PRAMOD KULKARNI, Editor
On the heels of giant Nigerian and Angolan field developments and first oil in Ghana’s deep water, frontier exploration commences in Liberia and Sierra Leone
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From left: Transocean’s Discoverer Spirit is conducting exploratory drilling in deepwater Liberia. The Nigerian government is partnering with IOCs to increase compliance with its gas flaring ban and channel the resource toward domestic consumption and LNG export. Total’s subsea layout for Usan field is typical of the giant deepwater production facilities offshore West Africa.
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West Africa presents a broad panorama of the oilfield E&P cycle. In Nigeria and Angola, giant deepwater fields discovered a decade ago are going through successive phases of field extensions with oil production ranging easily from 100,000 to 250,000 bopd. In Ghana, first oil was produced in August from the giant Jubilee field, with an expected plateau production of 120,000 bopd. The discovery has triggered a flurry of exploration activity, including 3D seismic surveys and wildcat drilling, in the neighboring countries of Sierra Leone, Liberia and Gabon with hopes of finding Jubilee-type giants in the Cretaceous fan formations and presalt structures. If additional giant fields are discovered as expected, West Africa will continue to dominate the world’s E&P scene for decades to come.
Overall, the demand for deepwater rigs is strong throughout West Africa, with 12 drillships, 13 semisubmersibles and two tenders working in the region that have water depth capacities of 4,500 ft or more, Table 1. In the onshore sector, integrated developments are underway in countries such as Nigeria and Equatorial Guinea to minimize flaring and use natural gas more productively in injection wells for pressure maintenance, and for domestic consumption and export as LNG. Political unrest still has a dampening effect on onshore development in regions such as Nigeria’s Niger Delta and Cote d’Ivoire.
| TABLE 1. DEEPWATER RIGS OPERATING IN WEST AFRICA (Click to enlarge) |
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Presented here is a country-by-country examination of recent exploration, drilling and production activities in the West Africa region.
NIGERIA
Nigeria is Africa’s largest oil producer with a nameplate production rate of 2.9 million bopd, but insurgent attacks and pipeline thefts reduced output in 2010 to a range of 1.7–2.1 million bopd, according to the US Energy Information Administration. Onshore production of about 1 million bopd comes from the Niger Delta with its 86 oil fields and 1,000 producing wells. In October, pipeline sabotage forced Shell to declare a short-term force majeure on exports from the Forcados terminal. Nevertheless, there is substantial upstream activity underway in Nigeria as evidenced by the extensive array of leased blocks, fields and pipelines covering the delta and extending into the offshore areas, Fig. 1. Table 2 lists current and upcoming E&P projects in Nigeria.
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Fig. 1. Congested upstream infrastructure and operating blocks in Nigeria.
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| TABLE 2. CURRENT AND UPCOMING OIL DEVELOPMENT PROJECTS IN NIGERIA |
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Abgami-2. Nigeria’s largest deepwater project, Abgami field was discovered in 1998 about 70 miles offshore the Niger Delta in 4,800 ft of water. The field has been producing since 2008 and reached a peak rate of 250,000 bopd in August 2009. Chevron has now embarked on a 10-well second development phase to reverse declining production and extend the life of the deepwater field to 2014 from potentially recoverable volumes of 900 million bbl.
Usan. Total’s Usan discovery well in 2002, located 60 miles off the coast of Nigeria, was drilled to 8,940 ft in waters exceeding 2,400 ft in depth. Up to 2005, Total drilled eight appraisal wells to confirm the extension of the oil field to both the east and the west. Production is scheduled to begin in the first quarter of 2012. The Usan FPSO arrived in Nigeria in August and is undergoing customs clearance. The vessel is 320 m long, 61 m wide, and 150 m high, including the flare, with processing capacity of 180,000 bopd and 2 million bbl of storage.
