March 2014

Regional Report: East Africa

Despite lackluster exploration results over the preceding decades, East Africa is beginning to emerge as an increasingly important hydrocarbon province.

Roger Jordan / World Oil
Left: Transocean’s Deepwater Millennium performs an accelerated well testing program that includes installing observation gauges and conducting several drill stem tests for Anadarko’s natural gas wells offshore Mozambique (image courtesy of Anadarko Petroleum). Center: A SASOL gas pipeline in Mozambique (image courtesy of SASOL): Right: Ocean Rig Poseidon, and associated support vessels, offshore Tanzania (image courtesy of Statoil/Heine Melkevik).

While Africa’s west coast has experienced a significant level of exploration over the course of recent decades, exploration for hydrocarbons on the continent’s east coast has been but a shadow of that level. According to the United Nations, East Africa includes no less than 20 countries—stretching from Eritrea, in the north, to Mozambique, in the south. This report will briefly examine developments in the region’s four main hydrocarbon players (Kenya, Tanzania, Mozambique and Uganda). It will conclude by examining a few of the innovative ways in which technology has been applied to enhance operations in the region.


Exploration history. Hydrocarbon exploration in Kenya dates back to the 1950s, with the first exploration wells being drilled in the 1960s.

Over the course of the past 50 years, a number of industry names—BP, CNOOC, Exxon Mobil, Shell, Total and Woodside—have tried their respective luck in Kenya. However, of the 33 wells drilled prior to 2012, none were deemed to be commercial, even though 16 showed potential for hydrocarbons.

Licensing. Licenses in Kenya have, traditionally, been awarded via direct negotiations. The country’s first licensing round, which would have afforded companies the opportunity to bid on eight blocks, was due to be held in June 2013, but was postponed. Furthermore, on Feb. 12, 2014, GlobalData, a research and consulting firm, reported that the licensing round is not expected before fourth-quarter 2014, at the earliest. The delay stems from a new proposed energy bill, which is expected to be passed in June. Energy Secretary Joseph Njoroge said the ministry was still consulting with county governors and senators.

Recent activity. London-based Tullow Oil operates five onshore blocks (10BA, 10BB, 12A, 12B and 13T), covering some 65,000 sq km, in the East African Tertiary Rift system; it also holds a 15% interest in Block L8, Fig. 1. The company is riding high, after drilling seven out of seven successful wells since the start of its Tertiary Rift basins exploration program in 2012, and it has ambitious plans for the future.


Fig. 1. Tullow Oil’s operated and non-operated onshore Kenyan interests (image courtesy of Tullow). 


On Jan. 15, Tullow updated its estimate of discovered resources in the South Lokichar basin to 600 MMbbl, gross, with a potential for over 1 billion bbl of oil. The announcement came after the company discovered oil in its Amosing-1 and Ewoi-1 exploration wells in Block 10BB, onshore northern Kenya.

Amosing-1 intersected a net oil pay of between 160 and 200 m, and Ewoi-1 encountered a net pay of 20 to 80 m. Angus McCoss, the company’s exploration director, said that the independent’s results from the basin, “have proven that Tullow’s onshore acreage in northern Kenya has the potential to become a significant new hydrocarbon province.” 

In November, Tullow announced that the Agete-1 well, Block 13T, had hit oil. The wildcat well, discovered and sampled moveable oil, with an estimated 100 m of net oil pay in good-quality sandstone reservoirs. In September, Tullow announced that the Ekales-1 well, Block 13T, found a potential net oil pay, in the Auwerwer and Upper Lokone formations, between 60 and 100 m.

In May 2013, Tullow commenced drilling on the Etuko prospect, 14 km east of Twiga South-1 in Block 10BB. The well encountered net pay of 90 m, and successfully opened the Basin Flank play in the eastern part of the South Lokichar basin. Etuko-1 flowed at a combined rate of over 550 boed. Additional, potential pay zones could not be tested, so a rig is now drilling a 650-m well, Etuko-2, to evaluate the shallower interval.

