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■ Geology - p31 ■ Gas - p34 ■ E&P - p36 ■ Technology - p46
Volume 8 Issue Two 2013
www.oilreviewafrica.com
Africa
Covering Oil, Gas and Hydrocarbon Processing
Emerging themes in the African oil & gas industry Mozambique gas discoveries could double its GDP
Europe m10, Ghana CD18000, Kenya Ksh200, Nigeria N330, South Africa R25, UK £7, USA $12
Angola recovering optimism
New opportunities in Liberia and Côte d’Ivoire FPS for ultra deepwater Subsea corrosion management: challenges and limitations Taking deepwater pipelines to the X-Stream Offshore communications: more, faster, better and cheaper?
Rogério Manuel, president of the Confederationof the Economic Assocation of Mozambique (CTA). See page 10
REGULAR FEATURES: ■ News ■ Contracts ■ Events Calendar ■ IT update ■ Company profiles ■ Products & Innovations
S01 ORA 2 2013 Start_Layout 1 03/04/2013 15:33 Page 2
...Africa is our home
Block 1
OML 130
S
outh Atlantic Petroleum has made significant contributions to the development of oil and gas in the Gulf of Guinea. This has been through our participation in the Total – operated Akpo and Egina developments in OML 130 deep offshore Nigeria, as well as the ongoing redevelopment of the SAPETRO – operated Sèmè oil field offshore the Republic of Benin. We are also actively exploring our Juan de Nova and Belo Profond assets in the Mozambique Channel where we acquired over 12,000km of 2-D seismic data using a combination of state-of-the-art solutions adjudged the largest such survey in the world at present with the technology. We continue to expand our interests in Africa and look forward to long lasting partnerships in our ventures.
South Atlantic Petroleum • Nigeria
• Benin • France • Madagascar www.sapetro.com
Juan de Nova (France) & Belo Profond (Madagascar)
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■ Geology - p31 ■ Gas - p34 ■ E&P - p36 ■ Technology - p46
Contents
Volume 8 Issue Two 2013
www.oilreviewafrica.com
Africa
Covering Oil, Gas and Hydrocarbon Processing
Emerging themes in the African oil & gas industry Mozambique gas discoveries could double its GDP
Columns
Europe m10, Ghana CD18000, Kenya Ksh200, Nigeria N330, South Africa R25, UK £7, USA $12
Angola recovering optimism
New opportunities in Liberia and Côte d’Ivoire
Industry news and executives’ calendar
FPS for ultra deepwater
4
Subsea corrosion management: challenges and limitations Taking deepwater pipelines to the X-Stream
Analysis Emerging themes in the African oil & gas industry
Offshore communications: more, faster, better and cheaper?
10
Eastern and southern Africa start to tap into their vast gas potential, as intermediates in Nigeria work to develop large plays left behind by majors.
Oil & gas global salary guide
Rogério Manuel, president of the Confederationof the Economic Assocation of Mozambique (CTA). See page 10
25
REGULAR FEATURES: ■ News ■ Contracts ■ Events Calendar ■ IT update ■ Company profiles ■ Products & Innovations
Oil and gas professionals in Africa experience salary growth.
The Deepsea Stavanger (DDS) drilling rig with a support vessel in Angola.
Country Focus Angola
14
Angola’s oil sector is growing with continued efforts to explore the deepwater and subsalt potential.
Mozambique
18
Mozambique’s gas discoveries could double its GDP.
Liberia and Côte d’Ivoire
22
These two countries offer new opportunities for drillers but the discovery of oil brings with it huge development challenges.
Risk Management Has In Amenas demonstrated a ‘new face to risk’ in North Africa?
28
How threats are impacting on international companies living and operating in the region and how these threats might best be mitigated.
E&P News and developments
36
A round-up of recent exploration and production activity from around the region.
Technical Focus Deepwater and floating production systems
46
According to Infield Systems, ultra-deepwater production of both African oil and gas is either imminent or under way.
Subsea corrosion management: challenges and limitations
Editor’s note ANGOLA’S OIL SECTOR is growing, despite having to adapt both to the technological and production cost challenges in going inceasingly into deepwater and subsalt acreage, as well as to the need to find new markets for its shrinking crude exports to the US. Overall offshore West Africa continues to be prolific. Most of the region is at a relatively early stage of development but there is optimism that it will continue to yield new discoveries as it is explored. In Nigeria local and international investments that could advance its oil and gas sector are being held back by obvious regulatory uncertainties; nevertheless there are substantial opportunites that are waiting for clever management teams to develop. Over on the east coast, Mozambiques’s gas discoveries could double its GDP and also act as a catalyst for investment and development for its neighbours, in particular South Africa. Libya's oil sector has recovered relatively quickly from the effects of the 2011 revolution. The national oil company and major foreign firms have been able to bring production back to 1.4mn bpd. The production level is almost 90 per cent of production levels before the revolution started. Many attribute the relative success in this area to the fact that Libyans know that the country desperately needs income from the oil resources.
50
Some important challenges of deep sea corrosion management and the main countermeasures to address them.
Corrosion management through Cathodic Protection Taking deepwater pipelines to the X-treme
54 58
A new concept has been unveiled that could dramatically cut pipeline construction and installation costs.
Integrating borehole and surface seismic data
60
Permanently buried onshore and offshore seismic acquisition systems could considerably improve the value of seismic for reservoir monitoring.
Weld overlay cladding
66
Using weld overlay cladding to increase pipeline longevity.
Information Technology Offshore communications
70
The c hoice of communications services open to the oil and gas industry is growing and could soon accelerate.
58 The X-Stream concept was designed particularly with booming areas such as West Africa in mind.
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Oil Review Africa Issue Two 2013 3
Industry News & Events
S01 ORA 2 2013 Start_Layout 1 03/04/2013 12:10 Page 4
Executives Calendar 2013 APRIL 15-17 16-17 16-19 22-24 22-25 23-26 29-1 May
SPE NATC 2013 Globalcom Angola 2013 LNG 17 19th Western Africa Oil, Gas & Energy Week Oil & Gas Libya Conference & Exhibition Ghana Summit 2nd East Africa Oil & Gas Expo 2013
CAIRO LUANDA HOUSTON WINDHOEK TRIPOLI ACCRA NAIROBI
www.spe.org/events/natc/2013 www.iirangola.com www.lng17.org www.petro21.com www.oilandgaslibya.com www.cwcghana.com www.expogr.com
OTC Petro.t.ex Africa 2013 SA Industry & Technology AIOGACE UMEC-Ist Uganda, Mining, Energy & Oil & Gas Conference & Exhibition
HOUSTON JOHANNESBURG JOHANNESBURG LUANDA KAMPALA
www.otcnet.org www.exhibitionsafrica.com www.exhibitionsafrica.com www.aiogace.com www.umec-uganda.com
NOG Logistics
LAGOS LAGOS LAGOS MAPUTO MALABO LONDON JOHANNESBURG NAIROBI LUSAKA
www.nog-logistics.com www.cwcnogtech.com www.lagos-power.com www.eliteic.net www.cwceg.com www.platts.com www.ifsecsa.com www.petro21.com www.zimeczambia.com
JOHANNESBURG
www.offshoreafricasummit.com
Angola Recruitment Summit
LUANDA
www.eliteic.ne
Offshore Europe
ABERDEEN
www.offshore-europe.co.uk
MAY 6-9 14-16 14-16 21-23 28-30
JUNE 4-6 4-6
Nigeria Oil & Gas Technology Lagos Power Mozambique Recruitment Summit
11-12 12-14 13-14 18-20 18-20 18-20
EG Gas
Platts Crude Oil Summit IFSEC South Africa 4th Eastern Africa Oil, Gas & Energy Conference 2013 ZIMEC (3rd Annual Zambia Intl Mining & Energy Conference & Exhibition Offshore Africa Summit
19-20
JULY 6-7
SEPTEMBER 3-6
Readers should verify dates and location with sponsoring organisations, as this information is sometimes subject to change.
Perspectives from Offshore West Africa
EAPCE 2013 concludes on a high note
THE 17TH ANNUAL Offshore West Africa Conference & Exhibition took place in Accra 19-21 March 2013 with the support of the Business Council for Africa and other organisations. The event drew in operators and other investors right across the oil and gas value chain in the presence of senior officials from government as well as private sector heavyweights. Among the numerous topics discussed such as exploring the dynamics of West African Offshore Potential, Understanding the Jubilee Field and the Carbonate Play of the Gulf of Guinea, some of the keenest debate was on local content, described by Mr Akin Osuntoki from the consultancy Richardson Oil & Gas Ltd as: "The quantum of local value-added through the use of indigenous personnel, goods and services which does not compromise on quality". Typically, the oil industry is capital rather than labour intensive. Nevertheless, the scope for the participation of the local population across the oil and gas value chain through the provision of goods and services cannot be ignored. Osuntoki said that if Nigeria truly desires to become a leading economy by 2020 as per the Vision 2020 espoused by government, then more must be done to create jobs. But a lawyer with Ghana's regulatory body, the Petroleum Commission, was of the opinion that the emphasis should not be placed on government: "Government is there to provide the enabling environment" but considered that it's for the private sector to play a decisive role.
IT WAS A memorable round of discussions as hundreds of delegates from around the world gathered in the northern Tanzanian city of Arusha for a week-long petroleum conference. Dubbed the 6th East African Petroleum Conference, the meeting was in many ways an eye-opener. Key participants included captains of the petroleum industry, regional leaders, top government officials, leading geologists and other specialists within the sector. In his keynote address during the opening session, Tanzanian Prime Minister Mizengo Pinda said the East African region was at an exciting stage of economic growth and development following the recent discoveries of oil and gas in three countries, namely Tanzania, Uganda and Kenya. “The number of companies interested in carrying out petroleum prospecting has grown tremendously since 2003 and the region continues to license more,” he said. The discoveries made in the region include gas in Tanzania, oil in Uganda and the recent oil finds in Kenya. Uganda’s deputy Energy Minister Shem Bagene said the East African Community (EAC) was fast emerging as a new exciting frontier for gas and oil investment. The EAC is an inter-governmental grouping – modelled along the lines of the European Union - that brings together five countries in East Africa, namely Kenya, Uganda, Tanzania, Burundi and Rwanda. Discussions at the conference revolved around key topics, ranging from developments in the petroleum sector in East Africa, oil and gas exploration to environmental and social impacts.
4 Oil Review Africa Issue Two 2013
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S02 ORA 2 2013 News_Layout 1 03/04/2013 12:12 Page 5
International Recognition for Local Expertise Local Content | Regional Content | African Content
ALDUCO ENERGY LTD: TEL: TEL:
Web: Email:
ALDUCO ENGINEERING SERVICES: TEL:
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News
FMC subsea services agreement with Tullow Ghana FMC TECHNOLOGIES HAS signed a five-year agreement with Tullow Ghana Ltd to provide subsea services for its developments in the Jubilee field. Under the terms of the agreement, FMC Technologies will support Tullow Ghana's completions and production operations for the Jubilee field from its Subsea Service Base in Takoradi, Ghana. FMC Technologies will provide offshore and onshore technical services, including maintenance, refurbishment, and inspection on FMC Technologies supplied equipment and tooling. "FMC Technologies has supported Tullow Ghana's development of the Jubilee field for several years," said Tore Halvorsen, FMC Technologies' Senior Vice President, Subsea Technologies. "This agreement will provide life-of-field support for this important development."
3rd Upstream & Downstream expo to be held in Abuja MRS ALISON-MADUEKE, Nigeria’s oil minister was quoted as saying that, oil theft in the country has grown into a major economic problem, with the country recording a loss of over US$6bn a year. The managing director of Petroleum Products Marketing Company, Mr Haruna Momoh, was also reported to have said that Nigeria loses about US$1mn to pipeline vandals and other theft cases even as the Group Chief Executive, Oando, Wale Tinubu, added his voice to the issue of oil theft. He said, the industry loses an average of 50,000 barrels of crude oil every day to thieves and other criminal activities that sabotage oil and gas facilities; including petroleum products pipelines vandalism across Nigeria. Such highly organised cases has affected the economy of the country which derives more than 80 per cent of its revenue from the oil and gas industry, and these are undoubtedly, major issues bedeviling the Nigerian economy. According to a CNN report in 2011, the worldwide cost of fuel subsidies from oil amounted to US$90bn in 2010 alone. The findings stated that such a huge sum of money is mostly paid in developing oil producing countries, including Nigeria. In Nigeria, over US$8bn was spent to settle subsidy claims in 2011, and with the country’s population growing at over 2.5 per cent annually, the cost will continue to rise. The upstream sector has, however, maintained a production capacity of 2.4mn bopd, while gas
production has increased from 6.3bn scfd to 7.8bn per day. The 3rd Upstream and Downstream, Oil & Gas Exhibition and Conference 2013 will focus on the Petroleum Industry Bill again, together with the worrisome crude oil theft in Nigeria and the subsidy question in the country’s downstream sector. The Annual U&D Oil and Gas Expo, now running for the third year, is the first of its kind in the West African sub-region, geared towards creating an enabling environment for all industry key players to synergise on new technologies, policies and opportunities. This event which is now endorsed by OPEC, National Petroleum Investment Management Services (NAPIMS), Petroleum Technology Development Fund (PTDF), Nigerian Investment Promotion Commission (NIPC), and other major industry players and stakeholders will be held at the International Conference Centre in Abuja from 2426 September, 2013 and is expected to be declared open by President H.E Goodluck Jonathan. With the display of modern technology and equipment in this highly dynamic industry, this event will serve as the window for further development and growth of the market in the region, making U&D Expo the ideal place for concluding contracts, equipment delivery, as well as expansion of companies potentials. The conference segment will discuss a range of industry activities, cutting across wide operational, economic and regulatory brands with special sessions to brainstorm on challenges.
Wood Group bags $240mn in African deals UK-BASED ENGINEERING giant Wood Group said its businesses have been awarded 11 new contracts in five African nations over the last year, totalling about US$240mn. The group’s brownfield production services company Wood Group PSN has secured contracts in Equatorial Guinea, Chad and Algeria to provide operations and maintenance and construction services. Wood Group PSN managing director for Africa, James Crawford, said that the company was very clear about the countries and projects it targets. “We are committed to building a sustainable business in Africa,” he said in a statement. “These wins feed our ongoing growth strategy for the continent.” In addition, rotating equipment specialist Wood Group GTS has won a long-term deal covering two GE-frame 9E gas turbines for an operator in Ghana, while process and facilities engineering business Wood Group Mustang has agreed to provide detailed engineering for wellhead platforms, a production processing platform and a living quarters platform for an offshore Angola project. Wood Group Mustang executive vice president Michele McNichol said that the group remained committed to bringing economic value to African countries. “We are expanding our history of successful project delivery to support the development of energy resources in this key oil and gas region and in providing career opportunities for local personnel,” McNichol said.
Opportunities and risks facing Libya ASPIRATIONS TO CREATE a democratic government will inevitably have an impact on how business gets done in Libya. The pressure for modernisation is powerful and is likely to lead to a more accommodative and co-operative governance structure for the industry in Libya. The opportunities facing the country are still world class. While the risks are numerous, the new political context sets a positive environment and the emerging trends are pointing to the establishment of a much more modern business orientated oil industry in the country. This will take time to establish and patience will be needed. Since the election of a democratic General
6 Oil Review Africa Issue Two 2013
Libya’s main basins.
National Congress in July 2012, a clear timetable has been laid out to develop a new constitution
and national institutions. Whilst progress is being made, the many political tensions in the country and continuing difficult security situation have inevitably introduced delays. Recently a process for electing a constitutional assembly was announced. This assembly will be elected through a national vote. It is likely that the drafting of a new constitution will stretch into 2014. This will finally establish the governance framework of New Libya and the management of the oil and gas resource will be a major element. In the meantime existing oil and gas agreements will continue to operate; with any adjustments that are needed being made at an administrative level.
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Industry News & Events
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Mozambique: waiting for oil and gas to save the country FOLLOWING THE 2013 Mozambique Gas Summit in Maputo, the United Nations Development Programme (UNDP) published its annual country index, ranking Mozambique as the third worst nation in terms of human development. The country, which has experienced an annual average growth of just seven per cent in the last decade, was ranked above Niger and the DR Congo – two African countries locked in armed conflict. Now, all eyes are on the oil and gas industry to save Mozambique from the deep poverty plaguing its population. The Mozambique Gas Summit, which took place from 12-14 March 2013, centred on debates about the country’s natural resources and brought together more than 550 attendees from more than 300 companies across 55 countries in Africa, Europe, the Middle East, the Far East and the USA. The summit discussed how the Mozambique government is aiming to exploit the tens of trillions of cubic feet of natural gas located beneath the earth. The gas being explored in the Temane and Panda areas of Inhambane province currently contributes to 1.7 per cent of the country’s GDP, a figure the government hopes to increase to 13 per cent by 2018. Former Venezuelan minister of energy and mines Alirio Parra, who attended the summit, said this target is reachable but requires the government to be prepared. “What I would say is it’s important to understand the playing of the market and the competition you’ll face, and the impact of market volatility,” he stated. Galp Energia chairman Manuel Ferreira de Oliveira, who was also in attendance, added that Mozambique’s late entry in to the export market for liquefied natural gas (LNG) could result in the reduction of the resource’s value. The Rovuma Basin in northern Mozambique is one of the largest gas projects in the world, involving a number of multinational companies such as Portugal’s Galp, the USA’s Anadarko, Malaysia’s Petronas, Canada’s Artumas, Italy's ENI and Norway's Hydro Norsh, among many others. Ferreira de Oliveira said, “Mozambique has a key role in developing this vital manufacturing capacity for the supply of energy in the world... if Mozambique is late in development of projects it will be an encouragement to others who appear [since] the position of Mozambique is almost equidistant from the European market, South America and the Far East.”
A key issue discussed at the summit was how Mozambique’s small and medium enterprises (SMEs) could benefit from the boom in natural resources and the rise of multinationals operating within the country. At the 13th Conference of the Private Sector, which was held in Maputo the preceding week, Rogério Manuel, president of the Confederation of the Economic Association of Mozambique (CTA), called upon the state to adopt a law conferring exclusivity to local companies in supplying goods and services to the multinationals. The vast majority of economists have argued that the mega-projects are not currently benefitting the national economy. For example, within the mining industry, the majority of workers are foreign due to a lack of skills among Mozambique nationals. If SMEs were to provide goods and services to the multinationals, this would alleviate the situation to a certain degree. Manuel said, “We know we have no money, but we have resources, so we require an appropriate legal framework that can protect Mozambicans companies in the opportunities that are offered by mega-projects.” The second Mozambique Gas Summit is scheduled to take place from 1114 March 2014.
Borges Nhamirre
Aker awarded Moho Nord offshore Congo
Rig players set for African drilling feast
NORWEGIAN OILFIELD SERVICES firm Aker Solutions has won an US$850mn contract from Total to deliver a subsea production system for the Moho Nord project in the Republic of Congo. The project is located approximately 76 km off the coast of Congo and consists of two developments: Moho Nord and Moho Bilondo 1bis. Aker and Total will run both developments as a single, integrated project. Aker said the scope of the work included the delivery of 28 vertical subsea trees, including wellhead systems, two installation and workover control systems, seven manifold structures, subsea control and tie-in systems. The project will use Aker's new vertical tree technology, the firm added. Management, engineering and procurement will mainly be performed at Aker's headquarters in Fornebu, Norway. The subsea trees and worker systems will be manufactured at the Tranby manufacturing center outside Oslo, while the production of manifolds will be carried out at the firm's facility in Egersund, Norway, and Aker's Aberdeen facility will deliver the control systems and the wellheads. Alan Brunnen, head of Aker's subsea business area, commented in a statement: "This is a major contract award for Aker Solutions. We are investing and growing internationally and Aker Solutions is committed to developing the oil and gas industry in the Republic of the Congo through knowledge sharing and local content." Moho Nord and Moho Bilondo 1bis are part of the Moho-Bilondo oil field which was commissioned in April 2008 for commercial production. It is the first deepwater offshore field of the Republic of the Congo at water depths ranging between 305 and 914 metres.
THE POTENTIAL OF West Africa’s emerging pre-salt play and big gas discoveries off East Africa are set to drive an 18 per cent leap in annual drilling expenditure to more than US$17bn across the wider region over the next five years, according to a business intelligence firm. The forecast from New York-based GBI Research, up from drilling spending of US$13.56bn in 2012, is based on expectations of higher exploration activity across Africa and the Middle East. Rig contractors, particularly those like Seadrill and Ensco operating modern units designed for Africa’s deep-water plays, are set to cash in on the prospecting surge with GBI estimating cumulative drilling expenditure of US$77.3bn over the period from 2012 to 2016 – up 22 per cent on US$63.5bn from the previous five years. West Africa is leading the way as players such as Statoil and Total target regional pre-salt plays after being awarded acreage off Angola where seismic is being carried out to identify drilling targets. However, GBI believes Ghana will emerge as a new hotspot for oil and gas exploration in the region after seeing 16 offshore discoveries between 2008 and 2012 – including Tullow Oil’s landmark Jubilee find - compared with 22 off Angola during the same period. It also expects relative newcomers to offshore exploration such as Sierra Leone and Liberia to figure more prominently on the radar screens of oil companies as drilling activity escalates. Nonetheless, it is off Angola where the really big bucks are likely to be earned on dayrates for deep-water rigs, which are currently around the US$600,000 mark and expected to reach a record US$700,000 in the not too distant future.