Gbaran-Ubie. Shell’s onshore integrated oil and gas project began producing in June 2010, and is expected to reach rates of up to 1 Bcfd and 70,000 bopd in early 2012. The project incorporates five oil and gas fields spread over a 650-sq-km area of Bayelsa and Rivers states. Expansions commenced this year in order to increase production include the drilling of more than 30 new wells and building of a central oil and gas processing facility. The gas will supply the LNG plant at Bonny Island for export and support local power stations in the Niger Delta.
Erha North Phase 2. ExxonMobil’s Erha and Erha North development went onstream in March 2006 and reached a peak of 200,000 bopd in July 2006. The facility consists of 32 subsea wells tied to an FPSO, with 300 Mcfd of associated gas reinjected for reservoir management. Erha North’s second development phase, with production of 50,000 bopd, is expected to come onstream during 2012–2013.
Bonga. Nigeria’s first deepwater discovery in 1995, Bonga lies at 1,000-m water depth across an area of 60 sq km and produces more than 200,000 bopd and 150 MMcfd. Shell’s planned Bonga Southwest extension and development of the adjacent Aparo field, with crude oil resource bases of 508 million bbl and 124 million bbl, respectively, are expected to come onstream in 2014. Another planned Bonga extension to the northwest, also planned for 2014 startup, will involve the drilling of 12 subsea wells tied back to the Bonga main infrastructure to produce up to 150,000 bopd, Fig. 2.
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Fig. 2. Shell is extending Bonga field development in both the southwest and northwest directions.
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Egina. Discovered in 2003, Total’s Egina field covers an area of roughly 500 sq mi in water depths up to 5,085 ft. Having delineated the field through five appraisal wells, Total is now conducting FEED studies. The Egina facility will include six subsea production manifolds, a network of flowlines and risers, an FPSO with 200,000 bopd of process capacity and an oil offloading terminal. Scheduled to come online in 2014, Egina will reach an estimated peak production rate of 150,000 bopd.
Uge. ExxonMobil operates Uge field, which was discovered in 2005 in 1,350 m of water. State-run Nigerian National Petroleum Corporation (NNPC) has objected to the operator’s plan to refurbish and deploy the Falcon FPSO, first used on its shallow offshore Yoho field, to the smaller Uge field. NNPC, with the support of other partners in the project, has instead called for a newbuild FPSO, which ExxonMobil complains has pushed up costs. When placed on plateau production after 2016 startup, the field is expected to produce 110,000 bopd.
ANGOLA
Angola is West Africa’s second leading oil producer with 2010 output of 1.85 million bopd. In the first half of 2011, the production volume decreased to 1.65 million bopd due to technical problems in ExxonMobil’s Saxi-Batuque fields in block 15 and the BP-operated Greater Plutonio development in block 18. At present, Angola’s onshore oil and gas operations are active only in the Lower Congo basin near the city of Soyo. This Soyo zone is run by Total, which is expected to hand over operations to an Angolan company Somoil with Sonangol, the Angolan NOC, as its technical partner. Table 3 lists current and upcoming deepwater projects.
| TABLE 3. CURRENT AND UPCOMING DEEPWATER DEVELOPMENT PROJECTS IN ANGOLA |
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Tombua-Landana. Chevron’s Tombua-Landana project is located 50 miles offshore in 1,200 ft of water in block 14. The development achieved first oil in 2009 and is expected to reach peak production of 100,000 bpd in 2011. Recoverable resources for the two fields are estimated at 350 million bbl. The 46-well project involves the use of a 1,554-ft-tall compliant-piled drilling and production platform, one of the world’s largest man-made structures, Fig. 3.
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Fig. 3. Chevron’s compliant-piled tower, built for drilling and production at Tombua and Landana fields, is one of the tallest manmade structures in the world—surpassing the Eifel Tower by more than 50%.
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The reservoirs produce water with high levels of barium, requiring seawater treating equipment to remove sulfates before injection in order to prevent formation of barium sulphate scale in the wellbore and production equipment. Tombua-Landana will also use produced-water reinjection for pressure support and to reduce the volume of seawater required to waterflood the reservoirs. The project is designed for zero routine gas flaring. As such, the associated natural gas will be processed and stored in block 0 until the country’s liquefied natural gas project is completed.
