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■ Geology - p22 ■ Gas - p24 ■ E&P - p26 ■ Technology - p34
Volume 9 Issue Four 2014
www.oilreviewafrica.com
Africa
Covering Oil, Gas and Hydrocarbon Processing
Europe m10, Ghana CD18000, Kenya Ksh200, Nigeria N330, South Africa R25, UK £7, USA $12
Oil Review Africa - Issue Four 2014
African finance for energy projects Equatorial Guinea regrouping or grasping for straws? Gabon’s watershed moment Fire safety: preventing the unthinkable Extending field life and increasing recovery rates The changing face of remote oilfield communications Nigeria’s transformation agenda
Pipelines www.oilreviewafrica.com
- modifying the Chad-Cameroon pipeline Wale Tinubu, chairman of Oando Energy Resources. See page 5.
REGULAR FEATURES: ■ News ■ Contracts ■ Events Calendar ■ IT update ■ Company profiles ■ Products & Innovations
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S01 ORA 4 2014 - Start_Layout 1 7/24/2014 11:35 AM Page 3
■ Geology - p22 ■ Gas - p24 ■ E&P - p26 ■ Technology - p34
Contents
Volume 9 Issue Four 2014
www.oilreviewafrica.com
Africa
Covering Oil, Gas and Hydrocarbon Processing
Europe m10, Ghana CD18000, Kenya Ksh200, Nigeria N330, South Africa R25, UK £7, USA $12
African finance for energy projects Equatorial Guinea regrouping or grasping for straws? Gabon’s watershed moment
Columns
Fire safety: preventing the unthinkable
Industry news and executives’ calendar
4
Extending field life and increasing recovery rates The changing face of remote oilfield communications
Analysis
Nigeria’s transformation agenda
Energy investment – a rising trend
10
Pipelines
A special report from the International Energy Agency sees an increasing role for governments in shaping investment decisions; in Africa the main focus will continue to be on development of oil resources.
- modifying the Chad-Cameroon pipeline Wale Tinubu, chairman of Oando Energy Resources. See page 5.
REGULAR FEATURES: ■ News ■ Contracts ■ Events Calendar ■ IT update ■ Company profiles ■ Products & Innovations
TD Williamson was tasked with executing the entire Chad-Cameroon pipeline modification project.
African Finance Sources for funds for African energy projects
12
A look at the fiscal challenges facing the banking sector in financing Africa’s current and future energy projects.
Editor’s note
Country Focus Namibia
15
Creating a tectonic atlas for Nambia and western South Africa.
Equatorial Guinea
16
Regrouping or grasping for straws?
Gabon
18
Gabon’s watershed moment.
Exploration & Production News and developments
26
The latest exploration and production news from around the region.
Safety Fire safety
34
Fire safety challenge spurs oil and gas industry to find innovative new solutions.
Meeting African onshore and offshore H2S challenges
38
INFRASTRUCTURE INVESTMENT IS critical for the economic and social development of the African continent. In this issue we look at problems faced by project promoters and potential lenders. Sources of funding for energy projects in Africa are diversifying to include local, foreign, public and private sector investment, and it is increasingly apparent that the private sector’s contribution to financing energy projects in Africa over the coming decades will increase whilst that of government will diminish. We look at Equatorial Guinea, where arresting mature decline would have been the best way to start staging a comeback for the tiny hydrocarbon nation. In fact, in many more established oil-producing nations of Africa, renewed brownfield investment in EOR techniques is needed. Luckily, the ability of operators to extend the life of their fields has never been greater. Reservoir modelling is one such technique and this has a crucial role to play in unlocking reservoir value, extending field life and increasing reservoir recovery. One area in which oil companies will never cut corners is safety. This issue looks at the fire safety challenge and innovative new solutions to prevent the unthinkable. We also look at the safety challenges in dealing with H2S and working in irrespirable environments around the world.
A look at the safety challenges in dealing with H2S and working in irrespirable environments around the world.
Technology Extending field life
52
42
The battle to prolong oil flow from Africa’s mature fields. Reservoir modelling has a crucial role to play in unlocking reservoir value, extending field life and increasing reservoir recovery.
Nigeria Ministry of Petroleum Resources: Live wire of transformation agenda
46
A look at the giant strides being made by the ministry under Alison-Madueke in respect of the strategic objectives of the industry.
Information Technology The changing face of remote oilfield communications
51
In the second of two articles on the changing face of oilfield data and voice communications in remote locations, Phil Desmond asks whether satellite networks can cope with growing offshore demand.
O3b network satellite fleet image.
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Oil Review Africa Issue Four 2014 3
Industry News & Events
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Executives’ Calendar 2014 AUGUST 5-7 18-19 18-20 26-27 25-28
NAICE-Society of Petroleum Engineers Nigeria Annual International Conference & Exhibition West Africa Oil and Gas Security Summit Oil & Gas Summit Africa Gas Africa Conference ONS
LAGOS
www. spenigeria.spe.org/naice
LAGOS MAPUTO SANDTON STAVANGER
www.waoilgassecurity.com www.africa.oilgassummit.com www.mcnaughtonevents.co.za www.ons.no
Cairo Energy Oil & Gas Exhibition South Africa Local Content Summit
CAIRO CAPE TOWN
www.cairoenergy.com southafrica-local-content.com
IADC Drilling Africa Conference & Exhibition CIEMEOGIS 2014 EAOGS-3rd East African Oil and Gas Summit Practical Nigerian Content Forum Global African Investment Summit Gabon Oil & Gas Mozambique Continuous Education & Career Development Forum Gulf of Guinea Gas
PARIS ABIDJAN NAIROBI YENAGOA LONDON LIBREVILLE MAPUTO ABUJA
www.iadc.org www.cotedivoiresummit.com www.eaogs.com www.ncipnc.com www.tgais.com www.theenergyexchange.co.uk www.elliteic.net www.cwcgog.com
Africa Oil Week NAPE-32nd Annual International Conference and Exhibition ADIPEC
CAPE TOWN LAGOS ABU DHABI
www.petro21.com www.nape.org.ng www.adipec.com
Valve World Expo
DUSSELDORF
www.valveworldexpo.com
SEPTEMBER 6-9 16-17
OCTOBER 1-2 7-9 15-17 18-20 20-21 23-24 24-26 28-30
NOVEMBER 3-7 9-13 10-13
DECEMBER 2-4
Readers should verify dates and location with sponsoring organisations, as this information is sometimes subject to change.
ADIPEC celebrates 30 years
Smart surveillance camera solutions at CIS
THESOCIETY OF Petroleum Engineers (SPE) is returning as conference organisers for ADIPEC 2014, organised by dmg events. This event is an opportunity for like-minded professionals to join and contribute to one of the largest industry shows in the Middle East. Providing a firstrate platform for exchanging knowledge and best practices, the conference brings together renowned international speakers, researchers, and experts with a carefully selected mix of technical. This multi-disciplinary conference is intended for international and regional oil and gas professionals, who are involved in both the technical and non-technical functions within the industry. The Abu Dhabi International Petroleum Exhibition & Conference (ADIPEC) will return on 10-13 November 2014 and will be celebrating 30 years of service to the industry. Since its inception in 1984, ADIPEC has provided an unrivalled platform for industry experts to come together and share knowledge and
INTERNATIONAL EXHIBITOR INTEREST and support for the Oil & Gas Africa and Maritime & Offshore Marine Africa exhibitions – two of the four component shows of the Cape Industries Showcase (CIS) – continues to surge. A major drawcard for visitors was the sheer volume of new technologies and high-tech products from around the world on display. CCTV technology supplier Videotec, already well-known in South Africa’s security market, plans to expand its product, technology and services footprint into industrial sectors. Videotec manufactures a wide range of CCTV surveillance systems, and now offers specialised high-tech products specifically designed to operate under extremely harsh conditions in the oil, gas and onshore and offshore marine sectors. The company launched its new Ulisse compact HD integrated pan-tilt-zoom (PTZ) camera at the CIS show. It was successfully launched at the Intertraffic Exhibition in Amsterdam in March. The Ulisse compact HD cameras feature true high-resolution progressive scanning with advanced image stabilisation; they also offer continuous horizontal rotation with day/night monitoring capability, and can withstand temperatures from -40°C to +60°C. “Security surveillance is an essential component of all business today and Videotec has the technology, expertise and solutions to make it effective, so please do visit us at the Cape Industries Showcase,” said Videotec’s marketing and communications manager, Alessandro Franchini. The Cape Industries Showcase (CIS) encompasses the Maritime & Offshore Marine Africa Expo, the Oil & Gas Africa Expo, the Refrigeration and Airconditioning Expo and the Empowertec Africa SME Expo. Maritime Offshore Marine Africa’s exhibition profile includes ship building and repair, marine engineering, offshore mining, fishing and work boats. Oil and Gas Africa is an event dedicated to West Africa’s offshore oilfield operations.
4 Oil Review Africa Issue Four 2014
meet with peers. ADIPEC remains in the top three oil and gas events in the world welcoming delegates, visitors and exhibitors from across the globe. Established as one of the largest conference programmes globally, the ADIPEC 2014 Conference, under the theme of 'Challenges and Opportunities for the Next 30 Years', presents two conferences in one, offering the following plenary and technical content: 6 81 Technical conference sessions 6 Ministerial panel session 6 Keynote address 6 Two CEO plenary sessions 6 Eight industry panel sessions 6 Four academia sessions 6 Three IT security sessions 6 Middle East Petroleum Club programme and more
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Industry News & Events
DR Congo added to transparency group THE DEMOCRATIC REPUBLIC of Congo has been given full membership to the Extractive Industries Transparency Initiative (EITI), the global organisation which promotes good management of oil, gas and mineral resources. The group has announced that This oil and gas field at Moanda has been in the Congo was made an official operation since the 1970s. Photo: UNEP part of the group just over a year after the country failed to disclose its mining sector revenue. EITI said the government had since addressed the issues raised in a 2010 report which resulted in the country’s suspension. It added that the DR Congo was now compliant. EITI chair Clare Short said the country had made efforts to reform, despite challenges. "Despite all the challenges facing the country, the Congolese people have been working together to bring transparency and accountability to the management of their natural resources," Short said. The organisation, which involves governments, companies, civil society groups, investors and organisations, encourages transparency by tallying revenue declared by states and comparing that to payments made by resources companies. The DR Congo was ranked 154 of 177 countries in Transparency International's 2013 corruption perception index.
Approval granted for Oando’s acquisition OANDO ENERGY RESOURCES Inc has received government approval for the acquisition of the Nigerian upstream oil and gas business of ConocoPhillips for a total cash consideration of US$1.65bn, subject to customary adjustments. OER and ConocoPhillips are now positioned to complete the ConocoPhillips transaction. Having received consent from the minister of petroleum resources, both parties have extended the outside closing date for completion of the acquisition to enable them to finalise activities required to conclude the transaction. Commenting, Wale Tinubu, chairman, OER said “We are delighted to receive the approval of the honourable minister of Petroleum Resources for the completion of the acquisition. It has been a long journey, wherein we kept faith with our strategy and executed every milestone diligently. This acquisition satisfies our criteria for assets in production, as well as excellent appraisal and exploration prospects. The coast now stands clear for us to immediately complete the acquisition”. OER will now work with ConocoPhillips towards completing the acquisition by the long stop date of 31 July, 2014. Wale Tinubu, chairman of Oando Energy Resources
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Oil Review Africa Issue Four 2014 5
Industry News & Events
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Atwood Hunter to work for CNOOC offshore EG ATWOOD OCEANICS INC has announced that one of its subsidiaries has been awarded a drilling services contract by China's CNOOC Africa Ltd for the Atwood Hunter (deepwater semisub). The contract will be performed offshore Equatorial Guinea, specifies a day rate of US$337,000 for a minimum term of 90 days and includes an option for one additional well. To the extent the term exceeds 90 days the day rate for days 91 to 180 shall be US$330,000. Any term in excess of 181 days shall have a dayrate of US$325,000. The Atwood Hunter is expected to commence the contract midAugust 2014. In connection with this contract, an Atwood subsidiary and Guinea Ecuatorial de Petroleos (GEPetrol) mutually agreed to terminate the parties' previously announced contract for the Atwood Hunter provided certain conditions are met.
Wood Group Kenny takes TEN job WOOD GROUP KENNY has been awarded a subsea engineering services contract on the Tullowoperated Tweneboa, Enyenra and Ntomme (TEN) project, off Ghana. Wood Group did not reveal the value of the contract which will see it supply subsea, umbilical, risers and flowlines engineering services on the project. It will provide Tullow with project engineering resources, specialist technical support and technical assurance services across the Surf implementation work scope through to first oil. The TEN fields lie in the deepwater Tano Block, about 60 km off Ghana, and the development will see the drilling and completion of up to 24 development wells which will be connected through subsea infrastructure to a floating production, storage and offloading vessel which is currently under construction in Singapore. First oil from the TEN fields is currently scheduled for mid-2016.
Avoid bringing politics in business, govts told AFRICAN GOVERNMENTS SHOULD not mix politics with crucial business ventures including the extractive sector, which is considered one of the big contributors in world economy. Stakeholders convening for training on reporting gas and oil issues in Kampala recently expressed their concerns saying political ‘meanders’ have fatally wounded the lucrative sector in Africa “Decisions based on political interests have seriously injured development of the extractive sector, and socio-economic set up of the African communities,” said Abeinomugisha Dozith, principal geologist in Uganda’s department of petroleum exploration and production, ministry of energy and mineral development. The geologist expressed fears about sustainability of the sector in some African counties citing Ghana, Tanzania and Uganda where politics had created considerable setbacks in the sector. “If technical people are not allowed to do their work due to political interference, entire communities will never benefit from the resources,” he said. In his presentation titled ‘exploration, development and production overview of oil and gas,’ the geologist said if the petroleum sector is well managed it can transform other sectors. African countries should build capacity for local people to participate in the sector so as to improve the people’s economic standards, he said. “Since most African countries do not have enough human resources to work in the sector, we need to train manpower to work in the sector,” Abeinomugisha noted. However, due to unfamiliar terminology in the oil and gas sector the geologist called on media houses to designate specific journalists who can effectively report on the sector by helping the community to understand what is available in the sector.He said technical terms in the sector have been misused because there are no specific journalists who have been trained to report in the sector. “Report responsibly, avoid sensational reporting because the oil and gas industry has the potential to disrupt other sectors,” he added.
MPL orders four ROVs from Forum
Seplat records 404% profit growth in 2013
FORUM ENERGY TECHNOLOGIES Inc has received an order from Marine Platforms Ltd (MPL) to supply four work-class remotely operated vehicle (ROV) systems each complete with a Dynacon launch and recovery system. The order includes three Perry heavy work class XLX Evo 200HP ROVs, the latest generation of the Perry XLX series. Two of the systems will be mobilised aboard MPL’s new “African Inspiration” multi-purpose service vessel for service offshore West Africa and the other two will be added to their global fleet. “Forum is very pleased with its continued association with Marine Platforms,” said Bill Boyle, Forum Subsea Technologies’ senior vice president. “The choice of Perry vehicles for their new vessel and for use in such an operationally demanding market represents a vote of confidence in the reliability of the XLX series and reflects Forum’s strategy of providing first class engineering and after-market service to our clients.”
NIGERIA'S LARGEST INDIGENOUS upstream operator, Seplat Petroleum Development Company, has reported a massive profit increase of 404 per cent for the full year 2013. The figures that would be exciting to shareholders of the dual-listed company – on the Nigeria Stock Exchange (NSE) and London Stock Exchange (LSE) – were contained in the 2013 annual reports released at the first Annual General Meeting (AGM) of the company as a public entity. “The future of our company is very bright,” declared the excited chairman of Seplat, ABC Orjiako, who was impressed by the continued exponential growth of the company amid uncertainties shrouding the oil and gas sector on the passage of the Petroleum Industry Bill (PIB) and reduction in US demand for Nigerian crude oil, among others. The company has managed to grow its crude oil production from 11.5mn barrels in 2011 to 18.8mn barrels in 2013, with an exit rate 61,700 barrels daily as at 31 December 2013. Revenue for the year ended 31 December 2013 also grew by 41 per cent in one year to US$880.2mn. Further into the future, Seplat intends to continue infrastructural development to enhance operational efficiency and in turn grow revenue, Seplat CEO Austin Avuru stated. “New developments for recent discoveries and the completion of identified development projects will also ensure that the company is well-positioned to grow both reserves and production by converting contingent and prospective resources into commercial reserves,” Avuru added. The oil and gas company is working on increasing capacity and revenue by commercialising gas production, averaging 99mn scfd in 2013 and expected to reach about 300mn scfd by 2016.
MPL’s new “African Inspiration” being guided safely to shore.
6 Oil Review Africa Issue Four 2014
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Industry News & Events
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Workforce survey in EG and Gabon
Ghana JV to build workforce for seabase
OILCAREERS.COM AND AIR Energi’s 2014 H1 Workforce Survey delved into the oil and gas market focusing on key areas of oil production in West Africa with thought provoking results. Equatorial Guinea has been a significant oil and gas exporter since the 1990’s with production mainly from the Zafiro, Ceiba and Okuma fields. Equatorial Guinea had proven oil reserves of 1.1 bn barrels as of January 2012 with developing technologies making access to these much easier. The industry has nurtured local candidates, with companies like Marathon Oil hiring a number of interns each year and offering training and development programmes for employees. However retention in Equatorial Guinea is low with the prospect of higher wages luring workers abroad. Gabon is a mature region that, despite facing declining output over the last decade, is still among the top five oil producers in subSaharan Africa. Although the area’s decline in production rate has reduced in recent years as international companies invest in longevity projects at mature fields, the current workforce faces the same issues as that of Equatorial Guinea with a lack of skilled professionals due to migration to better paid areas. Developments in both regions offer extensive opportunities for skilled oil and gas workers, however the market will be unable to thrive until the issue of workforce retention is addressed.
