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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


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.

Noble Revamps Equatorial Guinea

By Toyin Akinosho

For the five years between 2003 and 2008, the deepwater Rio Muni basin, off Equatorial Guinea, was the graveyard of optimism of operators looking in to share in the spoils that Hess Corporation was enjoying.

After Triton discovered the La Ceiba in 1999 and opened the Rio Muni basin, operators trooped to Equatorial Guinea and lined up drilling prospects around the new field.

But as Triton and latterly Hess (which bought out Triton), improved their fortunes in La Ceiba, the companies operating around and adjacent to the field came up with one frustrating result after another.

Pioneer Resources and partners, including the Australian independent Roc and the Nigerian minnow Atlas, drilled an early dry hole in Block H.

Chevron, and its partner, Sasol, dropped Block L, in 2007, after plugging and abandoning two wells in the lease. Devon and Hess, both partners in Block P, gave up their interests. Like Chevron and Sasol, Devon exited the country completely.

Petrobras and Petronas remain, unhappy with the two dry holes they have each drilled, but staying put either because they believe in the saying that “it takes more than five successive dry holes to write off a basin” or because, as state companies, they are not answerable to shareholders the way the private firms are, or something in between.

Still, as the story of a widening dust bowl dominated the headlines out of deepwater Equatorial Guinea, Noble Energy showed up with a harvest. The company had flowed 24million standard cubic feet per day (MMscf/d) of gas and 1,225BCFD of condensate in the O-1 wildcat on the Belinda prospect, in Block O. This was in October 2005. The story was largely ignored. The well was drilled in 250 feet of water, hardly the sort of geography that’s classified as deepwater; the fluid type was gas and condensate (these still don’t make hits in the Energy press in Africa) and three, the well wasn’t located in the Rio Muni basin.

In fact, the frenetic pace of work around Rio Muni basin had led to a fixation, in the public mind, that deepwater exploration in Equatorial Guinea was squarely about Rio Muni.

But Noble Energy had set up shop in the unheralded Douala Basin, farther up north from the Rio Muni cluster and closer in geology to the Niger Delta basin, in which the Zafiro field, Equatorial Guinea major oil field, was domiciled. Noble Energy’s operated blocks O and I are the Douala Basin.

As significant as any other data; Noble was chasing Miocene age targets in Douala basin, contrary to Cretaceous targets that everyone was looking for in Rio Muni.

What kept Block O in the news was Noble’s own loud press centre. The news just kept on coming. By August 2007, the Belinda pool had been extended by the appraisal well O-3, which established significant downdip resources. “Reservoir quality at the O -3 location, in 521metres of water was even better than was encountered at the O-1 discovery location while maintaining reservoir thickness”, the company release said.. Test results showed condensate-rich natural gas producing at maximum flow rates of 30.4 million cubic feet per day of natural gas and 1,540 barrels per day of condensate,

There was more to come…

Adjacent to Block O to the south is Block I where Noble Energy really got lucky.

In June 2007, the company encountered a Miocene reservoir on Block I while testing the Benita prospect, containing 41.5 meters of net hydrocarbon pay. Production tests from well I-1 yielded flow rates of 1,038 barrels per day of condensate and 34.3 million cubic feet per day of natural gas.

In October of the same year, Noble Energy announced results for well I-2, its first appraisal well on the Benito structure reporting approximately 45metres of net pay of which there is an estimated 10metres of net gas pay underlain by 35metres of net oil pay. The 1-2 well lies 42 km east of Bioko Island and 3 km southwest of the I-1 well, the original Benita discovery. I-2, in 951 metre water depth, was drilled to a TD of 3,225metres. The well wasn’t tested.

In December 2007, Noble announced it had found hydrocarbons in the I-3 well, drilled on the Yolanda prospect block. The well tested at 371 BCPD of condensate and 36 MMcf/d of natural gas in 896 metres of water is approximately 48 km east of Bioko Island and 10 km south of the Benita discovery, which is also on block I. It was drilled to TD of 2,890metres.