Pazflor. Located in the prolific block 17, Total’s Pazflor facility came onstream in August, several weeks ahead of schedule. The fields are located 150 km offshore the capital Luanda, in water depths ranging from 600 to 1,200 m with proved reserves of 590 million bbl. In the coming months, production will be ramped up to 220,000 bopd.
A key technical challenge for Total was producing two very different grades of oil from four separate reservoirs. The Acacia reservoir contains light Oligocene oil, similar to that of Girassol field. The Perpetua, Zinia and Hortensia reservoirs have heavier, more viscous Miocene oil. For the three heavy oil reservoirs, the gas is separated from the oil and water on the seabed. Once separated, the oil and water are pumped via ESPs to the surface. The lighter gas is brought to the surface via riser-bottom gas lift. The FMC Technologies-installed subsea infrastructure consists of 49 subsea wells connected via production and injection lines and risers to the spread-moored Pazflor FPSO. The topsides control system is designed accommodate an additional 21 wells and a fourth subsea separation unit.
PSVM. BP’s PSVM (Plutão, Saturno, Vênus and Marte) hub development in about 6,500-ft water depth in block 31 is expected to begin production at 157,000 bpd during the second quarter of 2012 and reach plateau production in 2013. The first discovery on the block, the Plutão exploration well was drilled in September 2002 in 6,627 ft of water. Reaching a total depth of 13,357 ft, the discovery well tested at 5,357 bopd.
The field development plan for PSVM encompasses 48 subsea wells, including producers, water injectors and gas injectors, connected to 15 manifolds, 106 miles of flowlines and 59 miles of control umbilicals linking the production to the double-hulled PSVM FPSO, which will have a storage capacity of 1.6 million bbl. Future development will involve bringing in production from the remaining 12 discoveries in the block.
Kizomba-D. ExxonMobil’s Kizomba field complex has recoverable reserves of nearly 2 billion bbl from four discoveries: Hungo, Chocalho, Kissanje and Dikanza. The wells intersect an oil column that exceeds 1,000 m in thickness. In 2008, ExxonMobil launched the Kizomba-D project to develop two satellite discoveries, Clochas and Mavacola. The two fields, which are estimated to contain 254 million bbl of oil potential, will be tied back to the Kizomba-A and Kizomba-B production facilities. The project calls for 18 production wells to be drilled, with first production expected in 2012. A peak production rate of 140,000 bopd is expected by 2013.
CLOV. Located in block 17, CLOV is Total’s fourth development in the country after Girassol, Dalia and Pazflor. Drilling will commence in 2012, and first oil is expected in 2014. CLOV consists of four fields—Cravo, Lirio, Orquidea and Violeta—about 140 km from Luanda and 40 km northwest of Dalia in water depths ranging 1,100–1,400 m. Proved and probable reserves are estimated at 500 million bbl.
Lucapa. Chevron’s Lucapa field was discovered in 2006 in deepwater block 14, at a water depth of about 4,000 ft, encountering 279 ft of net pay in Miocene-aged sands. In 2008, two satellite exploration wells were drilled in the Lucapa area. Currently, Lucapa is in the pre-FEED stage and production is expected in 2014.
Mafumeira Sul. This Chevron-operated field is located in block 0, about 19 miles off the Angolan coast in 200 ft of water. Development plans include a central processing facility, two wellhead platforms, about 75 miles of subsea pipeline and 51 wells. Production is expected to reach 110,000 bopd and 10,000 bpd of LPG. Front-end engineering and design began in January 2010, and a final investment decision is expected by the end of this year.
