Regional Report: West Africa

Etinde field, offshore Limbe in southwestern Cameroon, has an estimated 345 MMboe in gas and condensate resources (Left). Photo: Bowleven Oil & Gas. Cameroon has an established oil industry, with a history of oil production from the Rio del Rey basin in the eastern Niger Delta (Center). Photo: Bowleven Oil & Gas. Production was suspended at Jubilee field in March 2016, while the Kwame Nkrumah MV21 FPSO underwent maintenance for a damaged turret bearing (Right). Photo: Anadarko.

As a major subcontinent of Africa, West Africa continues to attract attention for its prodigious oil and gas resources. Global investors have taken notice of the opportunities that lie off the continent’s west coast, and its growth as an emerging energy giant. Chinese President Xi Jinping, for instance, has expressed interest in further strengthening ties with Africa over the next several years.

Even with West Africa’s growing potential, the industry downturn has had an adverse effect on E&P activity. Like the U.S. and Europe, explorers in the West African region have been forced to idle rigs. In May, offshore drilling reached its lowest level since 2009. Rig count, too, fell to its lowest point in four years.

Additionally, the rig count in Africa’s leading producers, Nigeria and Angola, has dropped by half in the last two years, and companies have continued to slash budgets. Tullow Oil, for example—a chief explorer in Africa—was driven to cut its capital expenditure for 2016 by $100 million.

Nevertheless, E&P activity in West Africa has resumed judiciously, and progress is being made in determining just how valuable the region could be to the oil and gas industry’s future.

MAURITANIA/SENEGAL

A significant gas discovery was made by Kosmos Energy in November, which was the company’s second major discovery of 2015. The Marsouin-1 exploration well, located on Block C-8 offshore Mauritania, encountered at least 229 ft of net gas pay in Upper and Lower Cenomanian intervals, made up of excellent quality reservoir sands. Situated approximately 37 mi north of the play-opening Tortue-1 (renamed Ahmeyim) gas discovery of April 2015, the well was drilled in approximately 7,874 ft of water.

The company’s Ahmeyim-2 appraisal well further defined its previous gas discoveries offshore Mauritania in March 2016. The well was drilled to a TD of 17,020 ft and, ultimately, extended the productive field area from approximately 50 km² to 90 km². Encountering nearly 256 ft of net gas pay in two excellent quality reservoirs, the well demonstrated field-wide reservoir continuity. The well results significantly increased Kosmos’ Pmean gross resource estimates for the Tortue West structure, as well as for the Greater Tortue Complex.

In November 2015, Sterling Energy acquired a 13.5% interest in a production sharing contract (PSC) for Block C-10. The block lies in water depths of 164 ft to 7,874 ft, and covers an area of approximately 10,725 km². PSC holders include Tullow Oil (operator, 76.5%), SEML (13.5%) and Société Mauritanienne des Hydrocarbures et de Patrimoine Minier (10%). The JV is planning to drill an exploration well to further test the prospect sometime in 2017.

Just south of Mauritania, Cairn Energy has had considerable success offshore Senegal. In May 2015, the company estimated that identified prospects, as well as several leads, could have an estimated mean risked resource base of more than 1 Bbbl.

Cairn’s basin play has been focused on the acreage around the SNE-1 discovery well. In January, the company tested its SNE-2 appraisal well, with positive results. The well reached a TD of 9,186 ft below sea level, and confirmed correlation of the principle reservoir units between SNE-1 and SNE-2. In March, SNE-3 tested successfully, as well, with similar reservoir quality and correlation of the principal reservoir units between the three wells. Operations were subsequently completed at the SNE-4 appraisal well in May, confirming correlation and presence of the principal reservoir units between each of the wells across the entire field.

Fig. 1. Kosmos Energy’s activity in the Tortue West structure indicates a large, continuous gas accumulation. The company has drilled five consecutive, successful wells offshore Mauritania and Senegal, through the Greater Tortue area. Image: Kosmos Energy.

In January, Kosmos Energy’s Guembeul-1 exploration well struck gas offshore Senegal. The well, just 3 mi south of Ahmeyim, was drilled to a TD of 17,208 ft and encountered 331 ft of net gas pay in excellent quality reservoirs. Most importantly, however, the well demonstrated reservoir continuity, as well as static pressure communication with Ahmeyim, which indicates a large, continuous gas accumulation, Fig. 1.

