It is the year of deepwater Namibia, that is for certain, and there will be several gas probes in the Eastern Mediterranean.
Elephant hunting returned to the African hydrocarbon patch in 2020/2021 and continued at a frenzied pace in 2022.
Despite two back-to-back annual Conferences of the Parties (COP 26 & COP 27) in 2021 and 2022, calling for decarbonization, oil companies continued foraging for fossil fuels in the continent’s frontier basins.
In the last edition of Africa Oil+Gas Report for the year 2021, we had declared: “For all we know, 2022 may turn out to be the year of basin openings. Shell and TOTAL continue their probes of the orange basin off the contiguous coasts of Namibia and South Africa; ENI will test the Lamu basin off Kenya; ReconAfrica will drill the first seismically defined location in the Kavango Basin. The testing of Zimbabwe’s Cahora Bassa basin is close to start”.
While Namibia opened up as a large deep-water frontier, it stumbled as an inland basin hunt. ENI lost its bet offshore Kenya and the jury is still out on Zimbabwe.
But we continue to have a wager on South Africa, despite the systemic opposition to fossil fuel development by the country’s political and business elites.
In this issue, we provide a list of new marginal field operators that look likely to get on the rig sites and start their development in the year. We also provide full disclosure on the three most prospective assets in the current Nigerian mini bid round.
We invite you to become a paying subscriber of our monthly harvest and walk through a number of operational events that will run through the year -from seismic activity through drilling count to oil field construction and FID issues. Our theme is Who Is Doing What and Where in 2023?
The Africa Oil+Gas Report is the primer of the hydrocarbon industry on the continent. It is the market leader in local contextualizing of global developments and policy issues and is the go-to medium for decision makers, whether they be international corporations or local entrepreneurs, technical enterprises or financing institutions. Published by the Festac News Press Limited since 2001, AOGR is a paid subscription, monthly hard copy and e-copy publication delivered around the world. Its website remains www.africaoilgasreport.com, and the contact email address is email@example.com. Contact telephone numbers in the West African regional headquarters in Lagos are +2348124374087, +2348130733523, +2347062420127, +2348036525979, +2348023902519.
Exploration in the Northwest African Margin has been a bumpy ride for wildcatters since the discovery of the Sangomar oil field in November 2014.
What you get in these deepwaters on the edge of Mauritania, Senegal, The Gambia, Guinea-Bissau, and Guinea-Conakry is not always as golden as the headline media stories promise.
The Sangomar discovery drew explorers to the MSGBC basin like ants to open, wet sugar.
New York listed Kosmos Energy encountered sizeable tanks of natural gas with the Tortue-1 well, drilled off Mauritania six months after Cairn Energy’s Sangomar find. The company made more gas discoveries after Tortue-1; in Guembeul-1 off Senegal, in Ahmeyin-2, off Mauritania, Terranga-1 and Marsouin-1.
Having found so much gas, and constructed an elaborate plan to valorize the resource through a Floating LNG development, Kosmos set out to look for crude oil in the same acreages where it had found gas, by interrogating the geologic trends it had mapped and refining its charge model in order to define the prospectivity of the deeper waters. But it never succeeded in encountering liquid hydrocarbons.
The second exploration phase, as it was called, threw up three dry holes out of four wells. The only discovery in that phase was the Yakar gas discovery, which Kosmos quickly moved to declare as the “industry’s largest hydrocarbon discovery of 2017”.
Elsewhere in the MSGBC, meanwhile, other operators had their issues.
In October 2018, the Australian minnow, FAR, announced that Samo-1, drilled in block A2 offshore The Gambia, was a dry hole. It was the first exploration well in the country in 40 years. But FAR, a small company without any hydrocarbon production to its name, has been talking things up. It is claiming it will drill another well in the vicinity of Samo-1 before the end of 2021.
TOTAL moved the drillshipPacific Santa Ana to drill the wildcat JAMM-1X, in 2,400metres of water offshore Senegal in April 2019. Some difficulty with the BOP (Blow Out Preventer) led to a break in drilling operations around the third week of June. The well was finalized in mid-August 2019, with minor oil shows. The French supermajor quietly licked its wound. The depressing story barely made it into the news.
TOTAL harvested a more disappointing result in the next well, the Richat-1 well located offshore Mauritania, further north of JAMM-1X. The prospect on the flanks of a large diapir structure, sitting close to the continent / ocean boundary, was drilled, in 1,500metre water depth, with the same Pacific Santa Ana.
Richat-1, was burdened with a lot of expectations: its primary objectives were prognosed to be submarine fan / channel sands at a distal location on a late Cretaceous delta / fan system, where the Nouakchott (Cenomanian-Santonian) and Nouadhibou (Campanian-Maastrichtian) systems overlap. The prospect lies along trend, with a likely similar stratigraphic setting to the giant Yakaar gas discovery and Requien Tigre prospect on the Senegal fan.
But it was dry.
