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The Myth Of Uganda’s 2Billion Barrels


One of the most widely circulated “rumours” on the oil patch is that Uganda holds Two Billion Barrels of estimated recoverable reserves. In the business media,  journalists, analysts, even CEOs of E&P companies, state without blinking that “Uganda has 2Billion Barrels of Oil reserves”. It’s a magic figure.

But Tullow Oil, the flagship operator in Uganda and all of East Africa, has never come out explicitly to give a figure to the country’s  “estimated recoverable reserves”, which is 1P reserves.

→   Read the rest of this entry

Subsurface Data Management Specialist/London

Contract (£: commensurate to experience)

An international oil and gas operator wants a Subsurface Data Management Specialist with Algerian and Russian focus to join the team in London on a competitive contract basis.
The Role encompasses many activities and has a wide responsibility to support geotechnical user and management community in all aspects of data management.

Areas of G&G Activity include, UK and Norwegian offshore, North Africa (Algeria) and Russia.
The role has an accent on support for the Algeria Subsurface team but is required to proactively support ALL geotechnical data management activities across E&P as and when required.
This position has the scope to develop and the company are committed to providing training in all relevant geotechnical applications as required

Under the direction of the Information Management/Data Management Manager, work with Information Management/Data Management, IT and Technical Application Platform colleagues to deliver consistent quality data management services


  • Implement and maintain efficient E&P data management framework(s) – Including Policies, QA procedures, methodology, best practice and services.
  • Promote and implement data management policies, processes and procedures for G&G technical data.
  • Deliver consistent quality assured corporate data management services to geotechnical users
  • Manage and administrate the cooperation with data service providers, partners and other third parties
  • Assess and prepare demand forecasts for data management services and infrastructure
  • Maintain an overview all G&G technical data support requests, activities and outcomes in the support register
  • Maintain and administrate corporate, project or other data repositories.
  • Pro-active communication and support of business and IM/DM colleagues across the E&P organisation.
  • Work with the local institutions, governance bodies, partners and the business to ensure compliance with statutory data reporting obligations, data trades and partner distributions etc.
  • Assist and work with users, Information Management /Data Management colleagues, IT and Technical applications managers in the selection of new E&P technical applications


  • Degree in geology or other geoscientific discipline
  • Additional language skills in French or Russian (advantageous)
  • Proven experience in the oil and gas sector data management – Managing North African, CIS and Russian data. Additional understanding and experience in data management in the European (especially UK and Norwegian)
  • Geodetic data management- coordinate systems, projections from different or unknown projection systems typical for the Russian and North Africa reg
  • Geotechnical data and application data management including data preparation using ASCII editing tools and scripts
  • Data lifecycle management


This notice expires on February 26, 2013

Disclaimer: Neither Africa Oil+Gas Report, nor its parent company Festac News Press Limited, nor any of its agents, is responsible for this transaction. This is just an announcement, an advertisement.

In West Africa, The Atlantic Loses Its Sparkle

In deep-water Africa, geology has proven to be a trickster god

Stories by Toyin Akinosho

The newest deep-water frontiers in West Africa’s exploration rush have not been as forthcoming as the sites of the last major wave of discoveries.

Liberia, Sierra Leone, Namibia and Cote D’Ivoire are the focus of wildcat activities today, the way Nigeria, Angola and Equatorial Guinea were in the mid -90s.

But in the place of the large elephant-sized discoveries of 1994-2004, the Sierra-Leonean Basin, the Abidjan Margin and the Ivorien parts of the Tano basin, have so far delivered mere pimples.west

Ghana, which represents the transition between the two waves, has provided the only really big finds, outside of Angola, in West Africa in the last five years.

As far as the elephants are concerned, the locus has shifted to East African deep-water, which is all about gas.

What’s clear so far is that the Cretaceous plays, the target of recent West African probes, have not shown themselves as prolific as the Tertiary, where the ongoing East African deep-water rush has played out.

Note that Nigerian deep-water(The Niger Cone) and Angolan deep-water(The Congo Fan), which dominated the headlines all over the world 10-20 years ago, are Tertiary plays(sediments deposited between 65million and 2.6 million years ago). Which leads us to something: as far as the data in hand suggest, to be big, your deep-water African prospects need to be in the tertiary. But that’s a digression.