Kosmos made yet another significant gas find offshore Senegal in May. The Teranga-1 exploration well was drilled to a TD of 14,714 ft and encountered 102 ft of net gas pay in good quality reservoir. This was Kosmos’ fifth consecutive, successful well offshore Mauritania and Senegal, through the Greater Tortue area.

GHANA

The Republic of Ghana is a principal contributor to the West African oil and gas sector. The country is Africa’s fifth largest in respect to proven reserves.

In March 2015, Tullow Oil was authorized to move forward with the Tweneboa-Enyenra-Ntomme (TEN) project, despite a maritime border dispute between Ghana and Ivory Coast. Ivory Coast had challenged offshore boundaries with Ghana and necessitated a halt in drilling, which included Tullow’s TEN project. A preliminary decision was made by the International Tribunal for the Law of the Sea, which allowed the project to remain on schedule, with first oil expected in early August 2016.

As operator, Tullow (47%) already has drilled multiple wells in the area and expects to reach 80,000 bopd in output by 2017, congruently when the tribunal is scheduled to reach a final verdict on the border dispute. Partners in the project include Kosmos Energy, Anadarko Petroleum, South Africa’s Petro SA and Ghana National Petroleum Corp.

Tullow Oil withstood some interference at its flagship Jubilee oil-and-gas field, as well, approximately 37 mi off the coast of the Ashantiland Peninsula. The field, which could contain up to 3 Bbbl of crude oil, underwent maintenance that caused the suspension of production from March until May.

The company released a statement recounting the delays at Jubilee. According to that statement, a technical investigation was launched on the Kwame Nkrumah FPSO, where it was confirmed that a turret bearing had been damaged and was no longer able to rotate. After output from the field fell to an average 80,300 bpd in the first quarter—down from last year’s 102,600 bpd—oil production and gas export resumed in May.

Additionally, the company announced plans to install a spread mooring on the vessel sometime next year, followed by a
deepwater offloading buoy in 2018. Jubilee reportedly will need to halt production once again, for eight to 12 weeks, while the new mooring system is installed.

Fig. 2. Ivory Coast has seen an increase in E&P activity since 1996, when data analysis showed significant potential for commercial prospectivity in the region. Image: EIA.

Ghana still heavily relies on imported oil, and suffers from frequent electricity shortages. The country has been battling blackouts, due to a natural gas shortage, as well as low water levels at the nation’s hydroelectric dam. To address the issue, the World Bank approved a $700-million investment guarantee for an offshore gas project. This represents the largest foreign direct investment in Ghana’s history. The Sankofa project should supply enough fuel to generate as much as 1,000 MW of power, reducing the country’s reliance on imported oil. According to the World Bank, Eni and Vitol Group are carrying out exploration and “commercialization” work. The project is scheduled to begin producing gas in 2018.

CÔTE D’IVOIRE

Next door to Ghana, Côte d’Ivoire—or Ivory Coast—is experiencing increased E&P activity, Fig. 2. In 1996, Petroleum Geo-Services (PGS) surveyed four offshore blocks, in an effort to interpret the hydrocarbon prospectivity offshore Ivory Coast, a historically under-explored area. Analysis of the data highlighted significant potential for commercial prospectivity. In 2014, PGS reprocessed the survey with more advanced broadband workflow, further underlining the region’s hydrocarbon potential.

More recent discoveries, including Total’s Saphir field and Anadarko’s Morue field (2014), indicate the potential existence of more undiscovered petroleum to the west. This is considered the most under-explored region offshore Ivory Coast.

The Marlin North-1 well, on Block CI-27, struck oil and gas from the Turonian and Lower Senonian intervals in March 2015. A 72-ft perforated section of the gas-bearing column in the Turonian flowed at a stabilized rate of 25 MMcfgd and 150 bcpd. Additionally, in the Lower Senonian, a 36-ft perforated section of the oil-bearing column flowed at a stabilized rate of 1,525 bopd and 0.6 MMcfgd. The well was drilled by Foxtrot International in approximately 213 ft of water, and reached a TVD of 9,153 ft.

During the year prior, gas production from Block CI-27 averaged 142.6 MMcfgd, or 70% of the country’s total. The block is also home to Marlin, Manta, Foxtrot and Mahi fields. In October 2015, Foxtrot International started production from a second platform on the block, which is part of a four-year, $1-billion expansion program to bring Marlin and Manta fields on production. Throughout 2015, average daily production, as well as prices, has increased marginally.

