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All posts tagged deepwater


The Indian Ocean Keeps Bubbling, By Sully Manope, in Maputo

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.indian2

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.indian 3

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.

 


West Africa Leads Global Deepwater Activity

By Moses Aremu

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.

  1. Take a look at fields that coming on stream in the next two to four years:

ANGOLA

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.

EQUATORIAL GUINEA:

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).

NIGERIA

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…

NIGERIA

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:

GHANA

Twenoboa/Owu

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.”


Ghana Turns The Commercial Corner

Toyin Akinosho reports.

… But geology can still obstruct the roller coaster,

Ghana is going from discovery to first oil in a giant deepwater oilfield, in less time than did Nigeria and Angola. If everything goes according to the press statements of the investing partners in the 800 million barrel Jubilee field project, the field would be delivering oil in just about three years from discovery. Jubilee was discovered in June 2007; the partners Tullow, Anadarko and Kosmos insist that the field is coming on stream sometime in the second half of 2010.

Angola’s Girassol and Nigeria’s Bonga, with roughly the same status and significance as Ghana’s Jubilee, made it to first oil in more than five years after they were each discovered. Apart from these two, there’s no other country on the Gulf Of Guinea that has deepwater fields of comparable size with Jubilee, a helpful explanation for why majors like ExxonMobil, ENI, and BP as well as CNOOC have shown keen interest in Ghana.

Ghana has had a good year in terms of overall oilfield activity relating to both the drill bit and the commercial playground; almost as soon as Tullow Oil announced the discovery of the Twenoboa field, proving that the deepwater oil tank extends beyond Jubilee, news filtered in about ExxonMobil ‘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 once the Deepwater Tano and Cape Three Points blocks have been taken, what other acreages can be prospective enough to interest the majors?

The discoveries of the last two years, principally Odum and Tweneboa, have basically confirmed the prolificity of these two acreages. Odum and Tweneboa are located outside the Jubilee channel, but they both reside on the megastructure.

Hess Corporation’s dry hole, Ankobra 1, drilled in 2008, is located in adjacent Deepwater Tano/Cape Three Points license, but is off the Jubilee megastructure. Is it possible that prospectivity decreases southwards, away from Jubilee and its satellites?

Are we replaying, in Ghana, the experiences of Equatorial Guinea Mauritania and Egypt where, every other operator/partner outside the flagship field has had much less luck than those operating the signature field?

Some background: As soon as Triton announced the discovery of Le Ceiba, in Eq Guinea’s deepwater Rio Muni Basin, everybody rushed in. But while Triton (and latterly Hess) kept deepening their understanding of La Ceiba and increasing their take points, every other company on leases adjacent to La Ceiba was reporting either sub-commercial finds or outright dry holes. In Mauritania, there was a host of smaller oil and gas discoveries, after Woodside’s Chiguetti find, but the commerciality was low and even Chinguetti’s own production headed south rather quickly.

In Egypt’s deepwater, no company has been able to encounter anything close to the size of the hydrocarbon accumulation in the West Deep Delta Marine Concession, the country’s signature deepwater asset, which provides all the gas for one of Egypt’s two LNG projects. Shell has struggled in the past five years to put an LNG project on the drawing board on the basis of accumulations in its North East Mediterranean Deepwater NEMED) Block, which is adjacent WDDM. So far, the Anglo Dutch major hasn’t come up with the reserves figure that can justify such a project.

So, is this the way the marginal (smaller) provinces of deepwater Africa, outside Nigeria and Angola, work?

Does this mean that Vanco/Lukoil, who hold the Cape Three Points Deep and ENI, which is operator of Cape Three Points South are far more likely to encounter dusters, or sub-commercial hydrocarbon pools?

The experience with Equatorial Guinea, Mauritania and Egypt says “Yes”. But we are the first to admit that this analysis is not being made with any hard technical data. We are not privy to anything more than well location and results and sheer common sense.

If there would be any other field of Jubilee size, outside the Jubilee megastructure, in Ghanaian deep waters near the size of Jubilee it would have to happen in another basin.

To explain this, let’s take another look at Equatorial Guinea.

While every company-major and independent- crowded around the vicinity of Le Ceiba in deepwater Rio Muni Basin, Noble Energy ventured northwards, to take a look at the largely unexplored deepwater Douala Basin. The company probed Miocene targets in Douala, contrary to Cretaceous age reservoirs that others were pursuing in Rio Muni. In three years of work, (2005 to 2007), Noble had encountered commercial sized hydrocarbon pools in Belinda, Benita, Yolanda and Diega prospects in blocks O and I. As of the time of our going to press, the field development plan for Benita (renamed Aseng) had been approved. The field is expected to produce some 50,000Barrels of oil per day at peak, a few months after it comes on stream in 2012. Noble will develop the other fields after Aseng by tieing them to the main facilities in Benita.