Tullow’s ongoing activities in Kenya include the testing of the previously mentioned Ekales-1 well, and the drilling of Emong-1 and Twiga South-2 exploration and appraisal wells. Testing operations on the Ekales-1 well are expected to be complete by the end of March. Emong-1 was spudded on Feb 5. Africa Oil, Tullow’s JV partner, places the gross best estimate of prospective resources for Emong at 242 MMbbl.

The rig that drilled Tullow’s recent Ewoi discovery has now been mobilized to drill the first of three back-to-back appraisal wells at the Twiga South oil discovery. Twiga South-2, which was due to be spudded in mid-February, is 2 km to the west of the Twiga South-1 discovery. The well is designed to assess the areal extent of the high-quality Auwerwer net pay encountered in the discovery well, and also the prospective resources associated with up to 150 m of shallower water-bearing, high-quality Auwerwer net sands encountered at Twiga South-1, which are within mapped closure at this location. Twiga South’s best gross estimate of unrisked prospective resources is 132 MMbbl of oil. An extended well test of Twiga South field is being planned toward the end of the year.

On Feb. 12, Tullow announced that it plans to conduct a significant drilling campaign over the course of the next two years. The company plans to drill approximately 40 exploration and appraisal wells to assess not only the South Lokichar basin, but up to a further six separate Tertiary Rift basins across its acreage.

Given the volumes discovered, and the extensive exploration, appraisal and seismic program planned to fully assess the upside potential of the South Lokichar basin, Tullow and its JV partner have agreed with the Kenyan government to commence development studies. In addition, the partnership is involved in a comprehensive pre-FEED study for an export pipeline. The current aim of both the government and the JV partnership is to reach project sanction for development, including an export pipeline, in 2015/2016. If further exploration success opens additional basins, there will be scope for the development to be expanded.

Tullow’s operations in Kenya have not, however, all been smooth-sailing. On Oct. 28, Tullow temporarily suspended all of its operations in Blocks 10BB and 13T. The suspension, which followed demonstrations by locals regarding concerns around employment, was lifted on Nov. 8, following discussions with officials and community leaders. 

Apache Corp. decided to exit Kenya after failing to find commercial quantities of gas in its sole Kenyan interest, Block L8. 

BG Group entered Kenya in 2011, signing PSCs with the government for two offshore exploration blocks, L10A and L10B, where it is the operator. BG owns a 40% interest in Block L10A and 45% of Block L10B. The UK-based company conducted seismic data acquisition, two 3D surveys and one 2D survey, during 2012 and 2013, and it plans to drill its first exploration well in 2014. BG believes that the potential, net unrisked resources are in excess of 1 billion boe.

Anadarko is the operator, with a 45% working interest, of five blocks (L-5, L-7, L-11A, L-11B, L-12) in Kenya. In its third-quarter operations report, Anadarko reported that the Kiboko-1 well encountered well-developed reservoir sands, with low permeability and indications of a working petroleum system. It plans to conduct additional exploration drilling in 2014.


Exploration history. According to Tanzania Petroleum Development Corp. (TPDC), 67 exploration and development wells have been drilled in the country’s coastal, deep sea and inland basins, with a total of 16 exploration and appraisal wells drilled offshore in deep water.

Fourteen gas fields have been found in Tanzania. Two of the fields—Songo Songo and Mnazi Bay—are already in production.

Licensing. Acreage offshore Tanzania is awarded through official licensing rounds. To date, three such rounds have been held, but, on Oct. 25, 2013, TPDC announced the country’s fourth licensing round. Seven deepwater offshore blocks (Blocks 4/2A, 4/3A, 4/3B, 4/4A, 4/4B, 4/5A, 4/5B), in water depths between 2,000 and 3,000 m, and the Lake Tanganyika North offshore block, which has a maximum water depth of 1,500 m, will be available for bidding. The deadline for the submission of bids is May 15.

Exploration activity. Tanzania boasts substantial reserves of natural gas. BG Group entered Tanzania in 2010 by farming into three blocks—1, 3 and 4—offshore southern Tanzania. The company assumed operatorship in 2011. The blocks cover more than 20,000 sq km of the Mafia Deep Offshore basin and the northern part of the Rovuma basin. Since 2010, BG has drilled 14 exploration and appraisal wells, with a 100% success rate.