Explorers haven’t exactly nailed a formula for the MSGBC basin, the way they have come to understand the Tano basin, a sub basin of the West African Transform Margin.
Remember how we got here.
In 2001, thirteen years before the Sangomar field was discovered, Woodside Energy announced Northwest Africa to the world, with the discovery of the Chinguetti field, located in 1,000metre water depth, 90kilometres west of Nouakchott, the Mauritanian capital. The company originally claimed 120Million barrels of oil as estimated recoverable reserves, and planned the $750Million field development on the basis of these reserves estimates, deploying a 1.6Million barrel capacity FPSO to drain the reservoirs. First oil came out in February of 2006. Nine months later, however, the Australian operator issued a statement reducing the field’s Proven and Probable (2P) reserves to 53Million barrels. At the end of 2007, 2P reserves were put at 34Million barrels.
Nor have the other fields discovered by Woodside in the neighbourhood of Chinguetti fared well either.
Plans to develop the Banda field for a gas to power project have suffered a still birth, as have the proposals to tie the Tiof gas field to Chinguetti’s development.
With such a history, it is instructive that deepwater Northwest Africa remains a magnet especially for majors.
TOTAL took 90% of Senegal’s Rufisque Offshore Profond blockn May 2017, with Société Nationale des Pétroles du Sénégal (Petrosen), holding the remaining 10%. The company signed into Blocks C15 and C31, sited off Mauritania, in December 2018, adding to the three blocks (C7, C9 and C18), it already had interest in. These were following after the agreement it had, a full year earlier, with the National Office of Petroleum of Guinea, for Technical Evaluation Agreement to study deep and ultra-deep offshore areas located off the coast of Guinea Conakry.
ExxonMobil initiated acquisition of its largest-ever proprietary seismic survey-anywhere in the world- over Mauritania’s blocks C-14, C-17, and C-22, in October 2018, covering more than 6,500 kilometers of two dimensional (2D) and nearly 21,000 square kilometers of 3D seismic data. The acreages are located in water depths ranging from 1,000metres to 3,500 metres.
BP had moved forcefully into MSGBC earlier than TOTAL and ExxonMobil, taking up 62% participating interest in Kosmos Energy held C-6, C-8, C-12 and C-13 exploration blocks in Mauritania and a 60% participating interest in the Cayar Profond and St Louis Profond exploration blocks in Senegal.
As operator of these assets the British supermajor is leading the Floating LNG project scheduled to deliver first gas by 2022. And plans are ahead to for the expanded phase of the project.
In November, BP announced that three appraisal wells drilled in 2019, GTA-1, Yakaar-2 and Orca-1, targeted a total of nine hydrocarbon-bearing zones. The wells encountered gas in high quality reservoirs in all nine zones, the company said.
So, it is quite a mixed grill in the MSGBC.
Woodside’s return to the region is a story that signifies the complexity of events in Northwest Africa.
Australia’s largest oil company bought into the Sangomar oil field development project and became operator, as if, despite its withdrawal from Chinguetti, nine years earlier, it could not bear to witness any other company take the glory of operating the first oil field in the region since then.
The field development has been sanctioned. Phase 1 of the Sangomar FDP will target an estimated 231 MMbbl of oil resources from the lower, less complex reservoirs, and an initial pilot phase in the upper reservoirs. Woodside has executed the purchase contract for the FPSO facility and issued full notices to proceed for the drilling and subsea construction and installation contracts, including to MODEC, Inc. for the purchase of an FPSO with an oil processing capacity of 100,000 bbl/day, to Subsea Integration Alliance for the construction and installation of the integrated subsea production systems and subsea umbilicals, risers and flowlines and Diamond Offshore for two well-based contracts for the drill rigs Ocean BlackRhino and Ocean BlackHawk.
All seems set, such that, by 2024, offshore Senegal and Mauritania would likely be hosting two floaters; an FPSO producing, mainly, crude oil and an FLNG exporting natural gas.
That would be 10 years after the discovery of Sangomar.
When Cairn Energy encountered the SNE field in deep-water offshore Senegal in 2014, it was hailed,in the energy press, as one of the largest oil discoveries anywhere in the world in that year.
The discovery opened, farther, the North West African segment of the Transform Margin, and spurred a renewed rush for acreage acquisitions in the Mauritania-Senegal-Guinea-Bissau Basin, in a way that could be compared to how Ghana’s Mahogany discovery, seven years earlier, animated conversations around the West Africa Transform Margin.
But Ghana’s Mahogany discovery, which became the basis for the Jubilee field development,reached the market in the space of three years after the find. The Jubilee Phase 1 development was approved in July 2009 and the field came on stream in the Christmas of 2010, targeting 120,000BOPD at peak.
Conversely, in the fifth year of its discovery, the SNE field is yet to reach Final Investment Decision.
For one, Ghana’s oil discovery was made as the price of crude oil was about to take off to stratospheric highs. The Senegalese find came as prices were plunging.