In the past two years, Afren has been the only company that has drilled a well outside of the Tano Basin in Ghana. Its Cuda 1, located in Keta Block on the Accra  Keta basin, which is farther east, towards the Ghanaian border with the Republic of Togo, was not completed. It may be stretching things a little to say that Afren will encounter a commercial sized pool in Accra-Keta basin for the simple reason that it is a long way away from the frenetic activity in the Tano Basin. From the point of view of its location, the Accra Keta is too close to the lack luster Togo Basin and the once productive, barren looking Benin Basin, to suggest that it might be prospective.

But then the Tano Basin itself was a grave yard of hopes just 10 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 four years ago.

It will be interesting to see what Vanco, Hess and ENI come up with, as they drill in the vicinity of Ghana’s main hydrocarbon prizes


Gabon Is Desperate To Join The Fray

 By Fred Akanni, in Libreville

Gabon has been out in the cold since I lit onset of the contemporary phase of deepwater exploration in the Gulf Of Guinea This is what the deepwater bid round, scheduled to kick off in May 2010, is about to change.. Gabonese authorities believe that the country’s deepwater acquatory has never been properly explored.

The country was producing it around 350,000Barrels of Oil Per Day (BOPD), about the highest in its production history, in the mid I 990s, when countries like Nigeria nod 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. But the wildcats that were later drilled in deepwater Gabon in the first few years of the 21st century failed in a big way.

  • In 2001, a consortium led by TOTAL drilled Judy 1, Genny 1 and Renee 1 to 4806metres, 4793metres and 4047metres respectively, all very deep wells, in the Astrid Marin acreage. They were all located in excess of 2000metre Water Depth. They were all disappointingly dry holes.
  • Inshore, in the Anton Marin acreage, Jeane-1 was drilled to 2882mTD in water depth of I ,500m. It was also a dry hole.

As these wells were all located in the lower Congo Basin, where operators in Angola had been having a field day harvesting giant oil fields, it was beginning to look like Gabon might not be part of the West African deepwater party.

But Agip wasn’t so sure. The Italian major picked up a lease northwards in deep offshore Ogooue Delta, part of the Gsbon Coastal Basin. This was even a riskier spot; unlike the broad, gentle slope from shallow water to deepwater in the Lower Congo basin, the descent to deep offshore is rather abrupt. In 2002, Agip came up dry at a TD of 2,882m in Powe Marin 1, drilled in 1,000m Water Depth on the Awoure lease.

In 2005 Amerada Hess, running on adrenalin from its successful foray in deepwater Equatorial Guinea, drilled two equally disappointing wells in deep offshore Ogooue Delta.

So what happened?

There have been explanations for the poor results in the Gabonese deepwater segment of the Oogue and the Lower Congo Basins.

• The Ogooue 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.

Gabonese authorities, aided by IHS energy, a firm of industry scouts, say that there is enough information in hand for the bid round to aid operating companies in determining the best locations for sizeable reserves of oil. A survey by CGG Veritas, launched in March 2009, includes more than 9600km of 2D seismic in Gabon’s southern and northern offshore zones, as well as a proposed 4,500 sqkm of 3D and 2D data in the southern zone.

Gabon desperately needs to shore up production, which has declined from 365,000BOPD in 1995, to 234,000BOPD in 2008.


Before The Deepwater Harvest, Ghana’s Production History

Out of the seven (7) discoveries made in Ghana it is the Saltpond field that has undergone production between 1978 and 1985. A total of about 3.47 MMbo was produced and 14 Bcf of gas was flared during the period. A Production Platform “Mr. Louie” which was used for the production is still in place.

In an effort to revive the field, the Ghana National Petroleum Corporation GNPC entered into an agreement with Lushann Eternit in the year 2000. This agreement resulted in the formation of a joint venture company – Saltpond Offshore Producing Company Ltd (SOPCL) – which is currently operating the field.

In the North and the South Tano fields, a number of appraisal wells have been drilled and GNPC has carried out an extended production test in the South Tano field, before the discovery of the large Jubilee field in the deepwater Tano Bain. GNPC is talking to a number of oil companies to utilize the gas from these fields for power generation. A 125MW power barge is already available in Ghana for such a venture.

The 3-AX block is envisaged to be an additional source of gas for the Tano power generation project.


BACK TO THE BASICS

By Toyin Akinosho

Nigerian deepwater oilfield activity is back in exploratory phase, in the main.

 With eight billion barrels of proven reserves, a daily output of 520,000barrels per day of crude oil and a long queue of oil field development projects waiting for approval, the Nigerian deepwater province is far from reaching the fullness of the potential that operators thought it had when the first set of 3D seismic data were acquired 1994.