On Dec. 10, BG raised its total gross recoverable resource estimate, for its three operated blocks, to 15 Tcf, with further exploration upside. As operator, BG holds a 60% interest in the blocks, while Ophir Energy and Pavilion Energy, which agreed to buy a $1.288-billion, 20% stake from Ophir in November, hold the remaining 40%. BG’s December announcement marked the conclusion of a successful campaign. The campaign confirmed Mzia as the JV’s second giant gas discovery, after Jodari, in its acreage offshore Tanzania. According to BG, Mzia boasts 4.7 Tcf of total gross recoverable resources. While further north, the JV’s discoveries in Block 4, Chewa, Ngisi and Pweza, are estimated to contain total gross recoverable resources of around 5 Tcf.

Upon the announcement, Chris Finlayson, BG’s chief executive, said that the company has “sufficient resources for a two-train LNG project in Tanzania. The aim of our appraisal program, now, is to optimize the future development plan and place the most economic gas into the proposed project first, to extract the most value across the chain.

“Onshore, BG Group and its partner, Ophir Energy, together with the partners in Block 2, Statoil and ExxonMobil, are continuing to make good progress in the assessment of a multi-train LNG project. We look forward to the Tanzanian government’s announcement of a decision on the location of an onshore site for an export facility.”

Two months later, on Feb. 14, Bloomberg reported that BG and Statoil are to build Tanzania’s first LNG plant in Lindi, and are due to meet with authorities about the project’s schedule and details in April. The proposed plant is expected to export LNG to Asia, in a bid to profit from rising regional demand. Tanzania’s government hopes that Statoil and BG will decide to build the plant with “at least” two trains, according to energy minister Sospeter Muhongo.

Following the latest Mzia well, Mzia-3, the Deepsea Metro-1 drillship was transferred to Ophir Energy for a one-well campaign. On Jan. 2, Ophir announced that drilling operations had concluded on its Mlinzi Mbali-1 well in Block 7, which is owned by Dominion Tanzania—a wholly-owned subsidiary of Ophir. Ophir CEO Nick Cooper said, “Mlinzi Mbali-1 was the first of a series of high-impact, high-risk wells that will be drilled by Ophir through 2014. This frontier well disappointingly did not encounter live hydrocarbons; however, it is the deepest stratigraphic test offshore Tanzania and will provide crucial information that will be integrated into our interpretation of the potential of Block 7, and the wider deepwater basins of Tanzania.”

Upon completion of the Mlinzi Mbali-1 well, the drillship was returned to BG, to drill an exploration well offshore Kenya. Upon completion of that well, the drillship will return to Tanzania’s Block 1 for further exploration and appraisal activities, including a drillstem test on Mzia-3. The vessel also will undertake operations on Ophir’s operated East Pande Block during first-half 2014.

Statoil has been present in Tanzania since 2007, when it signed a PSA for offshore Block 2. Statoil Tanzania is the block’s operator, with a 65% working interest, and Exxon Mobil Exploration and Production Tanzania Ltd. holds the remaining 35%.

In December, Statoil announced its fifth discovery in Block 2. The Mronge-1 well, drilled by the drillship Discoverer Americas, struck an additional 2-3 Tcf of natural gas-in-place, Fig. 2. The find brings the block’s total gas-in-place to 17-20 Tcf. Last May, Statoil farmed-in to offshore Block 6, acquiring a 12% working interest from the operator, Petrobras Tanzania. Petrobras was left with a 38% interest; the remaining 50% is held by Shell Deepwater Tanzania.


Fig. 2. The Discoverer Americas drillship working offshore Tanzania (image courtesy of Statoil/Paul Joynson Hicks).



Exploration history. According to Deloitte, hydrocarbon exploration in Mozambique dates back to 1948. Prior to 1971, 54 exploration wells had been drilled, of which 10 were offshore. However, despite these efforts, no commercial discoveries were made, and exploration came to a halt.