LNG project. Angola’s first LNG plant is expected to begin operations in early 2012. While Chevron and Sonangol will operate the plant near Soyo in northern Angola, gas for the project will come from Total’s block 17, BP’s block 18, ExxonMobil’s block 15 and Chevron’s blocks 0 and 14. The project will process 900 MMcfd of associated gas and will eventually produce 5.2 million tons per year of LNG from a single-train facility plus LPG and condensates, and process about 75 MMcfd of gas for domestic consumption. The LNG was intended for the US and other Atlantic basin markets, but due to low US prices, the LNG exports will likely head to Asia or Europe instead.
EQUATORIAL GUINEA
From 5,000 bopd in 1995, Equatorial Guinea’s oil production has ballooned to 300,000 bopd in 2010 due to offshore E&P activity in the Gulf of Guinea. Oil production is derived primarily from Zafiro (ExxonMobil), Ceiba and Okume (Hess) fields, while condensate production originates from the Alba (Marathon) field. Additional condensate is expected to come onstream in the next two years from Noble Energy’s Aseng and Alen fields. Aseng is expected onstream in the first quarter of 2012 with initial production of 50,000 bopd, and Alen will begin production in 2013 at 40,000 bopd. Natural gas from both fields will be reinjected to maintain reservoir pressure and for possible future production.
At the end of 2010, Equatorial Guinea had 1.3 Tcf of proved gas reserves. From 2001 through 2009, gas production increased rapidly from about 2.7 MMcfd to over 630 MMcfd, driven almost entirely by the development Marathon’s Alba field. Additional gas production, such as at Aseng and Alen fields, could come onstream if the government is able to implement plans to reduce gas flaring by 2013. Most of Equatorial Guinea’s gas production is exported in the form of LNG from the Punta Europa facility on Bioko Island.
GHANA
Ghana vaulted into West Africa’s oil and gas sector with the discovery of Jubilee field in 2007. Since then, the country has seen a high level of exploration activity from both majors and independent oil companies to seize the potential bonanza, Fig. 4.
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Fig. 4. Several independents are actively exploratory drilling in Ghana’s offshore blocks. Image courtesy of Kosmos Energy.
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Jubilee. Operated by UK independent Tullow Oil with Anadarko, Kosmos and Ghana National Petroleum Corporation as partners, Jubilee field straddles the Deepwater Tano and West Cape Three Points licenses. Tullow’s Mahogany-1 and Hyedua-1 exploration wells intersected a large, continuous accumulation of light sweet crude oil in excellent-quality stacked reservoir sandstone. Subsequently, six appraisal wells were drilled to delineate the play, which was determined to have a gross resource base of 500 million to 1 billion bbl. First oil was achieved in August from the FPSO Kwame Nkrumah at a rate of 40,000 bopd. With water injection, production had ramped up to 85,000 bopd by October following the resolution of problems with the BOP and delays in implementing a water injection plan. Production is expected to plateau at 120,000 bopd by mid-2012 as a result of the next development phase (1A), which calls for drilling of eight production and injection wells.
Enyenra and Tweneboa. In the Deepwater Tano block, Tullow is conducting appraisal drilling on its Enyenra and Tweneboa fields. An FPSO-based field development is expected to be sanctioned in the second half of 2012. First oil of up to 125,000 bopd is expected about 2.5 years after the project sanction.
Exploratory drilling. This year, Kosmos Energy has drilled at least three successful wildcat wells in the West Cape Three Points block: Teak-2, which encountered 90 ft of net hydrocarbon-bearing pay in Campanian and Turonian reservoirs; Banda-1, which penetrated a 10-ft oil-bearing zone; and Akasa-1, which discovered light oil in 108 ft of oil-bearing pay consisting of Turonian-age sand packages. Kosmos plans to continue its exploratory drilling program in 2012. In the Deepwater Tano block, Tullow Oil will test wildcat candidates Turonian Deep, Cenomanian Deep, Sapele and Wawa during 2012.
SIERRA LEONE
Until recently, Sierra Leone had been engulfed in civil strife that had continued unabated since its independence in 1961. Relative stability since 2002 has opened up possibilities for oil and gas development.