Some companies hit the mother lode thick and fast (ExxonMobil and Shell are producing Erha and Bonga  respectively at around 180,000 BOPD respectively, down from an excess of 200,000 BOPD each and both are working on field extensions). Others (like Conoco Phillips, Statoil),quietly folded their arms when the expected elephants didn’t show up on their telescopes, and yet a company like Agip ignored the rules of deepwater field size versus threshold financial profitability and put the 100 million barrel Abo field, located in 500 metres of water, in production, ramping quickly up to 30,000BOPD. (The production had fallen to 19,000BOPD by early 2008 and was to have been boosted by two new wells drilled later in that year). Devon Energy walked out and Petrobras has gone very quiet. Other operators are caught in the less emotional corridor between the spectacular and the disappointing. Chevron brought Agbami on stream at 65,000BOPD in July 2008 and it has ramped up to 135,000BOPD by December 2008. It’s not just the slowest of the big three producing fields in deepwater Nigeria, the production is far below the expected 180,000BOPD anticipated in the first six months of production for the 800MMBO field, TOTAL’s Akpo is on course for first oil before the end of 2009 and the company’s Usan-Ukot and Egina fields are expected on stream between 2011 and 2012. The last really big deepwater fish on queue for first oil in Nigeria is Bonga SW/Aparo, expected on stream about 2013.

With mixed results all over, oilfield activity in this segment of the Niger Delta basin has come full circle and back to where it all started; the exploratory phase. The mood is: “let’s go and check out what else is there”.

Newcomers and grizzly old hands are completing new seismic acquisition and drilling both rank wildcats and first appraisals, largely in areas that have proven to be prospective.

BG, the British gas company, commenced its drilling programme in the Oil Prospecting Lease OPL 286-DO, which was carved out from what used to be Chevron operated OPL 218. The company plans two wells on this lease before moving to OPL 284, which, DPR officials think “is far more prospective”. Its Ogide 1, located in the general, high pressured Boi -1 area(See story on page 13), is being drilled with the semi submersible rig Sedco 702.

After a sustained period of production and development work, Agip is drilling an appraisal well outside the Abo field licence area. The semi submersible rig MG Hulme Jr has reached a depth of 4,000metres subsea in Oberan 2, the first appraisal of the 2003 discovery in what was then OPL 211(now Oil Mining Lease OML 134). The logging programme is fairly comprehensive, including coring and-if there is oil as expected- testing the well. Agip is hoping that the well confirms or even increases, the 200MMBBO it hopes the Oberan structure holds. Swiss operator Addax, who has largely operated on the shelf, commenced its first major activity in deepwater in December 2008 and is currently completing a 1,000sq km of 3D survey in the Oil Prospecting Lease (OPL 291), lying between 500 and 2,500metres of water. The block was carved out of Chevron’s OML-127 (after production permit was granted) where the giant Agbami is seated. The acquisition will cover the northern part of the block extending into north OML- 127. If this G&G exercise in this block comes out successful, then Agbami might have a good tie-back customer in

Addax.

Petrobras is on queue to acquire 3D seismic with the PGS vessel that is doing the acquisition for Addax.

America’s largest major in Nigeria does not have exploratory wells on the drilling queue in 2009. ExxonMobil will acquire fourth dimensional 4D seismic data on the Erha field, but it doesn’t plan any drilling, exploratory or development, on any of its operated deepwater acreages in 2009.

Chevron may drill one well in OPL 247, now that it has evaluated the carpet 3D it acquired on the lease The company plans exploration drilling elsewhere in its operated deepwater acreages, but no candidate has been firmed up due to rig scheduling and ranking issues.

There are, for example, three candidates, “but the reserves figures are not giving the operator any comfort”, according to a source at the state owned NNPC, which is the concessionaire for all operated leases in deepwater Nigeria. Chevron is still drilling in Agbami for development and production purposes. Shell and TOTAL, on the other hand, have better defined, active drilling schedule, outside of ongoing development activity. Shell plans to drill four exploratory and appraisal wells, apart from the development work on extending Bonga production farther north. The company completed a 4D seismic acquisition on the Bonga structure in early 2008, but the 2009 exploration and appraisal campaign excludes the general Bonga area. Discussions are ongoing to resolve the dispute around OPL 245, where Shell discovered Etan and Zabazaba, its most recent finds and its not clear if any of the four wells is planned for this lease but some of the appraisal work will certainly be in OML 135, where Shell has the undeveloped  discoveries Ngolo, Bolia and the Nnwa-Doro gas field.

TOTAL plans to drill a well in the Continental Oil and Gas held OPL 257, which adjoins SAPETRO’s OML 130. TOTAL is the technical operator of both OPL 257 and OML 130 and -if it works-the proposed well in OPL 257 is meant to be part of the overall development of the Egina field, which is expected to come on stream in 2012.

What’s clear in the overall Niger Delta deepwater 2009 drilling activity, no company is venturing into the outer toe thrust belt. The great story of Nigerian deepwater, in the last five years, is the spate of disappointing wells that were drilled by Agip (Dou 1 and Emein 1, OPL 244), Chevron (Iroko 1, OPL 250), Phillips (Onigun 1, OPL 318), Petrobras (Erimi 1, OPL 324) and Ocean Energy 9Pina 1 and Tari 1, OPL 256). What’s happening may be a lot of exploratory work, but it’s taking place in areas already deemed safe bets.


BACK TO THE BASICS

By Toyin Akinosho

 Nigerian deepwater oilfield activity is back in exploratory phase, in the main.

