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Will the Current Drilling in Tobias Oil Field Bring New Life to Angola’s Onshore Kwanza Basin?

By Tako Koning, Calgary, Canada

Oil industry analysts and observers, both Angola-based and overseas, are closely watching a well testing programme underway in the Tobias oil field, located in the onshore Kwanza Basin, approximately 90 kilometres south of Angola’s capital city of Luanda.

This oil field has been inactive since it was abandoned in 1998 during Angola’s long civil war.

However, Sonangol – Angola’s state oil company and London-based Corcel Plc are attempting to bring life back into Tobias.

In the past half year they have drilled two wells, Tobias-13 and Tobias-14 in the Tobias field and have embarked on testing both wells.  Should they be successful, this could lead to a sharply rejuvenated interest in other opportunities within the basin.

History of Exploration and Production in the Onshore Kwanza Basin

The onshore Kwanza Basin was the first basin in Angola to have undergone oil exploration and development.  The first-ever well to be drilled for oil was in 1915 in the valley of the Dande River about 40 kilometres northeast of Luanda.  Oil exploration occurred sporadically for the next four decades with no commercial success.  The Belgium-based oil company Petrofina was the most active of the oil companies in the basin.  Petrofina drilled Angola’s first commercial oil discovery at Benfica, near Luanda in 1955.  Oil production commenced in the same year and eventually 80Million barrels of oil were produced from the onshore Kwanza Basin. The oil was delivered through a small diameter pipeline to the Petrofina refinery in Luanda.  The company achieved maximum production in 1988 when it delivered 18,000Barrels of Oil Per Day (BOPD).  About half of this oil was from eight fields which produced from the Lower Cretaceous-age Binga Formation limestones and the other half was from Miocene-age sandstones in the Quenguela North field.

Due to escalation of Angola’s civil war and the danger of attacks by the rebel faction UNITA, Petrofina stopped producing oil in 1998 and terminated all its field developments in the basin. Consequently, ten small oil fields remained unproduced or under-produced and eventually the fields fell into a state of disrepair.  In the past half decade, a few bid rounds have taken place where several blocks were available for acquisition.  Sonangol and some small Angolan oil companies and junior international oil companies are interested in rehabilitating the old oil fields using modern oil field technology. The Angolan companies have included Somoil, Simples Oil, Tusker Energy and Mineral One.  Edmonton, Canada-based MTI Energy has also obtained operatorship and non-operatorship in a number of blocks in the onshore Kwanza and onshore Lower Congo Basins.

Re-development of the Tobias Oil Field

In the past year, a high-profile event has been the drilling of two wells in the Tobias oil field in 2023 by Sonangol and Corcel Plc. This has resulted in a much-heightened interest by oil companies in the onshore Kwanza Basin.

The Tobias field is situated onshore in the southern area of the Kwanza Basin. The field consists of 12 historic vertical wells drilled in the 1960s and 1970s by Petrofina.   The discovery well, Tobias-2 was drilled in 1961 and discovered oil in the limestones of the Binga Formation.  Tobias is structurally a deformed anticline approximately eight (8) kilometres long and 1 kilometre wide. The Binga in Tobias is a low porosity limestone with an average of 2.0% porosity but locally the matrix porosity can be in the order of 14%, according to legacy 1983 and 1991 publications by Schlumberger.  Production is possible mainly because of the intense faulting and fracturing resulting from the folding of this structure.  The Tuenza evaporites serve as the caprock.

Structural cross-section across the Tobias oil field, onshore Kwanza Basin. From: Schlumberger, 1991 (Well Evaluation Conference, Luanda).

Oil in the Tobias field has a density of 31 degrees API.  The top of the reservoir is at a depth of 520metres (1,710 feet).  The initial oil column was 350 metres (1,150 feet) and the bottom hole pressure was 53kg/cm2. Due to the intense natural fractures in the Binga, the initial oil production was high at 12,000BOPD by solution gas drive (Schlumberger, 1983).  However, production dropped rapidly, and water injection was necessary to maintain production.  Prior to Tobias being abandoned by Petrofina, the field produced a total of 29Million barrels of oil.