Kosmos Energy, the finders of Mahogany-1, encountered a robust structure in deep water which,with Heydua-1 discovery (by Tullow Oil) several months later, was a straddle play that was the kind of hub structure they could develop rapidly.
Cairn, on the other hand, needed a string of appraisal wells to convince itself it could declarecommerciality of the SNE structure and construct a field development plan.
So the delays in development are as much a question of geology as they are about crude oil price regime and overall bankability.
French major TOTAL has taken two investment decisions on Angola’s deepwater Block 17, to develop satellite fields that will be tied back to existing infrastructures and will quickly bring additional production.
The CLOV phase 2 project, which requires the drilling of 7 additional wells, with first oil expected in 2020 and a production plateau of 40,000 barrels of oil per day (BOPD).
The Dalia phase 3 project, which requires the drilling of 6 additional wells, with first oil expected in 2021 and a production plateau of 30,000 BOPD.
Zinia 2, CLOV 2 and Dalia 3 will develop 150Million Barrels of additional resources to maintain the Block 17 production plateau above 400,000 BOPD until 2023, and further extend the profitability of this prolific block, with over 2.6Billion barrels already produced.
In deep-water Africa, geology has proven to be a trickster god
Stories by Toyin Akinosho
The newest deep-water frontiers in West Africa’s exploration rush have not been as forthcoming as the sites of the last major wave of discoveries.
Liberia, Sierra Leone, Namibia and Cote D’Ivoire are the focus of wildcat activities today, the way Nigeria, Angola and Equatorial Guinea were in the mid -90s.
But in the place of the large elephant-sized discoveries of 1994-2004, the Sierra-Leonean Basin, the Abidjan Margin and the Ivorien parts of the Tano basin, have so far delivered mere pimples.
Ghana, which represents the transition between the two waves, has provided the only really big finds, outside of Angola, in West Africa in the last five years.
As far as the elephants are concerned, the locus has shifted to East African deep-water, which is all about gas.
What’s clear so far is that the Cretaceous plays, the target of recent West African probes, have not shown themselves as prolific as the Tertiary, where the ongoing East African deep-water rush has played out.
Note that Nigerian deep-water(The Niger Cone) and Angolan deep-water(The Congo Fan), which dominated the headlines all over the world 10-20 years ago, are Tertiary plays(sediments deposited between 65million and 2.6 million years ago). Which leads us to something: as far as the data in hand suggest, to be big, your deep-water African prospects need to be in the tertiary. But that’s a digression.
“I always knew that the non-Deltaic West African Passive Margin (also known as the West African Transform Margin)is just beginning to be unraveled”, says Ebi Omatsola, Managing Director of the Nigerian independent Conoil Producing and the continent’s leading exploration thinker, warning that it is early days yet. Omatsola had anticipated the basin-opening discovery of Ghana’s Jubilee field as far back as 16 years ago. His prediction, given at a presentation in Accra in 1997, came to fruition 10 years after. Still he doesn’t want to raise expectations about Liberia, Sierra Leone and Cote d’Ivore. “You must understand the geometry of the sand body and other factors to make it work”, he contends.
Tullow Oil, the unfailingly optimistic British explorer, doesn’t sound terribly upbeat about these countries either. It has proven oil and gas condensate system in Sierra Leone and Liberia, it says, but “thick sands only have oil shows(breached traps) and oil bearing sands have low net-to-gross ratio”. The company declares, in its first half 2012 report, that the exploration campaign has found oil but “only satellite class discoveries” have been made to date, whereas, for commerciality, “ hub class discoveries are needed”.
Investec Securities, scrutinizing Tullow Oil’s portfolio, declares that, based on targeted barrels by Tullow, ”the west African transform margin(Kosrou, Mercury, Teak) failed to deliver and so did itsAtlantic (Jaguar and Zaedyus)mirror image play(Jaguar and Zaedyus, in the Carribeans) in 2012”.
Chevron has operated three deep-water acreages off Liberia since September 2010. An August 2012 farm in deal by Eni, the Italian major, into these tracts, signaled that the transform margin was firm on the radar screen of the industry’s majors. But a farm in by one major has meant a farm down by another. With that transaction, Chevron’s operated interest in LB 11, LB12 and LB14 was reduced to 45%, with the Nigerian minnow Oranto holding 30% and Eni has 25%. It’s instructive that Chevron has drilled in Liberia, but is not excited enough to share the results.
The biggest discovery in the Sierra Leone-Liberian basin has been that of African Petroleum Corp. APC, an Australian minor and, perhaps the smallest operator in the province. The company encountered 32 metres of net oil pay in two zones off Liberia with Narina 1, in February 2012.The well reached total depth of 4,850 metres, in water depth of 1, 143metres. Narina-1was the company’s second shot at the Liberian offshore. Its first well, Apalis-1, drilled in September 2011, encountered only minor oil shows.