With eight billion barrels of proven reserves, a daily output of 520,000barrels per day of crude oil and a long queue of oil field development projects waiting for approval, the Nigerian deepwater province is far from reaching the fullness of the potential that operators thought it had when the first set of 3D seismic data were acquired 1994.

Some companies hit the mother lode thick and fast (ExxonMobil and Shell are producing Erha and Bonga  respectively at around 180,000 BOPD respectively, down from an excess of 200,000 BOPD each and both are working on field extensions). Others (like Conoco Phillips, Statoil),quietly folded their arms when the expected elephants didn’t show up on their telescopes, and yet a company like Agip ignored the rules of deepwater field size versus threshold financial profitability and put the 100 million barrel Abo field, located in 500 metres of water, in production, ramping quickly up to 30,000BOPD. (The production had fallen to 19,000BOPD by early 2008 and was to have been boosted by two new wells drilled later in that year). Devon Energy walked out and Petrobras has gone very quiet.

Other operators are caught in the less emotional corridor between the spectacular and the disappointing. Chevron brought Agbami on stream at 65,000BOPD in July 2008 and it has ramped up to 135,000BOPD by December 2008. It’s not just the slowest of the big three producing fields in deepwater Nigeria, the production is far below the expected 180,000BOPD anticipated in the first six months of production for the 800MMBO field, TOTAL’s Akpo is on course for first oil before the end of 2009 and the company’s Usan-Ukot and Egina fields are expected on stream between 2011 and 2012. The last really big deepwater fish on queue for first oil in Nigeria is Bonga SW/Aparo, expected on stream about 2013.

With mixed results all over, oilfield activity in this segment of the Niger Delta basin has come full circle and back to where it all started; the exploratory phase. The mood is: “let’s go and check out what else is there”.

Newcomers and grizzly old hands are completing new seismic acquisition and drilling both rank wildcats and first appraisals, largely in areas that have proven to be prospective.

BG, the British gas company, commenced its drilling programme in the Oil Prospecting Lease OPL 286-DO, which was carved out from what used to be Chevron operated OPL 218. The company plans two wells on this lease before moving to OPL 284, which, DPR officials think “is far more prospective”. Its Ogide 1, located in the general, high pressured Boi -1 area(See story on page 13), is being drilled with the semi submersible rig Sedco 702.

After a sustained period of production and development work, Agip is drilling an appraisal well outside the Abo field licence area. The semi submersible rig MG Hulme Jr has reached a depth of 4,000metres subsea in Oberan 2, the first appraisal of the 2003 discovery in what was then OPL 211(now Oil Mining Lease OML 134). The logging programme is fairly comprehensive, including coring and-if there is oil as expected- testing the well. Agip is hoping that the well confirms or even increases, the 200MMBBO it hopes the Oberan structure holds.

Swiss operator Addax, who has largely operated on the shelf, commenced its first major activity in deepwater in December 2008 and is currently completing a 1,000sq km of 3D survey in the Oil Prospecting Lease (OPL 291), lying between 500 and 2,500metres of water. The block was carved out of Chevron’s OML-127 (after production permit was granted) where the giant Agbami is seated. The acquisition will cover the northern part of the block extending into north OML- 127. If this G&G exercise in this block comes out successful, then Agbami might have a good tie-back customer in

Addax.

Petrobras is on queue to acquire 3D seismic with the PGS vessel that is doing the acquisition for Addax.

America’s largest major in Nigeria does not have exploratory wells on the drilling queue in 2009. ExxonMobil will acquire fourth dimensional 4D seismic data on the Erha field, but it doesn’t plan any drilling, exploratory or development, on any of its

operated deepwater acreages in 2009.

Chevron may drill one well in OPL 247, now that it has evaluated the carpet 3D it acquired on the lease. The company plans exploration drilling elsewhere in its operated deepwater acreages, but no candidate has been firmed up due to rig scheduling and ranking issues.

There are, for example, three candidates, “but the reserves figures are not giving the operator any comfort”, according to a source at the state owned NNPC, which is the concessionaire for all operated leases in deepwater Nigeria. Chevron is still drilling in Agbami for development and production purposes.

Shell and TOTAL, on the other hand, have better defined, active drilling schedule, outside of ongoing development activity.

Shell plans to drill four exploratory and appraisal wells, apart from the development work on extending Bonga production farther north. The company completed a 4D seismic acquisition on the Bonga structure in early 2008, but the 2009 exploration and appraisal campaign excludes the general Bonga area. Discussions are ongoing to resolve the dispute around OPL 245, where Shell discovered Etan and Zabazaba, its most recent finds and its not clear if any of the four wells is planned for this lease but some of the appraisal work will certainly be in OML 135, where Shell has the undeveloped  discoveries Ngolo, Bolia and the Nnwa-Doro gas field.