NIGERIA

Often called the “Giant of Africa,” due to its copious population and economy, Nigeria has dealt with its share of difficulties in recent years—particularly concerning its responsibility to the oil and gas industry. It is the twelfth largest petroleum producer, ranks eighth as an exporter, and has the tenth-largest proven reserves in the world.

Despite more than 37 Bbbl remaining in those proven reserves, oil production in Nigeria has declined steadily as a result of stark underinvestment, as well as ongoing conflict and corruption. Last year, analysts predicted that the country’s new president, Muhammadu Buhari, would reform its oil and gas sector, in an effort to reverse the forecasted decline in production and, in turn, restore investors’ confidence. In March, by making it a priority to restructure the state-owned Nigerian National Petroleum Corp. (NNPC), Buhari took his first steps toward that reform. The NNPC suffered $1.34 billion in losses last year amid the industry downturn, as well as rumors of widespread corruption.

Oil output continued to plunge to a 27-year low, however, to 1.4 MMbpd—down from about 2.2 MMbpd—as the Niger Delta Avengers and the Boko Haram Islamist insurgency targeted oil infrastructure throughout the energy-rich nation. The violence in Nigeria contributed heavily to the 80% rally in Brent crude from a 12-year low earlier this year.

In May, an attack on a JV offshore platform caused Chevron to shut down output of approximately 90,000 bopd. Additionally, Chevron’s Okan offshore facility was shut down after it was “breached by unknown persons” and “resources to respond to a resulting spill” had to be sent. The company claimed that approximately 35,000 bopd of net production were affected by the violation.

Because of the recent militant attacks, companies—including Total, Eni, Shell, Chevron and ConocoPhillips—are selling onshore and shallow-water oil fields in the Niger Delta region, Nigeria’s foremost oil producing area. By becoming more risk-averse and focusing on their deepwater investments, which are farther from militants’ reach, companies are making a concerted attempt to minimize disturbances in Nigerian production.

The Delta region struggles to maintain economic accord, as it copes with poverty, a youth unemployment rate as high as 40%, and one of the worst infant mortality rates in the country. Now, with militants targeting the country’s primary source of foreign exchange, Nigeria’s economic crisis continues to worsen.

Peace talks with the Niger Delta Avengers reportedly began in early June. By the end of the month, a rebel ceasefire was agreed upon, and the country was seeking $40 billion to $50 billion in investment, as it raised crude output to 1.9 MMbpd. The OPEC producer had, reportedly, signed a potential deal for $8.5 billion of investment with China North Industries Group Corp., and expected crude output to rise to 2.2 MMbpd by August, if pipeline repairs were completed.

CAMEROON/EQUATORIAL GUINEA

With fairly high political and social stability, the Republic of Cameroon has a lot to offer to the oil and gas industry, particularly offshore. Its geological diversity also gives it the nickname, “Africa in miniature.”

The Etinde Exploitation Authorization Area—formerly Block MLHP7, offshore Limbe in southwest Cameroon—is being developed by NewAge Ltd. and its partners. As operator, NewAge holds 30% equity. Partners include Bowleven (20%), LUKOIL (30%) and SNH (20%).

Etinde field has an estimated 345 MMboe in gas and condensate resources. NewAge’s plans for the development include drilling two additional appraisal wells, as well as providing gas supply for LNG production and possibly a chemical fertilizer plant. This would help support the country’s agricultural industry. First gas is scheduled for 2019.

Exploration company Tower Resources signed a PSC for the shallow-water Thali Block in September 2015. With a 100% interest, the terms of the Thali PSC include three exploration phases: An initial exploration period of three years, which consists of geological and geophysical studies, 100 km² of 3D seismic acquisition and a commitment well with a minimum financial commitment of $13 million; a two-year first renewal period, which consists of one exploration or appraisal well with a minimum financial commitment of $15 million; and a second two-year renewal period, consisting of one exploration or appraisal well with a minimum financial commitment of $15 million.

The Thali Block covers an area of 119 km², with water depths from 26 ft to 157 ft. It lies in the Rio del Rey basin in the eastern Niger Delta. The basin, which is a sub-basin of the Niger Delta, has produced more than 1 Bbbl of oil, to date. Additionally, it has estimated remaining reserves of 1.2 Bboe.