Lukoil was drilling a well in SL-05-11 Block, off Sierra Leone as of the time of writing this. SL-05-11 is one of the two Sierra Leonean tracts in which the company holds interest. In November 2012, Lukoilacquired a25% stake in the SL-4B-10 block, which adjoins SL-05-11.
Cote d’Ivoire has always appeared more promising than either Sierra Leone or Liberia, in part because some of its most prospective structures are located in the same Tano Basin that has yielded all of Ghana’s big discoveries. Tullow Oil, for one, claims that its discovery well Paon 1(June 2012) was drilled on a sand fairway analogous to the fairways on which the Jubilee field and the TEN(Tweneboa, Enyenra and Ntomme), cluster wells are located(see illustration). Tullow and its partners say the well, which encountered 31 metres of net oil sands in one interval, “confirms the Upper Cretaceous fan system present in Ghana extends westward into Côte d’Ivoire and provides significant running room within the CI-103 block” in which it islocated.
The question of how many more Paons are in the fairway and how big they are, will be answered in the campaign that Tullow is leading in 2013.
Lukoil expressed its faith in Cote d’Ivore in October 2012 by converting an exploration licence to a production tract. Block CI-524 represents an eastern part of block CI-401 which Lukoil Overseas has been involved in exploring since 2006. Lukoil holds a 60% interest, PanAtlantichas 30% and state hydrocarbon company PETROCI has 10%. Less than a year earlier, in December 2011, the partners had announced a discovery Independance-1X in Block CI-401. Although the result communicated was that the well penetrated only “eight metres (26 feet) of hydrocarbon pay in good-quality Turonian-aged sand package”, Lukoil beamed that the well was its “most important discovery of the year 2011”.It’s difficult to understand.
What about the “older frontiers”, the site of the first big wave of African deepwater discoveries?
Equatorial Guinea came up with some noteworthy successes in 2012; with Ophir reporting three gas discoveries in its Block R; sizeable enough for the company to contemplate a 1 Train LNG project deliverable by 2017.
There has been no deepwater discovery in Nigeria in the last five years. And no one, as far as we know, plans a wildcat drilling in that country in 2013. Operators are placing a bet on Angola, which has been touting the potentials of the presalt sequence in its Kwanza basin.
Only three wells have been drilled in the “Brazil look-alike” sag basin part of the pre-salt Angola; including the Maersk Azul-1, Cameia-1 discovery & Cameia-2 appraisal, and the PetrobrasOgonga dry hole. This means that there have been only two discoveries, which can so far be described as encouraging “teasers” but it will take much more drilling to really know what is going on. My worry is that the Kwanza Basin is in the cretaceous. If the pre-Salt in Angola turns out to yield huge discoveries of elephant-size, I’d start looking positively on cretaceous basins again.
There has been no let up on the pace of gas discoveries offshore Mozambique since Anadarko announced 168metres of net gas sand in the Windjammer 1 well in February 2010. Barquentine 1 and Lagosta 1 discoveries followed with 127 metrenet gas and168 metrenet gas sands respectively in October and November 2010. These are quite tall hydrocarbon columns, with extensive widthin highly connected fairways. Massive pools of gas indeed. Anadarko’s 36.6% operated Area 1, in water depths of around 1,500metres, includes Mitsui E&P (20%), BPRL Ventures (10%)andVideocon (8.5%), as partners.
These discoveries have been combined together in what Anadarko has christened “The Prosperidade Complex”. With subsequent appraisal drilling and testing programme, the American independent estimates that this supertank, spanning approximately 260 square kilometers, “holds at least 17 trillion cubic feet (Tcf) of recoverable natural gas, and it could hold as much as 30 Tcf or more”, says Al Walker, Anadarko’s President and Chief Executive. “To put these numbers into context, that’s enough recoverable natural gas to transform Mozambique into the world’s third-largest exporter of LNG (liquefied natural gas) over the coming years”.
The Gulf/Atum complex, to the north of Prosperide, is credited with at least 15Tcf of recoverable natural gas, with the assumption that it could hold as much as 35Tcf or more. Initial appraisal drilling has been completed in this complex and integrated appraisal drilling is underway.
Beyond Prosperidade and Gulf/Atum, the company believes there is the opportunity for even more petroleum resources to be found in the 10, 500 square kilometre Offshore Area 1. “Our partnership has identified more than 20 additional exploration prospects and leads in the offshore block and is continuing an active exploration programme in these areas”.
ENI’s first discovery in deepwater Mozambique came over 18months after Anadarko cracked the geologic code. Yet the announcement was not without its drama. The Italian major described the find in the Mamba South 1as the largest hydrocarbon discovery in its history. The probe encountereda total of 212 meters of continuous gas pay in high-quality Oligocene sands. Eni went on to announce, without saying whether it had tested the reservoirs or not, that Mamba South held 15-20Tcf of gas in place. Eni has a 70% operatorship’s interest in Area 4, where all its discoveries have taken place to date, with co-owners being Portuguese GalpEnergia, Korea Gas Corp (KOGAS), and state-owned ENH, each holding a 10 percent interest. A week after the first announcement, Eni reported that the well had been deepened and a further 7.5 tcf of gas located. “22.5 tcf of gas-in-place” had now been found
Mamba South was followed, in mid-February 2012, by the Mamba North 1 discovery, located in water depths of 1,690 meters, drilled to a total depth of 5,330 meters and is located about 23 km north of Mamba South 1 discovery. The discovery well encountered a total of 186 meters of gas pay in multiple high-quality Oligocene and Paleocene sands.