TOTAL plans to drill a well in the Continental Oil and Gas held OPL 257, which adjoins SAPETRO’s OML 130. TOTAL is the technical operator of both OPL 257 and OML 130 and -if it works-the proposed well in OPL 257 is meant to be part of the overall development of the Egina field, which is expected to come on stream in 2012.

What’s clear in the overall Niger Delta deepwater 2009 drilling activity, no company is venturing into the outer toe thrust belt. The great story of Nigerian deepwater, in the last five years, is the spate of disappointing wells that were drilled by Agip (Dou 1 and Emein 1, OPL 244), Chevron (Iroko 1, OPL 250), Phillips (Onigun 1, OPL 318), Petrobras (Erimi 1, OPL 324) and Ocean Energy 9Pina 1 and Tari 1, OPL 256). What’s happening may be a lot of exploratory work, but it’s taking place in areas already deemed safe bets.


Tougher Times in Deepwater Nigeria

 By Stewart Williams and Alison Dines, Wood Macenzie

THE GENERAL PERCEPTION ACROSS West Africa’s oil industry is that the high cost inflation seen over the last few years is slowing, particularly with respect to rig rates. Absolute costs, however, are still increasing and 2008/9 will see deepwater drilling rates surpass the $500,000 per day mark for the first time. The specific rig in question is the West Capelle, a new-build driliship, which is due to begin drilling for TOTAL in Nigeria in the third quarter of 2008. Its sister ship, the West Polaris, is also due to start operations in the Gulf of Mexico. After completing its programme with ExxonMobil, the West Polaris will move to West Africa to drill exploration wells in the Nigeria, Sao Tome et Principe (NSTP) JDZ, Equatorial Guinea and Gabon.

With exploration in the region set to increase again and prospects being located in ever- increasing water depths, Wood Mackenzie has examined the effect of cost escalation in the deepwater Niger Delta. While the US Gulf of Mexico, with its very attractive fiscal terms, can support such day rates and subsequent development costs, West Africa has tougher fiscal terms and Nigeria is an increasingly expensive development area. This insight examines the reserves threshold for commercial oil development in Nigeria and the Nigeria-Sao Tome and Principe JDZ under the existing range of fiscal terms in this deepwater region using typical development cost scenarios.

Methodology

We have created four model fields containing between 100 and 600 million barrels to analyse commercial reserves thresholds in the deepwater Niger Delta. Cost estimates for the model fields are based on our knowledge of current exploration costs and future development cost expectations of the major oil companies.  The table shows the range of capex for the individual model fields.

High day rates for drilling have accompanied increases in costs for facilities and subsea equipment too. In fact, it is subsea that is the strongest growth area in terms of costs. At the start of the decade, unit capital costs for West African deepwater projects sanctioned for development were around $4 per barrel (nominal). For projects awaiting sanction today, these costs have tripled to at least $12 per barrel, but in many cases more than this.

We assume that these model fields are in water depths greater than 1,000 metres -water depth affects royalty rates -and also has a bearing on exploration and development

costs. We have used Wood Mackenzie’s latest price assumption that assumes a flat long-term real oil price of $50 per barrel (2008 terms).

We have modeled full-cycle returns. The model fields have a 2008 discovery date and first produce in 2015, following first development expenditure in 2011. Although 2015 may seem pessimistic, seven-to eight-year lead times are typical of Nigerian deepwater projects. Satellite developments have been performed much more quickly than this, but our scenarios assume a standalone new field development. All cases assume subsea wells tied back to a new-build floating, production, storage and offloading (FPSO) vessel.

Results and Discussion

The following chart shows the range of full cycle IRRs under four PSC systems that currently apply in deepwater Nigeria and the NSTP JDZ.

The chart demonstrates the evolution and general toughening of fiscal terms in Nigeria from the first deepwater round in 1993, when lenient terms were offered to encourage high risk drilling, to the tougher terms in the latest bid rounds, which have also been accompanied by high bonuses.

Under the latest Nigerian fiscal terms and cost estimates, around 400 million barrels has to be discovered to achieve a 15% full-cycle return. Discoveries over the last five years, however, have been getting smaller, typically less than 300 million barrels. Most major operators agree that the largest fields have already been found and that it will be difficult to develop new discoveries, even in a high oil price environment. In the early 2000s, the reserve thresholds were much lower, mainly because costs were substantially below the levels seen today.

We have not included signature bonuses in this chart but with a bonus of $50 million (the minimum set for the 2005, 2006 and 2007 bid round deepwater blocks) a 15% will be difficult to achieve, even with a 600 million-barrel discovery.

Why are costs particularly high in Nigeria?

Nigerian projects do attract a risk premium but it is difficult to put a figure on this — the contracts here are more expensive for a number of reasons. Security concerns in Nigeria mean that oil companies have to increase pay to encourage both their own staff and contractors to work there. A history of contract award delays, project design changes and significant re-tendering for contracts also add a premium when contractors are bidding for work in the country.