8 Oil Review Africa Issue Two 2013
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Analysis
Eastern and southern Africa start to tap into their vast gas potential, as intermediates in Nigeria work to develop large plays left behind by majors.
Emerging themes in the African
oil & gas industry W
ITH MORE THAN 500 delegates in attendance from all of the major players and many of the junior explorers and service providers in the sub-Saharan African exploration and production sector, the Africa Oil Week 2012 provided a good overview of the state of the African oil and gas industry. The 19th Africa Oil Week was held in Cape Town, South Africa from 29 October to 2 November last year. Several major themes emerged from the conference.
Key regions in sub-Saharan Africa There is significant activity in many diverse geographic locations at the moment. The anchors of the sub-Saharan African upstream business are Nigeria, the rest of offshore West Africa and the emerging gas plays in Mozambique and Tanzania. In addition, offshore Namibia is seeing substantial activity, as is the Rift Basin that extends in Kenya. In Nigeria, a number of intermediates are working to develop large plays left behind by the majors, despite uncertainty around certain elements of the national petroleum law. For some, the story of Nigeria will continue to be chronic logistical issues for the majors and civil unrest, but there is an emerging group of players focused on repeating the “post-majors” era of development of assets in the US and Canada. Many of the conference participants felt that there are substantial opportunities that have been bypassed by the majors and that are waiting for clever management teams to develop. Oando Energy Resources (among others) is an independent company that recently obtained a TSXlisting and is focused on this strategy. Outside of Nigeria, the rest of offshore West Africa continues to be prolific. Many independents, large corporates and national oil companies are
10 Oil Review Africa Issue Two 2013
operating and investing in the region, exploiting existing plays and developing new areas. Overall, the region is at a relatively early stage of development. There was optimism that it will continue to yield new discoveries as it is explored.
Africa’s gas potential The emerging plays in Mozambique and Tanzania lead to a consideration of Africa’s potential as a gas producer. South Africa is seen as having exceptional shale gas potential. Some conference participants felt that the gas potential in the sub-Saharan region is as large as its current oil reserves and that this part of the energy complex will support substantial growth in Africa’s industrial sector, which lags growth in other emerging markets. In Nigeria, this demand is already manifesting itself in the form of increasing demand for gas used to generate power. On balance, it was felt that much of this frontier work lies in eastern Africa and in South Africa. Because of the scale of the resource and its early stage, there is a great opportunity to get this development right and establish a sound foundation for liquefied natural gas (LNG) export and domestic consumption, on the scale of what has happened in Qatar. Other participants pointed out that the chemical sector will play an important role in this growth of gas in eastern Africa. There are limits on the supply of methanol and other gas-derived chemical products internationally, and East Africa might service this demand.
Gas export On the demand side, resources in sub-Saharan Africa are expected to play a major role locally and in Asia and Europe.
Statoil to convert Zafarani high gas discovery into LNG.
The emerging plays in Mozambique and Tanzania lead to a consideration of Africa’s potential as a gas producer. India will need additional LNG supply in order to meet its internal demand. East African supply is expected to be priced competitively with Australia and Canadian supply, when it comes on stream. Europe struggles with a variety of problems. Fiscal crisis, nuclear shut-downs, limited unconventional growth and constraints on supply from the North Sea all mean that although gas demand is flat, there is expected to be a major shortfall in gas supply by 2040. Fortunately, Europe has access to a rich range of supply options and a flexible distribution system which will permit it to develop alternatives and avoid concentrating too much risk on one supplier. Some participants felt that North American supply would have no price advantage over African LNG in serving the European market. There was pessimism over the ability of European unconventional gas to compete at current gas pricing levels, leaving plenty of room for LNG to supply some of the shortfall.
Market conditions On the equity side, capital-raising has been steady but not euphoric. There continues to be reasonable demand for the equity of African intermediates in London. Despite the somewhat tepid fund-raising conditions, the equity of African-focused companies has outperformed the equity of players working in other international markets and this seems to support additional
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Analysis
additional development. Representatives of most of the other national authorities were in attendance. Independents are feeling competition from the majors in accessing assets. They are much more active than in prior years and good land is not as easy to get. Representatives of Statoil, CNOOC, Sinopec and ONGC all made presentations. They exhibited a range of strategies, largely geared to their current position in Africa. All of them acknowledge the importance of the region and its role in their future growth. Statoil, Sinopec (through Addax) and ONGC have substantial positions. There was optimism that offshore West Africa will continue to yield new discoveries as it is explored.
Getting the deal done capital-raises by high-quality independents. In the M&A market, most activity is focused on assets because the equity market continues to value corporates at less than the underlying value of the assets. Deal volume has returned to 2005 levels, but has not yet equalled the 2006 peak. Most of the juniors are well-funded and debtfree, with London and Australia serving as the preferred capital markets; with the Canadian market
Independents are feeling competition from the majors in accessing assets.
12 Oil Review Africa Issue Two 2013
getting significant exposure on the back of the success of Africa Oil and the listing of Oando Energy. The conference heard from a number of technically-focused teams who are working on very early-stage plays in onshore and offshore eastern Africa using capital from those regions.
State interest Governments were well represented at the conference. Emerging jurisdictions such as Comoros, Namibia and Somalia made presentations, and the national oil authorities of Senegal and Madagascar were represented as sponsors, all of whom are interested in fostering
There is substantial focus on the management of political risk and the development of ties to local communities. Many argued that capability in this area is as important as “under the groundâ€? skills and that it is not possible to be effective in the region without deal skills in this area, no matter how large or small the business. In some cases the smaller players might have a substantial advantage over very large entities in creating positive ties to the communities in which they work, overcoming some of the limitations inherent in working in jurisdictions where economic and political systems are underdeveloped and state institutions are more informal and fluid. â–
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Angola
Angola’s oil sector is growing, despite having to adapt both to the technological and production cost challenges inherent in going increasingly into deepwater and subsalt acreage, as well as to the need to find new markets for its shrinking crude exports to the US. Samuel Ciszuk reports.
Angola - recovering
optimism A
NGOLA IS EXPERIENCING something akin to a revival in its oil production fortunes, following a dip in its production capacity during 2009-2011. Investment is buoyant and stands in a particularly stark contrast to Nigeria, where companies seem to be shying away from project commitments due to legal and fiscal uncertainty, continued high levels of violence as well as the wider geographical challenges brought on West African producers by the US shale oil boom. While Nigeria’s oil sector finds itself floundering in search for direction, Angola’s is growing, despite having to adapt both to the technological and production cost challenges inherent in going increasingly into deepwater and subsalt acreage, as well as to the need to find new markets for its shrinking crude exports to the US. Despite the challenges faced by Angola’s postcivil war economy and political situation, the overall stability and ease with which companies can anticipate changes in its legal framework, particularly in the oil and gas sphere, at least relative to its regional neighbours, has benefitted the country. Projects are moving forward, with 2012 witnessing continued efforts to explore the deepwater and subsalt potential. Discoveries were made, with Cobalt International Energy and Maersk Oil both reporting large finds last year. In Cobalt’s case, the offshore discovery served to dispel some of the doubts in the industry about the company’s immediate technical capabilities. After the relatively unknown and untested company initially secured one of the most coveted offshore deepwater and subsalt acreage licenses in the Kwanza basin’s Block 20 in 2011, suspicions that the company had managed to upstage its much larger and more experienced major and supermajor peers due to political connections were making their rounds in the press. Naturally, for a young company, taking an initial complex discovery further towards development and ultimately full production means that challenges only will be scaled up in the foreseeable future, however at least the notion that the company lacked the skills necessary and mainly filled a financial function have been proved wrong so far. The suspicion about Cobalt’s award and questions about its potential partners on the block were more damaging to Angola’s overall standing than one could have been forgiven to expect in the aftermath of the 2011 licensing round. It raised fears that the Angolan business environment was deteriorating and that the award in itself could be a harbinger of rising corruption levels in a country
14 Oil Review Africa Issue Two 2013
Projects are moving forward, with 2012 witnessing continued efforts to explore the deepwater and subsalt potential.
suffering from endemic governance levels in the wake of decades of armed conflict. To be sure, the wider region has not lacked similar examples of extractive industries frameworks, which after an initial period of close guidance and protection from the government during a start-up phase, start falling victim to parasitic interests from competing political groups. Fears of a similarly radical deterioration in the business environment similar to those in Nigeria, or for instance the Democratic Republic of Congo, have however proved unfounded so far, with the government continuing its efforts to ringfence the oil and gas industry with some success. This does not mean that corruption is not a problem in Angola, however in the regional context its operating and fiscal frameworks for the oil and gas industry remain above average.
hand, China has stepped in to fill the void created by the changed US import patterns, providing Angola with an important market share in a market set to grow healthily over the long term. Its forays into East Asia are also serving as a good stepping stone for increased marketing to other South and East Asian growth markets, with Angola no longer being thought of as outside of the natural geographic remit of Asian importers, despite its Atlantic-basin location.
Standing-out for the right reasons
Changed marketing position
The difference to most of the other oil producers in the region is important, securing Angola much investment at a time of crucial and fundamental change in the global oil markets. The US shale oil boom has over recent years led to West African and North African crudes being backed out of the US crude import mix. The trend has chiefly damaged Nigerian marketing strategies, as the country’s output is dominated by light and sweet crude. This is much less so the case for Angola; however the overall switch in geographical import patterns has still damaged its US market share. On the other
This changed marketing position has obviously become possible through Angola’s reputation as a producer with remaining growth potential, while its growth potential at the same time also is being enhanced through its abilities in finding new markets of a high growth potential. The contrast to Nigeria, where the political and fiscal uncertainty is exacerbating the marketing problems, is stark. Angolan crudes are of course in general more suited to the current tastes of Asian refiners, however its perceived predictability and stability as a producer is also benefitting its investor attractiveness.
In the regional context, Angola’s operating and fiscal frameworks for the oil and gas industry remain above average.
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Angola
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Repsol’s blocks and commitments in Angola.
Firm expectations Growth in Angola is set to continue through 2013 and 2014, albeit at a somewhat slower pace than previously hoped. Plans to reach a two million bpd output in the second half of 2013 have been delayed, amid significant underlying mature decline and a project phase which has not been able to live up to initial plans. The schedule slippage was confirmed by Oil Minister Jose de Vasconcelos in comments to Reuters in December 2012, saying that “to achieve two million bpd, we need to work more and more”, adding that he did not believe achieving that level in 2013 was realistic. Rather, Reuters reported, he saw Angola producing between 1.80-1.85mn bpd in 2013. In 2012 growth mainly came through the startup of production from the first phase of ExxonMobil’s Kizomba D satellite field, bringing a 140,000 bpd plateau production level gradually onstream, as well as from the continued ramp-up at Total’s 220,000 bpd Pazflor project. Both those projects will continue to add to 2013 growth, alongside the BP-led PSVM project, developing the Plutao, Saturno, Venus and Marte oilfields. PSVM
commenced production in January 2013, however only from three production wells at the Plutao field. Plutao is on its own expected to reach a production plateau of 70,000 bpd in the late parts of the year, with the remainder of the fields gradually lifting the overall PSVM output towards a 150,000 bpd plateau sometime during 2014. BP holds a 26.67 per cent operating stake in the Block 31 project, with ExxonMobil and Statoil partnering on 25 per cent and 13.33 per cent respectively. Angola’s NOC Sonangol controls 20 per cent while Marathon holds 10 per cent and the China Sonangol International joint venture holds the remaining five per cent. Thanks to combined growth from the three mentioned projects, all in their ramp-up phases, Angolan production should very comfortably reach the 1.85mn bpd level as soon as by mid-year, however with scheduled maintenance and a realistic view on the country’s underlying demand, as well as unscheduled downtimes at upstream facilities, Vasconcelo’s estimate of the average 2013 production remains a realistic assessment, shy of unnecessary optimism. Looking further ahead, growth seems assured, with Total’s Clov field complex in Block 17 and Eni’s West Hub project in Block 15/06 being slated for 2014 start-ups, bringing a capacity of around 150,000 bpd and 90,000 bpd respectively onstream. The West Hub development has slipped into the second half of the year, but with the first four-well drilling campaign nearing completion and the second campaign (taking the number to 10 production wells and six injection wells) seemingly on schedule for later this year, delays seem to have been reined in. Eni also seems confident of further growth at the block, planning to issue an FID for the 80,000 bpd East Hub project before the end of this year. By 2015 the second phase of Exxon’s Kizomba Satellites project should start to come onstream, as
well as Chevron’s Lianzi project, in waters shared by Angola and Congo (Brazzaville). Meanwhile Eni is also mulling how to proceed with the Lira gas discovery in Block 15/06. It is however not the only player looking to firm-up FIDs this or next year, with Total targeting a decision on Block 32’s Kaombo Split Hub and Chevron hoping to issue FID for its Block 14 Lucapa field before end-2014. The US supermajor took a decision to move forward with the second phase of its Mafumeira Sud project in early February, adding to the existing Mafumeira Norte development and taking total production at the two fields to around 110,000 bpd by 2015. Denmark’s Maersk is also looking to come to a definitive investment decision before 2015 on its Chissonga project on Block 16. The imminent start-up of the US$9bn Angola LNG project should also not escape a mention, catapulting Angola to the position of gas exporter with a capacity of 5.2 mmtpa of LNG. The successful launch of a first LNG facility could encourage other companies with existing or future deepwater gas discoveries to develop them, although given the weakness of Atlantic Basin gas demand and the planned rapid increase of LNG production in Australia - and later Mozambique - targeting the Pacific Basin is somewhat clouding the investor outlook for this sector in the years ahead. However, Angola will get to the markets way before the Australian projects bear fruit and before ground is even broken in East Africa. As we have seen over just the last decade, the trading field continues to evolve and adapt to circumstances as they present themselves. With around 100 significant oil discoveries having been made in Angola’s deepwater plays so far and less than 40 producing or having been committed to development, there is a proven scope for growth in Angola, even without the planned exploration spending for its sub-salt potential uncovering any further reserves. No surprise then that the Angolan government is seizing the moment amid the market optimism to launch a new 15block licensing round later this year, focusing largely on some of the less sought-after onshore acreage. ■
Siemens in Angola GERMANY'S SIEMENS, ONE of the world's leading engineering conglomerates, re-established offices in Angola in 2005 after an absence of many years. Siemens Angola had sales US$13.7mn in 2011, but its order book, worth US$20.6mn, pointed to growth. Current Siemens activity in Angola includes power generation and water pumping systems, notably for the offshore oil industry where Sonangol, Chevron and Total are clients. Siemens installed eight gas turbines to power Angola LNG's Soyo plant and has supplied an 11.5MW generator for Luanda's refinery. Siemens has become heavily involved in supporting education and training in Angola. "For Siemens, training engineers and managers is a core preoccupation in Angola and a contribution the company can make to the country. Siemens trains engineers and clients in the area of energy distribution, instrumentation and maintenance of turbines and electronic equipment, and to this end its ATEC training academy in Portugal has signed a co-operation agreement with Angola's
16 Oil Review Africa Issue Two 2013
Integrated Centre for Technological Training (Cinfotec). Siemens also recently made an agreement with Angola's Higher Polytechnic for Technology and Science (ISPTEC) for co-operation in developing human resources, projects and technologies in engineering, economics and management. Looking ahead Siemens is already highly involved in Brazil's pre-salt oil deposits development, an area in which Angola is currently taking its first tentative steps. Chemtech, Siemens' Brazilian specialist engineering subsidiary, has a leading role in contracts for engineering equipment employed in exploiting Brazil's pre-salt deposits. The company's training and experience in Brazil will enable Angola to prepare to meet the technological challenges of exploiting its own pre-salt oil. In order to facilitate this transfer of know-how, Siemens offers work experience for Angolan engineers who want to attend the Siemens corporate academy in Brazil to improve their engineering skills and project management. www.oilreviewafrica.com
S05 ORA 2 2013 Mozambique_Layout 1 03/04/2013 12:18 Page 17
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Mozambique
Nicholas Newman looks at the impact that gas e&p is having and will have on Mozambique and the surrounding region such as South Africa.
Mozambique gas discoveries could
double its GDP F
OLLOWING A NUMBER of huge natural gas discoveries off the coast of Mozambique, Tanzania and Kenya, East Africa is experiencing a “gas rush” in which Mozambique is, potentially, the greatest beneficiary. Mozambique is on the cusp of a long economic boom driven by the recent discoveries of vast deposits of coal and natural gas which have stimulated economic growth rates to 7.5 per cent during 2012, according to African Economic Outlook. Despite this recent impressive growth, Mozambique remains one of the poorest African states, with a per capita GDP of US$1,100, contrasting with neighbouring South Africa, whose GDP per capita is almost ten times greater. In the last two years major energy companies, most notably Eni and the independent US-based Anadarko Petroleum Corporation (APC), have been joined by Mitsui & Co Ltd, Bharat Petro Resources Ltd, Videocon Hydrocarbon Holdings Ltd, and PTT Exploration & Production, thus transforming Maputo, Mozambique’s capital, from a sleepy colonial era town into a modern metropolis worthy of the influx of multinationals and their money. “As a result, hotel prices are escalating” said Simon Ashby Rudd, Global Head of Oil and Gas, of South Africa’s Standard Bank. Last year, four of the five largest oil and gas discoveries in the world were made off Mozambique, reported Wood Mackenzie Energy Consultants. These recent finds are located in Mozambique’s northern waters of the Rovuma Basin which adjoin the frontier province of Cabo Delgado with Tanzania. The lead operators, Italy’s super major Eni and Anadarko, the second largest US independent oil and gas producer, have completed over 20 successful offshore wells. As a result of their discoveries, Anadarko Petroleum Corporation spokesperson John Christiansen has said “…we have found in Offshore Area 1, approaching 100 trillion cubic feet (tcf) of total gas with recoverable resources of between 35 and 65 tcf”. In the neighbouring Mamba Complex Area of the Rovuma Basin, Eni, the operating company, has confirmed reserves of some 75 tcf of gas, with 27 tcf exclusively located in Area 4. These finds confirm the status of the deep-water Rovuma basin as a world class natural gas province and are a most welcome addition to the country’s existing three onshore gas fields, Pande, Temane and BuziDivinhe, which between them have total reserves of nearly four tcf. If recent discoveries of gas are confirmed, Mozambique will rank fourth in the world for natural gas reserves behind Russia, Iran
18 Oil Review Africa Issue Two 2013
Last year, four of the five largest oil and gas discoveries in the world were made off Mozambique.
The recent discoveries made by both Eni and Anadarko Petroleum Corporation are simply world class. and Qatar. The size of gas discoveries on Africa’s East coast, together with very favourable geological conditions and potentially low production costs make Mozambique an attractive new source of supply to Asian and European markets whilst, at the same time, threatening the existing investment requirements of Australian mega-gas projects.
The discoveries “The recent discoveries made by both Eni and Anadarko Petroleum Corporation are simply world class,“ said Simon Ashby Rudd, who added: “they are in terms of size, quantum in scale, with gas fields stretching over 16 km in width and nearly 305 m thick”. Finding the gas has been relatively easy: developing, producing and marketing it will prove much more difficult. Investors in Mozambique’s natural gas reserves face at least two major challenges: firstly, the priority of raising sufficient capital - at least US$30bn - for the substantial requisite investment in LNG exports
plants; secondly, the difficulty of accessing sufficiently substantial markets. The domestic market, with a population of just over 23mn citizens, 70 per cent of which is engaged in agriculture, and with widespread poverty (some 54 per cent of the population surviving on less than a dollar a day, according to CIA World Fact-book), has little demand for natural gas. The nearest major market for natural gas is South Africa, accessible by either a land or sea route, both of which are expensive. Option one entails building a 1600-kmlong pipeline dedicated to South Africa; option two requires investment in LNG export plants and the delivery of gas via LNG tanker to South Africa. Martin Kelly, Lead Analyst Sub-Saharan Africa, Wood Mackenzie, suggested that “the prospects for building such a pipe line are unviable due to the costly logistics of building such a project. Instead, investors favour the construction of a network of LNG export terminals as the solution for delivering gas to the Asian Pacific region”. A final decision by ENI and Anadarko Petroleum Corporation to build the world’s second largest LNG plant comprising two five-milliontonne-per annum liquefaction trains costing some US$30bn in the Palma area of Cabo Delgado province is awaited. To this end Eni and Anadarko will not only unite their neighbouring gas fields but will bring in additional partners to share the cost
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Mozambique
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and to provide gas processing expertise. “The project faces a tight deadline, needing to complete project financing by 2014 and building the project in just five years,” said Simon Ashby Rudd. With exports of LNG slated for 2018, Goldman Sachs forecasts Mozambique gas exports reaching 21bn cubic meters a year by 2022.