SINCE THE DISCOVERY of the Jubilee oil field in the Gulf of Guinea in 2007, offshore Ghana has attracted considerable oil and gas investment that has been a boon to the West African country's economy. Ghana's annual overall economic growth rate has averaged approximately six per cent in as many years, according to a 2014 report by the African Development Bank Group. In the case of the service-oriented sectors and industry, economic growth has been even more robust during the period, the report states. Anticipating continued growth in Ghana's burgeoning oil and gas sector, Swift Worldwide Resources and the Eastern Nzema Stool community in the country's southwestern Atuabo region have formed a joint venture that will provide job opportunities for more than 2,000 individuals – mostly Ghanaians. The jobs will stem from the pending construction of the Atuabo Free Port, a US$1.5bn deep-water shorebase that Lonrho Ghana Ports Ltd will develop to support logistics needs of offshore operators in Ghana and elsewhere in West Africa. "We at Swift take seriously our commitment to the areas in which we work worldwide," said Swift CEO Tobias Read. "This partnership is a great example of leveraging our expertise to support community objectives, help bolster employment and develop skills in the local economy." “This joint venture is unique in the fact that its profits after cost recovery will be reinvested in training programmes for the communities, which will allow Ghanaians to acquire the skills necessary for obtaining more technical positions. The model is designed so that it can be mirrored over and over again.”
Africa’s growing energy sector now offers more top paying jobs than Middle East AFRICA'S BOOMING ENERGY sector now accounts for 13 per cent of the best paying roles advertised for international oil and gas experts, more than the Middle East, according to new research by Von Essen, the leading providers of tax advisory services to international contractors. Von Essen says that a growing number of oil and gas jobs offering more than US$170,000 per annum are being created by increased exploration and extraction activity in Africa, not just in well-established centres in northern Africa and Nigeria, but increasingly also in Kenya, Ghana, Tanzania, Niger, Uganda, Mozambique, and Angola. Von Essen explains that the business environment in many African countries has been improving, encouraging greater external investment. Ghana, Niger, Uganda and Kenya can now produce more than 100,000 bopd.
Nigeria is estimated to be the world’s tenth most oil-rich nation and one of the few oil producers that has not yet hit peak production. Nearly all of the country’s reserves are found in the delta of the Niger River where there are approximately 160 oil fields and 1,480 wells in operation. Angola has also become a leading producer of oil, becoming a member of OPEC in 2007 and is the third largest sub-Saharan African trading partner with the USA, largely because of its petroleum exports. Von Essen adds that Africa is now second only to Europe for the number of highly paid roles advertised for top UK oil and gas industry professionals. Lydia Marref, partner at Von Essen, commented: “The fact that Africa now offers the second largest pool of high paying jobs in the energy sector is a very significant
milestone. Africa has become increasingly attractive to international exploration companies and investors as it has become easier to access oil reserves and the continent has made great strides in becoming more business friendly.” “It is likely that in the future, oil and gas companies drilling in Africa will require more consultants as new reserves are found.” Added Lydia Marref: “With the most highly paid roles concentrated in Europe, there are plenty of attractive opportunities close to home. However, consultants shouldn’t overlook the fact that there are other regions also offering high pay, interesting work, and great opportunities for career progression.” “Our advice is that consultants should choose the best and most rewarding environments for them personally.”
DAP contract handled by ITECO in Kenya THE EVER EXPANDING oil and gas industry in Africa has seen figures double over the last two decades. ITECO, with a stronghold in the oil and gas supply industry, has been providing oil country tubular goods (OCTG) for the last 18 years. It has a presence in more than 10 countries through its sales offices and stockyards. ITECO Middle East has executed a contract for the supply of casings and tubing’s for the Menengai geothermal project in Kenya on a DAP basis (a typical example of mill to well concept). Aware of the critical time constraint, ITECO extended its work scope with assistance from a local team in Kenya and embarked on a mission never done before. The project called for ground co-ordination with the involved parties, such as port authority, ground handling agent, trucking crew, crane crew and client’s crew. The co-ordination and task scheduling resulted in completing the job ahead of schedule without any major damages.
8 Oil Review Africa Issue Four 2014
Project highlights included: 6 10,000 tonnes of carbon steel pipes (casings) transported to Menengai drilling site 6 450 trailers ferried the pipes 6 300,000 km distance covered without any loss time incidents. ITECO’s expertise is its understanding of the local market and to provide a personal approach and genuine knowledge. It is a trading, distribution and logistics business focussing on learning about the customers in order to provide them with the finest quality and best value products and services. The leading products and services provided by ITECO are recognised by major international oil and gas companies as well as renewable energy companies. ITECO is currently seeking trade partners in Africa. www.oilreviewafrica.com
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Analysis
More than US$1.6 trillion is needed as investment each year to meet global energy needs through 2035. Africa’s share will have to be substantial.
Energy investment -
a rising trend A
SPECIAL REPORT from the International Energy Agency* sees an increasing role for governments in shaping investment decisions relating to oil, gas and power-sector development. As the table summarised below shows, here in Africa the main focus will continue to be on development of oil resources. “Credible policy frameworks” and “stable access to long-term sources of finance” will be needed, the WEO publication says. “Neither of these conditions should be taken for granted”, the OECD’s energy watchdog warns. And chief economist Fatih Birol points out that essential sources of private capital will be deterred if governments in countries where Africa now sells most of its oil and gas change the rules in unpredictable ways on matters such as promoting low-carbon sources of power. Of the cumulative total investment required over more than two decades (US$48 trillion in all) more than four-fifths will be for energy supply - US$23 trillion of this for extracting fossil fuels, transporting and refining them. Almost US$17 trillion will be required for improving power supplies alone. “More than half of the energy-supply investment is needed just to keep production at today’s levels.”
New types of investors in the energy sector are emerging, but the supply of long-term finance on suitable terms is still far from guaranteed. A different investment landscape The June 2014 report emphasises the very significant costs of investment in new liquefaction facilities, one of Africa’s few feasible ways of selling surplus gas overseas. And it continues to call for significant further progress on reducing carbon emissions. A breakthrough in next year’s Paris UN climate conference is vital to “open up a different investment landscape” it warns. This report, the first to be issued by the IEA on investment issues since 2003, examines the differing structure of ownership and models for financing investment. It emphasises the continued importance of funds for oil development in the Arabic-speaking countries, including here in North Africa, to meet global demand, and the likely consequences of delay if these are not forthcoming. It examines the dynamics and costs of investment in LNG, and how this can shape the world’s future gas supply situation. The need for global investment in power
Average annual investment in energy supply – all-Africa (yr-2012 US$, billions)
Total Oil - upstream - transport - refining Gas - upstream - transport Coal Power
Historical 2000-2013 94 63 56 5 2 18 11 0 2 12
2014-2020* 138 66 61 3 3 39 24 0 2 31
Cumulative 2014-35* 3238 1395 1291 50 54 915 674 6 46 882
* Under IEA’s “New Policies” scenario Note: Comparable figures for 2021-25, 2026-30 and 2031-35 are also given, as are total cumulative investments under the more ambitious “450ppm” CO2 scenario, and required energy efficiency investments, for all regions
10 Oil Review Africa Issue Four 2014
Investment in LNG facilities will continue to create new links between markets and improve the security of gas supplies. Image source: Center for Liquefied Natural Gas.
supplies is covered, and the requirement for funds by the various low-carbon suppliers is stressed. Finally the new IEA report from its World Energy Outlook series looks at how global financing requirements will change if governments make serious attempts to address the challenge of climate change (ie, adopt the “450 ppm” solution), rather than merely adopting what are described as “new policies”. Amongst the key points made in this year’s call for action are: 6 More than US$1600bn was invested last year to supply the world’s energy consumers. This total has more than doubled in real terms since 2000. 6 An additional US$130bn had to be spent on improving energy efficiency. 6 Through 2035 the investment required each year to meet energy needs will rise steadily towards US$2000bn, with annual investment in energy efficiency increasing to US$550bn. 6 Less than half of the required US$40 trillion investment in energy supply will go to meeting growth in demand; the larger share will be required to offset declining production from existing oil and gas fields, and to replace power plants/other assets that reach the end of their productive lives. 6 Of the US$8 trillion in investment in energy efficiency required by 2035, 90 per cent will be spent within the transportation and construction sectors. 6 Decisions to commit capital to the energy sector are increasingly shaped by government policy measures and incentives, rather than signals coming from competitive markets. 6 Private sector participation will be essential to meet the world’s energy investment needs in full, but mobilising private investors and capital will require a concerted effort to reduce political and regulatory uncertainties. 6 Fortunately new types of investors in the energy sector are emerging, but the supply of long-term finance on suitable terms is still far from guaranteed. 6 Investment in the supply of natural gas will rise almost everywhere, but meeting long-term growth in oil demand will become steadily more reliant on investment in the Middle East. Here at “Oil Review” we think this will be the case in North, West and East Africa too. 6 Investment in LNG facilities will continue to create new links between markets and improve the security of gas supplies. However high costs for gas transportation may dampen the hopes of buyers in both Europe and Asia for access to supplies at significantly lower cost. ■
*”World Energy Investment Outlook”; an IEA/WEO Special Report; www.worldenergyoutlook.org/investment www.oilreviewafrica.com
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Finance
African Finance: Nicholas Newman looks at the fiscal challenges facing the banking sector in financing Africa’s current and future energy projects.
Sources for funds for African
energy projects I
NFRASTRUCTURE INVESTMENT IS critical for the economic and social development of the African continent. The African Development Bank estimates current levels of infrastructure investment across the continent at around US$45bn annually. However the World Bank estimates infrastructure-funding requirements in the continent at US$93bn annually for the next ten years. Almost half of this amount is needed to address the continent’s current power supply crisis which allows frequent blackouts and leaves many in energy poverty. Currently, two out of three sub-Saharan Africans — 600mn people — lack access to electricity, forcing them to spend significant amounts of their income on costly and unhealthy forms of energy such as smoky and scarce wood for indoor fires for cooking. The scale of the energy gap can be seen in Table 1. To reduce, if not eradicate energy poverty and the incidence of blackouts, both investors and utility operators, are looking at diverse sources of financing to fund new investment .
Problems faced by project promoters and potential lenders For project promoters “The challenge is to find the cheapest sources of capital”, said Theuns Ehlers, head of resources and project finance, Barclays Africa in a telephone interview of 12 June 2014. For potential investors and lenders the challenge is to accurately identify the most bankable deals. The global financial crisis of 2008 and subsequent imposition of new banking regulations, such as Basel III, have reduced the ability of traditional suppliers of capital, commercial banks, to provide project finance. Fortunately, new sources of finance are stepping into the breach including sovereign wealth funds eager to diversify their portfolios, private sector investors including insurance
Development banks remain a traditional source of finance for project promoters and developers.
There is no shortage of capital for energy projects in South Africa and the surrounding region.
companies eager for a long-term income stream and private equity firms alongside capital markets and government issued infrastructure bonds The challenges of raising finance for infrastructure projects are acute in most African countries, compounded by the existing limited institutional capacity, inadequate regulatory and legal framework, underdeveloped banking and inadequate capital markets that commonly exist outside South Africa, Nigeria and Kenya. However, the poor credit rating of some countries like Mozambique are likely to make it more difficult to fund its LNG export projects, when rival projects in Australia, Canada and the US offer a less risky environment, suggested energy experts. Nevertheless, despite all these obstacles, Ehlers asserts, “Interest from investors is worldwide, especially from Europe and America. There is no shortage of capital for energy projects in South Africa and the surrounding region, especially in renewable projects.”
Sources of finance Sources of funding for energy projects in Africa are diversifying to include local, foreign, public and private sector investment. Self-funding from existing
reserves or selling of assets by utilities and power generation companies is becoming more common. This is certainly a partial solution towards financing many oil and gas projects on the continent. For instance, in September 2013, Enel sold a 20 per cent interest in it’s Mozambique gas discoveries to China’s CNPC, in order to fund further development. The role and importance of African governments as a direct source of power project finance is much diminished and can no longer be taken for granted. However, governments remain important indirectly as they sanction the use of state-owned pension funds in private power infrastructure projects. For example, and most notably, the South African Government Employee Pension Fund is involved in the financing of a 44MWp concentrator photovoltaic (CPV) power plant, being built in South Africa by Soitec. The pension fund will hold 20 per cent of the project’s equity, reported the PVTech website in June 2014.
Development banks Development banks remain a traditional source of finance for project promoters and developers. For example, the African Development Bank (AfDB), in March 2014, launched the African Renewable Energy Fund. The fund, to be headquartered in
Table 1: Africa’s power gap Population Kenya Nigeria
44 million 162 million
Electrification Rate 16 % 50%
South Africa
52 million
84%
Current Generating Capacity 1,429MW 4.1GW
Current Demand
Demand in 2030
2,500MW 20GW
15,000MW 40GW
34,970 MW
35,364 MW
85,241 MW
Current Independent Power Sector share 20% Power sector in process of privatisation. 4%
Sources: US EIA, African Development Bank, Eskom
12 Oil Review Africa Issue Four 2014
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Finance
The US Government has committed more than US$7bn to secure 5,000MW of new electricity for Nigeria, Ghana, Kenya and Tanzania.
Nairobi, aims to raise US$200mn within the next 12 months for grid-connected development stage renewable energy projects including, small hydro, wind, geothermal, solar, biomass and waste gas. As of 12 March 2014, it had already secured US$100mn, to support small to medium-scale independent power producers (IPPs). Previously, in March 2013, the bank approved US$157mn in financing for a wind power project designed to add 300MW to Kenya’s generation capacity. Whilst the importance of commercial banks’ lending is somewhat diminished, they play an important role by arranging deals and raising capital for energy projects. For example, Barclays Africa was a joint mandated lead-arranger in the US$550mn deal to fund Bokpoort, a solar-powered renewable energy project in Northern Cape Province. In the latest round of South African renewable projects, Barclays Africa handled 30 per cent of the deals, numbering 14 projects in total. “Outside South Africa, Barclays has been involved in independent power projects in Kenya and Uganda as well as Mozambique and Nigeria,” said Theuns Ehlers. In addition, commercial banks are working as intermediaries, to access new energy project investment from export credit agencies including Japan’s Bank for International Cooperation (JBIC). State-sponsored export credit agencies such as the JBIC, the Export-Import bank of the United States and EXIM Bank China not only supply vital finance to their exporters of power goods and services but also provide finance for foreign companies. For example, America’s Export-Import Bank supplied a significant portion of the US$805mn upfront financing needed by Eskom, South Africa’s state-
Local sovereign Wealth Funds (SWF) are becoming a new source of funds for energy projects in Africa.
owned power utility, for its new 800MW coal power at Kusile, due for completion in 2015. Adding to traditional foreign aid sources of infrastructure finance, President Obama launched the “Power Africa Incentive” programme designed to help reduce energy poverty in June 2013. For its first five-year phase, the US Government has committed more than US$7bn in financial support and loan guarantees to secure 5,000MW of new electricity for Nigeria, Ghana, Kenya, and Tanzania. In addition, every government dollar committed to Power Africa, is backed by two dollars of private sector investment commitments. Power Africa’s financial partners, including the African Development Bank and World Bank, have committed more than US$14bn in project finance through direct loans, guarantee facilities, and equity investments to secure additional electricity supplies. Another recent development is that major multinational manufacturers and suppliers of energy related products and services, such as Siemens and GE, have set up in-house banks to provide finance, ranging from debt to junior capital and equity for client project developers. For example, Siemens, through its financial arm, is currently involved in wind power projects designed to provide Morocco with 26 per cent of its electricity by 2020.
Local sovereign Wealth Funds (SWF) are becoming a new source of funds for energy projects in Africa. Over the past few years, oil producing countries including Nigeria, Ghana and Angola have established their own sovereign funds managing US$1bn, US$100mn and US$5bn respectively. Other African countries are likely to follow over the next decade, according to Mthuli Ncube, chief economist at the African Development Bank. Foreign sovereign funds are also showing interest, attracted by improving economic growth and governance in many countries. In December 2013, for example, Singapore’s SWF Temasek bought a stake in Ophir Energy’s gas fields in Tanzania for US$1.3bn. The sale will help in the development of the fields. For a selection of diverse funders of power projects in Africa see Table 2 below.
Table 2: Some sources of funds investing in Africa US Power Africa Incentive US Blackstone LP US Power Africa Incentive financial partners EU Deutsche Investitions und Entwicklungsgesellschaft GmbH Africa African Renewable Energy Fund EU The European Investment Bank
$7bn $3bn $14bn $7.5bn $200mn $1.5bn
Source: IEA, Bloomberg, EIA, African Development Bank
A new and increasing trend is the entry of American and European investment funds attracted by the opportunities presented by numerous planned power projects in Africa over the coming decade. For example, Blackstone LP, the American private equity group, the largest alternative investment firm in the world, has announced plans to invest US$3bn over the coming years in African energy projects, reported the online financial news channel, Bloomberg in January 2014.
Important advice for project promoters
Barclays Africa was a joint mandated lead-arranger in the US$550mn deal to fund Bokpoort, a solar-powered renewable energy project in Northern Cape Province.