Corcel Plc has a 20% working interest (18% net) in Block KON-11 which is operated by Sonangol. Corcel is an Angolan – Brazilian oil and gas company focused on onshore upstream development as well as mining and mineral resources development.  Corcel also has a 22.5% working interest in Kwanza Basin Block KON-12 and 31.5% in KON-16.

Corcel is an AIM-listed company.  The Alternative Investment Market (AIM) is the London Stock Exchange’s (LSE’s) international market for small and medium size growth companies.

Corcel announced that Tobias-13, which was spud in September 2023 was drilled at a downdip location from historic production and reached its target depth of 959metres. Corcel’s press release mentioned that the full Binga reservoir section of about 120metres was encountered in the well as prognosed and intersected 80metres of Binga reservoir with several potentially productive zones in multiple intervals.  Corcel stated that the results of Tobias-13 implies significant hydrocarbon potential remaining.

Tobias-14 was drilled directly after Tobias-13 to its target depth of 781metres.  In a December 28, 2023 press release, Corcel said that Tobias-14 was located at the top of the Tobias anticlinal structure and is an offset to Tobias-4, the largest historic producer in the field, which produced 12,580BOPD at its peak, albeit penetrating only the first eight (8) metres of the reservoir. Tobias-14 penetrated a full Binga reservoir section of about 80 metres with identical zones encountered as in Tobias-13 and had oil shows throughout.  Tobias-14 drilling encountered highly fractured oolitic limestones in the reservoir with good primary porosity values in the range of 4 – 14%. Corcel believes that the porosity is enhanced by the extensive, naturally fractured carbonate system.  Initial pressure readings support Corcel’s predrill thesis that the reservoir has returned to its original pressure values through active recharge of the system.  Tobias-14 found no presence of water despite Tobias-4 watering out at the end of its production life. Corcel believes that this indicates the field has been fully re-equilibrated.

Tobias-14 and Tobias-13 Well Testing Programme

In a February 12, 2024 press release, Corcel announced that testing of Tobias-14 has formally begun. Delays in the start of the testing have been encountered over recent weeks primarily due to longer than expected timelines for deliveries of required testing equipment, combined with severe inclement weather at the well location, which included heavy rains and regional flooding.

Once completed, the Operator, Sonangol will then move the test equipment to the Tobias-13 well pad, which is already being prepared for testing, and will conduct flow testing on the Tobias-13 well.  Testing of both wells will determine formation pressures and ultimately the flow rates. Sonangol and Corcel believe the results will allow them to restart production via an early production system (EPS).

Various companies and oil industry analysts are closely watching the oil industry media for announcements on the Tobias wells testing programme.  If favorable results are achieved, then this would send out the message that there is positive life left in the other old oil fields in the Kwanza Basin.  This could start a stampede of companies exploring for oil in similar fields or focus on greenfield exploration.

It is evident that the investment community has high hopes for positive news from Tobias.  One year ago, Corcel’s share price was 0.25 British pence per share.  Their share price quadrupled to the current price of 1.0 pence.

 

Tako Koning is Holland-born and Canada-raised.  He has a B.Sc. in Geology from the University of Alberta and a B.A. in Economics from the University of Calgary.  He lives in his home city of Calgary, Canada.   During his long career in the Canadian oil industry, he also lived and worked in Indonesia from 1980 – 1986, Nigeria from 1992 – 1995, and Angola from 1995 – 2015. He was employed primarily by Texaco and also by Tullow Oil (Angola Block 1/06) and Gaffney, Cline & Associates. He has driven through most of the onshore Kwanza Basin and had the opportunity to study the basin’s outcrop geology as well as visit some of the abandoned oil fields including the Tobias, Galinda and Quenguela North.  He is pleased to share his knowledge in this article.  For the past 23 years, he has been a member of the International Advisory Board of Africa Oil + Gas Report (AOGR) since it was founded in 2001 in Lagos, Nigeria by Toyin Akinosho.


SDX Spuds Ksiri-21 Well in Morocco’s Gharb Basin

SDX Energy has commenced drilling the Ksiri-21 (“KSR-21”) well in Sebou Central of the Gharb Basin, Morocco.