Conceptual design of natural gas liquefaction facility.
Impact on economy The anticipated economic impact of investment in Mozambique’s gas will be felt directly and indirectly in Mozambique and by its neighbours. For example, the LNG export plants are expected to act as a focus for a cluster of new ventures. “Once the two LNG trains at Cabo Delgado come on-line in 2018, there will be more than sufficient excess capacity to meet additional needs such as fuel for power generation, feed stocks for petrochemicals, methanol, gas to liquids and urea for fertilisers,” said Simon Ashby Rudd. Simon expects a major industrial hub to be based in Cabo Delgado. As for jobs, John Christiansen stated: “currently Anadarko employs about a thousand Mozambicans, and this number could easily grow to ten thousand during the construction phase. In addition there will be countless ancillary job opportunities.” The construction of new cheap power generating capacity is likely to be welcomed in a region where demand for power exceeds existing generating capacity in both Mozambique and surrounding states who are members of the South African Power Pool. “The availability of cheap power will allow mechanisation of agriculture and improve irrigation systems, which should help turn Mozambique into a bread basket for the region,” suggested Simon Ashby Rudd. Whilst the new industrial zone will create many desperately needed jobs that will help lift many of the population out of poverty. “The revenues from natural gas development can help Mozambique build new infrastructure, create jobs, enhance education and training opportunities, and attract additional investment in the country,” said Mozambique’s President Armando Guebuza, and Godinho Alves, Deputy Director of State-run Investment Promotion Centre, anticipates that expectations of economic development arising from investment in natural gas and increased revenues will support planned investment in roads, railways and port facilities as well as development projects designed to turn Mozambique into a transit point
for goods and services to neighbouring landlocked Zambia, Zimbabwe and Malawi.
Impact on South Africa South Africa is Mozambique’s largest trading partner. The Northern Mozambique gas discoveries appear to be acting as a catalyst for investment and development. “Gas should be a major help in solving the region’s power problems, “says Tony van Velzen, of Wärtsilä Netherlands BV, a major power turbine manufacturer. South Africa is already benefiting from Mozambique’s gas supplies, via a direct pipeline link, facilitating an increase of natural gas as a percentage of primary energy usage from 1.5 per cent in 2004 to 4.3 per cent today. In addition, South Africa’s power consumers are benefiting from newer, cleaner power stations using Mozambique gas. There is the 107 MW Ressano Garcia Mozambique power-plant that exports 92 MW to South Africa. This site is to be expanded to meet growing power needs from across the border. Moreover, in South Africa, Sasol, an integrated energy and petrochemical company has opened two new power plants using Mozambique gas to improve security of power supplies, reduce its operating costs and carbon footprint. Such an investment is not surprising, given that the market for electricity supplies remains tight, according to reports from South Africa’s main power utility Eskom in October 2012. To benefit from Mozambique’s latest Northern gas discoveries, authorisation has been given for the construction of South Africa’s first LNG import terminal at Mossel Bay in Western Cape Province.
The anticipated economic impact of investment in Mozambique’s gas will be felt directly and indirectly in Mozambique and by its neighbours. Such a development will encourage the construction of a national main-line gas transmission grid, which, in turn, will enable the South African economy to reduce its dependency on coal for 77 per cent for its primary energy needs, 62 per cent of power generation requirements and 23 per cent of petrochemical feed stocks according to the South African Yearbook 2012. “Though, such supplies are likely to just augment existing imports from Mozambique, “suggested Martin Kelly, Wood Mackenzie. What will be of more interest to South Africa will be the results of gas exploration led by SASOL in the waters of Southern Mozambique, which are much more easily accessible to South African markets. The prospects and promise of the huge natural gas discoveries in Northern Mozambique have yet to be translated into reality. To expedite development, Mozambique is reviewing its petroleum, mining and gas policy, laws and governance and encouraging infrastructure investment. It remains to be seen whether it has the governance capacity to handle the pre requisite large scale investment to turn the dream into reality. ■
CNPC buys 20% of Area 4
Eni adds another 4 tcf to Coral gas find
ITALY'S ENI HAS agreed to sell a 20 per cent stake in Area 4 off Mozambique to China National Petroleum Corporation (CNPC) for US$4.21bn. CNPC acquired the stake by buying 28.57 per cent of the shares of Eni East Africa, which owns 70 per cent of Area 4. The other partners at the block are Empresa Nacional de Hidrocarbonetos de Mocambique (ENH), Korea’s Kogas and Portugal’s Galp Energia, all on 10 per cent.
ENI HAS SAID its latest delineation probe at Coral off Mozambique has added at least four trillion cubic feet of in-place gas to the Area 4 giant. The Coral discovery is now estimated to contain more than 13 tcf of gas in place, wholly located in Area 4, the Italian explorer said. Coral 3, the eighth well on Area 4, was drilled around 65 km off the Cabo Delgado coast about five kilometres south of Coral 1. Sunk to a total depth of 5270 m in water depths of 2035 m, it hit 117 m of gas pay in a high-quality Eocene reservoir. "The well proves the existence of hydraulic communication with the same reservoir of Coral 1 and 2 and confirms the giant size of the Coral discovery that is now estimated to contain 13 tcf plus of gas in place wholly located in Area 4," Eni said in a statement. "Coral wells deliverabilities showed during the production tests are excellent and each well is expected to deliver very high flow rates in production configuration.".
20 Oil Review Africa Issue Two 2013
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Liberia and Côte d’Ivoire
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Liberia and the Côte d’Ivoire offer new opportunities for drillers but the discovery of oil brings with it huge development challenges for this impoverished region.
Atlantic frontier
opens up W
EST AFRICA’S OFFSHORE industry just keeps on getting bigger. First there was OPEC member Nigeria, Africa’s biggest oil exporter, and a host of other traditional producers, the likes of Gabon, Cameroon and Congo. Then, as technology developed, and as Africa’s deepwater areas opened up, Angola emerged as the place to be. Interest around the Gulf of Guinea then pushed Equatorial Guinea to the fore, rising to the ranks of sub-Saharan Africa’s third biggest producer within a few short years. Then, when big oil was discovered offshore Ghana in 2007, the rest of West Africa got understandably excited. It’s early days in these so-called Equatorial Atlantic frontier areas but there are signs that this too could be an area ready to yield its oil and gas secrets. There have already been discoveries in Liberia and Sierra Leone, and in another of the region’s bigger economies, the Côte d’Ivoire. Here, it appears a new oil story is about to unfold following two big finds in recent months. In December, Russia’s LUKoil and the US’ Vanco (recently renamed Van Dyke) said they had found light oil on Côte d’Ivoire's offshore block CI-401, just six months after the UK’s Tullow Oil struck light oil on block CI-103. Tullow pioneered Ghana’s offshore industry with the Jubilee development, which came onstream in 2010.
Ivorian hopes For the Côte d’Ivoire, these are exciting times indeed. Like the rest of the so-called Atlantic margin region, the country has enjoyed a higher profile since Ghana shot to prominence. In fact, officials are already adding up how much of an impact these new offshore oil and gas discoveries could have on the nation’s economy. Ibrahima Diaby, head of hydrocarbons at the Ministry of Mines, Petroleum and Energy, said at the start of this year the country could be producing 200,000 barrels per day (bpd) within five years, from about 32,000 bpd now. "With these discoveries and projected investments, Côte d’Ivoire will be able to realise its target of raising output from around 32,000 bpd now to around 200,000 bpd in the five years ahead," Diaby told Reuters in an interview. LUKoil, Vanco (Van Dyke) and Tullow are all planning further drilling this year and 2014 to firm up their reserves.
22 Oil Review Africa Issue Two 2013
Côte d’Ivoire will be able to realise its target of raising output from around 32,000 bpd now to around 200,000 bpd in the five years ahead.
Tullow’s deepwater Paon-1X discovery, announced last June, found good quality light oil in 31 metres of net oil pay. The well, drilled to a depth of 5,090 m, in water depths of 2,193 m, was suspended for possible future use. Tullow operates the CI-103 licence and is partnered by the US’ Anadarko Petroleum and the Société Nationale d'Opérations Pétrolières de Côte D'Ivoire (Petroci). The first well to be drilled in the block, it has given the company great hopes for future drilling, extending a proven oil play westwards from Tullow’s successes in Ghana. The company, which has average current output in the Côte d’Ivoire of 3,400 barrels of oil equivalent per day (boepd), plans to drill the Calao prospect next, during the second quarter of 2013. It is also planning exploration work this year in Mauritania, further up the coast, and has signed up to explore in Guinea, reflecting its growing interest in this exciting sub-region.
More to come LUKoil and the Vanco (Van Dyke) are also planning to step up drilling work after their December find which struck light oil in offshore block CI-401 with the Independance-1X well. The well – drilled in 1,689 m of water, at a site 93 km south-southeast of the capital, Abidjan penetrated eight metres of hydrocarbon pay. The Independance-1X is the second well to be drilled in CI-401, which covers 619 sq km, in water depths ranging from 950 to 2,100 m.
Here [in the Côte d’Ivoire], it appears a new oil story is about to unfold following two big finds in recent months. Drilling is in progress on another deepwater exploration well in the block, the Albacore-1X, located 33 km to the east of Independance-1X. But it has not all been plain sailing for the Côte d’Ivoire’s oil and gas sector. Production has fallen by nearly half due to technical problems and low levels of investment during a decade of political turmoil that culminated in a 2011 civil war. During the war, some operators were forced to declare force majeure. The hope now is that oil will underpin, rather than undermine, future stability. The world's top cocoa grower, the Côte d’Ivoire is desperate to diversify its economy, in part by boosting its energy and mining sectors. More oil investment now seems likely with 14 production sharing contracts signed since the end of the war, according to Diaby, at the Ministry of Mines, Petroleum and Energy. The search for gas is also on the agenda with the government last year signing three exclusive deals for natural gas fields, including two with locally-based Foxtrot and another with Rialto Energy. Diaby says gas production could rise to 250 million cubic feet per day from about 170 mmcfd currently.
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In re-positioning the company for greater services, we recently acquired Fire Fighting Trucks, Emergency Medical Response Ambulances and other notable training equipment for efficient and professional service delivery. 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
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Liberia and Côte d’Ivoire
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FMC is supplying six subsea trees, eight wellheads, three manifolds, and a subsea control system to the Baobab Field.
Liberia also hopes to enjoy the benefits of this heightened investor interest. Liberia rising Next door, neighbour Liberia also hopes to enjoy the benefits of this heightened investor interest, after recording its own early discovery success stories although the scale of these lags behind those in the Côte d’Ivoire. Key players such as Chevron, Anadarko, and African
24 Oil Review Africa Issue Two 2013
Petroleum have rights to offshore blocks already. None have identified commercial reserves as yet, though African Petroleum said last year it had struck a "potentially large" reservoir on its Block 9, where it is pursuing further exploration. Tullow Oil, which found hydrocarbons in noncommercial quantities with the Montserrado-1 exploration well offshore Liberia, has also announced finds along the coast in Sierra Leone. And, once again, foreign investors are voting with their feet. In March, officials said the government was close to signing off a deal with US super-major ExxonMobil - the world's largest private sector oil
company - and its partner Canadian Overseas Petroleum Limited to develop offshore oil block 13. The deal - replacing a little-known UK energy firm Peppercoast Petroleum - would be a huge boost for Liberia’s nascent oil sector. However, like other emerging economies in this impoverished corner of Africa, the success of the energy industry will bring with it significant development challenges. One of the world's poorest and least developed countries, Liberia’s infrastructure is still in tatters after more than a decade of on-off civil war, which finally ended in 2003. A flood of foreign investment would no doubt help it rebuild, but it carries with it risks too, notably Africa’s infamous oil curse. This is where oil receipts have failed to spark genuine development only to be siphoned off instead but by a corrupt elite. President Ellen Johnson-Sirleaf is determined for that not to happen, and is keen to overhaul the nation’s petroleum policy to bolster transparency. Indeed, Liberia’s Extractive Industries Transparency Initiative (EITI) is currently auditing more than US$8bn worth of oil, mining, and agriculture contracts amid mounting pressure on Sirleaf to clean up the natural resources sector. The discovery of oil - and the investment it brings - will only intensify this challenge. ■
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Oil and gas professionals in Africa experience salary growth.
Analysis
Oil & gas global
salary guide 2013 T
HE SALARIES OF oil and gas industry professionals working in Africa have increased on average over the last 12 months, according to the Oil & Gas Global Salary Guide 2013. Published by recruiters Hays and Oil and Gas Job Search and based on figures obtained from more than 25,000 industry professionals, the report reveals the average worldwide salary in the industry to be US$87,300 per annum. The figure represents an increase of 8.5 per cent on the previous year. According to the guide, Nigeria comes out top on the continent in terms of local salary growth, with a 12 per cent increase over the past year, while Angola comes second with an 11 per cent growth. The guide suggests that if the price of oil remains above US$80 per barrel, salaries should rise further this year, albeit at the more modest rate of between four and six per cent.
Downstream and production roles take centre stage Following the economic downturn in 2008, projects put in to development in 2009 are now embarking on their operational phases, leading to a surge in recruitment over the past year in both downstream operations and upstream production management. This is indicated by the fact that the average salary has reached US$59,300 for an operator/technician in the downstream operations sector, while the average salary for the same role as listed in Oil & Gas Global Salary Guide 2012 was US$38,700. Meanwhile, operator/technician roles in upstream production management now have an average salary of US$68,300, while the 2012 guide reported an average salary of US$51,300. The report says, “Conversely, the disciplines associated with exploration were somewhat flat after sizeable rises in 2012, although high levels of production ensured it was a busy year in drilling.” The industry also experienced a large increase in graduate salaries, which are up by 12 per cent at an average of just under US$40,000. In terms of company type, equipment manufacturers and suppliers are reported to have seen salaries increase by 16.7 per cent on average, despite previously being labelled as ‘underachievers’. Service contractors, which have also been similarly labelled in the past, have experienced an 11 per cent growth in salaries. Duncan Freer, managing director of Oil and Gas Job Search, said, “Employer confidence in
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If the price of oil remains above US$80 per barrel, salaries should rise further this year.
Nigeria comes out top on the continent in terms of local salary growth, with a 12 per cent increase over the past year, while Angola comes second with an 11 per cent growth. increasing staffing levels during 2013 remains high. A quarter expects staffing levels to increase by more than 10 per cent, with almost 75 per cent anticipating some level of increase.”
Industry benefits According to the report, the rise in bonuses and benefits continues to be the dominant mechanism by which companies attract and retain talented employees, with this trend increasing across Africa. Matt Underhill, managing director of Hays Oil & Gas, said, “In addition to the rapid growth in salaries, the Salary Guide reveals that a rise in bonuses has continued and is now the dominant mechanism by which companies attract and retain talent.” The guide claims that the number of employees receiving bonuses has increased, with 42.8 per cent
of participants worldwide receiving some form of bonus – a 7.8 per cent growth from 2011. Underhill added, “On average, bonuses account for a further 5.8 per cent of the employees’ overall package with almost twothirds receiving some kind of benefit or allowance on top of their basic salary.” The report shows that 37 per cent of employees in Africa receive a bonus, an increase of four per cent on 2012’s figures and a higher percentage than those seen in Australasia, Europe and the Commonwealth of Independent States. Although the region does deliver relatively high levels of benefits across most categories, the base salaries in Africa are generally much lower than elsewhere, meaning it is imperative for companies to offer some form of benefit to retain employees. For example, although South Africa’s local employees receive the highest average salary on the continent of US$75,300, this falls far short of the global average of US$87,300.
Employment levels “Despite the concerns in Europe and a slowdown in China’s growth, the sentiment in the oil and gas industry remains positive. Current employees and new entrants to the industry can look forward to working in a dynamic and highly rewarding sector,” Underhill stated.
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Analysis
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In contrast to last year’s data, which indicated a rise in companies employing permanent staff, this year’s research shows that companies have experienced a moderate decline in confidence, opting to employ a more flexible workforce. For example, global super majors have increased their level of contractors by 7.5 per cent compared to 2012, with permanent contracts down by 6.9 per cent. Meanwhile, the number of oil and gas professionals working abroad has increased, with an average of 47.4 per cent now working abroad in contrast to last year’s 42.6 per cent. This growth can be attributed to the high volume of project work and the lack of home grown talent available, the research suggests. The trend is becoming increasingly prevalent in Africa, with the imported workforce standing at 35.6 per cent, contrasting with last year’s figure of 28.8 per cent. According to the research, expatriate workers in Nigeria are the highest paid in the continent and
the 11th highest paid in the world, earning on average US$140,800. Meanwhile, following the large influx of new and experienced employees in 2012, this year the industry presents a more stable market. Whereas the 2012 guide found that 36.3 per cent of employees had zero to four years’ experience in the oil and gas industry, this year the figure dropped to 28.3 per cent, creating a more even spread across the four categories. The guide says, “Tenure edged up slightly from last year’s figures, reflecting a less volatile market but one which continued to drive hiring.” This is seen in the fact that 24.6 per cent of respondents said they had been in their job for less than one year, only a slight reduction on 2012’s figure of 26 per cent.
Looking ahead “Skill shortages are now by far the major concern for employers in the industry,” the guide says. In response to a survey regarding their
concerns in the current employment market, 37.3 per cent of employers said they were concerned about skills shortages, suggesting it is still a candidate-led market. Employers’ confidence in the current employment market has however stayed at roughly the same level as 2011, with 26 per cent of respondents saying they were ‘Extremely positive’ about the market and 47.8 per cent saying they were ‘Positive’. The report suggests this optimism is due to a high oil price driven by growing energy demand, which in turn is providing operators with plenty of revenue to spend on development. On the other hand, this is balanced by concern surrounding China’s growth and the possibility of Europe triggering a ‘meltdown’. “It would, however, not take much to push the markets either way, so it is with some interest that we enter 2013. Whether or not the current positive feeling turns to trepidation we will have to wait and see,” the guide concludes. ■
Global oil & gas workforce survey results support oil company boss’s safety concerns WARNINGS THAT OIL industry safety standards are being jeopardised by a shortage of experienced staff are supported by a report published in March. 32 per cent of respondents to the latest joint report from OilCareers.com, the international jobs board for the oil and gas industry, and partner Air Energi, a global provider of manpower solutions to the energy sector, highlighted the on-going skills shortage as the biggest threat to the sector. The lack of skilled trainers was identified as a major training issue by over 20 per cent. The report confirms that heightened safety concerns due to economic instability combined with a continuing strong oil price and the on-going skills shortage, particularly in the LNG and subsea sectors, will continue to push oil related salaries upwards. The African oil and gas industry is facing increased security challenges. The four day siege at an Algerian gas plant, the recent seizure of an oil tanker off Côte d’Ivoire's main city of Abidjan and the pirate attack on offshore supply tug Armada Tuah in Nigerian waters, which saw six crew members taken hostage, highlight the heightened security concerns associated with working in Africa. It is not surprising that 69.6 per cent expect contract and salary pay rates to increase. The Global Oil & Gas Workforce Survey: Expectations for hires and pay rates in the oil and gas industry (H1) 2013 highlights that ensuring the right personnel are on the ground in the right place will present a continuing challenge for the worldwide oil and gas industry. The survey requested
26 Oil Review Africa Issue Two 2013
information and opinions from more than 170,000 oil and gas professionals worldwide. Africa is one of seven major oil and gas producing regions represented in the survey with respondents being drawn from over 50 countries. More than 15,500 were either direct recruiters or senior decision makers.