Another key issue facing operators is the local content requirement. Although Nigeria has been producing oil for over 50 years, it is only in the last few years that local participation has been pushed by the government. The haste in which this has been introduced means that there has been little time for Nigeria to build capacity in the local service and construction sectors that is required if all new deepwater projects are to meet the 70% built-in-country requirements. While the regulation is still not passed into law yet, the Nigerian National Petroleum Corporation’s (NNPC) Nigerian Content Division is trying to enforce it and this is becoming a barrier to project sanction.

Further costs are incurred in Nigeria through the addition of indirect taxes, which include VAT, import and custom duties, the Niger Delta Development Commission levy and education tax.

Company Outlook

The high cost issue is impacting the corporate view of the region. Already in 2007, we have seen several mid-sized to large lOCs either pull out or farm down their Niger Delta deepwater positions. Devon Energy and Pioneer have left the region completely, Chevron is farming down its share of the Nsiko deepwater discovery and ExxonMobil sold its share of the NSTP JDZ Block 1 (Obo discovery) to Addax in September 2007. Press reports suggest that Occidental, who only returned to Nigeria in 2005, has sold its deepwater position, which includes a stake in the Uge oil discovery.

Although many players are diluting their deepwater positions, others are still building theirs despite the high cost environment. Addax, a very successful Nigerian-shelf player, now has a significant deepwater portfolio in Nigeria and the JDZ. The company’s acreage in Nigeria, OPL 291, is one of the more prospective blocks and has the potential for a large discovery. In the NSTP JDZ, Addax now has an interest in four adjacent blocks, which could lead to cluster developments. This would probably lower each field’s individual reserves threshold required for commerciality. This is not the case with other, smaller Nigerian finds which are generally far apart from each other. BG too is developing a deepwater position and acquired a stake in OPL 323 in August 2007. This was, by far, the most sought-after block in the 2005 round due to its perceived prospectivity.

Conclusions

With commercial reserves thresholds increasing and discovery sizes falling, we expect to see a general slowdown in Nigerian deepwater development. Although the terms have become tougher (through a combination of legislation changes and competitive bidding), it is increasing development costs that are driving the increase in reserves needed for commerciality. Even existing fields with good terms and large volumes, such as Usan, Bosi and Bonga SW, have seen development schedules slip due to rising costs.

Satellite developments will become more attractive, as will infill drilling on the existing large developments that have attractive fiscal terms. However, if deepwater momentum is to continue in the region, then new development concepts have to be considered and NNPC may be able to help by considering some flexibility on the local content directives.

For new discoveries, reducing the time between discovery and first oil would improve the economics. Short lead times have been difficult to achieve for a number of reasons. OPEC constraints exist in Nigeria and the government has staggered deepwater development approvals to balance supply with the output from higher tax areas on the onshore and shelf. This problem should not be a concern in the Nigeria-Sao Tome Principe JDZ as production from this area is understood to be outside of Nigeria’s OPEC quota. The recently announced NNPC restructuring, however, does not bode well for the short-to mid-term as it may be difficult to get NNPC’s approval for project sanction.


Kosmos Seeks The Transform Margins

By Brian Maxted

Kosmos’s African deepwater business strategy involves serial exploration success with the drill-bit

KOSMOS, THE OPERATOR OF THE first major deepwater discovery offshore Ghana, has a straightforward deepwater strategy in Africa.

The primary goal is to deliver initial investor returns by building a highly marketable regional E & P enterprise using a $300 Million line of equity. We are seeking to create a value of one to two billion dollars in five to seven years.

Our objective is to drill between ten and twelve basin, play or fairway-opening exploration wells in a range of petroleum systems. Based on historical finding statistics, this exposure should ensure our business goals are achieved, assuming we perform at or above the industry average.

The strategy is technically-driven, seeking to unlock under-described or under-explored basins through franchising of newer ideas in both old and new geographies. The company is applying its technical insights to thematically pursue Upper Cretaceous and Lower Tertiary structural/stratigraphic combinations plays. It is this strategy which differentiates the company. This approach is coupled with taking pre-emptive above and below ground risk to create ‘first mover’ competitive advantage.

Kosmos divides the E & P value chain into four stages. These include Frontier (no established charge, reservoir and/or trap), Emerging (all play elements proven but no commercial success), Growing (a commercial hydrocarbon province) and Maturing (an exploited basin).

The industry as a whole is largely focused at the Growing and Maturing sectors as evidenced by the 2005 wildcat exploration drilling statistics. Kosmos is centering its portfolio on Emerging basin opportunities. It is this segment of the industry structure which is considered to provide the most significant value creation potential. The portfolio is being balanced with Growing basin assets to enhance delivery of  success in the near term and a Frontier project of choice to provide longer term option for growth.

Kosmos’s playing field is the Atlantic Margin of Africa from Morocco to South Africa. The company is principally focused in the Emerging Transform Margin, the Growing deepwater Niger Delta and West Africa Salt Basin, as well as Frontier North West Africa.

Kosmos Energy has interests in six licenses including Ghana (two), Cameroon (two), Benin and Morocco, as well as an economic interest in a seventh (Nigeria). Included are three operator ship and strategic working equities. 3D were acquired, processed and interpreted in Ghana, Nigeria and Benin and multiple, high quality ready-to-drill prospects were defined.