“I always knew that the non-Deltaic West African Passive Margin (also known as the West African Transform Margin)is just beginning to be unraveled”, says Ebi Omatsola, Managing Director of the Nigerian independent Conoil Producing and the continent’s leading exploration thinker, warning that it is early days yet. Omatsola had anticipated the basin-opening discovery of Ghana’s Jubilee field as far back as 16 years ago. His prediction, given at a presentation in Accra in 1997, came to fruition 10 years after. Still he doesn’t want to raise expectations about Liberia, Sierra Leone and Cote d’Ivore. “You must understand the geometry of the sand body and other factors to make it work”, he contends.

Tullow Oil, the unfailingly optimistic British explorer, doesn’t sound terribly upbeat about these countries either. It has proven oil and gas condensate system in Sierra Leone and Liberia, it says, but “thick sands only have oil shows(breached traps) and oil bearing sands have low net-to-gross ratio”. The company declares, in its first half 2012 report, that the exploration campaign has found oil but “only satellite class discoveries” have been made to date, whereas, for commerciality, “ hub class discoveries are needed”.

Investec Securities, scrutinizing Tullow Oil’s portfolio, declares that, based on targeted barrels by Tullow, ”the west African transform margin(Kosrou, Mercury, Teak) failed to deliver and so did itsAtlantic (Jaguar and Zaedyus)mirror image play(Jaguar and Zaedyus, in the Carribeans) in 2012”.

Chevron has operated three deep-water acreages off Liberia since September 2010. An August 2012 farm in deal by Eni, the Italian major, into these tracts, signaled that the transform margin was firm on the radar screen of the industry’s majors. But a farm in by one major has meant a farm down by another. With that transaction, Chevron’s operated interest in LB 11, LB12 and LB14 was reduced to 45%, with the Nigerian minnow Oranto holding 30% and Eni has 25%. It’s instructive that Chevron has drilled in Liberia, but is not excited enough to share the results.

The biggest discovery in the Sierra Leone-Liberian basin has been that of African Petroleum Corp. APC, an Australian minor and, perhaps the smallest operator in the province. The company encountered 32 metres of net oil pay in two zones off Liberia with Narina 1, in February 2012.The well reached total depth of 4,850 metres, in water depth of 1, 143metres. Narina-1was the company’s second shot at the Liberian offshore. Its first well, Apalis-1, drilled in September 2011, encountered only minor oil shows.

Lukoil was drilling a well in SL-05-11 Block, off Sierra Leone as of the time of writing this. SL-05-11 is one of the two Sierra Leonean tracts in which the company holds interest. In November 2012, Lukoilacquired a25% stake in the SL-4B-10 block, which adjoins SL-05-11.

Cote d’Ivoire has always appeared more promising than either Sierra Leone or Liberia, in part because some of its most prospective structures are located in the same Tano Basin that has yielded all of Ghana’s big discoveries. Tullow Oil, for one, claims that its discovery well Paon 1(June 2012) was drilled on a sand fairway analogous to the fairways on which the Jubilee field and the TEN(Tweneboa, Enyenra and Ntomme),  cluster wells are located(see illustration).  Tullow and its partners say the well, which encountered 31 metres of net oil sands in one interval, “confirms the Upper Cretaceous fan system present in Ghana extends westward into Côte d’Ivoire and provides significant running room within the CI-103 block” in which it islocated.

The question of how many more Paons are in the fairway and how big they are, will be answered in the campaign that Tullow is leading in 2013.

Lukoil expressed its faith in Cote d’Ivore in October 2012 by converting an exploration licence to a production tract. Block CI-524 represents an eastern part of block CI-401 which Lukoil Overseas has been involved in exploring since 2006. Lukoil holds a 60% interest, PanAtlantichas 30% and state hydrocarbon company PETROCI has 10%. Less than a year earlier, in December 2011, the partners had announced a discovery Independance-1X in Block CI-401. Although the result communicated was that the well penetrated only “eight metres (26 feet) of hydrocarbon pay in good-quality Turonian-aged sand package”, Lukoil beamed that the well was its “most important discovery of the year 2011”.It’s difficult to understand.

What about the “older frontiers”, the site of the first big wave of African deepwater discoveries?

Equatorial Guinea came up with some noteworthy successes in 2012; with Ophir reporting three gas discoveries in its Block R; sizeable enough for the company to contemplate a 1 Train LNG project deliverable by 2017.