The challenge of new frontiers being opened up to explore discoveries in countries is, to some extent, being overshadowed by security concerns. Employee packages are seeing a general upward trend with specific emphasis being seen in areas that are considered to be high risk. Mark Guest, managing director of OilCareers.com, said: “The recent tragic events in Algeria have served to further underline existing safety concerns throughout the oil and gas industry. It has long been the case that positions in certain geographic areas attract a higher level of remuneration to reflect the safety issues associated with the work location. Companies working in these locations take the security of their personnel very seriously and work to protect them and ensure their working environment is as safe as possible.” Mark continued, “The 2013 H1 survey and predictions for H2 confirm these safety inflation pressures are being reflected throughout the industry. In addition it should
be noted that without the right personnel in place to train the next generation the skills shortage is likely to continue and to become a bigger problem.” Ian Langley, group executive chairman of Air Energi, added: “Just over 34 per cent of those responding to the survey perceived economic instability as being the biggest threat to today’s oil and gas industry. The skills shortage was a very close second; 32 per cent view this as being a major challenge to overcome. In particular the shortage of subsea and LNG personnel is being felt throughout the industry and has a knock on effect in terms of project costs and delays.” The challenge of new frontiers being opened up to explore discoveries in countries including Mozambique, Congo and Gabon is, to some extent, being overshadowed by security concerns as highlighted by events in other African nations including Algeria and Nigeria. For the oil and gas industry to continue to expand these concerns will need to be overcome as well as potential civil, regulatory, technical and environmental challenges. Angolan projects are continuing apace. Angola is now considered to be in direct competition with Brazil and the North Sea for the top expertise necessary to access their natural reserves. The Nigerian Petroleum Industry Bill (PIB) should be passed this year. This complex legislation will result in the Nigerian government receiving increased levels of royalties, but those operating the area have warned that the significant uplift may make the area unviable. www.oilreviewafrica.com
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Risk Management
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Ed Butler from Salamanca Group discusses how threats are impacting on international companies and westerners living and operating in the region and discusses how these threats might best be mitigated.
Has In Amenas demonstrated a ‘new face to risk’
in North Africa? T
HE JANUARY 2013 attack by Islamist militants on the In Amenas gas facility in Algeria has caused a flurry of security sector activity in North Africa as international oil companies (‘IOCs’) reassess their security arrangements and host governments scramble to demonstrate their operational capabilities so as not to jeopardise future investment. In Algeria, Libya and Tunisia, government action has focussed on deploying further troop numbers to guard facilities and shore up border security. However, whilst these can be seen as welcome steps in a woefully under-resourced region, they are only part of the answer for IOCs seeking to mitigate Above Ground Risks (AGR) and protect their personnel, investments and reputation. In Amenas happened under the jurisdiction of the country with the largest military budget in continental Africa and one previously widely-credited with recognised counter-terrorism expertise. In the aftermath of In Amenas, a focus on hard security solutions risks a narrow definition of security which may limit IOCs’ capability to mitigate risk in North Africa, and across the continent as a whole, when a more intelligence-driven approach might be more constructive. Furthermore, In Amenas was a spectacular transnational threat; however experience shows that 90 per cent of the threats to IOCs’ operations in Africa derive from grievances held by local communities. A rush to mitigate short-term transnational risks through additional hard security, particularly in complex political environments, can antagonise local interests and ultimately create further insecurity for IOCs over the long-term if not guided by a comprehensive understanding of local dynamics.
Valuable lessons for IOCs Nevertheless, In Amenas provides a number of valuable lessons for IOCs operating in North Africa and the wider MENA region.
Understand state security structures In many North African jurisdictions, the bulk of hard security is likely to be provided by the state, and provision of private solutions may be frowned upon or illegal. State forces vary in their composition, capabilities and character, and Engineers surveying Algerian gas facility.
28 Oil Review Africa Issue Two 2013
Engineers conducting perimeter checks in Algeria.
Monitoring these dynamics is likely to become even more pertinent as IOCs look to mitigate risk across North Africa. each of these needs to be understood in order for an IOC to build an effective relationship and assess its likely interaction with these structures. In the case of Algeria, years of aggressively-targeted counter-terrorist operations against militant Islamist groups had bred a doctrine where the need to project power and deter future terrorist actions was undertaken at the expense of protecting hostages’ lives. Conversely, Libya presents a separate challenge where the state security apparatus is trying to reconcile its own limited capabilities with emergent, powerful revolutionary militias. Watchtower overlooking facility perimeter in Algeria.
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Risk Management
Perimeter security at a seismic camp in Algeria.
Engineers surveying an Algerian gas facility.
Engagement of state security structures is likely to be most beneficial when it is done with an appreciation of the capabilities, composition, character and leadership of those structures. In this respect, tools such as stakeholder/influence-mapping, ‘personality briefs’ and discrete due diligence can be used by IOCs to better understand those that are entrusted with the security of their facilities, and to build constructive relationships and capabilities for crisis management situations.
Analyse local political, commercial, tribal and security dynamics Although borders cross the Sahel region, dividing responsibility for securing it between a number of states, in reality it is a largely ungoverned space in which security is often negotiated rather than enforced. The Sahel is home to longstanding commercial and social trading networks in both licit and illicit goods, including weapons, cigarettes, Moroccan cannabis resin and cocaine. These symbiotic relationships are allowed to continue to function in part because local government officials have traded non-interference for a stable security situation. It has long been suspected that certain officials have cemented this arrangement by becoming involved in the trade themselves. Understanding this local dynamic of negotiated, rather than enforced security, is key to appreciating the potential vulnerability of In Amenas to a group prepared to break this negotiated state of affairs, despite the presence of the Algerian army. Monitoring these dynamics is likely to become even more pertinent as IOCs Approach to well site in Algeria.
look to mitigate risk across North Africa. In comparison to the majority of operational threats faced by IOCs in North Africa, In Amenas remains exceptional due to its transnational nature and the relative isolation of the facility, permitting a harder security response than may be tolerated elsewhere. Across much of the remainder of North Africa, IOCs now need to analyse risk through a far more complex political and security prism, dominated by the effects of the Arab Spring. This is likely to require a far more nuanced appreciation of local threat environments due to new interest groups competing for influence in fluid political environments, the fragility of state structures and grievances still to be settled post-revolution.
Monitor transnational threats Although the local threat environment is more likely to affect an IOC’s strategic business objectives over the long term, In Amenas has reaffirmed the need to monitor developing transnational threats. In hindsight, it is possible to see that the internal dynamics of Al Qaida in the Islamic Maghreb (AQIM) may have been a key motivation behind the In Amenas attack with Mokhtar Belmokhtar’s split from the group precipitating an attack to establish his credibility in the Sahel. Discussion of the Algerian decision to allow French warplanes to use Algerian airspace to attack militant Islamists in Northern Mali in connection with In Amenas also shows a welcome awareness of transnational risk. Although, the likely planning time required for In Amenas, coupled with the fact that Algeria has long been a target of AQIM due to its anti-Islamist policies, suggests that the true motivations lie elsewhere.
Planning for crisis to deliver security Whether operating in In Amenas, Ghadames, Western Egypt or examining new ventures, IOCs are aware that they do not operate in a vacuum but as part of complex local political, tribal, commercial and security dynamics. Since the Arab Spring, identifying and managing operational risk has become more complex. Crises now happen more quickly, requiring IOCs to have intelligenceled and agile security and crisis management plans. IOCs need to plan for volatility both at the geo-political level and at the local level. Therefore, successful crisis management and security plans need to be developed from a comprehensive understanding of the totality of the threats facing an IOC, underpinned by extensive due diligence, influence mapping and political risk reporting to ensure that the appropriate opinion formers and decision makers are approached and their motives understood. Local community engagement and CSR programmes remain an integral part of delivering ‘soft security’ solutions. Increasing the amount and quality of local content in the overall operation of an O&G facility will further co-opt local communities into protecting it, by providing the eyes and ears for early warning and locallydelivered defence. If local communities feel that they have a genuine stake in an O&G asset, then they will provide the best form of protection; ultimately, it is improving their wealth and long term welfare. While there may be a ‘new face to risk’ in North Africa and wider, this does not mean that the dangers of operating there have outweighed the gains. The more that everyone in a business understands the local and regional tapestry of the area they are operating in, the more likely that crises will be prevented, people and reputations protected and business continuity ensured. Crises now happen more quickly, requiring IOCs to have intelligence-led and agile security and crisis management plans. ■
30 Oil Review Africa Issue Two 2013
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INTERPRETATION OF THE preliminary gravity map of the Odewayne block is highly encouraging as it confirmed the presence of large rift-basin structures, which typically form structural prospects, within the Odewayne basin. Two additional basins have also been identified within the license area. There is also the presence of numerous verified oil/condensate seeps. Jacka says that the potentially attractive structures and the genetic relationship to the multi-billion barrel basins of Yemen result in a highly prospective play in this emerging petroleum province. The Odewayne block is surrounded by projects with multi-billion barrel potential, adding to its prospectivity. The JV (with Genel Energy and Petrosama) is preparing for the next phase of the exploration programme, acquisition of approximately 1,500 km of high quality 2D seismic data in what will be the first seismic survey within the Odewayne basin. The first seismic survey is scheduled and mobilisation for the survey should launch in April with the acquisition to start in May. The seismic survey may be extended beyond 1,500 km if necessary, to ensure multiple prospect grids are acquired. With the benefit of a dedicated seismic processing centre currently being established in-country, seismic processing can be accelerated to allow for early definition of prospects and identification of areas requiring additional acquisition while the recording crew is still in-country.
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Surveys in the news TGS HAS COMMENCED an extension to the offshore Angola 3D multi-client survey. The extension, covering 4,064 sq km over blocks 36 and 37, will add to the original 12,500-sq km survey. The seismic data is being acquired by the M/V Geco Eagle. Data processing will be performed by TGS and preliminary data will be available to clients from Q4 2013. Dolphin Geophysical has a letter of intent for 2 ½ months of 3D work off northwest Africa for an undisclosed client. The survey will be acquired by the Artemis Arctic, in direct continuation of the current project. Aminex is planning a 1,200-km 2D seismic programme over the deepwater area of the Nyuni block offshore Tanzania and at the time of going to press was in discussions with seismic vessel contractors to perform the survey during Q1 2013. Earlier this year, Aminex compiled 141 km of seismic data as part of a transition zone programme over the shallow waters, reefs, and islands of the Nyuni Area PSA. Also in Tanzania, Antrim Energy has updated the status of a potential exploration campaign over the PembaZanzibar exploration license offshore and onshore Tanzania, operated by RAK Gas. Seismic operations are expected to proceed soon. Seismic work in the waters of Lake Tanganyika is being organised, but with a different twist from the typical offshore survey. GAC UK and GACSeaforth have delivered a consignment of cargo for a seismic survey in the lake where Surestream Petroleum is the operator. GAC UK helped ship 60 tonnes of cargo to the seismic operations base on the lakeshore. After assessing the various delivery options, the main consignment was sent in containers by sea from Ipswich, UK, to Dar-Es-Salaam, Tanzania. Here GACSeaforth took over transportation of the cargo by road to Bujumbura, with selected items sent by air direct to the final destination.
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Geology
Jacka moves toward seismic in Somaliland
Geology
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CAMAC seals survey deal for Kenya blocks CAMAC ENERGY HAS signed an agreement with Sander Geophysics Limited (SGL) to shoot airborne gravity and magnetic geophysical surveys on its Kenya onshore Lamu Basin Blocks L1B and L16. The data acquisition will cover the entire 12,197 sq km in Block L1B and the entire 3,613 sq km in Block L16, exceeding the first exploration period's gravity and magnetic survey requirements for each block. The results of the airborne gravity and magnetic survey will be used to optimise the placement of 2-D seismic lines by identifying faults, basement structures and intrasedimentary volcanic layers and/or intrusions. Airborne gravity and magnetic data combined with 2-D seismic has been utilised to identify successful exploration targets in East African Rift Basins by regional operators Heritage, Tullow and Africa Oil. The company expects SGL to commence data acquisition in the second quarter of 2013 and provide initial results in the third quarter of 2013. Founded in 1956, the Ottawabased SGL provides worldwide airborne geophysical surveys for petroleum and mineral exploration, and geological and environmental mapping. SGL has operated on every continent including Antarctica, and under diverse conditions ranging from the tropics, deserts, mountains and offshore. "Executing this agreement with SGL is an important milestone for our Kenya exploration programme," said senior vice president of Exploration and Production Segun Omidele. "These gravity and magnetic surveys will satisfy the first requirement of the first exploration period, and most importantly, will allow us to delineate an optimal 2-D seismic programme on the blocks. This is the first step to unlocking the high potential value of our onshore Kenya acreage."
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Tangiers firms up Tarfaya potential A 3D SEISMIC survey has firmed up the potential of the Trident prospect on the Tarfaya Block off the coast of Morocco. Australia’s Tangiers Petroleum announced that the seismic data confirmed the Trident prospect and secondary objectives at Assaka and TMA potentially contained up to 750mn barrels of recoverable oil with a geological chance of success of 23 per cent. Tangiers had previously stated that it estimated the Trident prospect to hold a gross prospective resource of 450mn barrels. The Australian company recently struck a farm-out agreement with Galp Energia which will see the Portuguese player pick up a 50 per cent operated stake in the Tarfaya Block. Galp will spend US$41mn, including US$7.5mn in back costs, and fund an exploration well targeting
the Titan prospect and the secondary Assaka and TMA targets in exchange for the Tarfaya stake. “The Trident prospect alone is a potential company-maker and we have already identified several other Jurassic prospects in the block,” Tangiers executive chairman Eve Howell said. “With Galp carrying the cost of the first well, Tangiers has a significant exposure to this upside while also being free to pursue our strategy of acquiring other growth assets in Africa.” Following the completion of the farm-out, which is still subject to regulatory approvals, Galp will hold a 50 per cent operated interest, Tangiers will hold 25 per cent and Morocco’s Office National des Hydrocarbures et des Mines will continue to hold the remaining 25 per cent equity.
BP plans record supercomputer expansion AS THE SEISMIC data files get larger and interpretation and presentation demand more computing power, oilfield companies are moving to stay ahead of the technology. BP, for instance, says its geoscience computing needs are 10,000 times greater now than in 1999. In its latest effort, BP is building a new supercomputing complex in Houston that it says will house the largest commercial research computer in the world to date. The new High-Performance Computing (HPC) centre, scheduled to open mid-2013, will be a worldwide hub for processing and managing those huge amounts of geologic and seismic data. The new three-story, 10,220-sq m facility will be equipped with more than 67,000 CPUs and is expected to have the ability to process data at a rate of up to two petaflops. It will boast total memory of 536 terabytes and disk space of 23.5 petabytes.
Dolphin, Shell to rewrite seismic record books DOLPHIN GEOPHYSICAL REALLY needed to 'think big' for its recent 3D seismic survey with super-major Shell in the Orange Basin, South Africa. A huge survey area and limited timeframe led the Norwegian firm to adopt a radical approach to get the job done - it created, and successfully operated, the 'world's largest floating object'. Dolphin, working with Shell for the first time, won the task of surveying an 8,000 sq km deepwater basin, lying between 150 and 250 km off the western coastline of South Africa, in July 2012. The potential in this under-explored sector, with evidence of source rocks suggesting possibilities of significant oil and gas deposits, is huge... but so are the challenges in realising it. The weather is key. Bad weather, and there's no shortage of that locally, can create serious safety issues for seismic vessels and equipment. In addition, surface (wave) disturbances disrupt the operation of vessel streamers and impact upon data quality, creating unwanted noise. Dolphin's team therefore had a limited weather window of four months to operate in. They decided that, in this particular case, size matters.
In October 2012 the Polar Duchess mobilised with a configuration of seismic equipment that had never been seen before. The firm created the 'world's largest floating object' - eight streamers measuring eight km in length and separated by a distance of 200m, constituting a moving width of 1.4 km of equipment through the water. As such the total area of the apparatus being towed by the Duchess was 11.2 sq km. Prior to this point the largest surface area of streamer equipment that had been utilised was between eight and nine square kilometres. Phil Suter, Dolphin's VP marketing and sales, explained the thinking behind the bold move: "In order to get 8,000 km covered in the limited weather window we needed as wide a tow as possible. If we'd attempted this with a standard streamer configuration, of say 100 m separation, it is unlikely that we would have got anywhere near the number of square kilometres covered in the same time frame." The immense power of the Polar Duchess meant that, unlike the huge majority of seismic vessels, it could tackle the challenges of successfully navigating this heavy, wide-tow configuration through the water. www.oilreviewafrica.com
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Gas
BG, Statoil, ExxonMobil further boost East African Gas resources BG GROUP HAS completed an appraisal programme that further confirmed the natural gas resource and production potential offshore Tanzania, underscoring East Africa's importance as one of the energy industry's hottest new regions. Separately, Statoil ASA and partner ExxonMobil Corp have announced their third discovery in Block 2 offshore Tanzania. The mounting volume of gas discoveries off the coast of East Africa has stimulated a wave of interest in the region, culminating in China National Petroleum Corp's US$4.21bn acquisition of 20 per cent of Eni SpA's giant Mozambique offshore natural gas field. Anadarko Petroleum Corp has also attracted interest from several companies including ExxonMobil, Royal Dutch Shell,
India's state-run Oil & Natural Gas Corp and Oil India Ltd with the offer of a share of its natural gas discoveries offshore Mozambique. BG Group said testing on its Jodari-1 field offshore Tanzania showed better-than-expected reservoir properties, demonstrating that wells could produce at higher rates. BG Group holds a 60 per cent interest in the discoveries offshore Tanzania, with Ophir Energy holding 40 per cent. "The test results confirm the Jodari reservoir's world-class quality; and the potential for the field to underpin the LNG development," said Nick Cooper, chief executive of Ophir Energy Plc. Cooper was referring to a liquefied natural gas terminal that could be part of gas development in Tanzania. BG Group is in the process of selecting a site for an onshore LNG terminal. The capacity
of the terminal will be determined by further exploration and appraisal results across the company's three offshore blocks. BG estimates the total resource in Tanzania at nearly 10 tcf. Statoil said its latest Tanzania find brings recoverable gas volumes now discovered in the country to between 10 and 13 tcf. "[This] brings further robustness to a future decision on a potential LNG project", said Statoil's executive vice president for exploration, Tim Dodson. Statoil has a 65 per cent stake in the discoveries, with ExxonMobil holding the remaining 35 per cent. Eni and Anadarko have also said they are studying plans to build a LNG plant in Mozambique. Analysts say the region is wellplaced to serve growing energy demand in Asian markets.
WAGPO to resume gas supply THE WEST AFRICAN Gas Pipeline Company (WAGPCO) has declared 30 April 2013 as a tentative date for resuming its supply of gas from Nigeria. The WAGP has been working on its pipeline in Lomé, Togo, which supplies gas to Ghana, after a vessel damaged it last year. According to WAGP, it has completed two stages of work and was currently awaiting the final test to resume full operation for supplying gas to plants in Ghana. The first and second stages, termed as replacement and joint testing of the pipeline for integrity, have been completed. The final exercise, termed as ‘Drying the Line’, will see WAGP use hot air to dry the pipeline for free flow of gas through it. WAGP general manager in charge of corporate affairs Harriet WerekoBrobbey said her outfit had done what was technically known as ‘leak text’ on the two joint damaged pipelines at a different pressure level. Wereko-Brobbey revealed that divers had to swim 50 metres down to conduct the pressure test. The divers also went with a special equipment to take photographs of the leak text, which she described as a successful attempt.
The next exercise, according to Harriet Wereko-Brobbey, was for the WAGP to do what was technically known as ‘PIGING’. This is where it would launch special equipment together with the use of nitrogen to flush out the water and other debris left in the damaged gas pipeline.
Can Africa do it? DREWRY MARITIME RESEARCH’S latest LNG Shipping Insight report saw the LNG ShortTerm Freight Index remain unchanged at January’s level. This was largely because increased heating demand across the Northern Hemisphere, particularly in Asia, was balanced by an adequate supply of tonnage. This supply looks set to continue to increase. Gas discoveries in and around Africa indicate that the continent could emerge as the fourth major supply base for LNG, after the Middle East, Australia and the US, according to Drewry Maritime Research. If all the projects that are currently being pursued come on stream on schedule, Africa could leave Qatar behind in terms of nameplate capacity and LNG production by the end of the decade. Front-End Engineering & Design (FEED) for the
34 Oil Review Africa Issue Two 2013
first LNG terminal in Mozambique was awarded to a joint venture between Fluor Corporation and JGC Corporation by Anadarko Moçambique in January 2013. Initially, the FEED will deliver 20mn tonnes per annum of LNG, with the potential to expand its capacity to 50 mtpa of LNG in the future. Asian markets are aggressively pursuing longterm LNG contracts. Firms from Japan, South Korea, India and Thailand hold the majority stakes in the feed gas licences in Mozambique and are likely to buy most of the cargoes. However almost all the existing and emerging suppliers in Africa have faced problems. Commissioning of Angola LNG is now delayed by more than a year; Egypt has been facing FEED-gas supply problems, Olokola LNG hasn’t moved in a while and
Nigeria LNG declared force majeure on spot cargoes recently (though it has resumed operations). Algerian plans to attract investments in the energy sector were also jolted by the terrorist attacks on the ln Amenas gas facility. Hopes for the much-needed supply boost rest on Mozambique. If everything falls into place for Mozambique, it could become the most sought-after source for LNG buyers around the world. The Drewry LNG Freight Index is freight rate assessments based on actual deals and market reports for a conventional LNG carrier of 160,000-173,000 cbm and less than five years of age. Hire period for long-term freight rate assessments are for charter durations of 15 years or more. www.oilreviewafrica.com
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WEST AFRICA-FOCUSED Victoria Oil & Gas is now fully funded to meet its long-term corporate objective and to commercialise its Logbaba gas discovery in Cameroon after raising approximately US$36mn with institutional investors. Victoria said the funds, along with a US$15mn lending facility, will be used to fund the build-out phase of Logbaba project as the company increases production and sales. The company believes that having found substantial gas, established a market and completed an initial pipeline to that market, the optimal use of its capital is to complete the second phase of its pipeline, purchase power generation units and pay off existing financial and trade debts. At the end of January the company reported that it had 15 contracted customers taking gas at rates of 2.8mn scfd and that there remain a further 10 contracted customers awaiting conversion of their facilities to take gas. The firm has also identified more than 60 prospects for gas and/or on-site gas-fired power demand along existing and planned pipeline routes. Victoria chairman Kevin Foo commented in a statement: "The last three years have been extremely challenging but we have become the first onshore gas producing company in Cameroon. We have made a significant gas discovery and in this period we have delivered gas to a hungry market. Our gas and condensate field lies in the heart of a city of three million people that is the industrial hub of Central Africa, with a rapidly increasing demand for energy and power."