It just got better…

Results of the ‘I-5’ well on the Benita structure were announced in June 2008. The well encountered approximately 13 meters of net oil pay, defined the water-oil contact, and moved the lowest known oil down structure approximately nine (9) meters. Test results from this high-quality Miocene reservoir yielded flow rates of 6,250 barrels of oil per day and 5.4 MMscf/d of natural gas, with production rates limited by test equipment. Noble declared that, based on test information gathered, “the Benita development wells are anticipated to produce approximately 10 thousand barrels of oil per day”. Samples taken indicated a crude oil gravity of 300. This time, the company talked of a Field Development Plan. “We are moving forward with the engineering and production studies to submit a plan of development by the end of 2008, with hopes to sanction the project in 2009. Our target for first production from Benita remains 2012”, Charles D. Davidson, Noble Energy’s Chairman, President and CEO, said

..But the best was yet to come

By late August 2008, Noble Energy had tested a commercial pool of oil and gas in a prospect entirely different from the Benita structure. Diega 1 (which was drilled on , the last remaining Miocene channel prospect identified on the block by AVO response), encountered approximately 38 feet of net gas-condensate pay in the primary target, as well as an additional 30 feet of net gas-condensate pay underlain by 37 feet of net oil pay in a previously untested feature. Tests yielded a flow rate of 2,700BOPD of oil and 2.7 million cubic feet per day of natural gas. Fluid samples taken during the test indicated similar crude oil characteristics to Benita, which it complements. Noble Energy did not say whether the two would be jointly developed. The company, however, stretched interpretation rather far when it declared that “the development well completions in Benita can be designed to achieve production rates of approximately 10,000 BOPD of oil plus associated natural gas”. This is curious; Benita had only tested 6,500BOPD of oil 1-5, the fourth of the four wells announced on the Benita Field. No other well on the structure had flowed oil. So how would the company produce 10,000BOPD from the field when it hadn’t even flowed 10,000BOPD in the field? Perhaps there are some other tests that Noble Energy hasn’t announced.

Noble Energy operates in Block 1 in partnership with PA Resources (6%), Atlas Petroleum International (29%) and Glencore   (25%). GEPetrol (the national oil company of the Republic of Equatorial Guinea) will have a 5% carried interest once commerciality has been determined.

Noble Energy is working to further define the development and production scenarios to commercialize its discoveries in Equatorial Guinea. The company is focused on accelerating the Benita development with a targeted project sanction in 2009 and first oil production in 2012. The Belinda gas-condensate development will come Benita and will then be followed b addition of Yolanda and YoYo.


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.


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.


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.

Mauritania breaks A Dry White Season

The discovery of the Chinguetti field, nestled in 800 metres of water off Mauritania, called attention to the country as a prime destination for oil and gas explorationists. But the initial skepticism of the size of the Mauritanian play, among earth scientists, especially in major companies, seems to be returning, with the spate of dry holes witnessed in the country in the last one year.

So when the UK operator Dana Petroleum abandoned wildcat Aigrette 1 as an oil discovery in the offshore Block 7 last December, it was a welcome breath of fresh air in an environment that had started becoming suffocated with news of disappointing encounters.

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Equatorial Guinea: Progress Stalls on Exploration Front

THE MOST CURRENT NEWS on the West African fairway is that Equatorial Guinea is trying to be a large gas supplier to the United States.

It makes a lot of sense, considering that progress is not as vigorous as it used to be in the deepwater- until recently- the country’s core hydrocarbon business. There has been little significant development on the exploration front in deepwater Equatorial Guinea since 2005.
In the only exploration well drilled in 2006, operator Chevron plugged and abandoned L-2, its second (wildcat) well in Rio Muni’s Block L in May 2006, after failing to encounter hydrocarbons. L-2 was drilled on the Banyan prospect, with the hope of testing the hydrocarbon potential of a Campanian reservoir. The well is located in 1,980m Water Depth.  It went a further 2,000 meters to TD at 4,076m.  Block L is located in the Rio Muni Basin.  It covers 2,584 sq km west of Devon’s Block P and includes grid blocks I-15, I-16 and part of blocks J-14 and J-15.  The tract was reduced by 40% upon renewal in October 2005. The company almost immediately indicated that it was walking out of the block and by implication, out of the country.

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