid determination of reservoir-seal pairs; and, a detailed seismic interpretation to test fault independent closure thus mitigating trap risk. Much of this work has been tested and validated through the farm-in process with a wide range of industry majors and large independents.
As a result of this and earlier work BPC determined that the Southern Licences contained considerable oil potential, and in 2017 the Company engaged Moyes & Co, an international petroleum industry consultancy, as external technical experts to conduct an independent audit of BPC’s own assessment of the total petroleum system and prospect portfolio utilising the full range of the Company’s exhaustive database. The key findings were as follows:
- Stock Tank Oil Initially In Place (“STOIIP”) assessed for the prospect structures as 8.4 billion barrels, with an upside of up to 28 billion barrels;
- Applying a recovery factor in the range of 20% – 40% to the Moyes STOIIP volumetrics would result in an unrisked Estimated Ultimate Recoverable (“EUR”) in the range of 1.6 billion to 3.3 billion barrels (mean), and up to 11 billion barrels (upside); and,
- Moyes & Co. independently calculated the probability of success (“PoS”) factors for each of the stacked reservoirs assessed, the majority of which were calculated in the 25 – 35% range.
Based on several field developmental studies BPC believes that the minimum field size for an economic development of this nature is less than 200 million barrels (versus the resource estimates measured in billions of barrels, as noted in the independent Moyes & Co review), and that the project therefore offers robust commerciality even in a series of credible downside scenarios.
Combining all of the technical work and interpretation, the Company was able to build on earlier well design efforts to develop a range of potential well locations and well plan options, based upon in-depth reviews of wells previously drilled in The Bahamas. A particular issue affecting historical exploration well drilling performance was the slow rate of penetration (“ROP”) of the drill bit. Studies were initiated taking account of recent technology and drilling philosophy developments, whilst also adopting and implementing global standards and best practices. The results of these studies suggested that significant improvements could be made to ROP, thus substantially reducing the predicted time it would take to drill any chosen well. Based on these studies, BPC estimated that an exploration well to a depth of up to 6,500 meters (21,500 feet) would take between 40 and 60 days to drill and assess. Further, well cost updates have incorporated the substantial reduction in global rig rates and availability, to arrive at the current well cost estimates (refer to Section 5, Well Location, Historical Cost Estimates and Funding Strategy, below).
The Company has, to date, expended in excess of US$100 million, much of it in relation to the above summarised technical work (including data acquisition, interpretation and studies). In aggregate, the Company believes this technical work has established a project with:
- stacked play systems from Late Jurassic syn-rift clastics, to Cretaceous shallow water carbonates with reefal geometries and shallower slope talus debris fields, in structures and stratigraphies mapped from 3D – totalling over 20,000 feet of stratigraphic column;
- three and four-way dip closed structures mapped at over 70 kilometres along strike length, with gross column heights up to 1,000m and areal extent ~400km2;
- the prospect of a world-scale, multi-billion barrel petroleum resource, similar in scale and size to resources encountered in more well-known petroleum producing regions, and highly analogous to the Iranian Zagros mountains and the Mexican Salinas basins both producing from fold and thrust exploration plays, with the likely source rock charging the Company structures being the same age and type as the Bossier-Smackover petroleum system that charges the deepwater fields in the Eastern US Gulf of Mexico and nearby Cuba; and
- a significant reduction in estimated well cost when compared to prior estimates, attributable to current rig rates, an anticipated improvement in ROP (principally associated with technical advances in drill bit technology) and lower estimated logistical and support costs.