14 Oil Review Africa Issue Four 2014
Bankers are unanimous. Energy project promoters need to select a banking partner at the earliest point of the project cycle. Banks not only offer access to finance but also have the specialist skills and expertise to expedite matters and minimise costs. Theuns Ehlers advises project developers to treat “your bank as a proactive partner to the project.” It is increasingly apparent that the private sector’s contribution to financing energy projects in Africa over the coming decades will increase whilst that of government will diminish. ■ www.oilreviewafrica.com
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Creating a tectonic atlas for Namibia and
Western South Africa T
HIS HAS GENERATED an increased subsurface understanding for one of the world's leading frontier petroleum exploration areas. The area of interest is located in the geologically complicated area of a volcanic passive margin. Despite its complex geodynamic setting, the Namibian and South African Atlantic margins remain one of the world's frontier petroleum exploration areas, whose structure and tectonic evolution have major implications for hydrocarbon distribution and maturation. The structure of the passive margin is characterised by two strike parallel gravity highs – an internal high corresponding to the large basement ramp of the Atlantic Hinge Zone; and an external high that may represent a higher density transitional crust intruded by igneous rocks. In addition, sedimentary basins situated to the east of the Hinge Zone, though probably not very deep, may contain pre- and early Figure 1: Two alternative 2D gravity forward models for a seismic line syn-rift successions with a variety of crossing the Namibian margin in the E-W direction. potential source rocks. The objectives of ARKeX’s and boundaries of maximum density contrast. These Spectrum’s digital atlas was to compile a usually correspond density contrasts between comprehensive structural data based on a GIS basement and sedimentary cover. platform and to apply the kinematic implications of The overall structure and crustal architecture of the results obtained to redefine the morphology of the Namibian/South African passive margin, the basins in the area. revealed by offshore gravity data, allowed the Goals included redefining the major structural identification of two chains of structural and tectonic elements by using gravity data to depressions (depocentres): i) inner basins located on interpret the location of major depocentres and their a proper continental crust between the Atlantic structural framework; basin structure interpretation Hinge Zone and the coast which may contain preusing 2D gravity and magnetic modelling of seismic and syn-rift sediments and a reduced post-rift lines provided by Spectrum; and 3D gravity succession; and ii) outer basins situated on modelling to verify 2D interpretations and produce a stretched transitional crust in between two series of 3D geological horizons. dominant gravity highs. Those basins should The following basins and sub-basin definitions comprise an increased thickness of syn-rift deposits. were adopted in the study: basins extend over the 2D forward modelling of the data was then structural boundaries to include the full sedimentary carried out to put quantitative constraints on depth cover, which is typically of considerable thickness; to basement and to better understand the passive and depressions (depocentres) are structurally-bound. margins’ architecture, with models built on high Defining structural highs and basins quality seismic lines provided by Spectrum. Structural highs and basins were defined by positive To eliminate the ambiguity in recognising the and negative gravity anomalies respectively. In source of the gravity signal, 2D forward modelling addition, the total horizontal gradient of the gravity was calibrated by using the outcomes of a 3D gravity field was used for mapping structures. This inversion, constrained by seismic refraction data for derivative focuses positive gravity anomalies over the Moho surface. This approach extends the limits www.oilreviewafrica.com
for reliable reconstruction of subsurface structure and allows for two alternative interpretations of the architecture of transitional crust to be considered. To discriminate between the two alternative interpretations, the modelling of magnetic data was essential. Furthermore, the depth to basement estimates from 2D forward models was used to further constrain a gravity inversion for a top basement horizon. According to a conceptual model by Unternehr et al (2010), the transitional crust represents highly attenuated continental crust, subjected to intense syn-rift stretching. In addition, the Atlantic Hinge Zone not only correlates with the flexure in the floor of syn-rift basin, but also coincides with a zone of Moho necking. Consequently, the thickness of crystalline crust beyond the hinge zone may be reduced to approximately 10 km. Furthermore, since Seaward Dipping Reflectors (SDRs) are clearly visible throughout the seismic sections, abundant volcanic material within the syn-rift succession and, potentially, widespread igneous rocks intruded into and underplated beneath the basement are expected. The two alternative geological models for the passive margin architecture were successfully tested, both satisfying the observed gravity data, as can be seen in figure 1. Both models assume that a syn-rift succession is a mixture of basaltic volcanic material and clastic sediments. The second model (panel B) postulates that the majority of transitional crust represents a combination of stretched continental crust and high density underplated material. However, the outer margin of transitional crust in this model is of igneous origin. To conclude, the integration of 2D seismic and potential field data provided interpreters with an increased subsurface understanding for one of the world's leading frontier petroleum exploration areas. The Tectonic Atlas demonstrates a method of building a regional structural framework for exploration activities that can be consistently applied for frontier hydrocarbon-bearing regions. ■
Chris Anderson, ARKeX Oil Review Africa Issue Four 2014 15
Namibia
ARKeX, a leading provider of non-seismic geophysical services and data, and Spectrum, a multi-client services and seismic imaging company, have created an exploration framework for Namibia and Western South Africa through the integrated interpretation of 2D seismic and potential field data.
Equatorial Guinea
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The Equatoguinean government has a plan to bring growth back into the black with economic diversification as well as a renewed effort at luring explorers. Samuel Ciszuk reports.
Regrouping or grasping
for straws? G
ONE ARE THE days of record GDP-growth in Equatorial Guinea, when the country within one decade moved from among the poorest in Africa to the richest, counted in GDP per capita. A year of negative growth now looks to become at least three, according to the IMF. The government, however, says it has a plan and remains confident that economic diversification, together with a renewed effort at luring explorers, will bring growth back into the black. Equatorial Guinea, one of Africa's smallest and least developed states, started properly moving up the ladder of development and wealth in the mid-1990s. Several discoveries at the start of the decade started yielding results growth in the years between 1995 and 2005 could at times be as high as 40 per cent per annum. Yet the high growth, which to some extent also preceded the sustained rise in oil prices, masked the fact that as discoveries were developed the pipeline of new projects quickly started thinning. By 2005 the country's oil production peaked at 376,000 bpd and started declining. Last year it came in at 270,000 bpd, confirming the country's slide in the sub-Saharan Africa oil production tables from third to fifth. Rising oil prices, as mentioned, together with growing income from its gas monetisation programme, delayed the economic impact a few more years, however. Lacklustre growth at the start of this decade turned to an outright rout in economic growth in 2013, when the economy shrunk by 4.9 per cent. This year the IMF forecasts the economy to shrink a further 2.4 per cent and a massive 8.3 per cent decline is projected for 2015. While little is being done, it might seem, more is planned to be done in the future. The Equatoguinean government says it has regrouped and come up with a strategy which again shall restore growth and start the country on a path to lower its dependence on upstream oil and gas. At the same time it hopes to reinvigorate exploration in the country's waters, in order to start enhancing the country's reserve numbers and in due course again raise its oil and gas production rate.
The government says it has a plan to bring growth back into the black. Manifold challenges The challenges are manifold. Lacklustre terms and a lack of a proactive government approach means that not only have new exploration opportunities been missed over the past years, enhanced oil recovery (EOR) initiatives at the country’s main oilfields, particularly the dominating Zafiro field, operated by ExxonMobil, appear to have been neglected. Investment in both these strands is key to halting decline and shoring up the country's vital export earnings, in order to finance the government's vision of a more diversified Equatoguinean economy. Apart from luring more of the oil and gas service sector to the country, strategically placed in the middle of the Gulf of Guinea, the country hopes to attract significant investment into ventures in the petrochemical sector. The AMPCO methanol project, onstream since over a decade with one million tonnes per annum (tpa) capacity has given the country's leadership a taste for more, as it has created more jobs for locals than the equivalent offshore upstream projects so far and allows the country to capture more of the value added from its hydrocarbon production. Concretely, the government has already abolished the GEPetrol-based industry control approach, with the ministry taking a much more centralised grip on the award of exploration and development permits. That reform was
16 Oil Review Africa Issue Four 2014
Equatorial Guinea started properly moving up the ladder of development and wealth in the mid-1990s.
launched in 2011/2012 and had within a year resulted in nine exploration permits being awarded, compared to a total of eight in the preceding five years. The new approach is more flexible in that it allows for blocks in less prospective areas to be negotiated bilaterally with interested companies which have been shortlisted. In more competitive areas, however, bidding rounds will continue to be run.
Gas to become centre of attention Under the “Horizon 2020� national development plan, gas is to become the centre of attention, both as feedstock and energy for the petrochemical sector, as well as gas-to-power, enabling the development of mining in the resource-rich nation. In addition to those uses, the government also sees room for raising exports by adding another LNG-train to its 3.7mn tpa plant and hoping for Ophir Energy to add a floating liquefaction (FLNG) plant to its Block R gas discovery. In addition to the raised gas exports and petrochemical expansion, there are also plans to attract more investments in other sectors like fishing, tourism and finance, by emulating offshore trading and finance hubs like Dubai and Singapore. To this end, a US$1bn fund to invest along private enterprises in new projects has been created. There are problems with the buoyant plans and targets at closer look, however. After almost two decades as one of the continent's largest oil producers it still ranks 136th in the human development index, recent infrastructure investments to boot. That statistic is made to look all the worse by the country's per capita GDP, which in the past years has been roughly at the level of EU-member Portugal. The World Bank has consistently recommended that resources are reallocated from large-scale infrastructure projects to development of the country's health and education sectors, which historically have been chronically underfunded. Equatorial Guinea's constant
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Equatorial Guinea
place at the bottom of global rankings on civil and political freedoms effectively guarantees that the government's dreams of becoming a regional hub for banking, as well as a tourist destination will come to nought. That will leave it with a high dependence on hydrocarbons and other mineral resources for the foreseeable future, as well as with a continued dependence on foreign expertise.
Arresting mature decline would have been the best way to start staging a comeback for the tiny hydrocarbon nation. Another fundamental issue is the lack of new oil discoveries. Deep offshore the country's creage is regarded as promising but it is increasingly regarded as mainly a gas play. Generally that means lower incomes, which is likely to sway the Equatoguinean government towards maximising LNG exports and to some extent to feed export-oriented petrochemical projects, rather than to develop gas for power. The lack of a working domestic electricity market largely precludes attracting FDI to power plants, unless they are integrated in some particular gas-electricitymining project. Even so, the cost of piping relatively expensive offshore gas to Equatorial Guinea's mainland part, quite far from the most recent discoveries west of the main island Bioko, could well prove discouraging, compared with adding some further liquefaction capacity. That is likely to be the government's temptation, particularly if new discoveries fail to reach such a scale that the downward spiral in export earnings can be arrested. If so, the whole plan for increased job creation would be likely to go overboard too.
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This FPSO is operating offshore on the ASENG Field.
Perhaps the most worrying signal is the government's continuing preoccupation with trying to raise direct government take from oil and to some extent gas production further at a time like this, when it should instead have tried to adjust to an environment where renewed brownfield investment in EOR-techniques is needed. Arresting mature decline would have been the best way to start staging a comeback for the tiny hydrocarbon nation, however that would have required a readiness to give up some of the increased control over the resources the government has secured over the past decade. â–
Oil Review Africa Issue Four 2014 17
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Gabon
Gabon has managed to draw in some new exploration spending and might be seeing a sub-salt gas and liquids potential opening up, but will the government push through with reforms or will short-termism, brought on by fiscal pressures, derail the start of a potential output recovery?
Gabon’s watershed
moment G
ABON IS ONE of sub-Saharan Africa's most established oil and gas producers. That however also means it is one of the most mature producers, suffering all the challenges intertwined with having to arrest a diminishing production and create the terms necessary to encourage investment in enhanced oil recovery (EOR) techniques. Trying to achieve this, the country holds a chequered record. Gabon too often figures at the bottom of global rankings of business-friendliness and red tape thanks in part to a bloated bureaucracy which throughout the country's independent history seems to have been as much a tool to provide secure incomes for the country’s elites, as actually managing the country's governance.
Diversifying the economy New winds have, however, been blowing in Gabon, since current President Ali Bongo relatively narrowly won his first presidential term to support his late father, long-time President Omar Bongo in 2009. Efforts to diversify the economy and unlock other natural resources than hydrocarbons in the inner parts of the country have been launched. At the same time, the former OPEC member's oil output has steadily been sliding from around 370,000 bpd in 1997 to just around 270,000 bpd this year. That slide has for a resource-dependent country like Gabon translated to lower government incomes, although the impact for much of the past decade was softened by the large sustained rise in oil prices. A strained fiscal situation at times in the past years has resulted in some fiscal adventurism and resource nationalist tendencies on behalf of the government, as well as in a rising indebtedness towards the country's energy companies through delayed payments. Both these issues have combined to raise the industry's perception of business risk, serving as a rising barrier to attracting more investment. In that environment, a continued push by the government to take direct ownership stakes in oil and gas contracts has done little to help assuage fears of unchecked government interference. Still, some headway has been made particularly in the last few years and while some arbitration and legal disputes remain between the Gabonese government and some oil companies, a significant number of EOR projects have now been launched in the country’s mature plays. A recent forecast by energy consultancy Wood Mackenzie has estimated that crude oil production decline indeed will be arrested this year and output gradually
18 Oil Review Africa Issue Four 2014
Cobalt had the foresight to acquire several high-potential licenses off the coast of Angola and Gabon, pioneering West Africa’s pre-salt play.
More hope is being put to Gabon's offshore, where exploration increasingly is targeting the sub-salt potential. edge up to around 290,000 bpd, before falling back to today's level by 2017.
Sub-salt potential More hope is however being put to Gabon's offshore, where exploration is increasingly targeting the sub-salt potential. Discoveries further south offshore Angola and the Republic of Congo have raised hopes, particularly as many see geological analogies between the lower Gulf of Guinea and the seabed offshore northern Angola and the corresponding prolific waters off Brazil. A renewed effort at holding licensing rounds produced a good result last year, when a total of 11 IOCs secured 13 blocks mainly in the country's deepwater. According to oil minister Etienne Ngoubou, Gabon held good hopes for the country's oil output to double to around 500,000 bpd in a few years’ time, as a result of sub-salt and deepwater opportunities being unlocked, according to Reuters. While there certainly are leads to explore, some caution should best be added to the oil
minister's optimism. A discovery by France's Total, with partners Cobalt and Marathon with the Diaman-1 well in a water depth of 1,760 metres in the Diaba license did raise spirits, but still seems far from having proved up commercial reserves. The discovery struck gas and condensates, which likely complicates monetisation further, as the threshold reserves needed do not only have to be large enough to warrant the high production and development cost inherent in a deepwater subsalt field, but also the development of some sort of gas export venture or an integrated gas-topower project on the mainland. The latter would likely require that the government agreed to pay a higher price for the feedstock gas than currently is the norm in order to be viable, which itself raises some potentially tricky political questions. Indeed, unless a sub-salt oil discovery, or much more gas and condensate reserves, is made relatively soon, the probing of the country's nascent deepwater might well be put on hold after companies' commitment wells have been drilled, given the costs involved. In the meantime, the government needs to pull through with reforms and to clarify new legislation in order to make sure that the gains in investment approval which have been made after the fiscal instability and labour unrest of the past few years, do not come undone. Uncertainty over government stakes and to what extent they will be actively managed is for instance one issue which, particularly in a high-cost, high-stakes
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Gabon
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environment like deepwater, it would benefit the industry to have clarity on from the outset. The building up of state debt to the industry and the frequent withholding of money is another issue, which although it might improve in the next three years, looks likely to come back and haunt the energy sector as mature output returns to overall decline.
Clarity and fiscal discipline needed Delivering on that clarity and fiscal discipline will not be an easy feat for the President and his government. Practicing fiscal restraint in the face of the upcoming 2016 presidential elections might prove even harder, particularly given the tendencies of restlessness among groups like students and oil sector workers. With
that in mind it would not be surprising if several of the industry actors tried to postpone large investment decisions into the post2016 timeframe, itself risking to compound the country's economic malaise. Countering such a development by enhancing investment terms and cutting red tape more proactively would be the best course of action for the long term, but might of course be politically the hardest, as it would involve starving some of the country's elites of their normal incomes and benefits. Unfortunately that means that from the government's point of view, more fiscal short-termism could well seem like the most rational approach to Gabon's economic worries unless outright large gamechanging deepwater discoveries indeed are made. ■
While there certainly are leads to explore, some caution should best be added to the oil minister's optimism.
Proven oil basin map. Image: Pura Vida
Pure Vida discovers Brazil-level pre-salt potential PURA VIDA ENERGY has announced an upgrade to its prospective resource assessment of the Nkembe PSC, offshore Gabon. Further technical work undertaken by the company has revealed a significant new play in the pre-salt within the Syn-rift interval where carbonate Coquinas reservoirs are anticipated to be present. The inclusion of newly identified prospects increases the total gross mean unrisked prospective resources on the block to 1,680mn barrels of oil, 1,344mn barrels of oil net to Pura Vida. The carbonate play is analogous to similar plays that have resulted in the discovery of several billion barrels of discovered oil offshore Angola and offshore Brazil. Pura Vida’s technical work has also identified several areas which contain multiple stacked prospects that have the potential to be attractive drill candidates that could be tested with a single vertical well. "Our recent technical work on the Nkembe block has yielded an exciting new play resulting in a significant increase in the resource potential,” said Damon Neaves, Pure Vida’s managing director. “As our understanding of the geology of this block has developed we have come to recognise the block has the potential to unlock value through a number of alternative pathways. At this time, industry interest in Gabon is running high with significant drilling activity ongoing and a very competitive deep-water bid round recently completed. We are therefore focused on securing funding from the industry to undertake the exploration activities required to unlock the potential value of the block."
20 Oil Review Africa Issue Four 2014
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S06 ORA 4 2014 - Geology & Gas_Layout 1 7/24/2014 12:41 PM Page 21
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Geology
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3D seismic survey contract for Seychelles
OceanGeo receives ocean bottom award
OPHIR ENERGY PLC, operator of the jointly held Seychelles exploration blocks, has contracted Dolphin Geophysical to undertake the 1500 sq km Junon 3D seismic survey over the Junon trend. Ophir Energy holds 75 per cent equity in the Seychelles blocks and WHL Energy the remaining 25 per cent. The survey will be undertaken by the M/V Polar Duchess and is targeted to commence on 28 June. The survey will take 30 – 40 days to complete. An initial fast track processed data set is expected to be delivered in September and a PreSTM processed volume in December. The Junon 3D seismic survey is designed to mature a number of prospects for drilling on the Junon trend in the east of the Ophir Energy/WHL Energy Seychelles acreage (Junon South, Junon East and Junon Central), an area high graded by WHL Energy’s geological studies. David Rowbottam, WHL Energy’s managing director, commented: “It is very pleasing to see the Seychelles project reach an important milestone with the acquisition of the first 3D dataset in the acreage. Because of the geological nature of the Seychelles region, it is believed that 3D seismic data will provide a significant upgrade to the understanding of our large exploration area. The Junon 3D dataset for example is expected to provide a high definition image of the Junon structures and provide a number of prospects for targeted drill site selection. The Junon 3D seismic survey fulfils the 3D seismic obligation under Ophir’s farm-in agreement with WHL Energy and the company looks forward to the results of the survey. The company anticipates that an exciting exploration drilling opportunity will mature from this data.” As part of the farm-in agreement Ophir Energy will fully fund the initial 1,500 sq km 3D seismic acquisition programme up to a total amount of US$17mn.