Fig. 3. With 7 MMbbl of oil already discovered on Cameroon’s Thali Block, there is significant potential to develop prospects at deeper levels, once better imaging has been achieved. Image: Tower Resources.

With 7 MMbbl of oil already discovered through the Rumpi-1, Njonji-1 and Njonji-2 wells, the block potentially could hold up to four plays. Tower could, potentially, add incremental oil reserves to achieve commerciality, in addition to the potential development of prospects at deeper levels, in both structural and stratigraphic traps, Fig. 3. However, the company has confirmed plans to attain more enhanced seismic imaging first.

Bowleven Group, an Africa-focused exploration group, was awarded a one-year extension to the existing Bomono exploration license onshore Cameroon, in April 2016. Tertiary and Cretaceous prospects had previously been identified throughout the Douala basin, which resulted in the drilling of the Moambe and Zingana exploration wells in 2015, both of which encountered hydrocarbons.

Just south of Cameroon, Equatorial Guinea has seen substantial progress in spite of the industry downturn. The nation has seen a huge spike in E&P during the last two decades. Exploration in the 1990s resulted in an upsurge of daily production, from less than 5,000 bopd in 1992 to more than 410,000 boed in 2012.

The country’s 2012 and 2014 bidding rounds proved successful, prompting the Ministry of Mines, Industry and Energy to launch a new bidding round for all remaining deepwater blocks in 2016. Bids will be accepted during the 2016 bidding round, which began in June, until Nov. 30. Licenses will be awarded in January 2017. There are 37 blocks up for bid, 32 of which are offshore.

“The government of Equatorial Guinea is committed to promoting competitive exploration, contract sanctity and local content compliance,” said H.E. Gabriel Mbaga Obiang Lima, Minister of Mines, Industry and Energy. “We intend to create greater opportunities for explorers in the country, including our national oil and gas companies, GEPetrol and SONAGAS, which should play a greater role in the petroleum sector.”

Because of the increase in production, the country’s government partnered with Taleveras Group, Gunvor Group and the Strategic Fuel Fund to build a major storage hub at Punta Europa, on Bioko Island. The Bioko Oil Terminal, which will qualify as Africa’s largest oil storage hub, will have a total capacity of 1.34 MMt of crude oil storage.

Equatorial Guinea is the third-largest producer in Sub-Saharan Africa, and it continues to develop its resources. Through phased installation of a subsea production system made up of 20 wells, Ophir Equatorial Guinea Ltd. and its partners are developing gas reserves on Block R, 87 mi southwest of Bioko Island. The block covers an area of 2,450 km², with water depths from about 4,500 ft to more than 6,000 ft. The production system supplies dry gas to a locally moored FLNG facility with a capacity of 3 mtpa.

GABON/CONGO

With an economy dominated by oil, Gabon’s request to rejoin OPEC was approved at the 169th Meeting of the Conference and was effective on July 1, 2016. The Gabonese Republic still has significant unexplored potential, particularly in its pre-salt sector, and developments within the country will now be reflected in figures for OPEC crude production. “What is important for us is how we can work with OPEC towards fighting against this situation of oil prices going down,” said President Ali Bongo Ondimba. “It is just important that all the members be going in the same direction.”

Focusing on five highly prospective deepwater blocks, the Gabonese Ministry of Petroleum and Hydrocarbons held its 11th licensing round last year. During that time, the Ministry appointed CGG to promote the licensing round and acquire approximately 25,000 km² of new 3D BroadSeis, multi-client seismic data as part of an integrated geoscience program. The survey was aimed at enabling more advanced imaging of the under-explored area of Gabon that is in line with more recent pre-Aptian salt discoveries, including Leopard, Diaman, Ruche and Tortue.

Prior to the licensing round, however, extensive progress already was being made in the region. VAALCO Energy has been the predominant independent in Gabon during the last year. In February 2015, the company reported first production from Etame 10-H, the second development well to be drilled from Gabon’s Etame platform. The well was drilled to an MD of 10,314 ft, while overlying more than 590 ft of high quality reservoir. At the time, the well was producing approximately 3,000 bopd, and the the jackup rig, Constellation II, was preparing to drill additional development wells.