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Nigeria targets 2bcf of gas for power by 2015 NIGERIA IS TO boost its power generation with two billion cubic feet of gas per day by 2015, Nigerian National Petroleum Corporation, NNPC, group managing director Andrew Yakubu has said. Yakubu disclosed this at the Offshore West Africa Oil and Gas conference in Accra, Ghana, where he also disclosed that the country’s oil and gas production had been on the decline due to crude oil theft and severe flooding in the Niger Delta. Represented by the group general manager of Corporate Audit, Isa Inuwa, Yakubu said future growth in power generation would continue to be gasbased as the nation aspires to attain a 40MW generation capacity by 2020. But, he said that NNPC was more concerned about boosting the country’s crude oil and gas production capacity. He said: “Government’s focus on gas development and ensuring its availability for power generation is based on the firm belief that the spinoff effects of a reliable power supply would provide a solid base for industrialisation, leading to the provision of employment opportunity and attracting the much needed investment in the country. “Government plans to build a Central Processing Facility (CPF) in Rivers State from which would come wet gas from wells, which would be processed into dry gas and natural gas”. This, Yakubu said, involves the setting up of a world-class petrochemical plant with the capacity to produce 1.3mn tonnes of polyethylene and 400,000 tonnes of polyethylene yearly. The NNPC boss stated that the government was envisaging that from this plant, myriad secondary industries would be developed.
Oil Review Africa Issue Two 2013 35
Gas
Victorial now fully funded to develop Cameroon field
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FAR gets more space off Kenya AUSTRALIAN EXPLORER FAR has been awarded additional acreage off the coast of Kenya, increasing its existing L6 exploration permit by 60 per cent. The company said that this additional area, which had previously been relinquished and is now re-instated, increased the total Offshore Kenya: a map showing the previous and new L6 permit areas and permit area to 5010 sq km. leads and prospects. The dotted black The new acreage has been line is the block’s previous boundary. estimated to hold prospective resources of 773mn barrels of oil or, in a gas-only success case, 2141 bcf of gas. This brings the prospective resources estimate for the total L6 area up to 3.96bn barrels or 10.69 tcf. In addition, FAR said its recently acquired 3D seismic data and earlier 2D data on the L6 permit had identified a new play type, the Miocene carbonate reef play, which appeared to extend into the newly awarded acreage. The company holds a 60 per cent interest in Block L6, as well as a 30 per cent stake in the nearby Ophir Energy-operated Block L9. Both permits lie in the offshore Lamu basin and are located north of the recent Mbawa discovery made last year by US independent Apache Energy. FAR is planning to select the location for its first exploration well on L6 after the fully processed 3D data is received next month. It has also started a farm-in initiative to find a partner to fund and potentially operate this well.
36 Oil Review Africa Issue Two 2013
Senegal farm-out spearheads offshore well in early 2014 FAR LTD HAS announced a farm in agreement for its three blocks offshore Senegal in West Africa to Cairn Energy Plc. Pursuant to the farm in agreement, which is subject to Senegalese Government approval, Cairn will operate and carry FAR through an exploration well expected to be drilled in early 2014. Under the terms of the farm in agreement Cairn is to acquire a 65 per cent working interest and operatorship by fully funding 100 per cent of the costs of an exploration well and testing to an investment cap of US$80mn. As part of the farm-in agreement, Cairn will pay FAR US$9.8mn for past costs incurred on the block. FAR’s three contiguous Senegalese blocks "Rufisque, Sangomar and Sangomar Deep" have significant exploration potential. The blocks cover an area of approximately 7,490 sq km within the productive MauritaniaSenegal-Guinea-Bissau Basin. From 2,050 sq km of modern 3D seismic data acquired in the blocks, FAR has identified a number of play types and has mapped 11 potentially drillable prospects as well as numerous other leads, many supported by associated seismic amplitude responses. In combination, the Senegal blocks have prospective resources of 3.585bn barrels of oil. After the carried well, exploration costs will be apportioned Cairn 72.2 per cent and FAR 27.8 per cent. Petrosen (the Senegal National Oil Company) will continue to hold a carried 10 per cent WI through the exploration phase in accordance with the Production Sharing Contract. In addition, FAR and Cairn will enter into an Area of Mutual Interest agreement to work together to evaluate and consider applying jointly for exploration opportunities offshore Senegal.
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African Petroleum to drill offshore Gambia
LUkoil to resume drilling in Ghana
AFRICAN PETROLEUM EXPECTS to start drilling the Alhamdullilah prospect offshore Gambia later this year. The company has a 60 per cent interest in Gambian blocks A1 and A4, which cover a total area of 2,668 sq km. The remaining 40 per cent is held by Buried Hill via a farm-in agreement. In December 2010, the acquisition of 2,500 sq km of 3D seismic data over the blocks was completed. From the processed data, more than 30 exploration prospects and leads were identified, including five different play types. The four-way dip closed Alhamdullilah extends more than 24 sq km, with five mapped reservoirs and a gross thickness of 1,000 m . ERC Equipoise estimates prospective recoverable resources at 500 mmbbl. Following detailed mapping that focused on a series of stacked submarine fan complexes, a well location (AH-1) has been agreed and well planning is under way. The well will be drilled to a TD of 6,300 m in 2,300 m of water, targeting multiple reservoirs within the structural closure. Drilling is expected to start during the second half of 2013, subject to confirmation of a farm-in partner.
UUSSIAN OIL MAJOR Lukoil plans to resume drilling off the coast of Ghana in November. LUkoil Overseas, LUkoil's operator of its international upstream projects, has acquired the rights to become the operator of the offshore exploration projects CI-101 and CI-401 in C么te d'Ivoire and Cape Three Points Deep Water (CTPDW) in Ghana from the Vanco group. All three exploration blocks are compactly located on the deepwater continental slope in the Gulf of Guinea. LUkoil Overseas acquired a 56.66 per cent stake in these projects in July 2006. Since then, three deepwater exploration wells have been drilled at the CTPDW block (Dzata and Cheetah structures), hitting deposits with non commercial hydrocarbon reserves. Vanco has a 28.34 per rcent stake in the project, and the Ghanaian state company GNPC 15 per cent. The CTPDW block is on the Gulf of Guinea shelf 50 km to 100 km offshore. The closest port is Takoradi. The block is 5,142 sq km in area in waters from 200 m to 3,000 m deep. GNPC has the right to increase its stake by five per cent when commercial development begins. In 2010-2011, at the CTPDW Dzata and Cheetah structures, three deepwater prospecting wells were drilled, opening an oil and gas condensate deposit and confirming the presence of tight sand of high quality, but commercial amounts of hydrocarbons were not found. In order to be profitable, production on the Ghanaian shelf has to have reserves of some 150-200mn barrels of oil. LUkoil views Africa as a promising region for oil production. But after drilling four wells in C么te d'Ivoire and three in Ghana, the company decided to take a time-out to evaluate the data obtained. An updated geological model and programme for further work at CTPDW is being put together now. Last year, Ghana satisfied LUkoil's application for an extension of the timeframe for carrying out the offshore project for one year - until June 30, 2013.
38 Oil Review Africa Issue Two 2013
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Jacka awarded new Tanzania PSA and onshore. The terms of the PSA include an initial exploration period of four years, with work to be undertaken including the acquisition of airborne gravity and magnetics, the acquisition of a minimum 400 km of seismic and one exploration well. Jacka’s Chairman, Scott Spencer, commented, "It was a great pleasure to attend the ceremony and sign the PSA with the Government of Tanzania for exploration in the Ruhuhu Basin. "East Africa has become a global oil and gas exploration hotspot and Jacka is pleased to be involved in one of the world’s most prospective exploration provinces. "Tanzania is an area that our very experienced and successful, African-focused board and management have long identified as being of significant interest and we are excited to have been awarded this quality exploration opportunity. We are greatly appreciative of the support of the Minister and the TPDC at a significant time in Tanzania’s oil and gas journey. We look forward to working with the Tanzanian authorities and TPDC to unlock the Ruhuhu Basin’s full potential over coming months and years.”
HRT gets going in Namibia BRAZILIAN INDEPENDENT HRT Oil & Gas has kicked off its drilling campaign at an exploration play off southern Africa. The company has spudded the Wingat-1 well on production licence 23 in the Walvis basin offshore Namibia.
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The well, also called 2212A/07, is being drilled with the semi-submersible Transocean Marianas and is expected to take 60 days to reach total depth of around 4,100 metres. The main objective of the well is to test the resource potential of the Albian-aged
carbonate platform which it is expected to intersect at about 3,950 m. This is the first in a series of wells HRT will drill on its 10 operated blocks in Namibia. Portugal’s Galp Energia is taking a 14 per cent interest in the first three wells to be drilled.
Oil Review Africa Issue Two 2013 39
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JACKA RESOURCES LTD has confirmed it has been formally awarded a 100 per cent interest in a Production Sharing Agreement (PSA) for the onshore Ruhuhu Block in south-west Tanzania. The PSA for the 10,343 sq km Block was signed at a ceremony in Dar es Salaam by the Minister for Energy and Minerals, the Hon. Professor Sospeter Muhongo, the Managing Director of the Tanzania Petroleum Development Corporation, Mr Yona Killagane and Jacka representatives – led by Chairman, Mr Scott Spencer. This PSA award comes after a period of review of oil and gas licence terms by the Tanzanian Government following major discoveries of gas offshore. Tanzania is underexplored but is fast becoming an international oil and gas exploration hot spot. The country has grabbed petroleum industry headlines over the past 12 to 18 months following the announcement of several sizeable gas discoveries in the offshore. It is now attracting the attention of industry leaders, with companies such as Shell, Statoil, Total, Petrobras, ExxonMobil and Tullow entering the country to explore both offshore
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Equatorial Guinea to offer Nigerians oil blocks THE EQUATORIAL GUINEA government has indicated its readiness to award oil blocks to willing Nigerian investors interested in playing in its oil and gas sector. This is the outcome of President Goodluck Jonathan’s recent two-day official visit to the oilrich country. Speaking at a joint press conference with President Jonathan in Malabo, President Obiang Nguema Mbasogo said Equitorial Guinea was interested in tapping from the vast experience of Nigerians in the business to develop his country’s oil and gas sector. “Nigeria has been in the oil and gas business for the past 40 to 50 years whereas Equatorial Guinea’s situation started just recently and the experience that you have is far larger than ours. “That is why we place our trust and confidence in our Nigerian brothers to help and assist us to develop the sector.”
Statoil secures rig for Angola exploration STATOIL HAS SECURED the Stena Carron (UDW drillship) vessel for a three-year contract that will see the rig use for exploration drilling in two pre-salt blocks in the Kwanza Basin, offshore Angola. The contract, managed by Stena Drilling, has an estimated value of US$700mn. Statoil has also secured two one-year extensions. In Angola, Statoil will test the pre-salt potential of the Kwanza blocks by drilling wells in blocks 38 and 39. Statoil said that it has also allocated the Discoverer Americas (UDW drillship) to East Africa to perform exploration drilling in Statoiloperated blocks in Tanzania and Mozambique. There, the firm plans to drill three-to-four wells that will test for further potential in Block 2, Tanzania and explore blocks 2 and 5 in Mozambique. Statoil Executive VP for Exploration Tim Dodson commented in a statement: "Statoil has now secured rig capacity for its planned global exploration programme in 2013 and 2014. We have drilled four successful wells in Tanzania over the last year, and are now committed to drilling additional wells in Tanzania as well as in Mozambique and Angola. "Together with a three-well campaign in the Gulf of Mexico, three Statoil-operated wells in Canada, and a one-year drilling campaign in the Barents Sea, this demonstrates an ambitious exploration programme."
40 Oil Review Africa Issue Two 2013
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The Baker Hughes Rig Count tracks industry-wide 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.
February 2013 - OIL & GAS THIS MONTH Country ALGERIA ANGOLA CONGO GABON KENYA LIBYA NIGERIA SOUTH AFRICA TUNISIA OTHER Total
Oil 26 9 6 5 0 16 13 0 2 13 83
Gas 15 0 0 0 0 0 5 0 0 0 21
Misc 1 0 0 0 1 0 0 0 0 1 17
LAST MONTH Oil 27 8 5 6 0 16 15 0 0 12 79
Gas 16 0 0 0 0 0 4 0 0 0 20
Misc 1 0 0 0 1 0 0 0 2 2 6
LAST YEAR Oil 25 10 5 4 0 0 13 0 0 8 64
Gas 6 0 0 0 0 0 4 0 0 0 10
Misc 1 0 0 0 1 0 1 0 1 2 5
Source: Baker Hughes
Saipem awarded new contract in Egyptian WDDM SAIPEM HAS BEEN awarded new E&C Offshore contracts in North and West Africa (Egypt and Angola) for a total value of approximately US$1.1bn. In Egypt, Saipem has been awarded by Burullus Gas Company a contract for the development of the West Delta Deep Marine Phase IXa Project about 90 km off the Mediterranean Coast of Egypt. The scope of work encompasses engineering, procurement, installation, pre-commissioning and commissioning support of subsea facilities in the West Delta Deep Marine Concession, where Saipem already successfully performed earlier subsea development phases. New facilities include rigid and flexible flowlines, umbilicals and other related subsea structures, to be installed in water depths up to 850 metres. Marine activities will be carried out between the second and the fourth quarter of 2014.
Inpex farms into blocks off Mozambique STATOIL HAS FARMED down a 25 per cent working interest in its operated exploration licence offshore Mozambique to Japanese based INPEX Mozambique Ltd, a wholly owned subsidiary of INPEX Corporation. The licence, which consists of two blocks, under one licence agreement, is located in areas 2 and 5 offshore Mozambique in the Rovuma basin This is the first case for INPEX to participate in oil and gas exploration activities in Mozambique. This transaction is subject to the satisfaction of certain conditions including Mozambican government approval. This offshore block is located approximately 1,750km northeast of Maputo and covers an area of 8,041 sq km with a water depth of approximately 300 to 2,500 m. While the large scale reserves of natural gas discovered in the adjacent areas, this block is expected to hold crude oil reserves. The participants will drill two exploration wells this year. After the farm-in completion, the block will continue to be operated by Statoil Oil & Gas Mozambique with a 40 per cent participating interest, the other partners being INPEX Mozambique (25 per cent), Tullow Mozambique (25 per cent), a subsidiary of Tullow Oil and Empresa Nacional de Hidrocarbonetos EP, the Mozambican state oil company (10 per cent).
Eni strikes again offshore Angola ENI HAS MADE its ninth oil discovery in Block 15/06, in deep water offshore Angola, increasing the resource base of the West Hub project. The discovery was made through the Vandumbu 1 well, located approximately 150 km from the coast. The well was drilled at a water depth of 976 m and reached a total depth of 4,107 m. Additional drilling has been carried out from the Vandumbu 1 well in different direction (side track), Vandumbu 1 ST, that reached a depth of 3,480 m, finding a net oil (34째API) pay of 114 m, contained in Lower Miocene high quality sand. As suggested by data acquired, Eni www.oilreviewafrica.com
estimates that Vandumbu 1 ST has a production capacity in excess of 5,000 bopd. Eni is operator of Block 15/06 with 35 per cent. The other partners of the joint venture are SSI Fifteen Limited (25 per cent), Sonangol (15 per cent), Total (15 per cent), Falcon Oil Holding Angola SA (five per cent) and Statoil Angola Block 15/06 (five per cent). This discovery confirms Angola as one of the core countries in Eni's organic growth strategy. Eni has been present in the country since 1980 with a net production of 102,000 bpd in 2011. Oil Review Africa Issue Two 2013 41
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Project Databank & Project Focus Compiled by Data Media Systems
OIL, GAS AND PETROCHEMICAL PROJECTS Project Angola LNG Project Block 14 Lucapa Field Development Block 16 (Omal, Zenza & Zenza South Fields) Block 17 Offshore Oil & Gas Development Clov Project Block 31 Offshore Oil Development Field Block 8
Sector Facility Budget Gas Liquefied Natural Gas (LNG) 10000000000 Offshore Oil Field 300000000 Oil, Offshore Oil Field Development 500000000 Oil, Gas, Offshore Oil & Gas Field 9000000000
Status EPC FEED EPC EPC
Start Date Q2-2005 Q1-2006 Q2-2005 Q1-2007
Completion Date Q2-2013 Q2-2016 Q1-2014 Q4-2014
Oil, Offshore Oil
Oil Field Development Oil & Gas Field
10000000000 157000000
Q1-1999 Q4-2006
Q4-2014 Q4-2016
Block 9 & Block 21 Development Congo River Crossing Pipeline Project ENI - SONANGOL - Block 15/06 Development ExxonMobil - Xikomba Oil Field - Block 15 Lianzi Development Project Lobito Refinery Maersk Oil - Block 23 New National Assembly of Angola Statoil - Kwanza Block - Block 38 Statoil - Kwanza Block - Block 39 TOTAL - Dalia, Rosa, Girassol, Jasmine, Camelia Fields Exploration TOTAL - Pazflor Field Development Vanza Longui Area (GVLA)
Oil Pipeline Oil Oil, Offshore Oil Oil, Refining Oil Construction Oil Oil Offshore
Oil Field Development Gas Oil & Gas Field Oil Field Oil & Gas Field Refinery Exploration Office Buildings Exploration Exploration Oil & Gas Field
700000000 350000000 500000000 900000000 1900000000 8000000000 500000000 255000000 500000000 500000000 1000000000
EPC Feasibility Study EPC EPC EPC EPC EPC EPC EPC EPC EPC EPC EPC
Q1-2007 Q1-2009 Q4-2006 Q1-2001 Q1-2009 Q1-1998 Q4-2006 Q1-2009 Q4-2011 Q4-2011 Q1-2009
Q1-2015 Q4-2013 Q1-2015 Q4-2013 Q4-2015 Q1-2016 Q4-2016 Q3-2013 Q4-2019 Q4-2019 Q2-2017
Offshore Offshore
Oil & Gas Field Offshore Platform
8500000000 4000000000
EPC FEED
Q3-2006 Q1-2006
Q1-2017 Q4-2017
Project Summary Project Name
Lianzi Development Project
Name of Client
Chevron Texaco Angola
Budget ($ US)
1,900,000,000
Award Date
Q3-2012
Facility Type
Oil & Gas Field
Status
EPC
Start Date
Q1-2009
End Date
Q4-2015
Location
Block 14, Angola
Project Backgrounds Nigerian National Petroleum Corporation and Total have launched Phase 2 of the Ofon Field Development Project.
Project Status Chevron has been awarded the development licence for the Lianzi Development project, offshore Angola. As of mid March 2009, Chevron has selected Granherneas, the FEED contractor. The FEED work will involve front end engineering and design of the subsea system, connecting pipelines & flow lines, additional new topside equipment for the BB platform, and modifications and tie-ins required to the existing BB facilities. Additionally, the scope of the contract includes assisting Chevron in the development of AFE cost estimates to support project sanction and preparation of the bid packages for the EPCI contract to develop the field. As of March 2011. Engineering optimisation studies are underway. As of 2 December 2011, Angola and Congo Republic agreed to share production from the Lianzi oil field. FEED studies have been completed. The shortlisted bidders for Lianzi have submitted bids for the three major contracts, expected to take in the supply of three subsea production
wells, three water injection wells with the capability to add one each contingency production and water injection wells. Saipem, Technip and Subsea 7 are expected to bid for the SURF contract. In 30 July 2012, Chevron Corporation announced that Lianzi field is set to produce first oil in 2015. In 16 August 2012, Subsea 7 SA announced that it has been awarded an EPIC SURF contract valued at approximately US$600 million from Chevron Overseas Congo Ltd, for the development of the Lianzi field offshore. As of November 2012, GE Oil & Gas has won a contract to supply seven trees, nine subsea control modules, topside and subsea controls distribution equipment and vertical connection systems for Chevron's offshore Lianzi project in Angola. The offshore construction phase is scheduled for completion by the end of 2014. As of March 2013, Chevron has announced that first oil is expected in 2015 with a maximum daily output of 46,000 barrels of crude.