OCEANGEO BV, A geophysical company specialising in multicomponent ocean bottom seismic (OBS) acquisition, has been awarded a contract by a major European oil & gas company to acquire a substantial 3D ocean bottom seismic survey offshore Republic of Congo. Acquisition is expected to commence in third quarter 2014. Colin Hulme, OceanGeo’s chief executive officer, commented, “We are extremely pleased to announce this award. OceanGeo has a proven track record of successfully acquiring ocean bottom seismic data, safely and efficiently. Since 2008, our crew has been operating offshore Brazil and Trinidad & Tobago, delivering superior reservoir understanding for our E&P clients. This award is in keeping with our strategy of deploying our crew into the west African region. With the full support of ION, we are well positioned to compete and thrive in the growing ocean bottom seismic market and are truly excited about our future.” Meanwhile, in a separate statement, ION Geophysical Corp has entered into an agreement to increase to 100 per cent its ownership of OceanGeo. Brian Hanson, ION’s president and CEO, commented, “The OBS segment is the fastest-growing seismic market segment today, commanding an estimated 13 per cent of E&P company marine seismic spend, up from about six per cent in 2006. Our increase in the ownership of OceanGeo is indicative of our full commitment to the OBS market and is in keeping with our strategy of leveraging our key technologies, such as our Calypso next generation VSO acquisition system, to deliver solutions to oil & gas companies. With the addition of OceanGeo services, we now offer a fully-integrated OBS solution that includes survey planning and design, data acquisition using Calypso, and data processing, interpretation and reservoir services through our GX Technology group.”
Fugro Proteus first of three for 2014
Positive results from 12B seismic in Kenya
FUGRO HAS TAKEN delivery of the first of three Fugro Offshore Coastal Survey Vessels (FOCSV) being built by Damen. The first of a new class, the Fugro Proteus is a compact, survey ship capable of undertaking a wide range of survey, monitoring and inspection operations. The vessel is designed for a variety of survey and inspections duties including light geotechnical work, environmental baseline surveys, monitoring and inspection, and moon pool deployments. Diesel electric propulsion delivers excellent economy at all speeds. Fugro Proteus is the first of three survey vessels ordered by Fugro for delivery in 2014. Each will be operating in a different part of the world and so they have been adapted for the individual environments in which they will work. The operating company is a specialist in the acquisition of the full spectrum of survey data and so the vessels have been tailored to be adaptable for a wide range of tasks. Fugro Proteus is the first vessel to be built directly by Damen for Fugro. However the two groups have worked together on a number of refits in recent years, and and in the process have built a relationship based on trust and mutual understanding.
SWALA ENERGY LTD has announced that the 2D seismic acquisition programme in Block 12B, Kenya (Figure 1) has commenced. The work will be carried out by BGP International. Swala and its Joint Venture partners Tullow (operator) and CEPSA will acquire approximately 350 km of 2D Figure 1: Map of planned 2D seismic area. seismic over the coming weeks and the data will be processed as the survey progresses. The programme is designed to identify the main structural lineation in the basins and has the potential to identify structural leads for follow up infill seismic and/or possible drilling. Block 12B lies in the Neogene Nyanza basin, an off-shoot of the East African Rift System (EARS) where large quantities of oil have been proven in recent years by Tullow in Uganda and in Kenya. The seismic data will be vital in determining the forward exploration programme in the block. Although the basin has been under explored to date, with only 50 km of low quality seismic data recorded in 1989, reprocessing of this data by Swala has revealed a possible tertiary basin fill of more than 3,000 meters, supported by passive seismic work carried out by the JV in 2013. The new seismic lines will be acquired over the basin centre and work. The new data will be acquired using a high quality dynamite source compared with the very low impact vibrator source in 1989 and should provide a much better representation of the basin geometry and potential drilling candidates. David Ridge, Swala’s CEO said: “The start of the 12B seismic programme underlines the JV’s commitment to explore this frontier basin – an offshoot of the highly prospective East Africa Rift System. Our technical re-evaluation of the legacy seismic data is encouraging and we look forward to seeing the results of the seismic survey that has now commenced.”
Fugro Proteus is the first of three survey vessels ordered by Fugro for 2014.
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Gas
Sasol, Eni plan study of GTL plant in Mozambique SOUTH AFRICA’S SASOL is teaming up with Eni and Mozambique’s national oil company, Empresa Nacional de Hidrocarbonetos, to conduct a pre-feasibility study for a large-scale GTL plant in Northern Mozambique. The plant would use gas reserves from the offshore Rovuma Basin. GTL is highlighted as one of the many options for monetising Mozambique’s gas reserves in the country’s draft gas master plan. Along with LNG exports, the government is considering developing major petrochemical, steel, aluminium and cement projects near towns and cities, which will help boost employment and add value to the country’s vast offshore reserves. The gas master plan has already been submitted to Mozambique’s Council of Ministers, where it is expected to be approved within the next month. The government has yet to make a decision on how much Rovuma Basin gas to allocate to the domestic market and how much to reserve for exports, but the ministry estimates the country will only need around 1.02 tcm over the next 20 years. However, this figure could rise as the downstream industrial sector expands. Eni is also conducting a FEED study on a floating LNG facility based on its Coral gas reserves within Offshore Area 4, which is estimated to hold 2.4 tcm of gas. While Anadarko, the operator of offshore Area 1, has already submitted a development plan to the government for its two-train LNG plant, a final – more detailed – plan is still to come. Anadarko is planning to take an FID on the project before 2015, but this will depend on whether the government passes a decree law – which will lay out the framework for exploration and production contracts in the country, as well as changes to the petroleum and fiscal legislation – before elections in October.
Statoil increases gas reserves off Tanzania STATOIL HAS INCREASED its estimate of in-place natural gas in Block 2 offshore Tanzania to 20 tcf following the completion of the Piri-1 discovery well. The new gas discovery was made in the same Lower Cretaceous sandstones as the Zafarani-1 discovery well drilled in 2012. The The drillship Discoverer Americas. well location is two kilometers southwest of the Lavani-1 well at 2,360 m of water. Piri-1 was drilled by the drillship Discoverer Americas which now has moved to drill the Binzari prospect in block 2. The Piri-1 discovery is the venture's sixth discovery in block 2. It was preceded by gas discoveries at Zafarani-1, Lavani-1, Tangawizi-1 and Mronge-1, and a discovery in Lavani-2. “Additional prospectivity has been mapped and will be tested throughout 2014 and 2015. We expect to drill several additional exploration and appraisal wells and hope that the results from these wells will continue to add gas volumes for a future large-scale gas infrastructure development,” said Nick Maden, senior VP for Statoil’s exploration in the Western Hemisphere. Statoil operates the licence on behalf of Tanzania Petroleum Development Corporation and has a 65 per cent working interest. ExxonMobil Exploration and Production Tanzania holds the remaining 35 per cent.
Circle hits gas onshore Morocco CIRCLE OIL HAS reported that its SAH-W1 well on the Sebou Permit, onshore Morocco, has made a gas discovery. Circle said that the well – located in the western central area of the Sebou Permit – encountered gas shows at three levels within the target Guebbas sands after being drilled to a target depth of 1,263 meters. Wireline logging has confirmed the presence of three gas-bearing zones with subsequent pressure testing confirming permeable high-pressure reservoirs. The net pay from the wireline log analysis is six meters in the Top Guebbas, six meters in
the main target Intra Guebbas and three meters in the lower part of the Intra Guebbas. Circle now plans to produce the three zones sequentially from the bottom up – where the highest pressure is present. Circle CEO Professor Chris Green commented: "We are delighted to add another successful discovery to our Sebou gas portfolio. This is the first well of a six-well program to be drilled with our partner ONHYM in the Sebou permit and is coupled with another six-well program in the Lalla Mimouna permit."
Africa Oil discovers gas at Sala Prospect AFRICAN OIL CORP has made a gas discovery in Block 9 onshore Kenya. The Sala-1 drilled a large 80 sq km anticlinal feature along the northern basin bounding fault in the Cretaceous Anza graben and encountered several sandstone intervals which had oil and gas shows. The well was drilled to a total depth of 3,030 meters and petrophysical analysis indicated three zones of interest more than a 1,000 meter gross interval which were subsequently drill stem tested. An upper gas bearing interval tested dry gas at a maximum rate of six mmcf/d from a 25 meter net pay interval. The interval had net reservoir sand of over 125 meters and encountered a gas water contact so there is potential to drill up-dip on the structure where this entire interval will be above the gas-water contact. A lower interval tested at low rates of dry gas from a 50metres potential net pay interval which can also be accessed at the up-dip location. It should also be noted that there were oil shows while drilling and small amounts of oil were recovered during drilling and testing which indicates there may be potential for oil down-dip on the structure. Africa Oil is the operator of Block 9 with a 50 per cent working interest. Marathon Oil Kenya Ltd BV has the remaining 50 per cent interest. An appraisal plan to follow up this discovery is currently being evaluated
24 Oil Review Africa Issue Four 2014
by the partnership in consultation with the Kenyan government. Plans being discussed include an up-dip location to confirm the real extent of the gas zones tested where the full net sand interval can be intersected above the gaswater contact. The partnership is also considering a down-dip appraisal location to test an on-lapping stratigraphic wedge on the flanks of the structure which is of the same age as the zones in the nearby Ndovu-1 well which had oil and gas shows. In addition, the company is considering drilling an appraisal well on the crest of the large Bogal structure to confirm this large potential gas discovery which has closure over an area of up to 200 sq km. The gross best estimate of prospective resources for Bogal are 1.8 tcf of gas based on a third-party independent resource assessment. The company currently has two optional slots on the Great Wall drilling rig used to drill the Sala-1 well that are available for this appraisal programme. The company believes there is a very strong market for gas development in Kenya and has already engaged in discussions with power companies and the government to potentially fast track a gas-to-power project that could add significant value and create benefits for the people of Kenya.
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Kenya’s historic offshore discovery
Completion of farm-out of Kenya’s Block 12B
AUSTRALIAN OIL EXPLORATION firm Pancontinental Oil & Gas NL has confirmed an “historic” discovery of oil in an exploratory well sunk off the Lamu coast in southern Kenya. Pancontinental said analysis has shown there is a 14-metre thick oil column beneath a 29.6-metre column of gas in the ‘Sunbird-1’ zone. According to the company, the results are “first proof” that a prospective oil system is present in the Lamu Basin and is “expected to lead to a significant increase in industry interest offshore Kenya”. Pancontinental’s CEO Barry Rushworth said: “The Sunbird-1 oil is the historic first-ever oil discovery offshore Kenya. Furthermore, it is the only offshore oil column ever reported seaward of the eastern coastal margin of the African continent, from South Africa to the north-west tip of Somalia.” Rushworth said: “We encountered a thick and effective seal over the top of the reef, which was an initial risk for us, and the regional follow-on implications of this are truly significant. Porosity, permeability and seal for the reservoir were all better than Pancontinental expected. Now that we know there is a prospective oil system in the Lamu Basin and we know the important technical details, we are in a prime position to explore for larger volumes of oil over our very extensive portfolio of prospects and leads.” Pancontinental said: “The oil and gas have been geochemically typed in detail and the prospective source rocks have been dated and characterised for use in future exploration. Calculating the Sunbird results (in the area designated ‘L10A’) has been a lengthy process due to the complexity of the data derived from the well.”
SWALA ENERGY LTD has announced the completion of the farm-out agreement for a 25 per cent working interest in Block 12B (Kenya) to Compañía Española de Petróleos, SAU (CEPSA), a blue chip international integrated oil and gas company. As previously announced, the farmout agreement was subject to certain conditions that included the consent of the Kenyan Government and the Competition Authority of Kenya. These consents have now been received and the farm-out agreement has been finalised and is unconditional. CEPSA is a Spanish integrated energy company operating at every stage of the oil value chain. CEPSA is 100 per cent-owned by the Abu Dhabi government’s IPIC (International Petroleum Investment Company) and is Spain's fourth largest industrial group. Swala will retain a 25 per cent net working interest in Block 12B, CEPSA will own a 25 per cent net working interest and Tullow Oil will hold the remaining 50 per cent net working interest and continue to act as the joint venture operator. As part of the farm-out agreement Swala will have its past costs repaid and be free carried through two exploration wells up to a maximum of US$7.5mn for each one. Dr David Mestres Ridge (CEO) said, “I would like to again welcome CEPSA, a company of sound financial and technical standing to the Kenya Block 12B joint venture. Completion of this farm-in agreement will now allow the company to focus its resources on existing operated assets and the continued growth of our portfolio”.
Tullow strikes oil and gas in north west Kenya TULLOW OIL HAS discovered oil and gas in northwest Kenya with partners Africa Oil in Block 9. It said its Twiga-2 appraisal well had found 62 meters of net oil pay north of the companies’ Twiga-1 well, which had previously encountered some 18 meters of net oil pay with limited reservoir quality. The well encountered up to 39 meters of net oil pay and 11 meters of net gas pay and appears to have identified a new fault block trap north of the main Ngamia accumulation," said the statement. "The reservoirs were high quality with more than 200 meters of net reservoir sands with good permeability inferred from MDT sampling," Tullow’s exploration director Angus McCoss said. McCoss said the well has been suspended for testing and the rig will continue to drill up to four additional appraisal wells in the Ngamia field area for an extended well test programme. The firm also announced a gas discovery in Block 9 onshore Kenya. "The Sala-1 drilled a large 80 sq km anticlinal feature along the northern basin bounding fault in the Cretaceous Anza graben and encountered several sandstone intervals which had oil and gas shows," it
26 Oil Review Africa Issue Four 2014
said, “and we are evaluating an appraisal plan on the latest discovery in consultation with the Kenyan government.” The company also said that “four new basins in Kenya and Ethiopia are being tested”, via the drill bit, “during the second half of the year”. It added: “Five further basins will be tested in Kenya and Ethiopia during 2015”. The Ethiopian adventure has not been anywhere as successful as the Kenyan exploit and Tullow cited the former as one of three (including Mauritania and
Norway) in which it expects “a net exploration write off of US$415mn for the first half of the year”. Tullow clearly has a handle on Kenya’s South Lockichar basin, where its major discoveries were made. It has eyes on Turkana, Turkwel, North Lockichar, Kerio, Suguta, Kerio Valley and Nyanza basins. In Ethiopia, its concessions are located in Omo, West Omo and Chew Bahir. The Exalo 205 rig is drilling ahead on the Gardim prospect, located in the Chew Bahir basin in the South Omo block in Ethiopia.
An aerial view of a Tullow oil rig in Turkana.
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Chevron, ExxonMobil to share FPSO THE CHEVRON-OPERATED Nsiko field and the ExxonMobil-managed Uge field, located roughly 60 km apart, may be co-developed and produced into the same FPSO facility. This is one of the several field development options on the table, in the ongoing discussions among partners involved in OML 140 in which Nsiko field lies and OPL 214, where Uge field is domiciled. If this option is taken, the FPSO will be stationed midway between the two accumulations.
“Neither of the two fields make the threshold of 250mn barrels estimated recoverable reserves, which could allow a standalone project at water depths of between 1,300 and 2,500 metres”, said officials privy to the conversation. Nsiko was discovered in 2003 with Nsiko-1, drilled to a total depth of 4257 metres, in 1729 metres of water, hosting a substantial amount of net hydrocarbon pay in multiple zones. One zone was tested in the well and flowed at 6,500 bpd of high quality crude under restricted flow conditions. Uge was discovered in 2005 in 1,350 metres of water in OPL 214. An appraisal well confirmed the discovery and provided the major input for a field development plan that called for at least two more wells to drain the reservoirs. To develop the field, ExxonMobil initially planned to refurbish and deploy the Falcon, first used on the company’s shallow offshore Yoho field. NNPC, the state hydrocarbon company, rejected the plan.
ERHC to invest US$100mn in São Tomé block HOUSTON-BASED ERHC Energy Inc will invest around US$100mn on exploration and development of one of its blocks offshore São Tomé and Principe, the company's president said. São Tomé, a tiny former Portuguese colony in Africa's Gulf of Guinea, is surrounded by oil-rich neighbours but has failed to find oil after several years of prospecting. Other companies operating in the country include Equator Exploration Ltd on blocks 5 and 12, Sinoangol - a joint venture between China's Sinopec and Angolan state oil company Sonangol - on block 2, and Nigeria's Oranto Petroleum on block 3
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CAMAC spuds Oyo-9 well in OML 120 CAMAC ENERGY INC, an independent oil and gas exploration and production company, has announced that the Oyo-8 development well offshore Nigeria was spud 15 June. The Oyo-8 well is located offshore Nigeria in OML 120, where CAMAC Energy is the operator and owns a 100 per cent working interest. This development well lies within the Oyo field, which was one of the first deepwater oil discoveries made in Nigeria. The Oyo field is located approximately 75 km offshore Nigeria in water depths of approximately 300 meters. Oyo-8 will be drilled by the Northern Offshore Energy Searcher (mid-water drillship) to a total depth of approximately 1,800 meters in water depths of approximately 310 meters, and will produce from the Pliocene reservoir. The Oyo-8 well
OML 120/121 oil exploration blocks.
is expected to commence production in the fourth quarter and, together with the Oyo-7 well which will be completed subsequent to the Oyo-8 well, is expected to significantly increase production from the Oyo Field.