Licensing. Mozambique is poised to launch its fifth oil and gas bidding round in 2014, a government official told Reuters in November.

Exploration activity. Anadarko Petroleum entered Mozambique, through a subsidiary, in December 2006. The company signed an E&P concession contract (EPCC) for Offshore Area 1 in the Rovuma basin, which covers about 2.6 million acres, Fig. 3.


Fig. 3. Mozambique’s offshore Area 1 (image courtesy of Anadarko Petroleum).


In its fourth-quarter operational report, Anadarko reported that, in conjunction with Eni, the operator of Area 4, it had agreed to a development framework for its Prosperidade complex. According to the framework, Anadarko is pushing the initial development of two, 5-MMtpa LNG liquefaction trains. The FEED for offshore gathering infrastructure has been completed; the FEED for the liquefaction facilities is on schedule. The partnership has non-binding heads-of-agreements in place, covering approximately two-thirds of the first 5-MMtpa train.

Early in fourth-quarter 2013, drilling was completed at the Manta-1 well. The well encountered 358 ft of natural gas pay in two Oligocene reservoirs and 115 ft of well-developed Paleocene gas pay. Pressure data from the Paleocene within Manta-1 suggested static communication with the Paleocene reservoir at the Orca-1 discovery, 4.5 mi to the south. This increases Orca’s potential size, which is expected to be further delineated by Orca-2 and Orca-3.

In August 2013, Anadarko entered into a definitive agreement with ONGC Videsh Ltd., a wholly-owned subsidiary of India’s Oil and Natural Gas Corporation, to sell a 10% interest in Area 1, for $2.64 billion. Anadarko will remain as operator of Area 1, with a working interest of 26.5%. The transaction was expected to close during first-quarter 2014.

During the third quarter, Anadarko drilled Golfinho-5 at the down-dip edge of the northern end of Golfinho field, and encountered almost 330 net ft of well-developed Oligocene pay and no water contact. The well appeared to be in static pressure communication with the rest of the field. Golfinho-6 was drilled to the west and up-dip of the Atum-1 discovery. The well encountered approximately 240 net ft of high-quality Oligocene pay. This well also appears to be in static communication with the rest of Golfinho field.

On July 26, 2013, Italy’s Eni concluded the sale of a 28.57% interest in Eni East Africa (EEA) to China National Petroleum Corporation (CNPC). EEA retains a 70% interest in Area 4, offshore Mozambique. CNPC indirectly acquired, through its equity investment in Eni East Africa, a 20% interest in Area 4, while Eni retains operatorship and a 50% interest through the remaining stake. The total consideration was equal to
$4.67 billion.

The exploration campaign of the year concerned appraisal of the Mamba and Coral discoveries, and a new prospect in the Southern section of Area 4, where, in September 2013, Eni made the Agulha discovery, the tenth in Area 4. Eni believes that Area 4 could contain up to 2.65 Tcm of gas-in-place. In 2014, Eni will continue appraisal activities, particularly regarding the new exploration prospect, where the drilling of two to three additional wells is planned.

Statoil has been present in Mozambique since 2006. The company operates Blocks 2 and 5, offshore northern Mozambique in the Rovuma basin. In September, it was revealed that Statoil, in conjunction with JV partners Tullow, INPEX and ENH, had drilled a dry well in Block 2. In July, the JV’s Cachalote-1 well discovered a gas-bearing reservoir in an Upper Cretaceous deepwater channel system. The well encountered 38 m of good-quality, gas-bearing sandstone. It was, however, deemed unlikely to be commercial, and was plugged and abandoned.

In November, Reuters reported that Mozambique’s first commercial production and sale of crude oil, from an onshore oil field at Inhassoro, was planned for 2014. Sasol conducted extended well testing on the Inhassoro oil rim. The South African company is also preparing to expand an existing gas processing facility and a pipeline to South Africa.


Exploration history. Natural oil seeps on the shores of Uganda’s Lake Albert have been recorded for many years, and in 1938, the country’s first exploration well was drilled. Despite demonstrating the presence of oil, it would be nearly 70 years before further activity took place.