The vertical development well will be drilled to a planned total depth of approximately 1,950 metres.

Using existing three dimensional (3D) seismic, the well is targeting a well-defined prospect within the main Hoot formation, which is the main producing sand in the area.

SDX has drilled over 20 production wells in the same basin. As such, this new well presents a low-risk step-out location. The well can be immediately brought into production, supplying gas to existing customers, under the improved gas price announced on 5 June 2023.

The company considers the drilling “an early milestone in SDX’s new roadmap in Morocco”.

As part of re-energising SDX’s upstream production, “we will assess the feasibility of drilling additional wells, back to back”, says Daniel Gould, SDX’s Chief Executive.

“This type of programme would reduce capex per well, ensure operational efficiency, and prove sufficient reserves of ‘gas-behind-pipe’ to meet both existing and future demand.”

 

 


Cheiron Encounters New Oil in the Gulf of Suez

The Egyptian independent Cheiron has made a new oil discovery in the Geisum and Tawila West Concession in the Gulf of Suez.

The new find was made by the GNN-11 exploration well, which was drilled into a fault block to the east of the GNN oil field development. The well encountered 165 feet of good quality vertical net pay in the Pre-Miocene Nubia formation and this is the first time the Nubia has been found to be oil bearing in the GNN area of the Concession. The producing reservoir in the main GNN field is in the Nukhul formation.

The well was drilled from the recently installed GNN Early Production Facility (EPF) and has been successfully placed on production at a rate of over 2,500Barrels of Oil Per Day (BOPD). As result of the new well, and the successful drilling campaign conducted to date on the field, the gross oil production from the Concession has reached 23,000BOPD, compared to 4,000BOPD before the GNN field was developed.

Cheiron (through its PICO GOS affiliate) holds a 60% working interest and operatorship in the Concession, with Kufpec holding the remaining 40% interest. The field operations are managed by the PetroGulf Misr Joint Operating Company on behalf of EGPC (50%) and the Partners (50%).

GNN-11 is the fourth well to be completed from the EPF, which is located in the central area of the field and includes a conductor support platform, a mobile offshore production unit and a 10-inch oil export pipeline, tied back to the existing Geisum Star production complex. A further 3 wells can be drilled from the EPF and these will be used to complete the current phase of the GNN drilling program.

The new Nubia discovery confirms the exploration potential in the northern area of the Concession and Cheiron and Kufpec are planning to drill at least three additional exploration wells in the Concession area. In a broader sense, the discovery also demonstrates that whilst the Gulf of Suez is a relatively mature hydrocarbon province, it still has significant remaining exploration potential.


Schlumberger Signs a Turnkey Drilling Contract for Libya’s Murzuq Basin

Libya’s National Drilling Company, a subsidiary company of NOC, the state hydrocarbon company, has signed a contract with US-based SLB (formerly Schlumberger) to support an upcoming drilling campaign.

The agreement is a turnkey contract.

NOC says it is a first of its kind in the country.

SLB will provide support to the National Drilling Company in drilling three wells for the Remas Libya Company in the Nesr and Al Waha fields.

The three wells are to be sited in two concessions (NC 115 and NC 186), in the Murzuq Basin.

Spain’s Repsol Exploration Murzuq S.A. (REMSA) is the operating partner to NOC on the project.

NOC explains that the purpose of the three wells is to increase oil production and enhance collaboration between national and international companies.

 

 


Chevron Hits a Motherlode in the Mediterranean

Chevron and partners are evaluating a commercial sized accumulation of natural gas, encountered in the Narges 1 well, in the Mediterranean Sea offshore Egypt.

Tarek El Molla, the Egyptian Minister of Hydrocarbons, confirmed the discovery to the country’s parliament on Friday, December 16, 2022, but he did not give details of the estimated volume of the accumulation.

The Narges block in the Eastern Mediterranean is one of the assets that Chevron took over in the event of its recent acquisition of Noble Energy, the American independent.

The Middle East Economic Survey (MEES) reported in early December 2022, that the field could hold an estimated 3.5Trillion Standard cubic feet of gas. It also reported that the gas was encountered gas at the prognosed primary target depth of 3980 metres.