There has been no deepwater discovery in Nigeria in the last five years. And no one, as far as we know, plans a wildcat drilling in that country in 2013. Operators are placing a bet on Angola, which has been touting the potentials of the presalt sequence in its Kwanza basin.

Only three wells have been drilled in the “Brazil look-alike” sag basin part of the pre-salt Angola; including the Maersk Azul-1, Cameia-1 discovery & Cameia-2 appraisal, and the PetrobrasOgonga dry hole.  This means that there have been only two discoveries, which can so far be described as encouraging “teasers” but it will take much more drilling to really know what is going on. My worry is that the Kwanza Basin is in the cretaceous. If the pre-Salt in Angola turns out to yield huge discoveries of elephant-size, I’d start looking positively on cretaceous basins again.

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.


Nigeria’s unending Gas Dilemma, By Adedayo Ojo

Nigeria has enormous gas resources. The official estimates of the country’sojo natural gas reserves is in the region of 187 trillion cubic feet (TCF). Despite a history of more than 50 years of oil production, Nigeria is predominantly a gas province.
Almost every successive Nigerian government aspired at one time or the other to legislate a regulation that will optimize the use of the country’s vast gas resources. Quite a good number gas projects have been conceptualized but unfortunately few have been actualized. The bottom line is that decades after the discovery of gas in commercial quantity, Nigeria’s gas sector and gas system remains underdeveloped.
Today’s reality in the international oil and gas market requires Nigeria to wake up and make something of the gas resources or be left behind countries that are more committed to utilizing their gas resources. Ghana’s gas company is expected to begin production this year. If the tension in the Middle East abates (as it may), oil & gas prices will drop!
Gas Aspiration
Several Nigerian government policies have highlighted plans to monetise gas resources. In 2008, the Federal Government developed the Gas Master Plan (GMP) in order to lay a framework for gas infrastructure development and expansion within the domestic market. According to the Nigerian National Petroleum Corporation (NNPC), the GMP is a guide for the commercial exploitation and management of Nigeria’s gas sector which seeks to grow the Nigerian economy with gas. The GMP has three key strategies, namely to stimulate the multiplier effect of gas in the domestic economy, position Nigeria competitively in high value export markets and guarantee the long term energy security of Nigeria.
In response to government policy, a number of ambitious gas projects were initiated by both government and the private sector. Some of the most popular gas projects and initiatives include;
a) Liquefied Natural Gas (LNG) Projects

b) Trans –Sahara Gas Pipeline Project

c) The West Africa Gas Pipeline Project (WAGP)

d) Gas To Power Projects Around The Country

Liquefied Natural Gas
Despite initial momentum on LNG projects, Nigeria remains far behind. Production started from trains 1 and 2 at the Nigerian Liquefied Natural Gas Limited in 1999. By 2007, NLNG added four more trains. Although the seventh train has been planned, six years later, it hasn’t been sanctioned.
Apart from NLNG, other planned LNG projects include Brass LNG and Olokola LNG (OKLNG). Final investment Decision (FID) on Brass LNG was planned for 2006; it was later rescheduled for 2008; then 2010. The FID was never realised on any of those dates; nor has it been now. The same applies to OKLNG. The shareholders of OKLNG signed a memorandum of understanding (MoU) in 2006; FID was billed for 2007 while production was scheduled to begin in 2009.
The originally proposed dates for streaming these projects have long expired; yet final investment decision (FID) has not been taken on any of the projects. In all these years, not much has been accomplished on Brass LNG and OKLNG.

Other countries have shown more commitment with LNG projects. Consider Australia. In 2011 alone, four LNG projects in Australia reach FID. These projects include: Australian Pacific LNG T1, GLNG T1-2, Wheatstone LNG T1-2 and Prelude LNG. Another Australian project, the two train, Ichthys LNG T1reached FID in January 2012.

According to the international Gas Union, Qatar, the world’s largest LNG exporter produced 77 metric tonnes per annum in 2011, about 31 per cent of global supply. Meanwhile new LNG frontiers have emerged in Eastern Africa such the Anadarko’s LNG project in Mozambique and the onshore LNG project by BG in Tanzania.

The United States, a former net importer of LNG is now turning away cargoes while increasingly relying on unconventional domestic gas, such as shale gas, to meet its energy need. In addition, the United States plans to become a net exporter of gas in less than a decade, effectively shrinking the global gas market.