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Aggreko to help satisfy Southern Africa’s growing power demands AGGREKO HAS SIGNED Tri-Party Power Purchase Agreements (TPPA) with Electricidade de Moçambique (EDM), the Mozambique power utility and NamPower, the Namibian power utility, to provide 122 MW of gas-fuelled power from the Aggreko interim power plant located at Gigawatt Park at Ressano Garcia, Mozambique. The agreement follows the authorisation by EDM for the direct supply of power by Aggreko to NamPower and will see the installed capacity of 122 MW split between the two utilities with EDM utilising up to 32 MW and NamPower up to 90 MW, based on the specific needs of both utilities. Aggreko built the facility at Ressano Garcia in 2012 as part of an ambitious project in which it became the first cross-border, interim Independent Power Provider to the Southern African Power Pool (SAPP). Under the first phase of the project, which started power production in July 2012, Aggreko and its joint-venture partner Shanduka supplies power to EDM for national energy requirements in Mozambique, and also generates power for the South African utility ESKOM. The success of this initial project, which is currently providing 110 MW of power to the two utilities, has enabled Aggreko to offer additional power to other members of the Southern African Power Pool, which is one of the largest
interconnected grids in the world and links the power networks of nine countries in Southern Africa. The combination of Aggreko’s industry-leading technical expertise and its extensive gas-powered generation fleet has enabled it to offer this solution to help satisfy the growing power demands of Southern Africa. By utilising the exceptional regional transmission infrastructure, Aggreko will be able to supply power generated in Mozambique to Namibia, more than 1,500 km away, as well as locally to EDM. Both EDM and Eskom will play a key role in delivering this power to Namibia. EDM will transmit the power over its network to the South African border where NamPower will take delivery. Eskom on behalf of NamPower will handle the wheeling of the power across the South African grid network to Namibia. The new 122 MW plant is scheduled to go into production in the second quarter of 2013 and will supply power for a minimum of two years. Natural gas to the project will be supplied by the Matola Gas Company SA through their gas infrastructure at Ressano Garcia and Aggreko will generate power utilising a sub-concession agreement with Gigawatt Mozambique SA. The total value of the project is likely to be in excess of U$200mn, including fuel costs. Rupert Soames, Chief Executive of Aggreko plc
said: “This new project will make Ressano Garcia the world’s largest cross-border interim power plant, with over 232 MW of gas-fuelled power generation. It underlines the immense potential of the Southern African Power Pool to be a real conduit of cooperation and development among the countries of Southern Africa. The fact that three national utilities are collaborating to support each other’s energy requirements is testament to the benefit of working together for the common good.” Paulinus Shilamba, Managing Director, NamPower said: “This innovative approach to securing an effective power supply for the people of Namibia is a great example of the spirit of Southern African co-operation. This unique project will contribute to the provision of a reliable power supply across Namibia and support the continued development of the country.” Augusto Sousa Fernando, CEO of EDM added: “Following the first project enabled by EDM, in its role as the national power utility and system operator in Mozambique, we would once again like to welcome the second phase of the Aggreko interim power plant at Ressano Garcia, which will assist EDM and its partners in the SAPP to bridge the period until we implement our permanent plants in Mozambique.”
Total pushes for Uganda pipeline
PetroSA, Sinopec sign refinery framework deal
TOTAL SA IS pressing the Ugandan government to approve the construction of a crude export pipeline ahead of the planned development of the country's vast oil reserves in the Lake Albertine Rift Basin, according to a company. Total's top executives, led by its president for Africa Jacques Marraud, met Uganda's long-serving leader, Yoweri Museveni, in Kampala in March in a bid to persuade him to break the impasse over the construction of a refinery and crude pipe line, according to Ahlem Friga-Noy, Total's spokeswoman in Uganda. The development underscores Total's growing frustration with the Ugandan government, more than a year after the company acquired a stake in the country's oil assets. "The discussion raised the issue of the refinery and the crude export pipeline. Total underlined to the President its understanding of the need for a refinery... and restated its view that this refinery should be combined with an export crude pipeline" Ms. Friga-Noy said. "We are hopeful that parties will soon reach a convergence of views."
SOUTH AFRICA'S NATIONAL oil company PetroSA and China Petroleum Corporation (Sinopec) have signed a framework agreement to build a new crude-oil refinery in South Africa, which is set to become the biggest in Africa. The framework agreement follows the signing of a joint study agreement (JSA) for the development of the refinery between the two state-owned companies in May 2012. The estimated US$10bn Mthombo refinery will be built at the 110 sq km Coega industrial development zone near Port Elizabeth, in the Eastern Cape province of South Africa. It will have a capacity of about 360,000 bpd
Waltersmith eyes small Nigeria refinery INDIGENOUS MARGINAL FIELD operator, Waltersmith Petroleum Oil Limited, is currently musing setting up a 5,000 bpd capacity green field refinery, to be located in Ohaji Egbema, Imo State. The refinery, which is initially being estimated at US$40mn, is one of the measures the company is considering to take care of its crude production, in view of the challenges being encountered in evacuating the crude from the fields due to pipeline vandalism. Going forward, the company said apart from bringing other fields to production, it is also looking to acquire other potential fields, as it wants to grow beyond marginal field production to becoming a full fledged exploration and production company by buying assets divested by the oil majors.
44 Oil Review Africa Issue Two 2013
and is expected to create 27,500 direct and indirect jobs at the height of its construction and 18,000 direct and indirect jobs when it starts operating. South Africa now has four crude refineries with a combined capacity of about 497,000 bpd. The framework agreement creates also opportunities for cooperation in oil and gas exploration in South Africa and its neighbouring countries. Other areas of cooperation include the exploration of downstream opportunities in Southern Africa as well as the development and acquisition of storage and logistical infrastructure.
Oryx Energies to buy BP and Masana Petroleum Solution’s LPG businesses in South Africa BP AND MASANA Petroleum Solutions (in which BP has a 45 per cent stake) announced today that Oryx Energies has agreed to buy their liquefied petroleum gas (LPG) distribution businesses in South Africa. The deal is expected to be completed during the third quarter of 2013, subject to completion of all the required legal and regulatory approvals.
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SGS as the worldâ&#x20AC;&#x2122;s leading inspection, verification, testing and Certification Company, we provide competitive advantage, drive sustainability and deliver trust. Recognised as the global benchmark for quality and integrity, we employ over 70,000 people and operate a network of more than 1,350 offices and laboratories around the world. We are continually pushing ourselves to deliver innovative services and solutions that help our customers move their businesses forward.
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Brazil is usually the area that comes to mind in any discussion of ultra-deepwater E&P. But can geologically similar offshore Africa be far behind? In our second look at deepwater and floating production systems (FPS) Infield System’s Catarina Podevyn, author of a major new report, tells Vaughan O’Grady that ultra-deepwater production of both African oil and gas is either imminent or under way.
Africa:
the next Brazil? A
NEW REPORT* from independent energy research and analysis company Infield Systems Limited on the floating production systems (FPS) market suggests that the ultra-deepwater market is expected to dominate FPS demand to 2016. That demand will clearly be driven by Latin America — and notably Brazil. Will Africa also be a major ultradeepwater player? Catarina Podevyn, analyst, business strategy and analysis, with Infield Systems and author of the report, explains that her company defines deepwater as any depth of 500 m or greater. Ultra deepwater, by contrast, is considered by Infield to mean 1,500 m and greater. The operational fields offshore Africa were, until recently, all in water depths of less than 1,500 m. However, Infield Systems expects this to change — and soon. Angola’s Saturno (at 1,804 m) and Plutao (2,020 m) fields developments are onstream or about to come onstream. The remaining fields of BP’s PSVM (Plutao, Saturno, Venus and Marte) project are Venus and Marte, at respective water depths of 2,000 and 1,978 m. They are currently expected to be brought onstream by the close of 2016. Ultra-deepwater development in Africa is in fact about to speed up. “Ultra-deepwater developments are expected to increase substantially,” says Podevyn, “with seventeen developments expected to take place between 2013 and 2017. Developments offshore Angola are anticipated to lead this trend, with 11 ultra-deepwater fields expected to commence production during this timeframe.” Infield Systems expects further ultradeepwater developments to come onstream offshore Nigeria, Ghana, Equatorial Guinea and Congo (Brazzaville) over the following five years. Of course, the West African Salt Basin shares geological similarities with the Santos Basin offshore Brazil; this will be a key factor in terms of the continent’s future ultra-deepwater prospects. These prospects, Podevyn explains, extend as far south as offshore Namibia where increasing operator interest has been evident over recent years. This includes leading ultra-deepwater operator Brazil’s Petrobras, which is currently operating block 2714A with water depths ranging up to 1,500 m in a PSA with the UK’s Chariot Oil and Gas, which is the leading operator offshore Namibia. But West and Southern Africa are by no means the whole ultra-deepwater story for the continent — especially given the gas boom elsewhere. Podevyn says: “Drilling contractors are also witnessing an increase in ultra-deepwater rig demand from
46 Oil Review Africa Issue Two 2013
Seadrill’s West Gemini ultra-deepwater drillship is operating in West Africa offshore Angola for Total.
Ultra-deepwater developments are expected to increase substantially. operators exploring offshore East Africa, a region that is expected to experience significant investment over the forthcoming decade following a series of successful discoveries offshore Tanzania and Mozambique over the previous eighteen months. We can also now add Kenya to this increasingly prospective region, following Pancontinental’s natural gas discovery in Sept 2012.“
Local content requirements Good news indeed for oil and gas companies, although Infield does have a caveat in the shape of what it calls “significant local content requirements”. African countries are encouraging IOCs to incorporate higher proportions of local content. On the face of it this may not be surprising. Oil revenues, through corporate taxation, rents and royalties, have in recent years supplied a very high — perhaps the highest — proportion of budgetary revenues in many African countries; within Nigeria for example this has, according to some figures, accounted for 65 per cent of revenue and 95 per cent of export revenue. However, in order to realise stable and sustained economic growth, investment in local industry, services and manufacturing is viewed as crucial by many governments. Through decreasing unemployment, and encouraging IOCs to establish industry-specific educational programmes
and training, the aim is to substantially raise the level of human capital and economic growth through ‘learning by doing’ over time. Podevyn explains: “With ambitious economic growth targets going towards 2020, resource-rich countries such as Nigeria and Angola, followed by newly emerging players, in particular Ghana, have placed local content reform at heart of strategy going forwards. For Nigeria, its 2020 strategy targets structural and institutional change; implementing the Oil and Gas Industry Act in 2010, the goal is to take the country into the ranks of the world’s 20 largest economies by 2020.” This means that IOCs and others may face significant challenges. Trying to implement local content strategies may seem feasible but, as Podevyn suggests, there are a few risk factors that need to be considered. They include late delivery or inferior quality; over-ambitious scheduling that may not take into account the relatively inexperienced labour force; a lack of experienced project managers and quality workforce; late delivery of crucial equipment; and the possible need for rework due to lack of quality. However, operators are rarely expected in reality to meet the ambitious targets set by national governments. In any case there are certainly strategies to mitigate local content risk. They include: splitting the construction of hull and topsides; completion, integration and quality rectification at an experienced yard; employment of experienced management; and moving certain activities — such as welding —offshore.
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Technology
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The fifth-generation ultradeepwater Ocean Confidence is contracted for work offshore West Africa.
In addition, in regions where conditions permit it, the implementation of a more standardised approach to floating platform design could mean that the learning curve (the ‘learning by doing’ effect) would be accelerated. This could significantly reduce the risks associated with inexperience or lack of human capital. Overall then, with the worldclass reserve basins of West Africa, and the more recent promising explorations offshore South and East Africa, for the most part the economics of field development across the African region continue to very much stack up for the international operator. At the same time, however, Podevyn feels a balance between operator incentives and local content requirements will need to be struck.
A balance between operator incentives and local content requirements will need to be struck.
48 Oil Review Africa Issue Two 2013
“Yes there is a need to enhance local economies and increase global competition,” she says, “but ultimately African hydrocarbon producers remain for the most part reliant upon experienced international operators and contractors. For the foreign operator the rewards must always outweigh the risks and until the domestic offshore manufacturing and fabrication industry possesses sufficient experience, technology and human capital to become autonomous, incentives for attracting international operators must be maintained.”
Still, the African deep and ultra-deepwater opportunity is not likely to be ignored. The only remaining question, perhaps, is how deep this opportunity can go. At the moment the boundary seems to be defined by the 2,700 – 3,000 metre Alaminos Canyon in the Gulf of Mexico. “This seems to be the limit at the moment,” says Podevyn. “Anything around 3,000 metres is approaching the too deep mark,” she adds. Still, that’s hardly a cause for despair. As she says, “We still have many prospects between 500 and 2,000m that will be developed first and contain world-class reserves.” ■
*The Floating Production Systems Market Report to 2016 is published by Infield Systems, an independent energy research and analysis company that is dedicated to the provision of accurate and upto-date data, market reports, mapping, analysis and forecasts for the offshore oil and gas and associated marine industries. For more information, and to order the report, go to www.infield.com
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Epic Atlantic Limited Plot 212 Trans Amadi Industrial Layout, Ordinance Road, Port Harcourt, Nigeria Tel: +234 - 84897 691, 803 421 4616, 805 7049752 Email: consultants@epicatlantic.com Website: www.epicatlantic.com
Technology
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Subsea structures such as manifolds, line pipes and flow lines are important investments. Proper management of the corrosion of these structures is of vital importance to avoid ecological disasters. In this article we review some important challenges of deep sea corrosion management and the main countermeasures to address these.
Subsea corrosion management: challenges
and limitations D
EEP SEA OIL and gas extraction is becoming an increasingly attractive option for an energy-thirsty global industry. There are many economical benefits associated with this method, however it is also important to be aware of its potential to cause ecological disasters. Corrosion of subsea structures is a significant problem, as any failure in deep sea structures (such as manifold, line pipes and flow lines) could be devastating to the environment. Unlike onshore structures or even shallow water structures, regular monitoring and repair of deep sea structures is not easy due to the high costs involved and the difficult accessibility. As a result, corrosion management for subsea structures mainly relies on the estimation of corrosion rates. These estimated corrosion rates are calculated based on semi-experimental research results and are therefore always limited in terms of their assumptions and applications.
to apply the cladding, both the cost and the available sizes of the final product are important factors, in addition to mechanical properties which will affect its use. However, it must be noted that as application of these methods can change the overall microstructure, it can have some unwanted effects as well: a study on stainless-cladded carbon steels by hot-rolling, shows that micro structural changes along with the formation of residual stresses - which mostly have tensile natures - can lead to premature failures. An example of corrosion resistant alloys (CRA) is duplex stainless steel. These steels are mainly characterised by their “dual” crystal structure, Figure 1.
Corrosion management of deep sea structures There are mainly three aspects of deep sea structures corrosion management (DSCM) techniques that make them different from onshore and shallow water structures corrosion management (OF/SW CM) techniques: 6 Materials 6 Corrosion Management Practice 6 Cathodic Protection (CP) These three factors in combination determine the nature of work for subsea corrosion engineers and differentiate it from the work done by corrosion engineers working in other industries (such as mining).
Materials The variety of materials that are used in OF/SW CM applications is not seen with DSCM. This is in fact dictated by the corrosion models and their underlying design philosophy. The materials of frequent use in pipes for subsea applications are: (carbon) steel, stainless, duplex and superduplex stainless steels, clad and titanium pipes. A more general classification of the materials can be either: 6 Carbon steel (clad or lined) 6 Corrosion resistant alloys (CRA) such as, but not limited to, duplex stainless steels (DSS) Clad steel plate is a composite steel plate made by metallurgical bonding of the cladding material (such as all types of stainless steels, nickel and nickel-copper alloys and t itanium) to either or both sides of a carbon steel or low alloy steel plate (base metal). While different methods may be used
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Figure 1: An example of the microstructure of a duplex stainless steel (SAF2205): (bright: austenite, dark: ferrite). The structure shows 52 ± 2 wt% retained austenite.
Duplex stainless steels are considered more corrosion resistant than austenitic stainless steels owing to their relatively higher chromium content. A very important issue with duplex stainless steels is the spacing between austenite islands, as short austenite spacing is normally preferred due to both shorter hydrogen diffusion paths, more “hydrogen” tapping and crack stop properties. To avoid hydrogen-induced stress cracking (HISC), based on deformation mode and induced strains, an austenite spacing from less than or equal to 30μ to 60 μ is preferred.
Corrosion management practice Corrosion management involves issues such as corrosion allowance, corrosion models, inhibitor availability and the like. In contrast to many onshore corrosion management techniques, subsea corrosion management still applies “corrosion
Corrosion of subsea structures is a significant problem, as any failure in deep sea structures could be devastating to the environment. allowance”. This is in essence adding extra thickness to the pipe wall to compensate for corrosion. While it may appear as a simple issue of just adding “a few” millimeters to the net thickness of the pipe (to get the nominal thickness), this corrosion management technique has huge financial and application consequences. As an example, a pipe line which has a diameter of 8 inches and is 362 km long with a wall thickness of 8.2 mm would require an extra 3,700 tonnes of steel to increase the wall thickness by only 0.250 inches! Additionally, the internal capacity would need to be decreased by five per cent. Corrosion modeling and inhibitor availability are the two main features that set out the main differences between corrosion prediction models. In these models the type of inhibitor (cathodic, anionic or mixed) is of no importance and the assumption is that whatever the mechanism of action, it is the availability of the inhibitor that matters. Corrosion models can be classified into two groups, “conservative” such as BP (Cassandra) and NORSOK (with their various in-house alternatives) and the “liberal” Shell (Hydrocorr) model. Figure 2 schematically shows some of the features of these modeling approaches. BP, NORSOK, Statoil “conserva ve” approach
●
Uninhibited corrosion rate:3 mm/yr
●
Inhibited corrosion rate: 0.1mm/yr
●
90%-95% corrosion inhibitor availability recommended
●
Shell (hydocorr). “liberal” approach
●
Inhibited corrosion rate: 0 ◦ T<70 C, corrosion rate=0.05 mm/yr ◦ 70 C<T<120 C, corrosion rate=0.1 mm/yr ◦ T>120 C, corrosion rate=0.2 mm/yr
●
95%-99% corrosion inhibitor availability recommended
●
Carbon steel favoured
CRA favoured
Figure 2: Schematic comparison of the two most frequently used corrosion prediction models for subsea structures
Although the conservative BP (Cassandra) model is based on papers published by de Waard, and they essentially show similar results, there
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NORSOK approach
Corrosion rate
Technology
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BP approach
de Waard approach
Scaling Temperature
Temperature
Figure 3: Corrosion rates as predicted by three models for temperatures above scaling temperature (Norsok, by default, calculates ferrous ions unsaturated rates).
Any monitoring technique can provide only a limited amount of information, and the techniques should be regarded as complementary rather than competitive. are slight differences between the model and the work by de Waard, such as the use of a correction factor for carbon dioxide fugacity and its lack in the BP model . The Norwegian Norsok model, the de Waard model and the BP (Cassandra) model predict the same corrosion rates at temperatures below or equal to scaling temperature. For temperatures above scaling temperature these models will predict corrosion rates that can be different from each other, and thus will dictate different strategies. To illustrate how the same data can result in different corrosion management strategies according to these models, Marsh and Teh consider the example of 100,000ppm sodium chloride brine with 500ppm of bicarbonate ions, 100bara, five per cent CO2 (gas phase), 100oC, no significant flow effects considered and 20 year design life. The Cassandra model, by assuming a 95 per cent availability upper limit and an inhibited corrosion rate of 0.1mm/yr will recommend the use of CRA (such as 13 per cent Cr supermartensitic stainless steel or SAF 2205), whereas for the same set of data, the Norsok M506 model by assuming a 99 per cent availability upper limit and an inhibited corrosion rate of 0.05/0.1 mm/yr (65oC/100oC) will recommend carbon steel with a 3mm corrosion allowance. In addition to the de Waard, BP (Cassandra) and Norsok models, there are other corrosion prediction models such as Cormed (Elf), Lipucorr (Total), Predict (InterCorr) and CorPos (CorrOcean/Force Technology). While these models share the same basics, the input and results will differ. One important shortcoming of corrosion prediction models is that in models such as BP (Cassandra), de Waard and Norsok, microbial corrosion is not considered. The BP (Cassandra) model for example, is not valid for liquid velocities less than 1,5 ms. It is interesting to note that this is also the velocity limit where microbial corrosion
52 Oil Review Africa Issue Two 2013
The concept of corrosion monitoring has developed from two distinct areas, plant inspection techniques and laboratory corrosion testing techniques, with the original aim of assessing or predicting corrosion.
competitive. Where more than one technique will give the information required, the information is obtained in different ways; a cross-check can be valuable and differences in detail can add meaning. A corrosion monitoring technique rarely gives wrong information, unless the equipment used is faulty. "Nonsense" results arise because the information is correct, but irrelevant in the corrosion sense. The choice of a monitoring technique is a complex problem requiring expert knowledge. The first essential is to establish what type of information is needed. This necessarily involves an input from the management of the plant in question.