The site of this rich seam is the Rovuma Basin, deep in the Indian Ocean, the eastern boundary of the African continent.
It is in this same basin, in neighbouring Tanzania, that the BG/Ophir Joint Venture(Blocks 1,3, and 4) on the one hand and Statoil(Block 2) on the other, have both been encountering pools after massive pools of gas since 2011.
Drilling commenced in Tanzania’s “deepsea” (as the country’s authorities call it) in 2010 with Pweza-1 and since then, none of the operators have gone wrong with a well prognosis.
The partners did not sound terribly enthusiastic when they broke the news of the first two gas discoveries, both in Tertiary sequences, in Block 4, around the same time as the initial stories out of offshore Mozambique were making the rounds. This magazine, in particular, got the impression that the Tanzanian finds were somewhat suboptimal.
‘The statements from partners BG (60%) and Ophir(40%) are carefully worded sentences’, we reported. “The success of the Chewa-1 well follows on from the earlier Pweza-1 discovery and provides a measure of confidence in the use of seismic attributes to guide a successful exploration campaign, in Tanzania” said Allan Stein, CEO Ophir. “We have now calibrated the seismic response from two separate hydrocarbon bearing reservoir intervals and shall use this information to more fully evaluate the potential of this exciting new hydrocarbon province.”
The Joint Venture reported the third discovery, Chaza-1, this time in Block 1, in 2011. The find was approximately 200 kilometres south of the Pweza and Chewa discoveries. The Joint Venture acquired a 3,250 square kilometre 3D seismic survey in Blocks 3 and 4, and a second 3D survey of 1,850 square kilometres in Block 1. At this time BG took over operatorship. Further success came the following year with the Jodari discovery in Block 1 which, unlike the previous finds, was followed up with appraisal wells. The partners drilled three wells at Jodari South-1, Jodari South ST-1 and Jodari North-1. The JV at this time, began talking about gas volumes and putative field development.“These wells demonstrated consistent, high reservoir quality across the Jodari field and confirmed the mean recoverable estimate of 3.4 trillion cubic feet of gas. The work also confirmed the feasibility of high-angle drilling, thereby reducing developing costs”, Ophir noted in a press release..
3D seismic interpretation had, by now revealed basin floor fans and amalgamated channel sequences of Tertiary age, both being potentially analogous to those seen on the adjacent Mozambique side of the Rovuma Delta. The partners moved to acquire a further 2,500sq km 3D data to image thisMozambique-basin floor type play in Block 1.
But while that was going on, they’d gotten ahead to test sequences in the Cretaceous; older sequences of rock than the tertiary age sequences they had encountered in the first four discoveries. The late 2012 discoveries: Mzia 1 and Papa 1, encountered hydrocarbon sands in the Cretaceous.
“Mzia-1 opened up an extensive new play fairway within the JV’s offshore acreage in Blocks 1, 3 and 4, to complement the now proven Tertiary fairway.
Papa-1, drilled after Mzia 1, represents the first exploration test of Upper Cretaceous Intraslope play outboard of the Rufiji Delta and the first well to be drilled in Block 3. The well was designed to evaluate sandstones of Campanian and Albian age within the structural Papa prospect. “The Papa discovery further de-risks the deeper, Upper Cretaceous Intraslope play in Tanzania. Additional resources have now been discovered in the Cretaceous stratigraphy outboard of both the Rovuma and Rufiji Deltas by the Mzia-1 and Papa-1 wells”. Thus, while the BG-Ophir Joint Venture’s first four discoveries successfully tested targets of Miocene, Oligocene and Paleocene age in the Tertiary Intraslope Play and are currently estimated to have discovered total recoverable resources of ca. 7 TCF (1167 MMBOE), the fifth discovery, Mzia, and the sixth discovery, Papa, both in the new Upper Cretaceous Intraslope Play are expected to add considerable additional recoverable resource to this total.
By December 2012, two years after first drilling, BG/Ophir had announced six consecutive discoveries while Statoil/ExxonMobil, had come up with three, all of which make a total of nine, offshore Tanzania. The BG/Ophir JV figures it had discovered 13.5 – 21 TCF as in- place resource of October 2012 which means, in its view, it has proved up minimum commercial resources for two-train LNG development.