Kosmos is member of a consortium which provides the company access to a dynamically-positioned deep water drill-ship, the Aban Abraham (formerly Peregrine III). This is currently under renovation. It was upgraded to have a water depth capability of between 5,000 feet and 6,600 feet and was available mid-2007. Kosmos had a 90-day firm commitment together with a 90-day option.

The projects have been delivering results, even though up to eight wells are envisaged in the current portfolio, assuming no success. An active new venture programme is ongoing to capture an additional two to four exploration drilling opportunities.

Let us now look at our current asset portfolio. An early focus for the company has been the Transform Margin from North West Nigeria to Cote D’Ivoire.

This has a bad business address due to repeated failed exploration attempts over time. It provides an example of Kosmos applying new ideas in an old geography.

Over 100 wells have been drilled in shallow water (<200m) along the Transform Margin. The primary play is Lower Cretaceous structural traps. Technical success has been high with 37 discoveries giving a finding rate of approximately 1 in 3. Greater than 800MMBOE has been found but the average field size is only 20MMBOE. The commercial success rate is >1 in 10 due to a combination of two limiting factors: reservoir quality and trap size.

Regional petroleum systems evaluation has identified the Tano Basin in Ghana and offshore Benin as potential hydrocarbon sweet spots. This is based on a series of key criteria.

Both are outboard of proven shallow water petroleum systems: they are within or have direct access to mature source kitchens; the areas are down-dip of major re-entrants for Upper Cretaceous deep water slope/channel systems and base of slope fans; and critically, they contain plunging structural noses which provide both a regional hydrocarbon migration focus and trap making opportunities. In the Tano Basin, offshore Ghana, the plunging Tano Ridge distinguishes the West Cape Three Points and Tano Deep blocks. The structure sets up numerous combination traps involving Upper Cretaceous reservoirs along its south flank and down-dip nose, adjacent to a mature late Cretaceous source kitchen. A large lead/prospect inventory has been defined and ranked, basin- ward and along trend from the shallow water South Tano oil and gas discovery. Several deep water prospects have been matured for drilling. The Mahogany Prospect was a moderate risk, high reward combination structural (fault/dip) and stratigraphic (pinchout) play. It has seismic support for reservoir and hydrocarbon charge including amplitude and AVO, as well as attribute fit to trap.

Conversely, Teak is a moderate risk, high reward fault/dip depth closure with stacked, draped early and late Cretaceous reservoir targets. The prospect has seismic amplitude support for reservoir and a coincident gas cloud suggests hydrocarbon charging.

Block 4 in Benin is a very large, under-explored deep water license in a proven petroleum system which hosts two undeveloped Lower Cretaceous finds.

A series of Upper Cretaceous slope/channel and slope fan fairways offer significant

exploration upside. These are currently being evaluated based on re-processing of existing 3D and new 3D acquisition. A large number of leads/prospects are identified along and around two plunging structural noses.

An ultra-deep water rig is being procured for drilling.

A large, highly diverse inventory of exploration leads and prospects has been defined. Two contrasting examples include an Upper and Lower Cretaceous structural play involving an inversion anticline with good seismic DHI support and attribute coincidence with trap; as well as a large, base of slope Upper Cretaceous fan play.

Cameroon provides an example of sleeping geology in the Salt Basin. Kosmos has two assets in the country including Kombe-Nsepe and N’Dian River.

Cameroon offers the opportunity to explore the extensions of proven petroleum systems inboard and onshore the Douala and Rio Del Ray basins. Kosmos is focusing on under-defined and under-explored Early Tertiary and Upper Cretaceous structural/ stratigraphic fairways either up-dip of producing areas or along trend from recent discoveries.

Oil is targeted but emerging gas commercialization options potentially manage phase risk.

In board of the prolific Rio Del Ray Basin, the N’Dian River license provides the opportunity for exploration of deeper, Upper Cretaceous structural oil plays, as well as shallower Tertiary stratigraphic gas/condensate plays. Aeromagnetic as well as 2D seismic surveys are in planning.

To the south in Nsepe-Kombe. Upper Cretaceous and Lower Tertiary combination oil plays are being pursued. These have analogy to recent finds in the Rio Muni Basin of Equatorial Guinea.

Kosmos’s initiative in deep water Nigeria involves a contrarian idea in a new geography. The high-priced blocks awarded in licensing rounds have typically involved anticiline plays. Their explorations has had mixed results. Kosmos is looking in the lows rather than the highs of the west Niger Delta, pursuing combination structural-stratigraphic slope/ channel and base of slope fan plays. Kosmos’s acreage offers the company lower risk, higher reward lead/prospect opportunities which have strong seismic support for reservoir and charge and display good analogy with fields in the Congo Fan of Congo and Angola. For Kosmos, south Morocco represents our Frontier project of choice, both below and above the ground. Politically it is disputed with Western Sahara. The taking of pre-emptive risk in acquiring this acreage reflects our confidence in a timely and favorable resolution of the rights. Below the ground, the Boujdour block represents an opportunity to explore an untested early Cretaceous delta, similar in size to the Niger Delta, with proven Cretaceous reservoirs and numerous, large structural trapping trap geometries. The key petroleum system risk is charge presence and timing of generation/migration.