Use of corrosion monitoring data
Cathodic Protection
can be expected. Even the standards frequently used in subsea corrosion management (such as DNV) do not address microbial corrosion properly. This matter becomes important when we consider that microbial corrosion has been shown as a cause of failure in subsea structures.
Concept of corrosion monitoring for subsea structures
6 To provide operational or management information Corrosion can often be controlled by maintaining a single operational variable (eg, temperature, pH, humidity) within limits determined by prior monitoring or other investigations. If the significant variable is measured for other reasons, this measurement can be used directly for corrosion control. If the variable is not otherwise measured, or, in more complex cases where several variables interact, corrosion monitoring information can be used by plant operators to control plant operation so as to control corrosion. Any process change may have significant effects on corrosion, and corrosion monitoring techniques allow full scale trials to proceed with a minimum of risk to plant.
6 Corrosion monitoring techniques A wide range of corrosion monitoring techniques is now available allowing determination of total corrosion, corrosion rate, corrosion state, analytical determination of corrosion product or active species, detection of defects or changes in physical parameters. Associated costs can be small where simple instrumentation and a few measurements are appropriate but in some cases may be extremely costly and require expert skills. Much of the progress which has been made in the past few years has been due to advances in electronics which have allowed multiprobe measurement and recording at a tolerable cost. Instantaneous feedback of corrosion information can be obtained from various parts of the plant, which can be fed to the plant control room and/or plant computer to permit control of the necessary process variable to provide corrosion control.
6 Selecting a technique for corrosion monitoring Many techniques have been used for corrosion monitoring and it is possible to develop others. Consequently when a possible new application is being considered, a problem arises in choosing the most appropriate technique. Each has its strong points and its limitations, and none is the best for all situations. Any monitoring technique can provide only a limited amount of information, and the techniques should be regarded as complementary rather than
For obvious reasons, impressed current CP cannot be an option for deep sea water applications. According to DNV-OS-F101, â&#x20AC;&#x153;duplex and martensitic stainless steel linepipe, and C-Mn steel linepipe with SMYS > 450 MPa require special considerations of the susceptibility of environmentally assisted cracking (including SSC and hydrogen induced cracking related to cathodic protection)â&#x20AC;?. The Norsok workshop agreement is more detailed about the joint use of CP and duplex stainless steels. According to this document, duplex stainless steels are well protected for potentials more negative than -600 mV (Ag/AgCl) on the condition that a complete electrical insulation from the structural elements, that are protected at 1050 mV, is also applied. Although some modifications in CP system design may be promising in using both CP and supermartensitic stainless steel together, two major limitations on applying CP to subsea structures are that only one method of CP can be applied and we are limited to the use of certain alloys whose yield stress is lower than a certain limit.
In summary Subsea structures, like on-shore and other offshore (shallow water) structures need to be protected from corrosion. However, the practice of corrosion management for these structures is different from on-shore and off-shore in not only the materials used but also in applications such as cathodic protection. Due to factors such as difficulty in having access to the subsea structures and the costs involved, different corrosion prediction models have been developed. These models - with their in-house variants - are frequently used not only to estimate corrosion, but also to select the strategy that will be the most feasible to apply. Although these models have similar basics, due to their assumptions and conservative approaches, the very same inputs may result in different corrosion management strategies and therefore different budgeting for the projects. When applying these models, their limitations must be considered and their approaches must be taken with required precautions. â&#x2013;
Reza Javaherdashti; Chikezie Nwaoha; Alireza Bahadoric www.oilreviewafrica.com
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EMERSON'S ROSEMOUNT GUIDED wave radar enables accurate and reliable level measurements in challenging process conditions off the west coast of Africa. BP Exploration has replaced unreliable level transmitters previously used on a FPSO vessel with guided wave radar (GWR) transmitters from Emerson Process Management. The more accurate and reliable level readings from Emerson’s Rosemount 5300 Series GWR transmitters have helped BP Exploration increase safety, reduce shutdowns and increase production. Operating 160 km off the west coast of Africa, the BP FPSO processes and stores oil production for export. At 310 metres in length, it has an oil storage capacity of 1.77mn barrels and can process up to 240,000 bpd. Changing process conditions and the presence of foam and vapour, as well as dirty sticky fluids, made
this a difficult application for measuring level. The original GWR transmitters (supplied by another vendor) had compatibility issues with the FPSO’s Foundation fieldbus network, and their limited capabilities in detecting low-dielectric hydrocarbons required coaxial probes to increase the strength of the surface signal. Such probes are susceptible to the build-up of sticky solid materials entrained within the production fluid, which led to a significant number of unplanned shutdowns with resulting lost production. To address these issues, BP Exploration worked with Emerson to replace existing GWR units with Rosemount 5300 GWRs. With Emerson’s advanced signalprocessing technology that ensures detection of low dielectric fluids, the Rosemount GWR is able to send and receive a cleaner, stronger signal. This
Emerson’s Rosemount 5300 Series GWR transmitters have helped BP Exploration increase safety, reduce shutdowns and increase production.
allows the use of single-lead probes that increase tolerance to solids build-up and coating, and
eliminate trips due to false readings. In addition, the Rosemount 5300’s Foundation fieldbus interface made installation and configuration both quick and easy. The improved level detection enabled by the new instruments has also helped BP Exploration improve safety. The susceptibility of the existing GWRs to material build-up on the co-axial probes and their inability to distinguish the presence of a light hydrocarbon layer on top of the water meant that the level measurements were unreliable. This unreliability compromised one of the layers of protection used to ensure safe operations. Following the installation of the Rosemount 5300 GWR transmitters, the process data has confirmed the accuracy and reliability of the instruments and their suitability for the widely varying process conditions of the FPSO.
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Oil Review Africa Issue Two 2013 53
Technology
BP upgrades radar level measurement
Technology
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In this paper Alfredo Jones, managing director of Alduco Energy, an asset integrity management company providing services in the Gulf of Guinea, discusses improvements in offshore corrosion management of oil & gas facilities, the methods used and a case history to demonstrate the improvements.
Corrosion management
through Cathodic Protection S
UBMERGED AND BURIED offshore oil & gas structures are protected from corrosion through Cathodic Protection (CP). A Cathodic Protection system composes either a sacrificial anode or an impressed current anode with a power supply. A CP system works by supplying sufficient low voltage Direct Current (DC) flows from the anode to overcome the natural DC that flows from the offshore steel facility into the seawater during the corrosion process; this causes the corrosion process to stop up until the intended design life of the CP system.
Why is Cathodic Protection important? Many existing offshore platforms, FPSOs, pipelines etc have reached or are reaching the end of their Cathodic Protection design life. In other words their CP systems are depleted or no longer working; hence you have structures with no protection, which are at risk of catastrophic external corrosion failure, with all its consequences. According to the National Association of Corrosion Engineers (NACE) the total annual cost of corrosion in the oil and gas production industry is estimated to be US$1.372bn. It is widely recognised within the oil and gas industry that effective management of corrosion will contribute towards achieving the following benefits: 6 Statutory or corporate compliance with safety, health and environmental policies 6 Reduction in leaks 6 Increased facility availability 6 Reduction in unplanned maintenance 6 Reduction in deferment costs Reasons to retrofit and maintain oil & gas infrastructure against corrosion 1. The original corrosion management system has reached the end of its design life, and the integrity of the structure has to be maintained. 2. The structure is required to serve beyond its original design life (original anode designs are 25-30 years). 3. Damage to coating or anode systems, for various reasons ie, during installation, over design of CP systems etc The methodology to follow 1. Carry out CP survey of the facility 2. Calculate CP requirements and develop CP design based on data 3. Install designed CP retrofit solution on facility 4. Conduct post retrofit survey
54 Oil Review Africa Issue Two 2013
Improved and easy ways of connecting CP retrofit solutions to structures – Retroclamp.
Improvements in CP retrofit methodologies The conventional approach to CP retrofit of oil and gas structures is to replace depleted anodes with new ones, this method - even though it is still widely used - is dangerous and outdated, because adding anodes to, for example, an already old structure is adding more weight to it, further compromising its structural integrity, as some of these anodes could weigh as much as 500kg each. Also the cost of retrofitting CP systems the
Improved sacrificial anode CP retrofit solutions for pipelines – Smart Mart.
conventional way is very high, due to the installation costs involved including the hiring of supply vessels for the installation of the replacement anodes that could easily run in hundreds of thousands of dollars for carrying out a CP retrofit. For the above reason Deepwater Corrosion Inc in Houston, after various years of R&D, came up with the world’s most efficient and cost effective way of carrying CP retrofits with up to 80 per cent cost savings in some cases. Retroclamp replaces the need for welding CP systems onto the structures they are protecting. It works by providing an electromechanical tieback to subsea CP systems, connecting the CP systems to platforms, wellheads pipelines etc. It is very easy to install as only clamping is involved and can be carried out by an ROV or divers. The smart mart is a sacrificial anode system which is made up of a stabilisation concrete mattress with built-in cathodic protection anodes. This is used to retrofit aged or damaged pipelines that need CP protection. Installation is easy as the smart mart is dropped over the pipe it is trying to protect with a crane. It can be designed to give a life extension of another 30 years to a pipeline, with CP protection for up to three kilometres of pipeline in each direction.
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Technology
as the installation time is less than a quarter of the time it would take to install the equivalent amount of CP anodes using the conventional method which also gives the aging structure additional weight through attaching anodes to it. A high-capacity impressed-current cathodic protection system, designed primarily as a retrofit for existing structures. It utilises impressed-current titanium-anode rods housed in buoyant floats. This configuration keeps the anodes in constant contact with seawater, maximising the efficiency of the cathodic protection they deliver. The Retrobuoy can provide up to 400 amps of CP and protect up to 80,000 sq m of underwater steel. It is typically used for FPSOs and large offshore platforms. â&#x2013; Installation of a Retropod.
The Retropod is a CP system made up of a structure with four aluminum anodes joined by metal frames and arranged in a pod shape with a concrete stabilisation mattress at the bottom for stability. It is dropped onto the sea bed next to the structure it is intended to protect, and connected to it through cables and a retro
clamp. No additional weight is added to the structure because the Retropod lies on the sea bed next to the structure. This is an ideal system for replacing or supplementing the CP systems on an ageing or damaged platform. Installing the Retropod is less expensive than the conventional method of doing CP retrofits
Improved ICCP retrofit solutions for FPSOs, platforms and wellheads - Retrobuoy.
Improved sacrificial anode CP retrofits solutions for platforms â&#x20AC;&#x201C; Retropod.
Case study ALDUCO ENERGY WAS contracted to come up with a CP retrofit design for an ageing platform in the Gulf of Guinea for a multinational oil & gas company. The company first visited the platform and carried some CP surveys and also analysed the CP data that was made available by the client. Alduco Energy was able to ascertain that the CP system was not working as it had reached the end of its design life. Alduco Energy & partner Deepwater Corrosion then went about designing a new CP system, taking into consideration all the data available. They came up with an engineered Retropod, which was the best solution for the ageing platform, as adding more anodes to the existing ageing structure was ruled out. Amongst other reasons, including the cost savings to the client, Retropod was chosen as it is dropped and rests on the seabed alongside the structure it is protecting. The table below summarises the main benefits. Facility The client had a four leg jacket in 95m depth of sea water with no cathodic protection, as it had reached the end of its design life.
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Solution Alduco Energy, in conjunction with Deepwater Corrosion, did the engineering calculations and came up with a CP Retrofit design which met the current requirements of 634Amps, using the Retropod system. Benefits of using the improved sacrificial anode CP retrofit system on this project - Retropod. Specification
RetroPod
Dual Clamp-on Anode
Current output per unit
17.72 Amp
8.03 Amp
Weight per unit
-
490kg
Total number required
36
79
Installation time
3 days
20 days
Total cost
US$ 1,302,240
US$ 2,503,230
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Engineering above and below the surface
Global Oceon Global Oceon Engineers is a Nigerian offshore engineering design company, established in 2007 and promoted by Petrolog group, a US mudlogging giant, which has been operating in Nigeria for more than 30 years.
T
HE LOCAL CONTENT provision, which has defined the enhancement of increased local participation in Nigeria, has given the company more backing, opportunities and a vision. The government has put its weight behind the development of Nigerian companies with the courage to request collaboration opportunities. The law has further demonstrated to the International Oil Companies (IOCs) its intentions and seriousness to develop local talents. This is to further strengthen the federal government’s plans to grow Nigeria into one of the top 20 economies in the world by 2020. It also recognises the role that the oil & gas industry has played in growing its GDP in the past and the importance it will play in achieving its vision for the future. It has enacted regulations to maximise the amount and value of work that is done by indigenous companies in the domestic oil & gas industry, but this has put pressure on all players in the industry to change the dynamics of the industry. Furthermore, with the reinforcement of the Petroleum Industry Bill (PIB) being passed into law, the engagements with the IOCs would be defined, which would bring benefits within the industry bestpractise. Other provisions in the bill include separating the regulatory role of NNPC from the commercial role and precluding the regulator from being an operator. International oil companies accustomed to working with global players have stated their willingness to comply, but have also expressed doubt as to the quantity and quality that can be done by the indigenous companies, since there simply were
not many who were focused on the industry previously. Nigerian companies have also demonstrated their willingness to develop and provide the services required but also recognise there is some doubt as to their current capacity and ability to ramp up skills. Global Oceon, working with about 150 different engineering companies, is focused on offshore engineering and has continually built stronger capabilities in subsea, offshore and topside engineering. While not ignoring business onshore, Oceon is concentrating on its niche market offshore providing engineering design, project and construction management (EPCM) services particularly for offshore oil platforms, facilities and pipelines.
Focus to provide innovative solutions The focus is to provide innovative solutions for clients, satisfying the oil and gas sector needs using resources developed in Nigeria and by Nigerians. The company offers comprehensive engineering services which include: 6 Feasibilities, preliminary engineering, conceptual studies, front end engineering & design (FEED), detailed engineering design (DED), project management, fabrication & construction support, procurement, as wel as asset integrity management pipeline engineering 6 Management, fabrication & construction support, procurement, and asset integrity management pipeline engineering
Global Oceon is a winner of the inaugural Nigeria 50 Awards
6 Piping engineering, piping and equipment
6 6 6 6 6 6
layouts, general arrangement drawings, pipe stress analysis, development of isometric drawings, material take offs (MTOs) for piping and valves Structural engineering Computer Aided Design & drafting Process engineering Mechanical engineering Electrical engineering Instrumentation & control
Project experience Since it was formed four years ago, Global Oceon has worked on numerous projects including: OSO RE - risers, flowlines, topsides and platform modifications, transportation analysis, construction support; Pazflor - pipelines design; EGP3B – pipelines and risers, modification of existing offshore fixed facilities; EESP – offshore pipeline systems with PlEM and SPM loading buoy, cost estimate and schedule estimate; Kizomba C – marine transportation design; Agbami - design of offshore installation aids; EPC2B - offshore platform modifications; BONGA - structural failure analysis, MPN Satellite Filed Development Project Phase 1; etc. Global Oceon is fast becoming the foremost engineering design company in Nigeria, with roots that are authentically Nigerian, recognised for the quality of its people, the quality of its designs and the strength of its overall performance. ■
Oil Review Africa Issue Two 2013 57
Technology
S16 ORA 2 2013 Tech Feature 01_Layout 1 03/04/2013 12:40 Page 58
With new fields regularly being developed in ultra-deep waters and increasingly remote locations, longdistance export solutions for natural gas that cannot be flared are becoming project-critical. A new concept has been unveiled that could dramatically cut pipeline construction and installation costs while also representing a viable economic alternative to existing transportation options such as floating LNG units.
Taking deepwater pipelines
to the X-Stream D
NV HAS DEVELOPED a new pipeline concept, called X-Stream, that can significantly reduce the cost of a deepwater and ultra-deepwater gas pipeline while still complying with the strictest safety and integrity regime. “By controlling the pressure differential between the pipeline’s external and internal pressures at all times, the amount of steel and thickness of the pipe wall can be reduced by as much as 25–30 per cent,” says Asle Venås, DNV’s Global Pipeline Director. X-Stream is based on established and fieldproven technologies which have been innovatively arranged. It can reduce both the pipeline wall thickness and time spent on welding and installation compared to deepwater gas pipelines currently in operation. The exact reduction in the wall thickness depends on the water depth, pipe diameter and actual pipeline profile. Typically, for a gas pipeline in water depths of 2,500 m, the wall thickness reduction can be 25–30 per cent compared to traditional designs. “It’s essential for DNV that the new concept meets the strict requirements of the existing safety and integrity regime, and I’m pleased to confirm that this concept does,” said DNV Group CEO Henrik O. Madsen at a press briefing in London. “DNV has been instrumental in developing and upgrading the safety and integrity regime and standards for offshore pipelines over the past decades. Today, more than 65 per cent of the world’s offshore pipelines are designed and installed to DNV’s offshore pipeline standard. As the deepwater gas transportation market will experience massive investments and considerable growth over the coming years, new safe and cost-efficient solutions are needed,” Madsen said.
Thick walls Current deepwater gas pipelines have thick walls and, due to quality and safety requirements, the number of pipe mills capable of producing the pipe is limited. When installing pipelines, the heavy weights are difficult to handle and the thick walls are challenging to weld. Another aspect is that the number of pipe-laying vessels for deepwater pipelines is limited too. New offshore oil and gas fields are being developed in ever deeper waters, and export solutions for the gas are critical. New exploration activities are also heading for ultra-deep waters. The distance to shore is increasing too. The X-
58 Oil Review Africa Issue Two 2013
The X-Stream concept was designed particularly with booming areas such as Brazil's presalt province and West Africa, in mind.
X-Stream can reduce both the pipeline wall thickness and time spent on welding and installation compared to deepwater gas pipelines currently in operation. Stream concept can for such fields represent an alternative to eg, floating LNG plants combined with LNG shuttle tankers. By controlling the pressure differential between the pipeline’s external and internal pressures at all times, the amount of steel and thickness of the pipe wall can be reduced by as much as 25–30 per cent or even more, compared to today’s practice and depending on the actual project and its parameters. This will of course make it easier and cheaper to manufacture and install the pipeline. “By utilising an inverted High Pressure Protection System – i-HIPPS – and inverted Double Block and Bleed valves – i-DBB – the system immediately and effectively isolates the deepwater pipe if the pressure starts to fall. In this way, the internal pipeline pressure is maintained above a critical level for any length of time,” explained Asle Venås, DNV’s Global Pipeline Director.
Simple and reliable The new concept is simple and reliable. During installation, it is necessary to flood the pipeline fully or partially to control its differential pressure. During operation, the i-HIPPS and i-DBB systems ensure that the pipeline’s internal pressure can never drop below the collapse pressure – plus a safety margin. In sum, a certain minimum pressure will be maintained in the pipeline at all times. “It will also be important to maintain the minimum pressure in the pipeline during precommissioning. This can be done using produced gas separated from the water in the pipe by a set of separation pigs and gel. This technology is not new to the industry. This method has already been initiated as standard practice by several oil companies,” said Venås. A team of mainly young highly skilled engineers, headed by DNV in Rio de Janeiro, is behind the X-Stream concept. As with the other DNV concepts launched in 2010 and 2011, the XStream team was asked to think outside the box. The DNV study is a concept study, and a basic and detailed design will need to be carried out before the X-Stream concept can be realised. DNV intends to work further with the industry to refine and test the concept. ■
Per Wiggo Richardsen www.oilreviewafrica.com
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MSAR LTD, AN established specialist in aluminium boats for search & rescue and patrol operations, is presenting a new lifecycle lease concept offered over a full range of services including; design, construction, leasing, training (to STCW 95 standards), maintenance and end-of-life recycling. MSAR offers construction of a series of hulls from 15 to 42 metres complete with bespoke outfitting of equipment, meeting the needs of a vast array of rescue and patrol boats. Options which are being offered with these semi-custom hulls include; medical, scientific and military equipment, bullet-proofing, secure communications, cameras, tailoring for extreme climates, custom passenger comfort features, extended range and more. Standard engines installed offer a speed ranging from 36 knots up to 42 knots. Series construction of the hulls enables MSAR to install the best equipment at the lowest cost while ensuring long-term availability of parts. MSAR's lifecycle lease solutions cover acquisition and support for 12 years. The benefits of a single point of contact include the
customised design to any specification, 24/7 remote monitoring and technical assistance, annual maintenance, and refitting of vessel and equipment after six years. After the 12 year lease period the customer can choose between a second complete refit with a sixyear extension or a new boat and a new lease agreement. MSAR takes full responsibility for the dismantling and recycling at the end-of-life. An aluminium hull construction enables the possible recycle of over 90 per cent of the material. Annual maintenance can be provided by a partner who is in proximity to the customer. An MSAR technician will attend to every annual maintenance to assure service quality. MSAR can offer such lifecycle leasing solutions, based on its outstanding designs and assured reliability of its vessels.