The estimated 3.5Tcf volume is about 15% of the ultimate recoverable reserves in the giant Zohr gas field, discovered by ENI in the same Mediterranean in 2015, and the discovery is timely. Africa’s third largest economy has been determined to maximize its exports of natural gas to improve its Foreign Exchange earnings. With gas production averaging 6.5Billion standard cubic feet per day in third quarter 2022, a year-on-year drop of 700Million standard cubic feet per day, the country commenced, last August, a rationing of gas for domestic power production, in order to free up more gas for export.

The Narges block is 45% operated by Chevron with another 45% owned by ENI, the Italian explorer.   Tharwa Petroleum, an Egyptian state hydrocarbon company, holds the remaining 10%.

The Narges-1 probe is being drilled by the drillship Stena Forth, in an acreage which lies some 60 kilometres from the Sinai peninsula, about 80 kilometres east of the nearest Egyptian gas infrastructure and 70 kilometres west of the long dormant Gaza Marine gas discovery offshore Gaza Strip, a Palestinian enclave.

 

 


BP Awards a Four – Well Contract to Valaris DS-12 in Egypt

The European major BP has awarded a four-well contract to Valaris Limited for the drillship VALARIS DS-12 for a campaign offshore Egypt. The contract is expected to commence late in the third quarter or early in the fourth quarter 2023 and has an estimated duration of 320 days. The estimated total contract value, inclusive of a mobilization fee, is $136.4 million.

President and Chief Executive Officer Anton Dibowitz said, “We are honoured that BP has chosen VALARIS DS-12 for their upcoming development campaign offshore Egypt. The rig has a long and successful track record with the customer, having worked for BP in several locations offshore Africa, including Egypt, over the past three and a half years. We look forward to partnering with BP on another successful campaign.”

Mr. Dibowitz added, “We retain significant operating leverage to the improving deepwater market through our fleet of 11 drillships, including three uncontracted high-specification rigs VALARIS DS-7, DS-8 and DS- 11, plus attractively priced purchase options for newbuild rigs VALARIS DS-13 and DS-14.

 

 


ENI Hits Another Paydirt Onshore Algeria

Italian major ENI and Algeria’s state hydrocarbon company SONATRACH say they have tested 1,300Barrels of Oil Per Day(BOPD) bbl/day of oil and about 2Million standard cubic feet of associated gas per day in the Rhourde Oulad Djemaa Ouest-1 (RODW-1) exploration well in the Zemlet el Arbi concession, located in the Berkine North Basin in the Algerian desert.

The hydrocarbons were encountered in the Triassic sandstones of the Tagi reservoir.

RODW-1 is the third well in the exploration drilling campaign, but the second discovery, coming, as it is  after what ENI calls “the significant discovery of HDLE-1, announced in March 2022”, and the successful second appraisal well HDLS-1 in the adjacent Sif Fatima II.

“The development of these discoveries will be fast-tracked, thanks to their proximity to existing BRN/ROD facilities”, ENI says in a release.

“The RODW-1 discovery confirms the validity of ENI’s and SONATRACH’s successful near-field and infrastructure-led exploration strategy, that allows a rapid valorisation of the new resources”, the company explains.

The Zemlet el Arbi concession is operated by a joint venture between ENI (49%), and SONATRACH (51%). The discovery is part of the new exploration campaign which will include the drilling of five wells in the Berkine North Basin.

 


CGG Wins a 3D OBN Seismic Acquisition Contract for the Nile Delta

The Atoll field peaked at 400MMscf/d in 2020…

Norwegian geophysical company CGG, has been awarded a project by British Petroleum (bp) and its JV Partner Pharaonic Petroleum Co, for the three-dimensional (3D) seismic imaging of the first Ocean Bottom Node (OBN) survey ever conducted in Egypt’s Nile delta.

The coverage involves the Atoll and Atoll North fields.

“CGG will apply its unique high-end OBS Full-waveform inversion (FWI) imaging technologies, expertise and specialised high-performance computing (HPC) from its UK and Cairo imaging centres”, bp says in a statement, “to deliver the highest-quality 3D seismic images of pre-Messinian targets with greater velocity model detail, image bandwidth and AVO reliability for improved field development planning and near-field exploration”.