Bowleven signs agreement with Africa Fortesa AFRICAN OIL & GAS exploration group Bowleven has entered a drill-to-earn agreement with private company Africa Fortesa Corp (AFC) at the Bomono Permit in Cameroon. According to the agreement, AFC will earn a 20 per cent interest in the Bomono Permit in return for drilling two wells, it said. The cost of drilling is expected to be nearly US$15mn and drilling is likely to begin by the end of 2014, although the Cameroon government is yet to approve this deal, according to AFC. The Bomono Permit consists of two former blocks – OLHP-1 and OLHP-2, in the onshore extension of the Douala Basin covering an area of 2,328 km to the North and North-West of Douala City. Wells that were drilled in the 1950s and surface oil seeps and proven hydrocarbons in existing wells were discovered within the Bomono permit. Further explorations, mapping and volumetrics have revealed multiple prospects and leads with both tertiary and deeper cretaceous-aged targets, reports revealed. AFC, through its wholly owned subsidiary, Africa Onshore Drilling, has drilled numerous successful wells onshore West Africa and in Senegal, a number of which are currently producing for gas-to-power
NPDC threatens ‘surge’ in drilling activity STUNG BY CRITICISM of poor performance on assets it took over from Shell, state-owned Nigerian Petroleum Development Company (NPDC) is threatening aggressive rig activity that will boost gross output and alter media perception of incompetence. The company says it plans to have six rigs on different locations in OMLs 26, 30, 34 and 42 by the end of 2014, and stay on course with high drilling and field development activity in the near term. The first of the rig moves is to Ogini-5 on OML 26, where the Durga-2 rig, owned by British Oil Gas Exploration (BOGEL),will be active. ”The rig will be drilling Ogini-6 after this and we’re hoping to boost gross production on the lease from about 5,100 bpd to 8,000 bpd.”, NPDC officials said. Ogini-5 will be the first well drilled on any of these four leases since 2011, when Shell led the divestments of the 45 per cent combined equity belonging to itself, Total and Eni, to various Nigerian companies. After the divestments, the NNPC had transferred its 55 per cent interest to its subsidiary, NPDC, as operator of the blocks. The buyers had paid between US$102mn and US$850mn for the stakes, but three years on, OMLs 26, 34 and 42 have struggled at either the same output or have seen a decrease. Conversely, Seplat, which took operatorship of the same kind of asset from Shell, just a year earlier, has grown gross output from less than 20,000 bpd to more than 60,000 bpd. NPDC says it is deploying two rigs on OML 34 to drill two oil wells on the Utorogu field and three gas wells in Ughelli West and East. “The plan is that BOGEL Durga 3 will move to drill Utorogu 36 and 37, which are to appraise the new reservoir on Utorogu 35 as well as develop existing reservoirs. The swamp rig Imperial, owned by Depthwize, will be drilling Opuama 8 in OML 40 in a matter of months. Dredging has commenced and hydrographic surveys have been done. NPDC is hoping to add 3,000 bpd to current 1,200 bpd production on the lease when the well is tied in. NPDC has OML 42 drilling in its sights for 2015, but it says it is committed to drilling two wells on Olomoro-Oweh, as well as Afiesere, in the otherwise prolific OML 30, some time in 2014. www.oilreviewafrica.com
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Woodside secures Tanzania farm-in WOODSIDE PETROLEUM LTD has finalised a deal to farm-in to the prospective basin of Lake Tanganyika in western Tanzania. The oil and gas producer says Beach Energy Ltd has accepted its offer to acquire a 70 per cent participating interest in the Lake Tanganyika South Block and respective Production Sharing Agreement. While the commercial terms have not been disclosed Woodside believes the farm in provides the company with an opportunity to secure a large acreage footprint in an exciting and underexplored oil prone frontier basin.
CEO Peter Coleman said securing the acreage represents another step forward in building Woodside’s global exploration portfolio. Subject to government and regulatory approvals the proposed work programmes includes seismic studies with an option for future drilling and operatorship.
Farm-out agreement in Côte d’Ivoire AFRICAN PETROLEUM CORP has entered into an agreement with Buried Hill Africa Ltd to farm-out a 10 per cent interest in Block CI-509 offshore Côte d’Ivoire in return for Buried Hill funding 21.1 per cent of the cost of the next exploration well to be drilled on the block and an additional cash payment to African Petroleum representing 10 per cent of past costs incurred. African Petroleum will continue as operator on the licence. Completion of the farm-out agreement is subject to the satisfaction or waiving of certain conditions precedent, which, apart from one pertaining to government approval of the transfer, must be satisfied or waived no later than 1 November 2014 (unless extended in accordance with the farm-out agreement). African Petroleum operates eight licences located in fast-emerging hydrocarbon basins offshore West Africa. The company is actively seeking partners to share risk and reward across all assets. In line with this clearly communicated strategy, dialogue will continue with other potentially interested parties with a view of securing an additional farm-in partner for Block CI-509. www.oilreviewafrica.com
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The Infield Systems Ltd. Rig Count tracks industry-wide offshore rigs engaged in drilling and related operations, which include drilling, logging, cementing, coring, well testing, waiting on weather, running casing and blowout preventer (BOP) testing.
JUNE 2014 - OFFSHORE JUNE 14
MAY 14
VARIANCE
JUNE 13
MAY 13
Country Offshore ANGOLA 22 NIGERIA 16 GABON 7 CONGO (BRAZZAVILLE) 3 MOZAMBIQUE 2 GHANA 2 CAMEROON 2 EGYPT 15 TUNISIA 2 SOUTH AFRICA 3 TANZANIA 2 EQUATORIAL GUINEA 1 NAMIBIA 1 LIBERIA 2 LIBYA 1 TOGO 0 SENEGAL 1 BENIN 1 KENYA 0 MOROCCO 0 MAURITANIA 0 TOTAL 83
Offshore 22 17 7 3 2 1 3 15 2 3 2 0 1 2 1 0 1 1 0 1 1 85
From Last Month 0 -1 0 0 0 1 -1 0 0 0 0 1 0 0 0 0 0 0 0 -1 -1 -2
Offshore 18 19 4 6 4 3 4 19 2 1 2 2 1 0 0 1 0 0 1 0 0 85
Offshore 19 17 4 5 3 3 3 17 2 1 2 2 1 0 0 1 0 0 0 0 0 82
VARIANCE From Last Month -1 2 0 1 1 0 1 2 0 0 0 0 0 0 0 0 0 0 1 0 0 7
Source: Infield Systems Ltd.
Woodside farms into ‘prospective’ basin offshore Morocco AUSTRALIAN OIL AND gas firm Woodside has finalised an agreement with Chariot Oil & Gas to farm-in to the prospective Doukkala Basin offshore north western Morocco. Under the agreement Woodside will acquire an initial 25 per cent participating interest in the Rabat Deep Offshore permits I-VI. The agreement includes an option to acquire an additional 25 per cent and operatorship in these permits for a capped well carry obligation. The agreement is also subject to required government approvals. These undrilled permits are 10,782 sq km in area and water depths range from 150 to 3,600m. Woodside CEO Peter Coleman said the farm-in provided an opportunity to secure a large acreage footprint in an emerging petroleum province that is prospective for both oil and gas. “Exploration in this basin aligns with our strategy to secure new international growth opportunities in frontier and emerging basins characterised by materiality and quality,” said Coleman. “This opportunity has been supported by Woodside’s disciplined approach to studying regional petroleum systems, including the Atlantic margins, and is a good fit with our core capabilities in deepwater exploration and production.” The Rabat Deep permits complement Woodside’s acreage position in the nearby Canary Islands and are a further demonstration of continued efforts to build a global exploration portfolio.
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Sonatrach signs deal with Dodsal ALGERIAN STATE ENERGY company Sonatrach has signed a US$618mn deal with India's Dodsal Engineering and Construction for a project to maintain oil output at the OPEC member's main Hassi Messaoud oilfield. The sprawling North African energy exporter has been struggling to increase oil and gas output, on which it heavily relies to finance economic development and programmes that help ease social tensions. This deal covers the building of a gas compression unit with capacity of 24mn cmd and a 180-km-long gas pipe network, Sonatrach said. The project, to be implemented in 36 months, will help keep production at the field at its current level of 400,000 bpd, Sonatrach chief Abdelhamid Zerguine said at the signing ceremony. Zerguine said Sonatrach was planning more projects to boost production in Hassi Messaoud. A major gas supplier to Europe, Algeria has also planned a third boosting complex that will allow it salvage an additional 490 bcm of gas at its main gas field of Hassi R'mel, Zerguine said. Said Sahnoun, Sonatrach vice-president for upstream activities, said output would see a "considerable rise" from now to 2018 when the company starts production from its fields of Tinhert, Hassi Bahamou, Hassi Mina, Touat and Reggane.
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Profile
DAP contract handled by ITECO in Kenya IN THE EVER expanding oil and gas industry in Africa that has seen figures double over the last two decades, ITECO has been supplying oil country tubular goods (OCTG) with a stronghold in the oil and gas supply industry for the last 18 years and a presence in more than 10 countries through its sales offices and stockyards. ITECO Middle East has executed a contract for the supply of casings and tubings for the Menengai Geothermal Project in Kenya on DAP basis (a typical example of mill to well concept). Aware of the critical time constraint, ITECO extended its working scope and with assistance from a local team in Kenya embarked on a mission never done before. The project called for ground co-ordination with the involved parties, such as port authority, ground handling agent, trucking crew, crane crew and client’s crew. The co-ordination and task scheduling resulted in completing the job ahead of schedule without any major damages. Project highlights included: 6 10,000 tons of carbon steel pipes (casings) transported to Menengai drilling site 6 450 trailers ferried the pipes 6 300,000 km distance covered without any loss time incidents. ITECO’s expertise is its understanding of the local market. It is a trading, distribution and logistics business focussing on learning about the customers so to provide them with the finest quality and best value products and services. The leading products and services provided by ITECO are recognised by major international oil and gas companies as well as renewable energy companies. ITECO is currently seeking trade partners in Africa.
Gigawatt Mozambique secures financing POWER COMPANY GIGAWATT Mozambique has secured the financing to build a 100MW gas-fired power plant in the African country, which should be in operation late next year, one of its advisers said. The US$200mn project located at the Ressano Garcia border with South Africa will inject much needed power into the rapidly expanding country, which currently has very limited plant capacity to produce electricity from natural gas. Gas is seen as an attractive electricity source for Mozambique after major gas discoveries off its central coast. Its Rovuma basin is estimated to hold more than 150 tcf of gas, enough to supply Germany, UK, France and Italy for 15 years. "Construction will now commence on the project, with the intention being that the power plant will be onstream in Q4 2015," Eaglestone, an investment bank that advised the deal, said in a statement. Eaglestone said equity was provided by a consortium of Mozambique shareholders, Gigajoule Power, Old Mutual Life Assurance Company and WBHO Construction. Privately-owned Gigawatt Mozambique already has a take-off agreement with the state-owned utility Electricidade de Mocambique (EDM) but it hopes to attract industrial clients, whose higher tariffs would make the project sustainable over the long-term. EDM needs to provide more than 760MW but receives only 500 MW from the Cahora Bassa dam at a price of 1,080 meticais (US$35) per MW, according to a World Bank report on the country. The cost of purchasing electricity from other suppliers such as Aggreko and South Africa's Eskom is significantly higher at between US$145 and US$240, while EDM's average sale price is only US$76. South Africa's Standard Bank was lead arranger and underwriter for debt financing.
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The search for sustainable energy/resource solutions has taken Flying Doctors into some of the world’s most remote and often hazardous working locations. For the oil and gas industry these include distant swamp locations, offshore vessels, ships and forest locations.
Upgrading medical support in the
oil & gas industry R
EMOTE LOCATIONS PRESENT many challenges to the health of employees who work in them. In the event of an illness or injury, an evacuation would take a much longer time than can be expected in an urban setting. During this period, the patient’s condition may deteriorate leading to disability, or even death. Remote locations are also associated with higher risks (eg, hot or cold extremes in deserts or polar regions, or infectious diseases in tropical areas), limited access to basic necessities (eg, clean water) and limited supplies (due to logistical challenges of resupply). Remote locations are also often associated with limited communication options (eg, the lack of telephone lines, mobile network, satellite communications or Internet). This means a higher likelihood of harm to health (unless appropriate preventive controls are put in place). It also means that when people do get ill or injured, the likelihood of developing a complication or the condition worsening is high, unless mitigations are put in place.
Remote locations are also often associated with limited communication options. This means a higher likelihood of harm to health.
short distance jets. All of its flight physicians are critical care doctors/anaesthetists with hundreds of hours of combined medevac experience. The company provides both local and international evacuations from its aircraft bases in Lagos, Abuja and Port Harcourt in as little as thirty minutes. In addition to the medical evacuation, the Flying Doctors has provided medical staffing solutions for remote locations, certified first aid training, land ambulances and medical audit services.
in an urban centre can be achieved in remote locations with the correctly trained staff, emergency planning and equipment available. The Flying Doctors Nigeria has received various international and national awards for its works. It is also a member of the British Safety Council and recently became the first company in Africa to become a training centre for their accredited first aid courses. â–
Remote healthcare Higher stakes in Africa In Africa, the stakes are even higher as appropriate medical facilities that can manage certain injuries are often located in a different state or even a different country. Therefore, additional protocols need to be put in place to make sure that these extra risks are mitigated. For nearly five years the Flying Doctors Nigeria - a proudly Nigerian company - has been supporting the energy industry across West Africa by providing emergency medical evacuation by plane and helicopter for most remote locations. Its fleet of aircraft include both twin and single engine helicopters as well as long and
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Remote Healthcare (RHC) encompasses the health activities involved with the prevention, diagnosis, and treatment targeted at those working in remote locations. It represents a set of controls and mitigations that minimise the health risks of workers in these locations. It builds on the existing controls already in place in the energy sector and its associated maritime activities in such a way that enhances their effectiveness. Flying Doctors Nigeria aims to make sure that the remote locations in which a client works do not affect the standard of healthcare they receive. The company believes that the same standard of healthcare that is available
Oil Review Africa Issue Four 2014 33
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Fire Safety
Fire safety challenge spurs oil and gas industry to find innovative new solutions.
Preventing the
unthinkable
The Deepwater Horizon oil platform shortly before sinking.
T
HE HYDROCARBON INDUSTRY - from the extraction and processing of oil and gas, right through to its eventual sale and transportation presents unique health and safety challenges for all operators across the globe. Working in the cramped, tight conditions of an offshore oil rig, or a petrochemicals facility onshore, or even driving a tanker down the freeway, the volatile and highly flammable nature of the product means safety is uppermost in the minds of all players. Things are no different in Africa’s buoyant energy sector. In the past decade or so, West Africa - particularly Nigeria and Angola - has emerged as a key world oil producer of note, joining the more established countries of North Africa, the likes of Libya and Algeria. With more new and upcoming producers across the continent, including a nascent gas export industry taking shape off the coast of eastern Africa, the interest in all things safety is poised to increase significantly.
Leading industry expertise Leading industry players such as Dräger and Tyco Fire & Integrated Solutions offer a plethora of fire safety products and services to oil and gas companies across this market and others. These range from public address systems and alarms, right through to breathing apparatus, fire extinguishers, and even escape equipment for when things go wrong. Another well-known company, Intertek, specialises in rig safety training. No one wants to see life boats launched from a rig - perhaps one of the industry’s most dramatic spectacles to witness - but they are welcome additions should a fire break out in such a confined space. Luckily, Africa’s offshore industry is yet to experience any major fire disasters or explosions along the lines of the 2010 Deepwater Horizon tragedy in the US’ Gulf of Mexico that cost 11 lives.
The front line of defence is always first rate skills and training for workers, and in maintaining the integrity of equipment. 34 Oil Review Africa Issue Four 2014
Still, oil companies and workers are tested every single day to make sure that continues to be the case. Safety is never something that can be taken for granted, especially in such a dangerous industry as the oil and gas business.
Prevention better than cure Of course, prevention is always better than cure, so the industry priority will always be on making sure there are no fires, accidents, or slip-ups in the first place. This means the front line of defence is always first rate skills and training for workers, and in maintaining the integrity of equipment, from pumps and pipelines, through to control switches and compressors. But zero risk is not possible and this means the management of safety and fire hazards is perhaps the most important task of all facing all industry players. And so companies working in this space are always exploring ways to make things easier for operatives. A recently-launched Dräger mobile app, for example, helps employees to navigate through the jungle of hazardous materials they may be exposed to in the oil and gas environment. The free app, called ‘Voice’, makes it easy for staff to quickly review safety recommendations for more than 1,700 hazardous substances. Available in English and German, it also suggests products to protect users from these substances. Putting essential information like this at the fingertips of staff has become a theme of technology development in the energy safety niche, in a similar way that it has inside the ordinary home. The bottom line is that these state-of-the-art advances each play an incremental role in helping to save human lives from fire and other risks.
Every second counts And then there are the industry’s lifeboats which provide, quite literally, a lifeline should things go terribly wrong. In a similar way, technology has evolved here too. The Norwegian GES50 MK III escape boat - dubbed the world's most advanced, robust and safe lifeboat by makers Norsafe - is designed to fall from more than 50 metres, offering rig workers a near immediate emergency escape should they need it.