Exploration activity. Tullow obtained its first exploration license in 2004. Two years later, the independent made four discoveries, successfully demonstrating the Lake Albert Rift system’s potential as a working hydrocarbon basin. Tullow estimates the resources to be an estimated 1.7 billion bbl of oil. In 2012, Tullow concluded the sale of two-thirds of its Ugandan licenses to CNOOC and Total. 

On Feb. 5, the Ugandan government signed an MoU, that agrees to a commercialization plan, with Tullow, Total and CNOOC. The MoU concept involves an integrated development of the nation’s upstream, a crude oil export pipeline and a 60,000-bopd refinery, to be developed in a modular manner, starting with 30,000 bopd. A lead investor to develop the refinery is expected be selected by the Ugandan government by the end of first-half 2014. The partnership is conducting a comprehensive pre-FEED study for the pipeline. It has submitted production license applications (PLAs), including field development plans (FDPs), for seven of the fields, in line with the agreed commercialization plan in the MoU. Remaining PLAs and FDPs will be submitted during 2014. The FDP for the Kingfisher discovery area was approved, and the production license conditions have been met. 


As a frontier region, East Africa continues to be the subject of extensive geophysical and geological research, and the application of advanced technologies to enhance drilling and production operations. A few of the recent applications are outlined below.

Tectonics of the Mozambique margin through the integration of gravity and magnetic modeling. Rovuma basin case study.1 The Rovuma basin stretches about 64,000 sq km across both onshore and offshore areas. The correct depiction of the geologic evolution of a basin is important for the proper assessment of petroleum potential. Eni geoscientists performed an integrated study by applying structural analysis, and 2D gravimetric and magnetic modeling, to develop more predictive and reliable geological models. The study resulted in a better definition of the structural lineaments and their relative chronology. Most importantly, the study characterized the continental, transitional and oceanic crust bodies, and defined a continental ocean boundary.

Organophilic chloride-free reservoir drill-in fluid meets the challenges of the first horizontal well in Mozambique.2 An operator was planning to drill the first horizontal well in Mozambique’s Inhassoro field with an open-hole completion, utilizing expandable screens. The formation had highly reactive shale stringers, requiring an inhibitive fluid. Due to environmental restrictions, a non-aqueous fluid system could not be used to drill or complete the horizontal section. MI-Swaco developed, tested and successfully implemented a chloride-free, potassium acetate as an alternative base fluid.

First application of progressing cavity pumps for appraisal well testing in Uganda’s Albertine Graben basin.3 Ugandan crude is moderately viscous, with a low-gas/oil ratio, and it was discovered in shallow, lower-energy systems. In addition, Ugandan crude has relatively high pour points and wax appearance temperatures, which result in flow-assurance challenges during production testing operations. Tullow engineers retested Well X-1 with a new completion design, incorporating a progressing cavity pump. High-quality well-test data were acquired, and the real-time data were used extensively to optimize flow and buildup periods, and well operating envelopes. wo-box_blue.gif


  1. Longoni, R., M. Gilardi and G. Spadini, “Tectonics of the Mozambique margin through the integration of gravity and magnetic modelling: The Rovuma basin case study,” International Petroleum Technology Conference, doi:10.2523/17345-MS, Jan. 19, 2014
  2. Ezeigbo, C., M. Luyster, R. Ravitz, A. Pereira and C. M. Nguyen, “A specially designed organophilic chloride-free reservoir drill-in fluid meets the challenges of the first horizontal well in Mozambique,” Society of Petroleum Engineers, doi:10.2118/151837-MS, Jan. 1, 2012.
  3. Sathyamoorthy, S., A. Steyn, J. McGilvray, H. Fuchs, B. Ainebyona, P. Kyomugisha and D. Basiima, “First application of progressing cavity pumps for appraisal well testing in the Ugandan Albertine Graben basin,” Society of Petroleum Engineers, doi:10.2118/159163-PA, Jan. 21, 2013.
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Roger Jordan
World Oil
Roger Jordan
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