A re-description of the blocks is in progress and partners will be secured before drilling.


Shell Proves Nigeria Right

MARTYN MNDERHOUD LOOKED up briefly from the presentation and faced the audience. “Somebody said that Zabazaba was a discovery”, he said. “Well, I don’t know”.

Then almost immediately Shell’s Vice President for Exploration and Production in Africa put up a series of slides, indicating that Shell considers Nigeria the best place to look in its deepwater portfolio worldwide. The scene was the banquet hail of the Sheraton Hotel in Abuja, at the conference of the Nigerian Association of Petroleum Explorationists(NAPE) in November 2006.

In the last three years (2003-2006) almost everyone has lamented the lack of success in ultradeepwater Nigeria. But not Shell. The Anglo Dutch giant has always had a successful story. Shell reported in 2006 that Bobo -l in OPL 322, encountered some 120m of hydrocarbon. Indeed, in his paper, (See illustration) Minderhoud declared Bobo-1 as a “fat cat” discovery. Bobo is located squarely in the ultradeepwater, outboard of 1 ,700m water depth, and its location is not in the Outer Toe Thrust(OTT)Belt area, which has proven quite problematic in terms of structuration for holding hydrocarbon. But if the general rule has been that the farther and deeper from 1 ,600metre water depth you get, the less likely you are to find a significant hydrocarbon tank, then Shell has proven an exception to the rule. Agip’s Dou-1 and Emein-1, OPL 244, both drilled in 2,000m of water encountered marginal gas. Chevron’s Iroko- l(in 2000m WD) in OPL 250, was as much a disappointing story as Phillips Onigun- l (2,200mWD) in OPL 318, Petrobras’s Erinmi-1(2,300mWD) in OPL 324 and Ocean Energy’s Pina-l (in 2,500mWD), which encountered some gas and Tan-1 (2,000m WD) in OPL 256.

While Minderhoud abstained from outright declaration of Zabazaba-l ( 2,000metre water depth) as a discovery, the company has gone ahead to drill Zabazaba 2, an indication that the first well, at least, opened doors to possibilities. Outside the rank wildcat area, Shell is proving up more oil in fields already established.

The January 2007 edition of AAPG Explorer, the influential in house magazine of the largest grouping of earth scientists on the globe, cites Bonga North 2X, as one of the four major discoveries in subsaharan Africa in 2006. Bonga North 2 X is the dual leg appraisal to the Bonga North 11X discovery in OML 118, where the Bonga main, (the main field of the Bonga structure) is producing over 200,000BOPD, or at least 8% of Nigeria’s entire production, today.

AAPG Explorer says that “Shell is trying to prove up enough reserves (500MMBO+) that could lead to Bonga North being developed separately from Bonga”. But Shell sources say that the Bonga North field will be tied to the FPSO of the Bonga main.

Meanwhile, plans have progressed with Chevron to develop Bonga South-West/ Aparo (Chevron’s Aparo wells probed the same sands as Bonga South West, hence a unitization proposal). This means two projects of some 1 50,000B0PD each, at peak, apart from Bonga. Translation; on the Bonga structure and its satellites alone, the company is going to be  exploiting, by 2015, three fields delivering a total of at least 500,000BOPD.

One key beneficiary of this is ExxonMobil, who holds 43.7% interest in OML 118. The company will be rewarded whenever these fields come on stream; and it doesn’t even have to lift a finger. Shell itself has 43.7% in ExxonMobil’s OML 133, which hosts the Erha and Erha North fields, producing 230,000BOPD today. The two largest oil producers in Nigeria thus currently deliver close to 500,000BOPD, roughly one fifth of the country’s total production, from deepwater. ExxonMobil’s rich pickings apart, Nigeria has made a rebound in exploration effort in deepwater, an indication that the overall pessimism that hung over the terrain two years ago, is wearing off. Eleven wildcats were spudded in deepwater Nigeria in 2006, a figure which is higher than all the exploratory wells drilled in both shallow water and land last year.

Chevron’s Obo 1 is one play that may put to lie the perception that the outer toe thrust belt is a no no. AAPG Explorer reports that the first deepwater well in the Joint Development Zione (JDZ0 between Nigeria and Sao Tome et Principe, “encountered a cumulative 45 metres of net hydrocarbon pay in multiple reservoirs”.

The magazine said: “Reserves are runmoured to be not as large as expected, leading to speculation that the well was not sited at the most prospective location but rather on the edges of a major structure to check its extent”. As new discoveries show up with less and less reserves than the first set of discoveries, in just 10 years of exploration, there is a spirited debate on the knowledge base regarding the thrust belt features in the Niger Delta deepwater.

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