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Tolmann Deepwater Survival Training Centre, a world class Facility built solely for the purpose of addressing the safety, survival and training needs of persons working in and around Deepwater facilities and installations comes complete with Accommodation facilities located within the grounds of the school, for the ease and comfort of our esteemed clients. In achieving this laudable objective, we have put in place global standard infrastructure that demonstrates Health, Safety, Environment and Security challenges which are of immense value to deepwater operations and maritime related activities. We offer the following courses at the center among others: TBOSIET HUET/SAS Basic Fire Fighting & Self Rescue Basic First Aid Offshore Safety Induction FOET
AED Advanced Fire Fighting Advanced First Aid IMIST STCW 95 PSCRB
COXSWAIN HLO Swing Rope EHS Fork Lift Crane Operator
OFFICE/TRAINING FACILITIES Offshore Safety Training Centre (OSTC) 58 Trans-Amadi Industrial Layout, Port Harcourt Tel: +234 803 312 9962, 0803 760 0151, 0809 990 1280 Email: tolmann@tolmann.com. Website: www.tolmann.com International Centres Texas Engineering Extension Services (TEEX) USA Survival Systems Ltd. Canada
Fire Safety
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During tests, however, the vessel plunged successfully from more than 60 metres. It has been designed to always land upright, is fully equipped with seatbelts, and has enough capacity to hold 70 people who can climb on board in just one and a half minutes. Lifeboats are also deployed on mobile drilling units. Maersk Drilling is to equip its soon-to-be completed XL Enhanced 4 jack-up rig with seven ‘Boat-In-A-Box’ lifeboat and rescue systems from Danish firm Xervo. Again, with lifeboats hopefully never used for their intended purpose - like airbags in a car - this is an area where maintenance is critical to ensure all systems perform when required. Research has gone into other areas too for when things do go wrong. Dräger, again, recently re-engineered its safety hood for workers that gives them valuable breathing time if they are escaping from a fire, or smoke, or another toxic substance.
The Nigerian government is keen to see local players take on more responsibility.
The Norwegian GES50 MK III escape boat - dubbed the world's most advanced, robust and safe lifeboat by makers Norsafe - is designed to fall from over 50 metres, offering rig workers a near immediate emergency escape should they need it.
Maersk Drilling is to equip its soon-to-be completed XL Enhanced 4 jack-up rigs with seven ‘Boat-In-A-Box’ lifeboat and rescue systems from Danish firm Xervo. Photo Xervo.
The Parat escape hoods are equipped with high-performance filters, enabling workers to breathe even in the harshest of conditions.
Emergence of local players There is also a growing role for indigenous companies servicing this important area too, a popular theme especially in Nigeria right now. The Nigerian government is keen to see local players take on more responsibility within the nation’s strategic energy sector, from upstream oil production right through to the smallest of industry services. Seafloat Marine Services Limited has emerged as one of the leading indigenous marine safety specialists in the country. It offers life craft testing, inspection and certification, among other services, and is keen to expand its presence throughout West Africa. It is also responsible for fire extinguisher inspection and service onboard rigs and other installations. Seafloat’s client list includes most of the big multinationals working in Nigeria today (the likes of Chevron, Total, Addax), plus a roster of local and overseas service companies and drilling firms. Like most other players active in this niche space, it is all valuable work, but not often recognised until after things go wrong. Still, with oil and gas production tipped to rise in Africa, it is a market that is poised to see yet more growth in the years ahead. One area in which oil companies will never cut corners is safety. ■
Dräger explores new depths with Drägersorb BLYTH DRAEGER MARINE & Offshore, part of the Dräger Group, is among the leading providers of safety solutions in the Oil & Gas industry with its Drägersorb product used by saturation divers. With safety one of the top priorities for the Health and Safety Executive’s Offshore Division, and with manned diving an essential part of operations in the Oil & Gas industry, Dräger is passionate about protecting lives. On offshore oil and gas assets it is critical that divers are equipped with the best safety solutions to enable them to remain submerged in really deep water for long periods of time. Drägersorb (soda lime) gives offshore divers a lifeline after they have carried out challenging underwater inspections and maintenance work on installations in the field. Trips up and down from great depths risk causing ‘the bends’. Therefore, due to the
36 Oil Review Africa Issue Four 2014
rising demand for deepwater operations up to 300MSW and up to 28 days inside a decompression chamber system on board a Dive Support Vessel (DSV). On board every DSV as part of the entire saturation diving system (SAT) are life Support Systems with Environmental Control Unit (ECU) which contain Drägersorb-ECU (soda lime). An average ECU will contain around 20 to 30kg soda lime, that needs to be exchanged on a regular basis during diving operations. Depending on the SAT system used it will contain different numbers of ECU units. Divers’ lives depend on these tiny white granules which absorb carbon dioxide (CO2) while they wait in a decompression chamber for their bodies to readjust to surface air pressure. Exhaled air contains around four per cent carbon dioxide and the soda lime removes this CO2, so the remaining air - enriched with oxygen - can be fed back into the breathing circuit. On average, 1kg gram of soda lime can
Protecting the lives of oil and gas saturation divers, operating in deadly environments
absorb up to 120 litres of carbon dioxide. An integrated gas detection system on board the DSV is able to pick up when the Drägersorb is low and needs to be replaced. It can be refreshed by an on-board technician who looks after the diving team. Frank Pietrowski, business development manager for Dräger, said it’s interesting to see performance tests from established users have found capacity of Drägersorb to be approximately 20 per cent better than the company’s main competitors. www.oilreviewafrica.com
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Technology
Allan Cameron, technical director with Sabre Safety, world leaders in Hydrogen Sulfide (H2S) services, takes a look at the safety challenges in dealing with H2S and working in irrespirable environments around the world.
Meeting African onshore and offshore
H2S challenges A
S GAS SAFETY and breathing experts, we work in all manner of irrespirable environments where equipment, training and teamwork are the cornerstones of ensuring the safety of staff and partner company staff, as well as that of third parties. This is true of any gas environment, and at Sabre Safety we deal with some of the most threatening ones to be found on the planet. As a former driller, I have first-hand experience of the hazards of dealing with H2S at the oil-well. A natural by-product of organic decay, H2S is unlocked as a result of drilling and well-servicing operations. Oil and gas fields, tankers and production facilities all have the potential to contain significant amounts of H2S. It is a hugely challenging gas to deal with. H2S is a killer gas that acts as a broad spectrum poison when inhaled by mammals. Broad spectrum means that it can affect many different systems in the body – from the respiratory, pulmonary and circulatory to the digestive system. It has claimed the lives of numerous workers around the world in incidents that might have been prevented had they known more about the properties of H2S. The gas occurs naturally in geological formations, with certain geological periods being more likely to contain it than others. Higher risk geological periods are: Triassic; Permian; and Carboniferous. All petroleum industry jobsites are potential H2S locations. The effects of this neuro toxin gas can range from mild discomfort to death. It is so toxic that it quickly overwhelms the nervous system, with initial inhalation overcoming the sense of smell. At higher concentrations, the effects are immediate and can be catastrophic. H2S is colourless and therefore invisible – there are no visual clues to its presence. Although it has a distinct ‘rotten eggs’ odour, it attacks and quickly impairs a victim’s sense of smell, even in low concentrations. Quite simply, it could be fatal for a person to rely on their nose as a detection device: there are no second chances. As H2S is heavier than air, it tends to settle in low-lying areas such as pits, cellars or tanks. It is a potentially explosive as well as a poisonous gas. Mixed with the right proportion of air or oxygen, H2S can ignite. The ignition range is 4.3 and 46 per cent of atmosphere and it can auto-ignite at temperatures around 260˚C. Add to that its highly corrosive qualities, and the fact that it is soluble and can therefore be present in any container or vessel used to carry or hold fluids, and you have a formidable adversary. In terms of toxicity, five parts per million (5 PPM) is the long-term exposure limit. A dose of 500 – 700 PPM will cause loss of consciousness and death within 30 minutes to one hour. A dose of 1,000 PPM (the equivalent of one tenth of one per cent) will cause immediate unconsciousness and death within a few minutes – even if the casualty is removed to fresh air. As can be imagined, there is absolutely no margin for error when working with this toxic and highly dangerous gas. It means that everything we do as a company has not only to meet but to exceed safety requirements, with multiple backups to ensure that there is no interruption to breathing systems under any circumstances.
Offshore African operations Wherever the company operates, Sabre’s work is really all about coming up with particular BA safety engineering solutions. Recent work in Africa has included operations on a drill ship off the coast of Kenya. The ship had a breathing air (BA) system on board that was installed 10 years ago, and that had been tested routinely but had never been used. Sabre carried out a full inspection to establish what was needed to modify the system to get it to optimum performance – changing many of the fittings
38 Oil Review Africa Issue Four 2014
A new wellhead is lowered into position-PA270121.
and overhauling the system generally, as well as making recommendations for the future. In the end, Sabre’s work meant that the well was completed using a combination of its system and the existing system. The original main hardpipe system was used and Sabre deployed its own personnel lines and retractor reels from the existing outlets, which were modified in the auto-selectors to ensure that it all functioned together. Incidentally, the project also entailed working with our Norwegian partners Vestteknikk to move forward and sort out the technical solutions. In a truly international industry, expertise really does come from all parts of the world, and the sum of the whole is greater than the individual parts. There is another point to this too: ISO standards and everything that goes with them are applied to everything that Sabre does, whether it’s in the North Sea or off the coast of Africa, which is a major consideration for customers. On another ship off the coast of Benin, the oil company involved did not want a cascade system on board, preferring instead the modification of a system. Sabre used BA compressors and a system similar to one it has been using on the Brents in the North Sea. running HP lines to the work sites where they were needed; Sabre had the same manifolds and reducing stations as on the Brents and connected personnel lines on to them. Getting to the drill floor was quite challenging as it was essential that bulkhead integrity was maintained.
Adapting ways of working to suit local conditions Sabre has recently deployed off the coast of Malta as part of a project that has involved drilling operations there, with a further two initial wells off the coast of Morocco. This project has involved the delivery of an extensive cascade breathing
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Technology
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system. The rig does not have pressurised accommodation so it cannot be used as a temporary refuge. This would normally be our preferred way of working as most rigs have such accommodation. In the absence of this, we had to set up an external breathing muster station for around 130 people and provide much more airline breathing apparatus. Once it is fully rigged up the system will stay in place wherever the rig moves. Sabre would normally supply 140 standard Elsa breathing sets, but here we are having to supply Elsa musters with an airline attachment so that people can connect to a breathing cascade system. A wireless gas detection system has also been installed on the rig. As a BA specialist company, Sabre does not make people wear BA unless absolutely necessary. That is one of our reasons for using pressurised accommodation as a temporary refuge, wherever possible, because people can muster there without BA. In such situations, people still of course have to don BA to evacuate the rig and get out of the refuge, but the principle of only using BA when absolutely necessary remains.
Meeting onshore challenges – location and logistics Onshore challenges for safety companies include the sheer diversity of landscape: onshore drill site locations can vary from desert to jungle, and from mountain to farmland. Recent work in Mauritania for two major oil companies has focused on exploration projects in the desert, where sand storms and high temperatures combine to make for a difficult working environment. In order to mitigate risks, the system on the HP side is designed to be within a container. Staff still have to be careful moving in and out of the container, but the system itself is protected. Only LP distribution lines and BA sets, which can be cleaned off, are exposed to the elements. Logistics can be daunting in such locations. It is all very well being able to do a job in one relative ‘easy’ location, but quite another to be able to work in some of the most inaccessible and inhospitable terrain on the planet. In both
40 Oil Review Africa Issue Four 2014
cases, however, oil companies will expect H2S companies and other suppliers to have robust and failsafe measures in place to get people and equipment to the right location and at the right time – always. The ability to deliver to schedule and specification across the world and at short notice is of primary importance. Location spares and additional equipment have to be planned ahead of the equipment package being mobilised to the site. It entails envisaging problems and coming up with solutions before the problems are encountered.
Dealing with emergencies Over the years Sabre has been called out to numerous well blow-outs with suspected H2S. An incident that occurred in Libya highlighted the issues faced by specialist companies as the Sabre team mobilised within 24 hours of receiving the call. Detailed knowledge of local customs regulations meant that the Sabre team was ushered through and was on-site and quickly operational alongside the well control company – all within a couple of hours of arriving in Libya. It took well control two days to set up, during which time Sabre took samples from the blowout with full BA sets and from the tree where it had blown. The company was also tasked with monitoring conditions around the perimeter of the site, depending on time of day and wind direction; we were trying to establish where the plume was landing so that we could take samples. Precise country knowledge in terms of procedure was a decisive factor in a successful deployment. The expansion of Oil & Gas operations into ever more challenging areas of the world is driving demand for specialist services provided by companies such as Sabre Safety. Whether in exploration or decom work, Oil & Gas operators are looking for innovation and expertise that underpin their activities against a backdrop of tight margins. This is an area in which specific expertise and the latest technology and training can really improve safety and profitability. The contribution of specialist service companies is set to be an increasingly vital part of Oil & Gas operations all over the world. ■
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Technology
In search of eternal youth: the battle to prolong oil flow from Africa’s mature fields.
Live long
and prosper N
EW TECHNOLOGY ADVANCES, high oil prices, and a general scarcity of resources worldwide, means squeezing every barrel from each and every reservoir is now a top priority for all 21st Century energy companies. That’s especially true in some of Africa’s more established producers, the likes of Nigeria and Gabon, and the North African states, where oil and gas has been flowing for decades. It’s a similar story too in many other oil producing territories of the world, including the Middle East Gulf. However, even relatively newer producers are facing up to this same challenge. Chad, for instance, is looking to halt declining production from its maturing fields. Its output is now down to around 100,000 bpd, from a peak of 176,000 bpd in 2005; that’s less than 10 years ago. Similarly, Gabon’s oil production declined to 11mn tonnes in 2013 from 11.6mn tonnes in 2012. A modest pick-up is expected this year, due to operators’ new techniques to drill marginal fields, but production “will at best stagnate in 2015”, according to ratings agency Fitch.
Strategic interest Indeed, for all of these locations, arresting - and even reversing - the decline from mature oil fields is nothing short of a matter of vital national interest; a means of sustaining cash flow into the wider economy as a whole. For poor countries especially, such as Chad, this need becomes even more pressing. While drillers scouring frontier locations, such as the deep offshore (think Mozambique, Ghana, among others), to unlock big new oil finds captures the imagination more than anything else, it is perhaps the quiet work behind the scenes of the scientists, geologists and other technicians, that is more valuable in the long-run. Only by maximising value from these existing assets - whether oil, gas or indeed other minerals - can companies, and countries, benefit fully from their natural resources. It’s important from a global perspective too, making available precious hydrocarbon reserves to a world at a time when many perceive growing scarcity. But it is a great challenge too, and one that varies considerably from field to field, and place to place. Oil recovery factors vary wildly from one location to another, from less than five per cent to greater than 80 per cent. Perhaps a reasonable estimate of the average oil recovery factor around the world is in the region of 37 per cent. Anything drillers can do to raise this number - even fractionally - can make a massive difference to the overall profitability and longevity of a field. Proper field management can improve recovery rates by addressing both near- well conditions and the reservoir as a whole. This strategy is common practice today.
Technology leap Luckily, the ability of operators to extend the life of their fields has never been greater. While a strong oil price environment and growing resource scarcity provide the market backdrop and economic justification, it is the advance in technology that has made it all possible. New developments, such as the rise of horizontal drilling, have given
42 Oil Review Africa Issue Four 2014
The Moho Nord project will target additional reserves in the southern part of the license and new reserves in the northern part.
The ability of operators to extend the life of their fields has never been greater. operators more tools with which to unlock and access underground oil and gas pockets. Computer modeling and seismic technology also offer greater visibility into reservoir systems than at any other time in history. As well as prolonging the life of mature fields, these innovations - many of which have been pioneered in places like the North Sea and the Middle East have also been used similarly to access new deposits, both onshore and offshore. Other new tools are also available for engineering an entire field. Acquisition of repeat seismic surveys, called a time-lapse seismic study, can provide valuable information for field optimisation. In addition, changes in fluid saturation and composition, or the lack of change, can indicate areas of the field that would benefit from more wells, or wells that need work-overs.
Africa context These are issues facing all operators in Africa today. For Total, one of West Africa’s leading producers, the management of its mature fields portfolio is a critical strand of its business. In Congo-Brazzaville, while it pushes further offshore in search of new discoveries, the emphasis is very much on maintaining production flow from existing onshore and shallow water assets. About 60 per cent of the group’s production in the country comes from maturing fields, such as Nkossa, one of Congo’s flagship developments. Without any intervention, Total says the natural decline rate from these fields would be around 15 per cent; the goal is to limit the decline to five per cent. The strategy includes ‘heavy intervention’ methods (production from new layers, well activation conversions, increased recovery on developed reservoirs), plus ‘light intervention’ (dewaxing, gas lift, perforations, acid stimulations). And the success is there for all to see: in 2012, for instance, re-entry wells on the Yanga and Sendji fields added a further 5,000 bpd of production. As well as the redevelopment of these mature fields, the focus is also on the development of satellite - often previously marginal - fields, and the exploitation of non-conventional reservoirs; these include Tchendo Senonian tight oil and Sendji C viscous oil. This work complements the search for new oil and gas deposits in frontier zones too. Total will add 140,000 bpd to its local capacity via the Moho North offshore project, an indicator perhaps how oil companies still see bigger impact and more immediate returns from new finds, rather than squeezing incremental barrels from existing reservoirs.
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Gas sector It is a similar story when it comes to maintaining output from Africa’s gas fields too. It is an area that requires not only technology but also extensive capital investment too. In one of Africa’s leading gas exporters, Algeria, there are multiple projects in play to extend the life of its producing fields. UK services group Petrofac, for instance, is working with Italian contractor Bonatti to extend the life of the Alrar gas field on behalf of state energy company, Sonatrach. The field, in southeast Algeria, has been in operation since 1987. The US$650mn project encompasses engineering, procurement, construction, and commissioning services for the development of new
Africa’s gas fields is an area that requires not only technology but also extensive capital investment too.