In August 2009, Anadarko made the Venus discovery in block SL-06 with 50 ft of net hydrocarbon pay at 5,900-ft water depth. In November 2010, Anadarko encountered 135 ft of net oil pay with the Mercury-1 well in the adjacent SL-07 block. Both discoveries are in the Cretaceous-aged fan system that appears to be a geologic extension of the Jubilee find in Ghana. Anadarko is planning to drill its third exploratory well in the Jupiter prospect, which is located 16 miles west of the Mercury discovery, in late 2011.
LIBERIA
Liberia has no oil and gas production at this time, but exploratory drilling is currently underway in this frontier area, which is adjacent to the recent Cretacious fan wildcat successes in neighboring Sierra Leone. The leading operators are Anadarko, Chevron and Africa Petroleum. Simba Energy, a Canadian independent, is pursuing onshore opportunities in a coastal block. Australia-based African Petroleum announced the completion of its Apalis-1 well in September to a depth of 3,665 m in block LB-09. The well confirmed a prospective oil basin, but did not find commercial volumes of hydrocarbons. The company is planning to drill additional wells during the fourth quarter of 2011 and first quarter of 2012.
Anadarko operates three contiguous blocks: LB 15, LB 16 and 17. The company’s exploration program began in 2009 with a 6,164-sq-km 3D seismic survey on the blocks to develop the Cretaceous fan prospects. The Transocean drillship Discoverer Spirit is drilling the Montserrado-1 well in Block 15 to target the Cobalt prospect estimated to hold about 1.2 billion bbl. Anadarko will drill another well in the block, Strontium, during the second quarter of 2012. Chevron embarked on a three-year exploration program in 2010, but has yet to begin drilling operations.
GABON
Shell is the largest oil producer in Gabon with 70,000 bopd. The company discovered two of the largest oil fields in the country: Gamba-Ivinga in 1963 and 1967 and Rabi Kounga in 1985. In July of this year, CGGVeritas completed a 3D survey for Shell in 1,000–3,000-m water depths over complex salt structures. Shell will initiate a drilling program once targets are selected from the evaluation of seismic data.
Total produced 47,600 bopd in Gabon during the first half of 2011, a drop of 7% due to declining production, malfunctions in subsea pipelines and a labor strike. The French major is currently evaluating results of a 3D seismic survey conducted in 2010 over the Diaba license, and is entering Phase 3 of its offshore Anguille field redevelopment, which will involve the drilling of 21 wells next year.
The other major operator in Gabon is Eni, which was awarded six new exploration licenses in 2009, two in shallow water and four onshore, for a total area of over 7,600 sq km. Addax Petroleum, owned by Sinopec since 2009, has limited production in the range of 1,000–3,000 bopd at several onshore and offshore licenses.
OTHERS
Politically unstable Cote d’Ivoire (Ivory Coast) has seen E&P activity and limited production since 2001. However, civil strife has forced several of the operators to declare force majeure on operations. If political conditions improve, operators such as Tullow, Anadarko and Lukoil may begin drilling. In Mauritania, Tullow has acquired Roc Oil’s interests in the previously active Chinguetti oil fields. In Cameroon, Kosmos is performing technical evaluations of the initial drilling results in the Kombe N’sepe block. The company is expected drill the Liweny prospect on the N’dian River block in 2012. UK independent Bowleven has initiated drilling of the Sapele-3 well in the Douala basin.
TECHNOLOGY ADVANCEMENTS
Technology has been a key factor in the successful exploration and development of West Africa’s oil and gas sector. Some of the recent technology applications in the region are presented here.