The chokehold in the world LNG market and the emergence of new supplier nations will ultimately make Nigeria’s position increasingly vulnerable if the country’s LNG projects are allowed to continue to suffer. If FIDs on existing LNG projects in Nigeria are not taken now, the global LNG market will become increasing tougher for the country and more so in the coming years.

Trans-Saharan Gas Pipeline

In January 2002, the Nigerian and Algerian governments, through their respective national oil companies signed a memorandum of understanding (MoU) to build a Trans-Saharan gas pipeline running from Nigeria to Algeria to make Nigerian gas available to European market.

Since the signing of the MoU eleven years ago, not much has happened on the project except the feasibility study and intergovernmental agreement between the governments. As a result of the decade-long inactivity, it does appear that the project may have been abandoned.

Dr Ghaji Bello, Acting Director of Nigeria’s Infrastructure Concession Regulatory Commission (ICRC) said in Abuja in January that the Federal Government of Nigeria has earmarked $400 million for the project in the 2013 budget. Industry analysts received the news with scepticism in view of apparent non-commitment to the project.

West African Pipeline Project
The West African Gas Pipeline is a 680-kilometre gas transport project jointly-owned by Shell, Chevron and the Nigerian National Petroleum Corporation (NNPC) forming the African Gas Pipeline Company (WAGPCo). The project takes Nigerian gas from Itoki in Ogun State through Agido near Badagry in Lagos, passing through 33 Nigerian communities to Togo, Benin Republic and Ghana. West African Gas Pipeline Company (WAGPCo) and the participating countries signed an International Project Agreement (IPA) in May 2003 to pipe 200million standard cubic per day of gas (200mmscf).

Over the years, this project has failed to deliver the anticipated volume of gas due to a plethora of reasons – policy, politics, infrastructure, funding, security, etc.

Central to the operation of WAGPCo is the availability of gas. With vandalism and associated shut-ins, gas supply is never guaranteed.
As a result unavailability of gas, an average of 134mmscf is often piped in the 475mmscf capacity pipeline, thus making the $1billion facility to be sub-optimally utilised.

Other Gas Projects

Ironically, it is in the smaller gas projects operated by small Nigeria independents that real success has been observed. Consider the Ovade-Ogharefe gas processing facility, the largest carbon emission reduction project in sub Saharan Africa. The first phase of Pan Ocean’s gas utilization project which was streamed in 2010 has capacity to process 130 million standard cubic feet of gas per day. Pan Ocean is expected to stream the second phase of its Ovade-Ogharefe gas project before the end of 2013.

Uquo gas project: Seven Energy and Frontier Oil have made commendable progress on Uquo gas project. The gas central processing facility (CPF) of the Uquo gas project is owned by Frontier and Seven Energy while Seven Energy through its subsidiary, Accugas, runs the pipeline. The gas is delivered to Ibom Power plant owned exclusively by Akwa Ibom State Government. Power generation at the Ibom Power Plant is tied to gas generated at Uquo. The project has the capacity to boost power generation in Nigeria by 1000 megawatts of electricity.

East Horizon Gas Company (EHGC), a subsidiary of Oando Plc, is a special purpose vehicle set up to Develop, Finance, Construct and Operate a gas transmission pipeline linking the Calabar Cluster of Industries to the Nigerian Gas Company (NGC) grid in Akwa Ibom state. The company is embarking on a $125m project which involves the construction of an 18inch by128 kilometre (km) gas pipeline through forest, swamps and built up areas. The project has a total capacity of 100million standard cubic feet of gas per day (mmscfd).
Oando Gas and Power Limited has developed a robust natural gas distribution network. The company has built extensive pipeline network to distribute natural gas to industrial and commercial consumers and has successfully revived private sector participation in the gas distribution business in Nigeria. Oando has over 100km of pipes already laid in Lagos State and another 128 km in progress in Akwa Ibom and Cross River States.

If more players will be as committed as these not-so-big players, the collective contribution will add to big gains in the drive to grow the gas sector and optimize Nigeria’s gas resources.

Wake up call

The time left for Nigeria to make something tangible from her gas resources is running out. As we end the first quarter of 2013, policy makers and oil and gas industry operators have another opportunity to think long and hard and make the committed decision of making the Nigerian gas a key contributor to national economic life.