BP started gas production from the offshore field in February 2018. The Atoll field, in the North Damietta concession in the East Nile Delta, peaked at 400Million standard cubic feet per day and 11,430Barrels of Oil Per Day in 2020.

Peter Whiting, Executive Vice President, Geoscience, CGG, said: “This new 3D OBN imaging project is the first of its kind in the Nile delta. With our in-depth geological knowledge of the region, based on our 35-year operating experience in Egypt, and our industry-leading OBS imaging technology, I have every confidence in CGG’s ability to overcome the seismic imaging challenges in this area and deliver the best possible subsurface insight to bp and joint-venture partners at Atoll.”


ION Completes Close to 20,000sq km of 3D Seismic Reprocessing in Mauritania

ION Geophysical Corporation (has completed the reprocessing and reimaging of approximately 19,100 km² of 3D seismic data offshore West Africa for its Mauritania 3D reprocessing programme.

The multi-client project was undertaken through an exclusive agreement with the Ministry of Petroleum, Energy and Mines in Mauritania. It is comprised of 11 vintage seismic surveys and provides a seamless, modern, high resolution data set spanning the Mauritanian offshore coastal basin. This basin is a key part of the frontier MSGBC basin in which several large-scale, offshore, gas fields have been discovered, with an estimated 63trillion cubic feet (Tcf)* in place in Mauritania thus far, ION declares.

“With foreign investment flowing in, field developments expected to come online in 2023, gas favoured as a source of energy for the energy transition, and capacity expected to exceed domestic needs, contracts for LNG export to European and other markets is anticipated”, the company reiterates.

“The MSGBC basin has become one that matters in the global oil and gas landscape, even if it is still today a frontier area. We have an enormous potential and we must find the right solutions to use these resources for the development of the country,” stated Chemsdine Sow Deina, Exploration Director at Societe Mauritanienne des Hydrocarbures (SMH).

“With ION’s delivery of its Mauritania 3D reprocessing program, operators now have a lower cost, lower risk, sustainable solution for evaluating the offshore hydrocarbon potential of Mauritania,” said Chris Usher, President and CEO. “As a result, we anticipate additional discoveries will be made that ensure Mauritania’s long term energy security, as well as exports that fund sustainable economic growth and development.”

The Mauritania 3D reprocessing program was supported by the industry and almost triples the amount of 3D data that ION has delivered this year from approximately 10,000 km2 to 29,000 km2. Final pre-stack depth imaged deliverables are now available. Learn more at iongeo.com/Mauritania.

*Estimate from Mauritania-Senegal: an emerging New African Gas Province – is it still possible? October, 1, 2020. The Oxford Institute for Energy Studies

 


TGS to Start a Second 3D Multi-Client Seismic Survey in the Egyptian Red Sea

The Norwegian geophysical company TGS, has announced a new three dimensional (3D) seismic survey in the Red Sea, Egypt, in partnership with Schlumberger.

This survey represents the second phase of new acquisition for the partners in this region and will encompass a minimum of 5,000 square kilometers. Data will be acquired with long offsets and processed using a Pre-Stack Depth Migration (PSDM) workflow to enable subsalt imaging. The acquisition is expected to start in April 2022, with final products anticipated in mid-2023 to ensure availability ahead of future license rounds in the region.

Egypt’s attractive, stable investment climate, enhanced by established exploration infrastructure and complemented by regular, transparent, and well-managed licensing rounds, has helped bolster interest in the Red Sea. The region is considered to hold significant hydrocarbon potential characterized by a wide range of prospective hydrocarbon systems comprising large, untested structures.

TGS and Schlumberger have a long-term commitment with the Egypt Ministry of Petroleum and South Valley Egyptian Petroleum Holding Company (GANOPE) to promote the prospectivity of the Egyptian Red Sea. Through the acquisition and processing of seismic data. GANOPE is responsible for managing Egypt’s hydrocarbon resource potential under latitude line 28°.

The survey is supported by industry funding.

 

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