Wellbore positioning practices and challenges. During onshore drilling in West Africa, it is standard practice to acquire only a single-shot survey of the inclination is acquired. A paper by Gary Skinner of Baker Hughes describes how more thorough directional surveys allow wells drilled more safely with closer spacing. Today, directional drillers routinely hit 50 m diameter targets from 5000 m away after having turned horizontally through 50° or more of azimuth. This has been made possibly through the use of modern drilling technologies, such as rotary steerable systems (RSS), and advanced surveying practices.1
Offshore fracturing campaign for Gabon’s Anguille field. Total’s Anguille offshore field was developed in the late 1960s with a combination of 73 producer and injector wells. Despite 40 years of production, the recovery factor has been low. As part of a redevelopment strategy, the operator decided conduct a nine-well hydraulic fracturing campaign using a rigless setup with slickline and coiled tubing. Multi-zone fracturing was performed using composite bridge plugs. Among the challenges included milling the bridge plug in under-pressured oil wells and scale deposition.2
First high-pressure drill pipe riser for intervention systems (DPRIS). For Total’s Usan project offshore Nigeria, Cameron and Vam Drilling helped implement the industry’s DPRIS to install and retrieve the production adapter base and tree cap. Before DPRIS, operators used conventional drill pipe with limited success due to interference between the drill pipe and hydraulic lines. The DPRIS employs drill pipe with heavy wall thickness and a proprietary double shoulder connection featuring a gas-tight metal-to-metal seal on the inner shoulder. Since July 2010, the DPRISS string has been used for a total of 20 runs, resulting in the safe and efficient installation of four trees with no cleaning issues and no rust debris impacting operations.3
Accurate vertical drilling and LWD evaluation for HPHT well eliminates casing string. An operator in offshore West Africa planned to drill a vertical well to acquire data for pore pressure management and reservoir fluid analysis in three main sand targets 3,800 m below the mudline under 150°C HPHT conditions. Accurate vertical drilling with the Power V HT system and high-quality, real-time arcVision HT and sonicVision HT data enabled informed decisionmaking that resulted in the saving of eight days of rig time and cost reduction of US$8 million due to the elimination of a casing sting, Fig. 5.
Gravel packing in deviated well avoids premature bridging. In a cased-hole operation in Equatorial Guinea, an operator sought to deploy a gravel pack operation in a highly deviated well while avoiding any premature bridging. Such premature bridging can leave voids throughout the gravel pack. These voids in downhole assemblies can lead to formation production, fines migration, formation collapse and other destructive events. Baker Hughes recommended using the DirectPak Ultra, a gravel pack secondary-path technology, which uses tubes located on the outside diameter of the screen to allow bypass of premature bridging to ensure a complete gravel pack around the screen. The job was completed, pumping approximately 7,500 lb of proppant into the perforations and around the screen. The gravel was successfully transported throughout the entire interval length.
E&P HOT SPOT
With the Gulf of Mexico still struggling to recover from the post-Macondo slowdown and the majority of Brazil’s deepwater operations under Petrobras control, West Africa is the leading deepwater oil and gas opportunity for both IOCs and small independents. As massive development and production projects are continuing at a consistent pace in Nigeria, Angola and Equatorial Guinea, the exploration frontier has shifted northward to Sierra Leone, Liberia and Gabon. 
LITERATURE CITED
1. Skinner, G. “Wellbore Positioning Practices and Challenges in Africa,” paper SPE 139122 presented at 2011 SPE/IADC Drilling Conference, 1-3 March 2011, Amsterdam, The Netherlands.
2. Gilles, LeBlanc; Bonifasius, Muryanto; and Stephane Ducourneau, “An Innovative Offshore Fracturing Campaign for a Mature Oil Field: Case Study Offshore West Africa,” paper 143565 presented at the SPE European Formation Damage Conference, 7-10 June 2011, Noordwijk, The Netherlands
3. Camus, M. et al, “Successful Qualification and Deployment of a High Pressure Drill Pipe Riser in West Africa,” paper OTC 22226 presented at OTC Brasil, 4-6 October 2011, Rio de Janeiro, Brazil.
Click here for a detailed case study of how well intervention using drill pipe riser is being deployed offshore in Nigeria’s Usan field, see the article by VAM, Cameron and Total authors at WorldOil.com. Additionally, see the expanded online version of this article for a review of technological advancements that are being applied throughout West Africa, as well as information about deepwater rigs operating in the region.
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