The largest obligation rests with the government. A robust and thriving gas sector would require good legal framework that will clearly specify the rules of engagement. The law will necessarily provide good fiscal terms that will encourage investment in the gas sector. The gas sector will only thrive under an effective regulatory structure. These are the necessary conditions that can ensure private sector commitment in the gas sector. It is the government that can provide them.

Adedayo Ojo is Lead Consultant/CEO of Caritas Communications Limited, a specialist reputation strategy and corporate communication consultancy in Lagos/Accra.
Caritas is the West Africa affiliate of Regester Larkin, the pioneer reputation strategy and management consultancy with offices in London, Washington, Houston, Singapore and United Arab Emirates.

Is Ghana Stuck At Tano Basin?

Since commercial production commenced with the deepwater Jubilee field in December 2010, Ghana has ranked prominently on the hydrocarbon map of the world.
It looks likely to record average 2013 production in excess of a hundred thousand barrels of crude oil per day as Jubilee ramps up to peak of 120,000BOPD.
But all the current production, planned production and drilling successes are clustered around the Tano Basin and its sub-basin: the Cape Three Points.
Any step out of the Tano, into another basin has so far resulted in failure.
The UK listed Afren Corp., has felt the full brunt. Barely six months after it acquired 68% interest in Keta Block on the Accra Keta basin, Afren spudded Cuda 1. It came out unsuccessful.
The company beamed with optimism after the failure, saying that the block, located farther east, towards the Ghanaian border with the Republic of Togo, had both Tertiary and Cretaceous prospectivity, with the principal exploration focus being the Cretaceous Albian to Campanian sections. “The block offers multiple prospects and leads, with a variety of trapping and depositional settings. A number of these show potential for significant stratigraphic trapping and giant field potential”, Afren enthuses on its website. In 2011, Afren farmed out 35% participating interest and operatorship to Italian major Eni, who in turn drilled a well within a year of buying in.
Eni’s well, Nunya-1X(formerly named Cuda 2) was a spectacular failure. It didn’t encounter a drop of hydrocarbon and more, it gave the lie to Afren’s claims that Cuda-1 would have encountered oil if it had drilled deeper.
Apart from the Afren/Eni adventure in Keta, there hasn’t been drilling on any other basin outside the Tano. The Saltpond basin still delivers trickles (less than 500BOPD) through the Saltpond filed. Operators have not ventured to drill in the deepwater Saltpond/Central Basin, which is the country’s third prominent deepwater basin.
Still, who cares whether these other basins deliver, as long as there’s continuing success in the Tano Basin?
A field development plan of a 100,000BOPD(peak) has been submitted to government.
The Plan Of Development (POD) looks to bring together a cluster of fields collectively named TEN(Twenoba, Enyenra and Ntomme).
Another such cluster of fields, the MTAB(Mahogany, Teak, Akasa and Banda) is in pre-development plan stage and is expected to deliver 100,000BOPD at peak.
Both projects, located in Deepwater Tano/Cape Three Points Blocks, envisage the crude to be produced through an FPSO each. ghanaThey are also, both, being operated by the British explorer Tullow Oil, with partners including American independents Anadarko and Kosmos Energy.
Meanwhile, Eni, which has failed in Accra Keita, announced a successful find in the Offshore Cape Three Points(OCTP), in the Tano Basin early in 2012, testing 5,000BOPD of “high quality oil” from a gross oil column of 76metres.
And Hess Corp, reported, in 2012, its fifth discovery in Deepwater Tano-Cape Three Points License. The company reported that Pecan 1 follows the previously reported discoveries at Almond (16metres net oil pay), Beech (44metres net oil pay), Hickory North (30 metres net gas-condensate pay), and Paradise (37metres net oil pay and 90 metres net gas-condensate pay). Ghana has had a good five years, since the discovery of Jubilee(2007-2012) in terms of overall oilfield activity relating to both the drillbit and the commercial playground: almost as soon as Tullow Oil announced the discovery of the Twenoboa held, proving that the deepwater oil tank extends beyond Jubilee, news filtered in about ExxonMohil s interest in acquiring Kosmos Energy’s stake in Jubilee for $4billion. The reputation of the putative buyer and the amount of money on the table heightened the perception of profitability of the overall Ghanaian portfolio. But beyond the Deepwater Tano and Cape Three Points blocks and adjacent acreages, what other acreages can be prospective enough to interest any company? The Tano Basin itself was a grave yard of hopes just 15 years ago, until Kosmos, Anadarko and Tullow started re-interpreting the data differently from earlier explorers. Kosmos itself described the Tano Basin as a bad address only six years ago.