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Mounting problem But with more oil and gas fields in Africa maturing it is a growing issue for all players. According to the US Energy Information Administration (EIA), production is set to drop in a multitude of countries - Sudan and South Sudan, Equatorial Guinea, Cameroon, Congo (Kinshasa), Mauritania, as well as Chad and Gabon because of the natural decline in mature fields, which will not be offset by sufficient output from newer finds. While other countries, like Nigeria and Congo (Brazzaville), may be facing similar struggles with mature fields, new production will at least keep output level - for now. It is only in Africa’s newest and upcoming producers - the likes of Ghana, Uganda, Tanzania and Mozambique - where the challenge of mature production has yet to be faced. With technology advancing at such pace, there will be plenty of lessons and experience to be had for these new and emerging producer states. ■
Oil Review Africa Issue Four 2014 43
Technology
With the Alrar Gas Field Extension project, Sonatrach is aiming at maintaining the plateau production of this depleting gas field.
separation and booster compression facilities. But this kind of thing all comes at a cost, as the Alrar project illustrates. The days of ‘easy oil’ are widely considered to be over, even in fertile lands such as the Middle East, and that goes not only for discovering it, but also in producing it. It means prolonging field life is an essential part of the life cost matrix for any upstream asset. This additional cost burden, in maintaining production from ageing fields, and reversing decline, is something that operators must now routinely factor in. Engineering and technology input also shifts throughout the life cycle of any field, as needs and demands dictate. Mature fields typically have increasing water cuts, for instance, both from natural aquifer encroachment into the producing zones and from water-injection programmes to sustain oil flow.
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Technology
Extending field life and increasing oil & gas recovery in Africa. By Samir Walia, Emerson Process Management.
Increasing recovery
rates F
OR ALL THE technological developments in the oil & gas industry over the past decade, global oil & gas recovery rates remain remarkably low. Today, according to Italian operator Eni, average world oil recovery rates are 35 per cent against a technical limit estimated at between 70 and 80 per cent. Many recovery rates are much lower than this in the 20’s. Furthermore, the pressures on increasing or even just maintaining current recovery rates is only likely to increase as companies move into ever more complex areas and challenging geologies. Africa is no exception to this as operators continue to tap into frontier areas offshore West and East Africa. This is in addition to the complex geologies onshore, such as the East African Rift – the largest continental rift on Earth that extends 3,500 km from the Red Sea in the north to Mozambique in the south. Such large, complex and high-cost environments are likely to put huge pressures on profitability and focus operator minds even more on gaining maximum returns from their fields for as long as possible. Resource owners today are demanding best-in-class technologies to maximise the value of their existing and future assets and extend the field’s lifecycle. It’s against this context that reservoir modelling has a crucial role to play in unlocking reservoir value, extending field life and increasing reservoir recovery.
Role of reservoir modelling 3D reservoir modelling today is the standard platform for the mapping, understanding and predicting of reservoir behaviour worldwide. A robust, reliable and accurate reservoir model provides an integrated picture of all available subsurface data and allows the operator to build and test multiple production scenarios. In this way, operators can determine how best to develop and produce their resources and access crucial information on oil in place. Successful reservoir models today, however, must reflect all faults and the true compartmentalisation of the reservoir, represent the controlling flow properties - such as porosity and permeability at the right scale - and ensure a seamless and cost-effective workflow from seismic through to simulation. This article will examine what makes a successful reservoir model and the impact on African operators.
The role of seismic Any model that oversimplifies geological complexities in the reservoir is not going to deliver the vital information African operators require. That’s why it has become so important to incorporate 3D seismic into the reservoir model with seismic interpretation becoming a central element and prerequisite of reservoir modelling today. Emerson’s reservoir modelling workflow, Roxar RMS, for example, now comes with seismic interpretation, seismic inversion and seismic
Reservoir modelling has a crucial role to play in unlocking reservoir value, extending field life and increasing reservoir recovery. attribute tools that allow geoscientists to use seismic data to create a rock property model quickly and accurately. Yet, despite the embracing of seismic, for many workflows there still remains a reliance on just a single model to calculate uncertainty predictions even if it is widely accepted that multiple scenarios fit the data. There is also often ambiguity in the data collected, where many configurations or scenarios (fault configurations, for example) are supported by the data and yet are unable to be distinguished based on the data alone. Uncertainties in static reservoir properties, for example, are often difficult to quantify, due to limited well control and seismic resolution, and physical limitations in seismic acquisition technology can result in only a portion of the earth response being captured in a seismic image.
Importance of an integrated workflow As well as seismic interpretation that is tightly linked to geological model building, another
Figure 1: Base case surfaces with faults network.
44 Oil Review Africa Issue Four 2014
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Growth in model-driven interpretation It’s with these issues in mind that Emerson has developed a new reservoir modelling approach within its latest software, Roxar RMS 2013, where uncertainty is captured during the interpretation process and where the model is effectively the interpretation. The process can handle multiple models, capture the limitations of the data, and quantify geologic risk as early in the reservoir modelling process as possible with direct correlations with the seismic. Rather than creating one model with thousands of individual measurements, with RMS 2013 modellers create thousands of models by estimating uncertainty in their interpretations. The software then generates statistically significant ensembles of models based on these probability distributions, thereby providing immediate value to the geoscientist. The interpretation is based on uncertainty information being collected and paired with an interpreted geologic feature (horizon, fault, contact etc), thereby more accurately representing the limitations of the data and the interpreter’s vision for the geologic structure. In this way, the new method can show what parts of the model are most
Many conventional interpretation and reservoir modelling workflows today are disjointed and independent within organisations. www.oilreviewafrica.com
Technology
prerequisite for reservoir modelling and its role in generating an accurate description of the reservoir is an integrated workflow from seismic acquisition and interpretation right through to simulation. Such a workflow ensures maximum productivity of all members of the asset team, the ability to share knowledge and resources, and gives interpreters the ability to move back and forth between different modelling tools covering everything from seismic interpretation and structural model building through to facies petrophysical modelling, well planning and uncertainty modelling tools. A strong workflow also provides flexibility in deciding which areas of the model to focus on. Many conventional interpretation and reservoir modelling workflows today, however, are disjointed and independent within organisations. This leads to a lack of agility on the part of the typical asset team, whether it is difficulty in adapting and responding to new data or challenges correcting errors in existing data. Such a disjointed workflow can lead to a high number of points and clicks to map just a single geological feature and little flexibility for the reservoir modellers to change direction. With geophysicists interpreting thousands of points at seismic scale, and geomodellers doing the best they can to fit the model to the interpretation, data and crucial decision-making information can subsequently often be overlooked.
Figure 2
uncertain, and can quickly indicate where more detailed investigation is needed and where new data needs to be acquired. In addition, users will also receive instant feedback on the consequences of a measurement with fewer points and clicks required to map a geologic feature. Through this, interpreters will be able to rapidly map the key features of the reservoir using a sparse representation and with no additional quality control phases. So what impact will this new model-driven interpretation workflow have on extending field life and increasing oil & gas recovery for African operators? The new workflow generates a more complete representation of the data irrespective of the quality of the data leading to a better picture of the subsurface and more valuable input for effective reservoir management decision-making and delivering returns on the asset. The workflow can also generate early estimates of reservoir volumes, enabling geoscientists to quickly build risked models of static reservoir volumes and generate the best possible estimates to support commercial decisions. Histograms and distributions of static reservoir volumes, for example, can be quickly constructed and analysed, resulting in probability estimates directly used in financial modelling. Risk estimates for drilling decisions can also be generated through a combining of interpretation and structural uncertainty modules. Operators can make risked predictions of horizon or fault positions and integrate this with loggingwhile-drilling data and precision steering to reduce risk in drilling.
Quantifying GRV uncertainty GRV uncertainty is often one of the most significant uncertainties, especially in the early phases of field appraisal and development with the correct handling of structure and contacts often key to realistic uncertainty assessment. To this end, Emerson’s new model-driven interpretation capabilities is able to generate a
multi-realisation 3D uncertainty structural model where interpreters can define lateral and vertical uncertainty at every pick during the seismic interpretation workflow alongside velocity models and fluid contacts. Figure 1, for example, illustrates an example where the control points were used for the two surfaces – the upper surface control points, the lower surface control points, and the base case surfaces with the fault network. Each point represents a best estimate coordinate with different uncertainty ranges then applied for each point. Through this approach, standard deviation maps can be generated. Figure 2, for example, compares a new standard deviation map from the modeldriven workflow (on the right) with the map generated from a conventional uncertainty workflow (on the left) with the new map reflecting greater confidence in the quality of the seismic data rather than constant uncertainty ranges inputted by the interpreter. The standard deviation map will be used as valuable input in the creation of a 3D grid, the generation of multiple realisations, and eventually gross rock volume ranges with greater accuracy that can have an important role in field development.
Focal point of decision-making Too often in the past oil & gas production strategies have been guided by short-term decision-making and a knowledge that once the easy oil has been found and a recovery rate of say 30 per cent has been achieved, easier oil can be found elsewhere. No longer! This ability to quantify geologic risk early in the interpretation process and the integrated seismic to simulation workflow is likely to have a strong future impact on not only drilling decisions but the accuracy and effectiveness of bid valuations, production estimates or divestments, and, of course, in increasing recovery. Reservoir modelling will play a key role in achieving this. ■
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Nigeria
Nigeria has an enormous endowment of natural resources, chief among which is hydrocarbons. We look at how the management of the petroleum sector under Alison-Madueke has contributed to the giant strides being made in respect of the strategic objectives of the industry.
Ministry of Petroleum Resources Livewire of transformation agenda
A
S AN ECONOMIC resource, the oil and gas resources is the mainstay of the Nigerian economy providing 30 per cent of the country’s GDP; 80 per cent of government revenue and 95 per cent of the country’s foreign exchange. For Nigeria to realise its national aspiration of becoming one of the top 20 economies of the World by 2020, the success of the oil and gas industry is crucial. This strategic industry has in the last three years been under the purview of Diezani Alison-Madueke, Hon minister of Petroleum Resources. To have a robust view of the contribution she has made to the industry, it is pertinent to segment the industry activities in respect of its various sectors such as upstream, midstream and downstream.
The upstream sector The upstream sector is the heart of the oil and gas industry. Here, the management of the industry under Alison-Madueke has exceeded expectations. In about 2010, Nigeria’s daily crude oil production went down to as low as 800,000 bpd. Today crude oil production has been maintained at an average of 2.3 mbopd with gas production increased from 6.3 to 8.1 bcfd by year-end 2013, in spite of incessant pipeline vandalism and crude oil theft. tAlison-Madueke has also mounted concerted efforts to grow Nigeria crude oil reserves in the inland sedimentary basins especially in the Chad Basin with the acquisition of additional 3D data and commencement of Phase 5 of the exploration programme. Data processing and interpretation are also ongoing to establish drillable prospects in the basin. The result has been an increase in NPDC crude oil production which now averages about 150,0000 per day. The oil and gas industry under the watch of Alison-Madueke is also paying deserved attention to the management of the environment of the oil and gas operation. An organisational as well as implementation structure for the execution of the recommendation of the Ogoni UNEP Report which provides information on the level of devastation of Ogoni land has been put in place. Already, the processes and intervention programmes which include remediation, economic empowerment of impacted communities as well as funding have been agreed upon by the industry.
The midstream sector In the midstream, under her watch, the industry has sustained gas supply for power generation and industrial use following the execution of gas supply
46 Oil Review Africa Issue Four 2014
Alison-Madueke at Okrika Jetty.
intervention programmes, resulting in increased gas supply to the Western Gas corridor which has in turn positively impacted electric power generation in the country. The implementation of critical pipeline infrastructure for gas supply has been pursued vigourously. ELPS Phase I expansion project has been commissioned which has increased the delivery capacity of the Escravos-Warri pipeline system from 399mmscfd to 600mmscfd. Gas supply to Olorunsogo has also been commissioned, while OB3 and Oredo-Ogherefe gas supply projects are progressing. As part of the efforts to support the creation of new gas based industries, President Jonathan’s administration through the NNPC has secured the support of JBIC of Japan to part-finance NNPC equity interest as well as get the strategic participation of the Japanese investors in the Brass LNG project. This is expected to facilitate the attainment of FID for the project soonest. In March 2011, the present administration launched “The Gas Revolution: Rebirth of Nigeria’s Industrialisation”. The objective of the initiative is to stimulate industrialisation through gas-based industries. The initiative will also involve establishing an industrial gas city in Delta State. The gas city will comprise establishing a worldclass petrochemical plant with the capacity to produce 1.3mn tonnes of polyethylene and 400,000
tonnes of polypropylene per annum. Government plan is that from this plant alone, myriad secondary industries will develop producing such items as plastics, packaging stuffs and high-end products as printed circuit among others. The initiative is expected to bring into the country foreign direct investment of about US$10bn between 2011 and 2014. It is also expected to generate massive employment opportunities, support for agricultural production and boosting the government’s plan to provide stable power for economic development.
The downstream sector The Downstream Sector has encountered festering challenges such as pipeline vandalism as well as loss of hard-earned resources due to administration of subsidies on petroleum products in the country. Alison Madueke has striven to ensure that all parts of the country receive petroleum products in the quantity that will sustain their economic activities. Where there were hiccups in petroleum products supply, she had taken up the challenge and put an end to such occurrence. She has also undertaken an aggressive repair, rehabilitation and upgrade of industry facilities. In the last few years, the Port Harcourt–Aba product pipeline has been re-streamed, while the integrity of Warri–Benin, Aba–Enugu pipelines are being reestablished. Within the period under reference, Aba Depot and Okrika Jetty were re-commissioned. It is
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Nigeria
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worthy of note that the integrity of most of the network of pipelines serving the North has been re-established such that products are now being moved to locations such as Jos, Gombe and Kaduna through pipelines. Undertaking a holistic rehabilitation of the three refineries has been a major position of the minister since her assumption of office. Her plans are to contract their rehabilitation to the original manufacturers to guarantee an excellent job. As at today, Port Harcourt refinery is undergoing a major rehabilitation while Warri refinery as well as Kaduna refinery has been scheduled. While the focus is to abolish petroleum subsidies as soon as possible, she has also put in place stringent measures to curb corruption in the system.
Local Content Development The Nigerian Content Development is an issue which the minister of Petroleum Resources considers a top priority. To date the contribution of the oil and gas industry to the GDP is a mere 30 per cent. In one stroke, the Nigerian Content Law , reversed this trend by attracting investors to set up facilities in Nigeria, provide avenues to ensure procurement of goods and services are domiciled in-country, stimulate employment and provide opportunities for training for Nigerians as well as
create an environment that promotes in-country support services and linkage industries. Due to the enactment of this law, expected impact of Local Content on the national GDP in the next four years is put at the following: 6 Retention of US$10bn out of 20bn average annual industry expenditure 6 Creation of more than 30,000 direct employment and training opportunities 6 Establishment of three to four new pipe mills to service industry demands 6 Development of one or two dockyards and utilisation of existing shipyards 6 Transformation of ownership profile of marine assets supporting industry 6 Integration of indigenes and businesses residing in the oil producing areas and 6 Capture of over 50 per cent to 70 per cent of banking services, insurance risk placements and legal services.
The Petroleum Industry Bill Much has been written about the Petroleum Industry Bill, PIB; much more will still be written about it now and in the nearest future. In essence, the bill is a reform legislation which promises to establish the legal and regulatory framework, institutions and regulatory authorities
for the Nigerian petroleum industry. Alison-Madueke has shown serious commitment to progress the bill to the point of being passed into law. As at today, the bill has passed a Second Reading in the House of Representatives, for instance. What is re-assuring is that given the commitment of the minister to facilitate the passage of the bill, the industry is hopeful that the PIB will be enacted into law in the life of the Jonathan administration, with all the major changes it promises to effect on the industry and for the benefit of its players.
Giant strides and mounting challenges Although some giant strides are being made in the industry, the journey has been anything but rosy. Challenges posed by pipeline vandalism and crude oil theft are taking a heavy toll on the industry. Similarly, the activities of crude oil thieves also endanger exploration activities in the upstream sector. It is estimated that in the past five years these challenges have cost the industry more than US$1.5bn in crude oil and product losses. To move the industry to the next level, every Nigerian is encouraged to identify with the efforts of Alison-Madueke to rid the industry of these unnecessary challenges and move it to the next level. â–
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48 Oil Review Africa Issue Four 2014
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W O R L D - L E A D I N G MANUFACTURER and distributor of precision tubes for critical applications Fine Tubes has been awarded a major order by FMC Technologies for the supply of advanced tubing for Total's offshore Egina project. Located some 150 km off the coast of Nigeria at a depth of up to 1,750 metres, the Egina oil field is being developed by Total Upstream Nigeria Ltd for whom FMC Technologies is providing all the subsea production systems. The oil field is estimated to reach a peak production rate of 150,000 bpd and covers an area of around 1,300 sq km. Fine Tubes has been contracted to supply FMC with significant volumes of seamless instrumentation tubing for the control, hydraulic and injection lines required for the subsea manifolds. Fine Tubes sales and marketing director Brian Mercer said: "Winning this contract is an important achievement for Fine Tubes, given the environmental and operational demands that will be placed on the tubing. It's further evidence of our expertise in working with the most advanced materials to meet the most stringent quality and safety standards." Fine Tubes has been delivering high precision tubes for super critical applications in the oil and gas industry for the last 70 years. The tube mill regularly supplies precision tubing in stainless steels 904L (UNS N08904) and 6Moly (UNS S31254), as well as nickel alloy 625 (UNS N06625) and alloy 825 (UNS N08825) for global offshore and onshore projects. Fine Tubes oil and gas business development manager Ryan Dover said: "The subsea production systems deployed within the corrosive environment of the Egina oil field demand specialist corrosion resistant tubing. This is where our expertise lies with our extensive range of high performance alloys that offer extended product service life in the most hostile offshore conditions." www.oilreviewafrica.com
Pipe-in-Pipe pipeline meets challenging flow assurance demands TO MEET THE challenging flow assurance demands of an Angolan deepwater development in Total's Clove field, Subsea7 recently designed a high-performance Pipe-in-Pipe ({PIP) pipeline which is currently being installed by J-lay from its flagship pipelay/heavy-lift vessel, the Seven Borealis. The PIP installation is more than 125 km long and is being laid in 1400 metres of water. Subsea 7 is also delivering similar high-performance PIP technology by using the reel-lay method. The main challenges during this project were: 6 achieving the required thermal performance 6 the laying tension in excess of 550 t during the installation of the PIP production lines 6 the large number of flowline structures 6 the stringent welding acceptance criteria for flowlines susceptible to lateral buckling. Subsea 7 collaborated on an advanced PIP design with development partner ITP InterPipe using a 24 metres-long double joint which was fabricated onshore. The annulus in the double joint contains a blanket of Izoflex and the outer pipe is swaged down and welded to the inner pipe. The annulus is then drawn down to a reduced pressure to achieve the required insulation properties. A further benefit offered by this design is that offshore welding activities can be confined to just the inner pipe.