Since commercial production commenced with the deepwater Jubilee field in December 2010, Ghana has ranked prominently on the hydrocarbon map of the world. It looks likely to record average 2013 production in excess of a hundred thousand barrels of crude oil per day as Jubilee ramps up to peak of 120,000BOPD. But all the current production, planned production and drilling successes are clustered around the Tano Basin and its sub-basin: the Cape Three Points. Any step out of the Tano, into another basin has so far resulted in failure. The UK listed Afren Corp., has felt the full brunt. Barely six months after it acquired 68% interest in Keta Block on the Accra Keta basin, Afren spudded Cuda 1. It came out unsuccessful. The company beamed with optimism after the failure, saying that the block, located farther east, towards the Ghanaian border with the Republic of Togo, had both Tertiary and Cretaceous prospectivity, with the principal exploration focus being the Cretaceous Albian to Campanian sections. “The block offers multiple prospects and leads, with a variety of trapping and depositional settings. A number of these show potential for significant stratigraphic trapping and giant field potential”, Afren enthuses on its website. In 2011, Afren farmed out 35% participating interest and operatorship to Italian major Eni, who in turn drilled a well within a year of buying in. Eni’s well, Nunya-1X(formerly named Cuda 2) was a spectacular failure. It didn’t encounter a drop of hydrocarbon and more, it gave the lie to Afren’s claims that Cuda-1 would have encountered oil if it had drilled deeper. Apart from the Afren/Eni adventure in Keta, there hasn’t been drilling on any other basin outside the Tano. The Saltpond basin still delivers trickles (less than 500BOPD) through the Saltpond filed. Operators have not ventured to drill in the deepwater Saltpond/Central Basin, which is the country’s third prominent deepwater basin. Still, who cares whether these other basins deliver, as long as there’s continuing success in the Tano Basin? A field development plan of a 100,000BOPD(peak) has been submitted to government. The Plan Of Development (POD) looks to bring together a cluster of fields collectively named TEN(Twenoba, Enyenra and Ntomme). Another such cluster of fields, the MTAB(Mahogany, Teak, Akasa and Banda) is in pre-development plan stage and is expected to deliver 100,000BOPD at peak. Both projects, located in Deepwater Tano/Cape Three Points Blocks, envisage the crude to be produced through an FPSO each. They are also, both, being operated by the British explorer Tullow Oil, with partners including American independents Anadarko and Kosmos Energy. Meanwhile, Eni, which has failed in Accra Keita, announced a successful find in the Offshore Cape Three Points(OCTP), in the Tano Basin early in 2012, testing 5,000BOPD of “high quality oil” from a gross oil column of 76metres. And Hess Corp, reported, in 2012, its fifth discovery in Deepwater Tano-Cape Three Points License. The company reported that Pecan 1 follows the previously reported discoveries at Almond (16metres net oil pay), Beech (44metres net oil pay), Hickory North (30 metres net gas-condensate pay), and Paradise (37metres net oil pay and 90 metres net gas-condensate pay). Ghana has had a good five years, since the discovery of Jubilee(2007-2012) in terms of overall oilfield activity relating to both the drillbit and the commercial playground: almost as soon as Tullow Oil announced the discovery of the Twenoboa held, proving that the deepwater oil tank extends beyond Jubilee, news filtered in about ExxonMohil s interest in acquiring Kosmos Energy’s stake in Jubilee for $4billion. The reputation of the putative buyer and the amount of money on the table heightened the perception of profitability of the overall Ghanaian portfolio. But beyond the Deepwater Tano and Cape Three Points blocks and adjacent acreages, what other acreages can be prospective enough to interest any company? The Tano Basin itself was a grave yard of hopes just 15 years ago, until Kosmos, Anadarko and Tullow started re-interpreting the data differently from earlier explorers. Kosmos itself described the Tano Basin as a bad address only six years ago.