Gabon, Locked Out, Bangs On The Door

By Fred Akanni, in Libreville

Gabon is hoping to launch a new deep offshore oil licensing round in June 2013, offering licences in its own segment of the pre-salt sequence, which has been imaged by seismic shots that have penetrated layers of sediments deposited during the break-up of the supercontinent in which Africa and South America were joined together.
That supercontinent, named Gondwanaland, included most of the landmasses in today’s Southern Hemisphere, but Africa and South America were particularly tightly knit within that space. The split of Africa/South America, 125 million years ago, resulted in the creation of the south Atlantic. This is why an oil discovery in Brazil could be sometimes seen to be a positive thing for Africa, especially those parts of Africa which were essentially “joined at the hip” with Brazil, when Gondwanaland existed. Those parts include Angola and Gabon.gabon
Previous deepwater exploration in Gabon led to four wells drilled in the lower Congo Basin between 2000 and 2002. A TOTAL led consortium came up with three dry holes, located in water depths in excess of 2,000metres to total depths of 4806metres, 4793metres and 4047metres respectively, all very deep wells, in the Astrid Marin acreage. Agip came up dry at a TD of 2,882metres in Powe Marin 1, drilled in water depth of 1,000metres.
In 2005 Amerada Hess, running on adrenalin from its success foray in deepwater Equatorial Guinea, drilled two equally disappointing wells in deep offshore Ogooue Delta.
There have been explanations for the poor results in the Gabonese deepwater segment of the Oogue Delta and the Lower Congo Basins:
• The Ogoeue Delta is not formed by the kind of large sized rivers like the Congo River which birthed the Congo Basin, or the Niger and Benue rivers which created the Niger Delta.
• The part of the lower Congo Basin that is in deepwater Gabon contains the obligatory hydrocarbon source, but it is buried too deep and the apparent lack of structuration disallows the source to adequately charge the reservoirs. Seismic data doesn’t suggest the presence of large scale canyons that could help deliver products of turbiditic flows into the deeper waters. There have been questions about of whether the direction of flow of the Benguela currents, which impact sediment movement on the Nigerian coast for example, could have anything to do with the possible lack of commercial hydrocarbon reservoirs in deepwater Gabon. The jury is still out on that.
Whatever the explanations, Gabonese authorities say they desperately need to shore up production, which has declined from 365,000BOPD in 1995, to 225,000BOPD in 2012.
New data acquired in the last three years by CCGVeritas have shown up the potentials that inhere in testing the presalt sequence, invoking the theory that if Brazil could find massive volumes of oil in the pre-salt deepwater sequence in Tupi(now Lula)-1 well in the Campos Basin, so can wells in Gabon. The survey included more than 9600km of 2D seismic in Gabon’s southern and northern offshore zones, as well as 4,500 sqkm of 3D and 2D data in the southern zone.
Geologists now know that some of the basins on either side of the south Atlantic were formed at the same time during the rift phase and today are mirror images of each other.
Gabonese authorities believe that the country’s deepwater acquatory has never been properly explored.
Gabon had planned a licencing round for 2010, but postponed it in order to complete the promulgation of a new set of regulations. There were also issues of rising drilling costs and environmental concerns after BP’s massive spill in the Gulf of Mexico.
The percentage the national oil company could hold in the newly licensed fields would depend on its financial capacity but would usually be up to 20%. Approximately it’s between 10% and 20% on (a) commercial basis.
The country was producing around 350,000Barrels of Oil Per Day (BOPD), about the highest in its production history, in the mid 1990s, when countries like Nigeria and Angola started witnessing a series of spectacular discoveries in water depths outboard of 750 metres. As Gabon shares the prolific Congo basin with Angola, and was the third largest oil producer in sub-Saharan Africa, it was expected to be part of the game.

Africa’s 2012 Hydrocarbon Finds

  • Cobalt reported that its Came iapre salt oil discovery in Block 21,offshore Angola, flowed at an unstimulated, sustained rate of 5,010 barrels per day.
  • Statoil described its Zafarani discovery in Block 2 offshore Tanzania a “high impact

discovery” with as much as 5 Tcf of gasin place. ExxonMobil is a partner in the well.