A few months later, VAALCO announced first production from Etame 12-H. Drilled to an MD of nearly 11,319 ft, the well targeted the untapped, lower lobe of the Gamba reservoir. It ultimately was brought online at a rate of approximately 2,000 bopd.

VAALCO’s North Tchibala field proved profitable last year, as well. In September, the company reported that the North Tchibala 1-H, the first development well drilled in the field, was brought online at a rate exceeding 3,000 bopd. The well was drilled to an MD of approximately 11,160 ft, targeting the undeveloped Dentale reservoir. The well represented the first offshore production from Dentale, as the formation had only proven productive onshore Gabon until that time.

While Gabon relies on petroleum for nearly half of its gross domestic product, and about 75% of its exports, the country has seen a shift toward seismic acquisition during the downturn. Drilling has greatly decreased, but there are more seismic surveys being conducted, in an effort to amplify future exploration opportunities.

Next door to Gabon, Chevron has progressed in the development of Lianzi field, situated 65 mi offshore, in a centralized offshore zone between the Republic of Congo and Angola. It includes a subsea production system and a 27-mi electrically heated flowline system, which transports the field’s oil to the Benguela Belize-Lobito Tomboco platform on Angola’s Block 14. In November 2015, the company announced first production from the Lianzi project, and anticipated an average production rate of 40,000 bopd.

Total also brought a project online off the Congo coast in December. The Moho Phase 1b project, about 46 mi off the coast of Pointe-Noire, was brought onstream with a production capacity of 40,000 boed. The project, located in water depths from 2,460 ft to 3,937 ft, includes 11 new subsea wells, as well as the installation of two subsea muli-phase pumps. It is tied back to the floating production unit (FPU) on Moho Bilondo field.

ANGOLA

In addition to VAALCO’s activity in Gabon, the company has been operating offshore Angola. The Republic of Angola, the seventh largest country in Africa, holds vast petroleum reserves and is a key worldwide supplier.

In March 2015, VAALCO’s post-salt Kindele-1 well was spudded on Block 5. As the first exploration well on the block, it tested a faulted area adjacent to the Mubafo discovery. It was planned to initially drill to a depth of 5,905 ft, to evaluate the Mucanzo sand section within the Pinda group formations. However, after being drilled to a TVD of about 6,000 ft, the well was found to be water-bearing. It subsequently was plugged and abandoned.

Eni, however, was more successful in nearby Block 15, where it began production at the Kizomba Satellites Phase 2 project ahead of schedule. The subsea development contains Kakocha, Bavuca and Mondo South fields. Mondo South field has been developed with tie-backs to the Mondo FPSO, while Kakocha and Bavuca fields are tied back to the Kizomba B FPSO. The project develops approximately 190 MMbbl of oil, with peak production estimated at 70,000 bopd. That production rate is expected to increase Block 15’s total daily production to 350,000 bbl.

On Block 15/06, Eni began production at Cinguvu field in April 2015, two weeks ahead of schedule. As part of the West Hub Development Project, which is comprised of Sangos, Cinguvu, Mpungi, Mpungi North and Vandumbu fields, the wells are connected to the N’Goma FPSO. The first two fields onstream, Sangos and Cinguvu, were reportedly producing 60,000 bopd. By January 2016, Mpungi field began producing, as well, bringing production to approximately 100,000 boed in first-quarter 2016.

Block 17, too, reached a major milestone in May 2015, producing a cumulative 2 Bbbl. Block 17’s landmark production rate of 700,000 bopd represents Total’s most prolific asset. It operates four FPSO units within the Girassol, Dalia, Pazflor and CLOV production zones. Total operates Block 17 and has a 40% interest. Partners include Statoil (23.33%), Esso Exploration Angola (20%) and BP Exploration Angola (16.67%).

Just two months later, Total started production from Dalia Phase 1A. Also on Block 17, about 84 mi off Angola’s coast, Dalia Phase 1A is developing additional reserves of 51 MMbbl and will contribute heavily to the block’s overall production. The project involves the drilling of seven infill wells that are tied back to the Dalia FPSO.

Cobalt International Energy signed a sale-and-purchase agreement with state-run Sonangol in August 2015, handing over its 40% participating interest on Blocks 21/09 and 20/11 offshore Angola for $1.75 billion. The agreement secured a new operator, as well as an obligation to reach a final investment decision for the Cameia development, on Block 21, in an attempt to see Cameia deliver first oil in 2018.