Cameroon jungle pipelines modified WITH THE COMPLETION deadline of the massive Lom Pangar dam construction project looming on the horizon, a leading Italian construction firm has been hard at work in the jungles of Cameroon modifying sections of the Chad-Cameroon pipeline. The necessary modifications had to be made well before the pipeline is submerged in the reservoir when the dam becomes operational later this year. Described by Michael Ngako Tomdio, minister of energy and water for Cameroon, as the “keystone in the arch of the Cameroonian electric system," the Lom Pangar Dam will generate electricity for industry and millions of residents throughout Cameroon. In preparation for constructing the dam, extensive environmental assessments and studies were carried out, revealing that two sections of the pipeline would be flooded in the reservoir when the dam is completed, so they would have to be modified. It was essential that there be minimal impact on the surrounding environment, which is a semi-deciduous rainforest and the home of Cameroon’s Deng Deng National Park. The park is a wildlife-protected zone that boasts a rich variety of wildlife, including primates, so it was critical that every precaution be taken to ensure that the pipeline modifications be carried out flawlessly. The Chad-Cameroon pipeline extends 1,080 km from Chad to Kribi, Cameroon on the Atlantic coast. It transports oil from Chad through Cameroon’s coastal port, where it is exported. The two 13 km pipeline sections in need of modification lay in partial jungle terrain east-northeast of Douala. The objectives of the modification programme were to re-route and strengthen the two pipeline sections to ensure that they would be capable of supporting 20-meter water columns that would eventually be installed upon completion of the dam. Tasked with executing the entire pipeline modification project, the construction firm retained TD Williamson (TDW), specialising in pipeline intervention and pressure isolation services, to isolate the live pipelines so that repair or modifications could be made safely, without disrupting product flow. Working in the jungle heat, the TDW team, consisting of four technicians based on-site throughout the operation, carried out more than 30 hot tap and plugging operations to isolate pressure in the two sections. TDW used the tandem Stopple
pipeline pressure intervention method to achieve a double block and bleed isolation, which makes it possible to cut, plug and safely isolate pressure from the sections without shutting them down, which would have resulted in disruption to flow. While the lines were safely isolated, providing a safe working environment, the necessary modifications to the lines were made so that they could be rerouted. Each line was safely isolated for approximately 20 days while the tie-ins were completed. The entire pipeline intervention operation, from deployment to completion of the final intervention, was completed by TDW well within the four- month timeframe. The isolation made it possible for TDW’s customer to connect the existing pipeline to the new pipeline safely and efficiently. Maintaining product flow throughout this complex operation was critical, so TDW’s ability to make that possible was key. Operating in the remote jungle, in such hot and humid conditions, called for detailed planning in logistics and operational safety. In addition, given that the pipelines were located in jungle terrain, TDW worked closely with the construction firm to plan every move very carefully, especially in terms of personnel safety and transporting equipment and materials. “We worked very closely with this construction firm which, like TDW, has vast experience in executing pipeline operations in remote, harsh environments, “ said Alexandre Flamand, project manager – Europe/Africa/Middle East for TDW. “As a result, our joint efforts and shared commitment to careful planning and high levels of safety led to a successful result: the timely completion of the tie-ins, with an absolute minimal impact on the environment,” he added. Oil Review Africa Issue Four 2014 49
Technology
Advanced tubing for Total’s Egina Project
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Technology
Simon Marr, Robotic Technologies business development manager with Fugro Subsea Services Ltd, explains how to minimise risk and increase production.
Subsea control and
simulation O
FFSHORE CRUDE OIL production has grown steadily over the last halfcentury to nearly 25mn barrels per day (bpd) in 2005 or one third of the total world crude oil production. In 2005 the Gulf and Middle East topped the list of offshore producers. Of the total world offshore crude, shallow water accounted for 20.3mn bpd and deepwater 3.5mn bpd. Thirty years ago deepwater exploration meant water depths of 800 ft. Today, depths below 1,500 ft are shallow, between 1,500 and 7,000 ft is considered deepwater, and more than 7,000 ft ultra deepwater. (Source: I Sandrea and R Sandrea; Oil and Gas Journal, 5 and 12 March 2007.) All the construction and maintenance of production infrastructure installed in waters deeper than 300ft is managed from the surface and relies heavily on Remotely Operated Vehicles (ROVs) and advanced tooling capabilities. The management and control of installations at depths up to 9,000ft is possible but is technically very challenging and much more expensive. Operators pay great attention to ROV pilot skills, offshore operations awareness, and to reliable, wellengineered solutions.
Fugro also uses DeepWorks to build accurate and functional models of ROVs and their associated tooling. Unpredictable Rigorous investigation and testing of designs in simulation before deployment increases the likelihood of success and reduces risks to an acceptable level in what can be a very hostile and unpredictable environment. The offshore oil and gas industry sets strict standards for deepwater field developments and defines compliance criteria for the verification of designs, operability and maintenance of production systems. This is due not only to the increasing complexity of the design of deepwater production systems - often multiple wells accessed via a template or clustered around a manifold exporting to a floating production system - but also to the high costs of new developments and changing existing developments. Full scale system integration tests are not economically practical so the oil industry applies modern simulator technologies for virtual testing
50 Oil Review Africa Issue Four 2014
FCV3000 ROV operator console.
of subsea systems to discover and rectify design flaws particularly at the concept and early engineering phases of projects, when the greatest savings can be made and there is time to improve designs and mitigate risk. Subsea services contractors use modern simulation tools with models of deepwater systems to verify system functions, and dynamic properties, against various requirements specifications and under a wide range of environmental conditions. This includes model-based development of plant equipment and deepwater solutions for the design, installation and maintenance of safe deepwater production systems. The leading European producer of ROV simulators is Fugro Subsea Services Ltd. (FSSL). Their robotic technologies business line based in the UK provides DeepWorks: an ROV trainer, engineering simulator and live operations visualisation toolset.
Interactivity The DeepWorks ROV pilot training simulator uses dynamic simulation, with hydraulic and electrical component libraries to reproduce the actual subsea conditions and ROV tooling that mimic the physical environment and pressures under which ROV pilots work. DeepWorks ROV brings full force-modelled physics simulation to subsea scenarios so that remotely operated vehicles and other moveable
subsea assets respond to electrical and hydraulic demands, environmental forces, and friction just like the real thing. ‘Touch and feel’ interactivity gives ROV pilots the same graduated tactile response as if they were actually navigating the ROV, or deploying a tool from a manipulator like a measurement probe or a hot stab. Rehearsing operations across a wide range of conditions helps to validate procedures and to define the safe operating envelope for successful inspection, maintenance and repair operations. Being able to rehearse specific tasks easily and repeatedly allows ROV pilots to hone their skills quickly and allows ROV supervisors to assess the job skill level required and to grade pilots for specific operations based on an objective assessment of their performance.
Evaluation For fast engineering and trustable solutions, DeepWorks Engineer provides a sophisticated dynamic simulation engine which models the true hydrodynamic responses of offshore equipment when acted upon by environmental conditions. Engineers can quickly drag and drop components from the extensive libraries to build subsea scenarios containing items like vessels, risers, pipes, cables and ROVs and drive them with force inputs. Engineers can also build and save their own custom assemblies by importing 3D engineering models, associating them with components from the
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Technology
library and then connecting them together. DeepWorks speeds up the evaluation of subsea engineering designs by simulating complex subsea interactions and collisions in great detail whilst recording all the engineering data for offline analysis. By enabling the ‘live’ features, the software can be driven by data captured in the real-world. Onshore, missions can be played out in advance by using previously recorded datasets to drive the simulation and verify acceptable windows for safe offshore operations.
Simulated data Offshore, the software is integrated with ship systems and accepts NMEA standard inputs such as GPS, Gyro and USBL. DeepWorks has been integrated with ship systems on Fugro support vessels and on third party vessels of opportunity. On Fugro vessels configuration is simplified because they all use Fugro Starfix via Message Manager. DeepWorks synthesises navigational and positional data in real-time to generate a clear, augmented reality view of what is really happening subsea both near and far from the vessel. This is a valuable tool for ships’ superintendents and crane and deck teams as they can each have their own viewpoint to improve work co-ordination. This makes vessel positioning and winched operations easier for more accurate deployments within the water column and on the seabed. Realtime feedback enables offshore teams to react faster to unforeseen events. Additionally, simulated data is used to fill the gaps between measured points which is essential for accurately tracking flexible lay or replacement operations. A permanent record is saved for subsequent post mission review and for comparison with previous operations. Fugro Subsea Services in Aberdeen (FSSL) uses DeepWorks’ Live capabilities for real-time monitoring of subsea operations. They also use DeepWorks Engineer and DeepWorks ROV extensively to support engineering services projects. These simulation tools enable fast and accurate verification of new engineering, as well as tooling designs and deployment solutions and support procedures development for the installation and
FCV3000 ROV training scenario for pipeline inspection.
repair of subsea production infrastructure. FSSL is committed to forging strong and enduring partnerships. Over the last two years FSSL and Kongsberg Maritime have jointly developed an Integrated vessel and subsea simulator. This is used for cross-disciplinary training of vessel, crane and ROV teams for the installation and repair of subsea production infrastructure. FSSL also works closely with GE Oil & Gas to support their tree design and field development projects and with Innospection Ltd who design ROV deployed inspection tools. Like most subsea companies, FSSL previously relied on building prototypes, SITs (system integration tests), small scale wet tests, and other expensive and time-consuming processes. Due to its wide range of construction, survey and dive support operations across the whole upstream oil and gas process, simulation is now benefiting more parts of the business, resulting in shorter project timeframes and enabling the delivery of a more cost-effective service.
Configuration Fugro ROV training and offshore simulators are manufactured in-house by Fugro Subsea Technologies in Singapore which makes the programme of global rollout easier to manage. DeepWorks has established itself as a leader in the simulation field primarily because it is easy to use and because it is underpinned by trusted physics. Engineers perform their work efficiently
FCV3000 ROV training scenario for torque tool operation.
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DeepWorks ROV brings full force-modelled physics simulation to subsea scenarios using the intuitive Windows-style drag and drop interface to build scenarios and the drop-down menus to change property values. The absence of any need for scripts or programming skills to configure the system enables high utilisation and widespread use with minimal training. Fugro also uses DeepWorks to build accurate and functional models of ROVs and their associated tooling. With access to the underlying electrical and hydraulic circuits, new tooling and tool deployment units can be configured quickly and it is easy to change the vehicle configuration for different kinds of mission, thereby saving significant time and money. “We are talking about bespoke equipment we make for our clients such as tooling, control systems and other kit for the ROV,” said Nick Alvarado, senior subsea engineer, Fugro Subsea Services Ltd (Aberdeen). “When clients encounter a subsea problem we occasionally have to design a set of tools specific to that job and sometimes the ideas and mechanisms have never been used before, so being able to test before we actually start manufacturing is of great value.” For training in fault detection and repairing, the underlying circuits are fully modelled. Training supervisors can ‘break’ individual circuits or components to test how well pilots understand their equipment. The supervisor can do this in real-time, or develop a problem scenario to test whether the trainee responds correctly. The system is setup so trainees can easily repeat a scenario until they get it right. The whole scenario and simulation data is recorded and can be returned to any point for review and detailed behaviour response analysis. DeepWorks provides an integrated suite of tools to help subsea operators complete each project task speedily and effectively. Simulation and control technologies now give operators an unprecedented insight and ability to intervene directly in the design, development, deployment, operation and maintenance of subsea and seabed equipment, minimising risk and speeding up production. ■
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ICT
Oil and gas operations are generating more data than ever. But if your rig or vessel is way offshore how do you get that information back to land? In the second of two articles on the changing face of oilfield data and voice communications in remote locations, Phil Desmond asks whether satellite networks can cope with growing offshore demand.
The changing face of remote oilfield
communications - part 2 I
N OUR FIRST look at the data and voice communications requirements of oil and gas operations in remote locations we discussed new and emerging communications needs and how they are driving demand. Of course, demand is largely irrelevant if those needs can’t be met. And that usually means satellite — even on land. For example, in metropolitan areas fibre and other fixed or wireless services may readily be available and provide a robust and resilient communications medium. Also, across oilfields, WiMax, Wi-Fi and VHF/UHF radio links may be required to communicate locally and are often installed and left unsupported. However, when it comes to the wider world, the answer is often satellite communications. Bill Green, global account director with Hermes Datacomms, a provider of managed networks for the upstream oil and gas sector worldwide, explained, “In remote locations or where the local infrastructure is unreliable — intermittent cable cuts for instance — VSAT is often the viable choice.” For onshore sites and offshore jack-ups, that means fixed VSAT implementation. However, stabilised antennas will be required on vessels and floating rigs. Green added, “Onshore, rigs may move frequently so an autodeployable antenna could be required to ensure the rig can deploy to a new location and establish communications quickly without the need for the attendance of a costly, skilled communications engineer.” Offshore, on a mobile platform, blocking may require the deployment of more than one antenna. “So,” Green suggested, “consideration needs to be given to how this can be deployed cost-effectively, giving ‘always on’ communication whilst partitioning between crew welfare and mission critical operations and approaching almost 100 per cent availability”. The most popular satellite bands are usually Ku, C and increasingly Ka band, each of which has its advantages and disadvantages in terms of licencing, interference and rain fade, not to mention size of antenna. The recently arrived O3b satellite system is an example of a growing trend towards Ka band as free bandwidth on Ku and C becomes difficult to access. An advantage here is that O3b’s constellation is lower in orbit than many systems, which brings advantages in terms of limiting latency — that is, delay. O3b satellites are not geostationary, unlike many of the more distant satellites, so they do require two antennas to manage the handover between satellites as they move through the sky.
52 Oil Review Africa Issue Four 2014
03b network satellite fleet image.
However, Simon Maher, vice president, Enterprise O3b Networks Ltd, points out that the antennas are very small and the data rates “phenomenal”.
Technology has gone a long way to coping with rain fade. Also O3b doesn’t quite cover the entire globe. This is not going to be a problem in most cases; if a rig isn’t going anywhere else for a long time it won’t matter at all. More important perhaps is the argument that communications on the Ka band can be affected by monsoon conditions — rain fade, as it’s known. This, regular readers will know, is a well-worn topic. O3b’s Maher points out that technology has gone a long way to coping with rain fade. “Ka has developed significantly. We have multiple advantages.” Referring to two technologies that can help to compensate for weather-induced changes, he said, “We can use adaptive coding modulation (ACM) with uplink power control (UPC) to get through those rain events. But it ultimately comes down to the link budget and the service you’re offering: what guarantees you’re prepared to provide behind that.” Either way O3b does seem happy to target some of the more rainy areas of Africa. “As far as offshore is concerned yes,” Maher agreed, “Angola and Nigeria are massive areas of opportunity for O3b.” Simon Bull, senior consultant with specialised telecommunications consultancy Comsys, has a slightly different view of the rain fade question. He suggested: “If you’re a rig offshore Nigeria and you
can pick up one of the Yahsat [regional Ka service] beams, might you put a Ka band service on? You may well do; it will give you an awful lot of bandwidth for a very low cost on a small antenna. But are you going to use it for mission-critical stuff? No, you’re not, because it’s not going to have the availability rates you’re going to need. “ But, he suggested a hybrid service might be the answer: Ku or C for mission-critical communications and Ka for crew welfare, which can cope with, say, an hour offline in bad weather. However, we shall see soon enough how well these satellites perform. O3b isn’t the only company offering Ka. Inmarsat’s Global Xpress service is due soon. And the Epic Intelsat offering brings together not just Ka but Ku and C band — or will when it starts service in a few years.
Fibre still an option Of course fibre is still an option in some cases, even offshore — and that leads to another possible hybrid. Martin Denari, Orange Business Services’ global director of oil, gas and mining vertical explained: “If you have, for instance, a production offshore platform you know is in place for a long period of time, it might make sense to consider fibre optics. If, by contrast, we are considering a drilling rig utilised in non-conventional exploration, then that rig is not going to stay for long on a given point. In this case, it might be better to consider satellite connectivity. There might be situations where a hybrid solution is the best option, for instance in vessels and a platform. You might connect the platform using fibre optics, but connect the vessels to the platform using microwave or satellite.”
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Referring to his company’s offering, he added: “Today we have plenty of solutions ranging all the way from a SIM card to having ships that are able to deploy subsea fibre optic cables.” There is, as he pointed out and as Bill Green noted earlier, no clear rule. Even onshore you might have to go with satellite in areas where burying a cable underground is prevented by environmental regulations. Similarly, weather conditions in an otherwise fibre-friendly environment might force you to go for a satellite solution.
Angola and Nigeria are massive areas of opportunity for O3b. Either way remote communications is likely to be more the norm as exploration goes further offshore and deeper — to areas offshore Brazil, say, that make even the depths plumbed so disastrously in the Gulf of Mexico by the Deepwater Horizon depths seem shallow. “It’s not like you’re ever going to run fibre round that,” said Bull. So it’s just as well — for E&P — that satellite is becoming more competitive and that service providers are recognising the need to drive lower prices. As Green said, “Using
If you have a production offshore platform you know is in place for a long period of time, it might make sense to consider fibre optics.
cutting edge technologies such as the Hermes VMS platform over Africa allows us to be competitive with local service providers whilst maintaining a high level of service.” Maher added another note of optimism. “The satellite market is growing year on year — and it’s a phenomenal market. But innovation has been lacking somewhat. Now the satellite
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