Gabon is hoping to launch a new deep offshore oil licensing round in June 2013, offering licences in its own segment of the pre-salt sequence, which has been imaged by seismic shots that have penetrated layers of sediments deposited during the break-up of the supercontinent in which Africa and South America were joined together. That supercontinent, named Gondwanaland, included most of the landmasses in today’s Southern Hemisphere, but Africa and South America were particularly tightly knit within that space. The split of Africa/South America, 125 million years ago, resulted in the creation of the south Atlantic. This is why an oil discovery in Brazil could be sometimes seen to be a positive thing for Africa, especially those parts of Africa which were essentially “joined at the hip” with Brazil, when Gondwanaland existed. Those parts include Angola and Gabon. Previous deepwater exploration in Gabon led to four wells drilled in the lower Congo Basin between 2000 and 2002. A TOTAL led consortium came up with three dry holes, located in water depths in excess of 2,000metres to total depths of 4806metres, 4793metres and 4047metres respectively, all very deep wells, in the Astrid Marin acreage. Agip came up dry at a TD of 2,882metres in Powe Marin 1, drilled in water depth of 1,000metres. In 2005 Amerada Hess, running on adrenalin from its success foray in deepwater Equatorial Guinea, drilled two equally disappointing wells in deep offshore Ogooue Delta. There have been explanations for the poor results in the Gabonese deepwater segment of the Oogue Delta and the Lower Congo Basins: • The Ogoeue Delta is not formed by the kind of large sized rivers like the Congo River which birthed the Congo Basin, or the Niger and Benue rivers which created the Niger Delta. • The part of the lower Congo Basin that is in deepwater Gabon contains the obligatory hydrocarbon source, but it is buried too deep and the apparent lack of structuration disallows the source to adequately charge the reservoirs. Seismic data doesn’t suggest the presence of large scale canyons that could help deliver products of turbiditic flows into the deeper waters. There have been questions about of whether the direction of flow of the Benguela currents, which impact sediment movement on the Nigerian coast for example, could have anything to do with the possible lack of commercial hydrocarbon reservoirs in deepwater Gabon. The jury is still out on that. Whatever the explanations, Gabonese authorities say they desperately need to shore up production, which has declined from 365,000BOPD in 1995, to 225,000BOPD in 2012. New data acquired in the last three years by CCGVeritas have shown up the potentials that inhere in testing the presalt sequence, invoking the theory that if Brazil could find massive volumes of oil in the pre-salt deepwater sequence in Tupi(now Lula)-1 well in the Campos Basin, so can wells in Gabon. The survey included more than 9600km of 2D seismic in Gabon’s southern and northern offshore zones, as well as 4,500 sqkm of 3D and 2D data in the southern zone. Geologists now know that some of the basins on either side of the south Atlantic were formed at the same time during the rift phase and today are mirror images of each other. Gabonese authorities believe that the country’s deepwater acquatory has never been properly explored. Gabon had planned a licencing round for 2010, but postponed it in order to complete the promulgation of a new set of regulations. There were also issues of rising drilling costs and environmental concerns after BP’s massive spill in the Gulf of Mexico. The percentage the national oil company could hold in the newly licensed fields would depend on its financial capacity but would usually be up to 20%. Approximately it’s between 10% and 20% on (a) commercial basis. The country was producing around 350,000Barrels of Oil Per Day (BOPD), about the highest in its production history, in the mid 1990s, when countries like Nigeria and Angola started witnessing a series of spectacular discoveries in water depths outboard of 750 metres. As Gabon shares the prolific Congo basin with Angola, and was the third largest oil producer in sub-Saharan Africa, it was expected to be part of the game.
West Africa remains the top deepwater exploration and production destination on the planet. In the sixteen years since the contest for deepwater spoils was established, this corner of the south Atlantic has led the two other contestants: Brazil and the US Gulf Of Mexico, in attracting investment dollars.
In spite of the recent boost in activity of the US Gulf of Mexico and the discoveries of huge reservoirs below the salt cover in deepwater Brazil, the early lead that West Africa had taken in the mid nineties has turned its waters into a vast, busy parking yard for FPSOs, with such decade old fields as Zafiro, Girassol and Dalia each doing in excess of 150KBOPD on average, even as reservoir maintenance work sets in; relatively newer fields are gushing oil at world class rates and a queue of field development projects are lined up from Equatorial Guinea to Angola.
Take a look at fields that coming on stream in the next two to four years:
Pazflor. TOTAL’s Pazlor project in Block 17, will develop production from the Perpetua, Acacia, Zinia and Hortensia discoveries. First oil is expected in 2011 at the initial rate of 220,000 BOPD. The four fields are scattered over an area of 600 square kilometers, six times the size of Paris, at a water depth of about 1,200metres. Acacia contains light oil, whereas the other three are Miocene characterized by heavy, viscous oil. TOTAL plans to use subsea oil-water separators for the Heavy Oil reservoir. The separated oil and water will be pumped to the FPSO using Electrical Submersible Pumps(ESPs). TOTAL has built an FPSO capable of processing 220,000 BPD of oil and with storage capacity of 1.9 million barrels, The produced water will be re-injected into the reservoirs. The two subsea production systems encompass 49 wells (25 producers, 22 water injectors and two gas injectors) and three subsea separation units connected to six ESPs. The topsides control system is designed to accommodate 21 additional wells and a fourth Subsea separation unit.
CLOV, also in Block 17, will involve gathering hydrocarbon fluids from tour fields: Cravo, Lirio, Orchidea and Violet (CLOV). TOTAL has received approval from its partners to begin drilling in 2012 so as to achieve first oil in 2014. The subsea development will consist of 34 wells tied back to an FPSO with a processing capacity of 160,000 BPD at plateau and storage capacity of 1.78 million Bbls. The FPSO will be able to process two types of crude oil, light oil from Oligocene reservoirs and heavier oil from Miocene reservoirs. Both oil streams would be combined aboard the FPSO in a single train prior to storage.