Offshore Nigeria, Afren and Amni tested a light oil discovery on OML

112. Afren claimed that future horizontal wells at its Okoro East oil discovery, offshore

South east Nigeria, should yield 4,500-7,000barrels of oil per day per well.


  • Onshore Kenya, Tullow Oil’sNgamia-1 well found more than 328 feetof oil pay over a gross oil-bearing intervalof 2,130 feet in multiple zones.
  • Anadarko Petroleum added seven to 20-plus Tcf of recoverable gas offshore Mozambique at an explorationstrike about 30km northwest of its Prosperidade complex.
  • In an exploratory well on the Ebok North Fault Block offshore south east Nigeria, Afren and Oriental Energy Resources identified 370 feet true verticalthickness of net oil pay in what Afren described as  “excellent quality reservoir sands.”
  • BG Group reported a fifth gasdiscovery offshore Tanzania with the Mzia-1exploratory well on Block 1 – a first successin the deeper Cretaceous section.
  • Agiba, a joint operating company, operated the Emry Deep 1X well about 288km southwest of Alexandria in Egypt,which encountered 250 feet of net pay in multiplesandstones of the Lower Cretaceous Alam El Bueib Formation and flowed 3,500barrels/day during testing.
  • Offshore Mozambique, an AnadarkoPetroleum partnership hit more than 300 netfeet of natural gas pay in two high-qualityOligocene fan systems with the Atum discovery well in Offshore Area 1 in theRovuma basin.


Tullow Oil’s Paon-1X deepwater exploration well, a light oil discovery in a Turonian fan system in the CI-103 licenseoffshore Cote d’Ivoire, extended a provenoil play westward from previous discoveriesoffshore Ghana.


In Offshore Area 4, Mozambique, ENI’sMamba North East-2 giant gas discoveryencountered more than 650 feet of payin stacked, multiple, high-quality zones,adding at least 10 Tcf to the play’s potential. The Papa-1 deepwater wildcat on Block 3 offshore Tanzania became the first

Cretaceous gas discovery outboard of the Rufiji Delta, according to partners Ophir Energy and BG.


  • Tullow Oil said Twiga South-1 in Block13T, onshore Kenya, found 98 feet of net oilpay with further potential to be assessed.
  • The Mamba South 2 and Coral 2delineation wells in Area 4, Mozambique, added about six Tcf potential in the Mamba complex for ENI and partners.

Eco Signs Three JoAsFor Walvis Bay Basin

Eco (Atlantic) Oil & Gas has signed three joint operating agreements with NAMCOR, the National Petroleum Corporation of Namibia, and Azimuth Ltd., an exploration and production company backed by majority-ownerSeacrest Capital Ltd. and Petroleum Geo-Services ASA (PGS).

The agreements were signed with respect to the Guy, Sharon and Cooper license blocks located in the prospective Walvis Basin offshore Namibia.

Colin Kinley, chief operating officer of Eco Atlantic, says that the three partners collectively, “bring extensive oil and gas experience to the Walvis Basin. We understand this oil play and the significant potential it has and look forward to working collaboratively with both companies to continue our exploration work in the Walvis basin, where significant drilling activities are scheduled for 2013 commencing this quarter.” ObethKandjoze, managing director of NAMCOR, commented that the agreements “signify the international support and interest in the development of Namibia’s oil and gas resources.”


AOC Executes Rift Basin PSA, ETHIOPIA

Africa Oil Corp has announced the formal execution of a new Ethiopian Production Sharing Agreement.  The agreement covers the 42,519 square kilometer “Rift Basin Area”, previously held by the Company under a Joint Study Agreement and referred to then as the “Rift Valley Block”.     The Rift Basin Area is located north of the Company’s South Omo Block and includes the extension of the Tertiary-age East Africa Rift Trend in Ethiopia.  The new license is on trend with highly prospective blocks in the Tertiary rift valley including the South Omo Block, and Kenyan Blocks 10BA, 10BB, 13T, and 12A.  During the joint study period, the Company completed an airborne high resolution gravity and magnetic survey over the block. In addition, satellite-imaged natural oil slicks were ground truthed, which indicate the presence of an active petroleum system in parts of the block. The Company plans to complete a Full Tensor Gravity Gradiometry survey and exhaustive environmental/social impact assessment over the block during 2013.

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