Aseng: First production from the Aseng field is estimated to commence by mid-year 2012 at 50,000 barrels of oil per day gross (16,500 barrels per day net). Equatorial Guinea’s authorities approved the field development plan for this Noble Energy operated field in July 2009. Located in Block I, it represents the first oil development in the country’s part of the Douala Basin. Initial development of the field will include five subsea wells flowing to a floating production, storage, and off loading vessel (FPSO) where the production stream will be separated. The oil will be stored on the vessel until sold, while the natural gas and water will be injected back into the reservoir to maintain pressure and maximize oil recoveries. The FPSO, to be located in approximately 945metres(3,100feet) of water, will be designed with capacity to handle 120,000 barrels of liquids per day, including 80,000 barrels of oil per day. In addition, the vessel will be capable of re-injecting 170 million cubic feet per day of natural gas. Storage on the vessel will be approximately 1.5 million barrels of oil and condensate. Total cost of development, excluding the cost of the FPSO, which will be leased, is estimated at $1.3 billion ($530 million net). The majority of this capital is to be invested in 2010 and 2011. Over the life of the project, the company expects to recover gross hydrocarbon liquids of approximately 100 to 120 million barrels, with initial reserve bookings beginning in 2009. In addition, there is an estimated 450 to 550 billion cubic feet of gas resources at Aseng that will be produced as part of an integrated gas monetization project once the pressure maintenance phase is completed.
AlenFirst production at Alen field, in deep- water Equatorial Guinea, is estimated to commence by the end of 2013 at 37,500 Bbl/d gross (18,750 barrels per day net). The country’s Ministry of Mines, Industry, and Energy approved the field development plan in December 2010. Initial field development will include three production wells and three subsea natural gas injection wells tied to a processing platform. Produced condensate will be separated and piped to the Aseng floating production, storage, and offloading vessel on Block “l’ 24km to the south, where it will be held until sold. Associated natural gas will be re-injected back into the reservoir to maintain pressure and maximize liquid recoveries. The Alen processing facility will be located in approximately 240 feet of water and is designed to handle 440 million cubic feet per day (Mmcf/d) of natural gas and 40,000 barrels per day (BCPD) of condensate. Natural gas reinjectiori is estimated to be 380 Mmcf/d during gas-recycling. The total cost of development is estimated at $1.6 billion ($735 million net).
Usan Production startup is projected for this TOTAL operated oilfield, in 2012. Maximum total production of 180,000 BOPD is expected by 2013. Located in 900metres of water, Usan Field was discovered in 2002 and began development in 2008. Development drilling commenced in June 2009. There will be 23 production wells as well as 19 water and gas injection wells. Hyundai Heavy Industries will deliver the FPSO in late 2011. Cameron was awarded the contract for the 44-well subsea development.
2. And those that may come on stream in the next four to seven years…
Egina: Front-end engineering design of TOTAL’s deepwater Engina development was nearing completion as of July 2010. The French major awarded the subsea FEED to Nigerian company Dover Engineering in July 2009, with Wood Group companies J P Kenny and MCS Kenny assigned to support the project’s delivery. Egina, discovered in 2003, is in 0ML130, in water depths up to 1,750 m. The Greater Egina development will take in the Egina Main, Egina South, and Preowei fields, although the current programme only covers the Egina Main field — the other two fields are probable future tiebacks. The subsea work scope of work included design studies and engineering assessments; development of specifications; and documentation and technology studies, all relating to the design of the umbilicals, flowlines, risers, and the subsea production systems.
Uge: Negotiations with government and partners for field development is moving slowly along for this 2006 discovery. Uge-1 encountered 100 meters net oil in 1,263 meters of water in OPL 214. The discovery well was drilled a total depth of 5,260metres.
Bosi: Sanction for ExxonMobil operated Bosi field development has been much slower than would have ordinarily been expected of this 1996 discovery. Since a Final Investment Decision(FID) hasn’t happened, all figures are mere estimates. One such is that production will be around 135,000 BOPD optimum, and the crude will be stored in a refurbished FPSO.
Aparo and Bonga SW.
These two fields share a common geologic structure and will be developed simultaneously. The structure is located in 1,344m water depth. The project was delayed in 2009 to secure agreement among the stakeholders on the scope and commercial terms of the project.
Nsiko: Chevron’s next Deepwater project is Nsiko Field, located 144km offshore the western Niger Delta at 1,812m water depth. Subsurface evaluations and field development planning were completed in 2008. Development activities and FEED will begin upon negotiation of the commercial terms.
3. And still in the smithy…
West Africa’s New deepwater discoveries:
This is what Tullow Oil, the UK listed independent, says: “In March 2009, the Tweneboa-1 exploration well discovered a highly pressured light hydrocarbon accumulation. This was followed up by the successful Tweneboa-2 well in January 2010, which encountered oil and gas-condensate 6km south of the original discovery. In July, the Owo-1 oil discovery continued the extraordinary success of Tullow’s West African Equatorial Atlantic campaign, intersecting 53 metres of net oil pay, establishing Owo as a major new oil field. Further appraisal of both fields will form a major part of the 2011 programme with additional prospects already identified.”