Damen introduces new anchor handler design DAMEN SHIPYARDS GROUP has introduced its newly designed Damen AHTS 200, a versatile deepwater anchor handling tug supplier able to operate in water depths in excess of 3,000 m. The AHTS 200 is the latest addition to the ongoing Damen Offshore Series. Following the companyâ&#x20AC;&#x2122;s ambitions to increase its market share in the offshore industry, Damen heavily invests in designing state of the art vessels for several offshore sub-markets, noticeably the offshore support, offshore wind, (seismic) research and transport and installation industries. Backed by ample R&D and engineering capacity, its own construction yards, specialised partner yards and a rapid expanding service organisation, Damen feels confident that the chosen approach will be successful. The Damen AHTS 200 includes a new and innovative winch arrangement which is quite decisive for the overall dimensions and layout of the vessel. For the development of this extensive
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winch package Damen teamed-up with Huisman Equipment (The Netherlands), which specialises in heavy lift and deepwater cranes, winches and drilling equipment. The electrically driven winches resulting from this co-operation may be considered an innovative approach, as the market is traditionally dominated by low-pressure hydraulics. The electrical-drive winches provide a clean, green, economical, functional and safe solution for the anticipated operations. The vessel is suited to generate 200-250 t Bollard Pull and is fitted with engines in a fatherson layout, featuring twin-in single-out gearboxes driving CP propellers in a nozzle. High performance flap-type rudders fitted to rotary vane steering gears facilitate a high degree of manoeuvrability
supported by ample side thrust capacity, including tunnel thrusters as well as retractable thrusters in fore and aft ship. Forward of the winches ample space has been reserved for the fitting of a high-end ROV system with the possibility of launching through a side door. The high beam AHTS could serve as a suitable platform for mounting a subsea construction crane. The design can easily be upgraded with dedicated anti-heeling systems, moon pools and sophisticated diving systems.
Oil Review Africa Issue Two 2013 59
Innovations
MSAR presents its lease concept: One partner during the boat lifecycle
S17 ORA 2 2013 Tech Feature 02_Layout 1 03/04/2013 12:41 Page 60
Technology
Permanently buried onshore and offshore seismic acquisition systems could considerably improve the value of seismic for reservoir monitoring, say Ghiath Ajlani and Michel Denis of CGGVeritas.
Integrating borehole and
surface seismic data S
INCE THE EARLY days of water, steam, gas, CO2 and other Enhanced Oil Recovery (EOR) schemes that were introduced to improve recovery and extend the life of oil fields, there has been a critical need to monitor and understand flood front distribution and sweep efficiency (Figure 1). This need has been successfully addressed up to a point by conducting time-lapse 3D seismic (4D) with marine streamer and/or ocean bottom acquisition, mainly for offshore clastic reservoirs. By shooting successive 3D seismic surveys at appropriate time intervals and interpreting the differences in the signal at the reservoir it is possible to monitor the effects of EOR on the reservoir. However, and particularly in the case of onshore carbonate fields, the high accuracy of the 4D measurement in relation to noise required to be able to detect this reservoir 4D signal has proven to be elusive. This is due to the relatively small 4D signature for carbonate reservoirs with a comparatively rigid matrix as well as all the usual challenges posed by onshore seismic acquisition. These include the lack of appropriate repeatability between the base and monitor surveys, 4D noise relating to human and operational activity and variations in environmental conditions, particularly in the near-surface where a multitude of factors affect source and receiver coupling and seismic wave propagation. To tackle these 4D issues, the seismic industry focused on enhancing conventional surface seismic source and receiver equipment, geometries and methodologies. However, some inherent problems with onshore surface seismic measurements persist, such as variable coupling and sensitivity to near-surface variations which limit the sensitivity of the technique. It is true that injection and production monitoring goals are usually achieved when the 4D differences between base and monitor seismic surveys after injection are large (>15 per cent), in terms of acoustic impedance and/or two-way travel times at reservoir levels, especially in the case of shallower clastic reservoirs. However, in the case of carbonate reservoirs in the Middle East where two-way travel time variations are only a few milliseconds (or even less) and amplitude changes are equally subtle, the 4D reservoir signature may be below the sensitivity threshold of surface seismic. This reality has led many operators to abandon implementing
60 Oil Review Africa Issue Two 2013
Figure-1. Example of Enhanced Oil Recovery installations using Steam-Assisted Gravity Drainage (SAGD) (originally published in the Autumn 2002 Oilfield Review (Kopper, et al, 2002).
4D seismic for EOR monitoring of onshore carbonate reservoirs due to the significant costs and time losses incurred without tangible benefits. Subsequently, at the turn of the new century, the seismic industry shifted gear towards seismic Permanent Reservoir Monitoring (PRM) through permanently buried installations. CGGVeritas has been, and continues to be, at the forefront of PRM technological breakthroughs offering a portfolio of solutions that spans onshore and offshore installations, including equipment, acquisition services, dedicated 4D processing, reservoir characterisation and 4D
feasibility studies prior to the start of any pilot or field project. In such studies 4D rock physics templates provide the model to test various production scenarios and estimate the impedance, reflection amplitude, and travel time anomalies expected. Armed with this information the suitability of the reservoir for monitoring by various techniques can be assessed and the survey parameters optimised. Equipment manufacturing is one of the main challenges involved in developing and implementing effective 4D seismic PRM projects using buried installations. It was found that success is highly dependent on tailor-made
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S17 ORA 2 2013 Tech Feature 02_Layout 1 03/04/2013 16:27 Page 61
Technology
S17 ORA 2 2013 Tech Feature 02_Layout 1 03/04/2013 15:23 Page 62
Figure-2. SeisMovie installations in a heavy oil field using SAGD to enhance production (image courtesy of CGGVeritas).
Figure 3. From top to bottom are the results of successive SeisMovie 3D buried seismic PRM surveys recorded over a 12-week period showing +0.5 to -0.5 millisecond transit two-way travel time variations and +10 per cent to -10 per cent amplitude variations at top of the injection reservoir. These results are from a SAGD installation in Canada (Data courtesy of Shell - Forgues et al, 2006).
62 Oil Review Africa Issue Two 2013
equipment, which must be designed, manufactured, calibrated and installed to be fully consistent with the overall project requirements. Offshore, mature fields in the North Sea were the first to receive this PRM approach deploying buried seismic installations, and operators of these pioneering systems have been clear about the value of the information they have delivered for reservoir modeling and managing production (for example the Valhall Field as described in Gestel et al., 2011). CGGVeritas has deployed the Sercel Optowave fibre optic seismic cable system which is permanently trenched at the seafloor to overcome the difficulties faced when acquiring ocean bottom 4D seismic in offshore fields that are heavily congested with complex surface and subsurface facilities. The use of this permanently buried fibre optic system made a major breakthrough in PRM technologies, bringing higher reliability: no electrical components are deployed subsea, no subsea power is required, a nearly unlimited bandwidth is provided and transmission losses are minimal. Moreover this system is free from inherent noise. All these benefits provided by Optowave, combined with advanced processing, contribute to a better understanding of the reservoir, optimised oil recovery and an extension of the fieldâ&#x20AC;&#x2122;s lifespan. For onshore permanent reservoir monitoring, CGGVeritas designed SeisMovie (Bianchi, 2004), a unique solution providing high-resolution, high-accuracy monitoring of shallow reservoirs on a continuous basis. SeisMovie is well suited to monitor subtle and rapid production effects associated with EOR techniques such as Steam-Assisted Gravity Drainage (SAGD) which conventional 4D seismic is unable to discern. It features innovative piezoelectric vibrator sources and receiver arrays
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S17 ORA 2 2013 Tech Feature 02_Layout 1 03/04/2013 16:38 Page 63
buried below the weathering zone to remove the effects of the near-surface variations which plague onshore 4D seismic. A variety of receiver configurations can be deployed from 1C geophones or hydrophones to 3C and 4C stations in horizontal networks and vertical wellbore arrays (Figure 2). At the design stage, meticulous attention is paid to the required seismic signal’s depth of penetration, frequency bandwidth, amplitude, and vulnerability to various forms of noise and attenuation/dispersion in different near-surface environments. At the implementation phase, careful consideration is given to the deployment and coupling of the piezoelectric sources and velocity/pressure receivers (geophones and hydrophones) in the shallow boreholes and trenches, to ensure effective and consistent signal propagation with the required bandwidth and strength. Burying the lion’s share of the system means that there is minimal environmental impact and minimal surface interference at busy production sites during operations. Since these buried sources and receivers are expected to perform reliably with a high repeatability over the course of many years, a buried system also offers protection from weather and other environmental factors. Once this continuous, automated and buried seismic PRM system has been installed and is operating, it is managed as a remote and autonomous acquisition system, which records data continuously for daily harvesting and automated processing. This provides a daily snapshot of both travel time and amplitude variations which can be viewed as a www.oilreviewafrica.com
CGGVeritas has been, and continues to be, at the forefront of PRM technological breakthroughs “movie” revealing the evolution of conditions within the reservoir. Most seismic data interpretation specialists expect high-resolution 3D or 4D volumes to provide a temporal frequency bandwidth of at least 6-70 Hz at target levels, in order to be able to map the required intervals and perform subsequent reservoir characterisation tasks. In seismic PRM projects, aimed at mapping reservoir variations caused by EOR, geophysicists require wider bandwidth data and greater sensitivity to detect two-way travel time variations measured in milliseconds, or fractions of a millisecond. Additionally, amplitude variations at target levels can also be mapped to analyse the variations caused by injection and reservoir fluid movements. Such finely detailed mapping of daily amplitude and two-way travel-time variations has been demonstrated in several heavy oil reservoirs with a precision and accuracy of a fraction of a millisecond (Figure 3) (Forgues et al., 2006). This has largely been due to the versatile and flexible designs which have successfully addressed vertically and spatially small 4D reservoir variations. The reservoir depths expected to be reached reliably by these permanently buried seismic PRM systems with low-power buried sources vary
Acknowledgements The author would like to thank the managements of Shell and CGGVeritas for permission to publish this article. References Van Gestel J., Kommedal J.H., Barkved O.I., Mundal I., Bakke R. and Best K.D. [2008] Continuous seismic surveillance of the Valhall Field. The Leading Edge 27, 260–265.
Bianchi, T, Forgues, E., Meunier, J, Huguet, F. and Bruneau, J. [2004] Acquisition and Processing Challenges in Continuous Active Reservoir Monitoring. SEG Expanded Abstracts, 23, 2263. Forgues, E., Meunier, J, Hubans, C., and Edwards, R. J. [2006] Steam Injection Seismic Monitoring Experiment. Canadian Society of Exploration Geophysicists. Hornman, J.C., van Popta, J., Didraga, C. [2012] Continuous Monitoring of Thermal EOR at Schoonebeek for Intelligent Reservoir management. SPE 150215, Intelligent Energy International conference, Utrecht. Oil Review Africa Issue Two 2013 63
Technology
Figure 4: Results from Schoonebeek. relationship between the time shift extracted from SeisMovie and the pressure actually measured in a well on the Schoonebeek field during depletion and injection. The solid symbols represent depletion, the open symbols injection (Image courtesy of Shell - Hornman et al, 2012)
depending on source strength, geology of the overburden and near-surface conditions. Usable and accurate permanently buried 3D seismic source-receiver 4D signals down to 914 m have been achieved. The Schoonebeek SeisMovie project conducted for Shell illustrates the uplift brought by SeisMovie in the understanding of heavy oil reservoir dynamics (Hornman et al, 2012). The Schoonebeek field (Netherlands) is a medium heavy oil field where steam is injected to increase the recovery factor. The objective of the reservoir engineers is to understand the expansion of steam. The SeisMovie system was deployed and then the 4D attributes measured during the injection process. Comparison between attributes derived from SeisMovie and data measured along the observation wells showed a good correlation between time shifts (from SeisMovie) and pressure (measured at the well), see Figure 4. Many obstacles faced in seismic permanent reservoir monitoring projects have been resolved with the extensive research, development and implementation of dedicated permanently buried systems in land and marine environments. Other critical success factors behind these seismic PRM systems include comprehensive modeling of the 4D signatures of reservoirs and EOR production scenarios (for feasibility analysis and system design), careful consideration of the conditions and environments for source/receiver deployment, and the development of automated PRMspecific data processing. All these developments have led to tangible improvements in the derivation and interpretation of 4D attributes, making possible seismic monitoring of fields that were hitherto considered unsuitable for this kind of survey. ■
Innovations
S17 ORA 2 2013 Tech Feature 02_Layout 1 03/04/2013 16:39 Page 64
Wintershall digs into pocket for Badger
Aveva Marine delivers savings in Angola
GERMANY’S WINTERSHALL IS throwing its financial weight behind Badger Explorer’s bid to develop an innovative tool for drilling from the seabed, adding to the list of big-name backers for the technology including ExxonMobil. The Stavanger-based company is looking to develop the autonomous drilling tool, also named Badger Explorer, beyond the prototype stage to a fully fledged commercial product under a demonstrator programme. Wintershall has now signed a sponsorship agreement for development of the literally ground-breaking technology, joining existing sponsors ExxonMobil, Chevron and Statoil. No value was given for the deal. Badger chief executive David Blacklaw believes the make-up of the sponsorship group demonstrates the industry’s commercial belief in the project, which he said would be further accelerated by Wintershall’s support. The demonstrator programme is intended to implement lessons learned from an earlier prototype project to refine the design of the reservoir evaluation tool, which can drill autonomously from the seabed and relay key data from sensors back to a surface module via an integrated cable. Both Badger and industry backers hope it can lead to major savings on drilling costs by avoiding the use of a rig while making exploration safer and more efficient in challenging operating environments such as the Arctic and deep water. Before bringing Wintershall onboard, the project had received about US$35mn in funding from the industry, including a US$3.4mn grant from Innovation Norway. Badger has also gained US$1.4mn from the Research Council of Norway for a commercial field pilot project, which it aims to carry out next year after completion of the demonstrator programme.
AVEVA’S PORTO AMBOIM Estaleiros Navais Lda (PAENAL) Yard, an Angolan joint venture between Sonangol, SBM Offshore and DSME, has implemented Aveva Marine for the integrated 3D design of offshore steelwork and outfitting across its construction yard. Aveva’s software was selected for its ability to efficiently handle complex steelwork and outfitting design for offshore assets such as FPSOs and platforms, saving time and man-hours, not only in design, but also on the production field. By using a single model database, Aveva Marine will enable PAENAL Yard to create, develop, manage and exploit engineering and design data, achieving benefits such as improved design quality, reduced production rework and optimised use of resources. PAENAL Yard will use Aveva Marine Outfitting to create precise production information such as plate nesting and workshop drawings. “Members of our joint venture have used Aveva software for a number of years on many successful FPSO projects, so we are fully aware of its capabilities,” said Sung-Ho Son, Engineering Manager, PAENAL Yard. “For offshore projects, the technology advantage of integration between disciplines in Aveva Marine is considerable. The ability to drive efficiencies through the entire engineering process using Aveva's highly productive tools helps to ensure that we offer our customers the highest possible quality while delivering savings both in construction deliverable generation and production that improve our bottom line. The work at this yard will support Angola’s growing and strategic offshore oil & gas sector.” “Aveva Marine provides a business-critical set of applications to support PAENAL Yard’s large and complex projects, including Topsides”, added Fredy Ktourza, Senior Vice President – West EMEA, Aveva; “Aveva’s expertise in shipbuilding and offshore is second to none. By offering fully integrated, concurrent development of 3D design data, our other shipyard customers achieve savings of up to 30 per cent. We are confident that by upgrading to Aveva Marine from competitive solutions, PAENAL Yard will be able to achieve similar savings on its projects in the future.”
Huge new testing facility for Viar Vavole
Ground-breaking: the Badger Explorer tool.
VIAR VALVOLE, AN established Italian manufacturer of floating and trunnionmounted ball valves, has invested heavily in a new testing facility close to their factory in Sumirago. The company is represented by Trouvay and Cauvin Ltd. Eric Buchanan, managing director of Trouvay and Cauvin UK commented: “Trunnion-mounted ball valves are often used in critical applications, for instance, oil & gas production and pipelines. Reliable performance, in demanding operating conditions is vital and this new facility sets Viar Vavole at the forefront of testing, verification and quality assurance to meet production and compliance demands in several applications.” Sealing and pressure containment are two critical areas for ball valves: Subsea applications are always sensitive, due to the potential impact on the marine environment and production conditions.
Ghana to build water treatment plant for Jubilee oilfields THE GHANAIAN GOVERNMENT has outlined plans to build an exclusive water treatment plant for the Jubilee oilfields in an attempt to stop the importation of water for oil production from neighbouring countries The measure will be expected to generate more revenue for the government and aid in oil exploration and production activities in the oil field. The plant, when completed, will enable the Jubilee partners to use the treated water for
64 Oil Review Africa Issue Two 2013
their operations instead of importing them from Ghana’s neighbour, Côte d'Ivoire. Ghanaian water resource minister Alhaji Collins Dauda announced the move recently during a one-day duty tour to inspect water plants in the western region. He said that companies operating in Ghana’s oil fields purchased treated water from Côte d’Ivoire because of the shortage of treated water in the country. Alhaji Dauda indicated that the Ghana Water
Company Limited (GWCL) was losing substantial revenue in the oil sector as a result of this situation. The proposed water treatment plant will be build at Essiama in the western region. Major partners at the Jubilee oilfields include America’s Kosmos Energy and Anadarko as well as Anglo-Irish oil explorer Tullow Oil. Meanwhile, Ghana also has plans to build a second desalination plant in the country which will also be located in the western region. www.oilreviewafrica.com
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Weld Overlay Cladding
S18 ORA 2 2013 Offshore_Layout 1 03/04/2013 18:10 Page 66
Alan Robinson, managing director of Arc Energy Resources, discusses the benefits of weld overlay cladding to protect pipelines and associated components from corrosion; and reviews the options available using corrosion resistant alloys.
Using weld overlay cladding to increase
pipeline longevity I
N ORDER TO maintain the efficient and reliable operation of pipelines and other equipment in the oil and gas industry, engineers need to know what techniques are available to extend the life of new components or refurbish worn or corroded ones. Just as importantly, they need to know what the cost benefits are of such techniques compared to the use of expensive base materials or replacing the part. There are a number of options available to protect flanges and the internal surfaces of equipment but the final choice will normally be based on an evaluation of factors such as the application, required service life, operational priorities, installation deadlines and, of course, budget restraints. So, how can engineers ensure the long-term integrity of internal surfaces of pipelines, flanges and other equipment against aggressive corrosion caused by hazardous and corrosive oil and gas environments? Where budget is not a constraint, engineers can simply specify components in corrosion or wear resistant alloys known to withstand the conditions. However, this is rarely the case and other, more cost-effective options are usually sought. Where pipe, flanges or fittings and other components such as valves and pumps, require protection, weld overlay cladding is certainly a versatile option, providing the assurance of a heavy-duty metallurgically-bonded protective layer that will not be degraded in hostile environments. The use of carbon and low alloy steels clad with a corrosion resistant alloy has been common practice for some years and is a well proven, economical and technical alternative to solid alloys. For use in aggressive applications, weld overlay cladding should be considered the default option because it will provide excellent protection and extend service life for new equipment; as well as refurbishing worn or older components that are already badly corroded or eroded. Even pipeline equipment in enclosed areas would benefit from weld overlay cladding. While internal surfaces may need to be fully protected, a conventional and inexpensive stainless steel deposit may be adequate for the flange seal faces of pipes, valves and pumps that may suffer corrosion during their normal service life. For the most corrosive applications, the use of a higher grade stainless steel, complex nickel chromium or hardfacing alloys is normally recommended. Whilst these tend to be expensive if used in solid form, a three millimetre thick layer applied to the affected surface will offer the same operational performance and could lead to significant savings from the extended life expectancy of the equipment.
Protective materials These include austenitic (300 series) stainless steels, ferritic/martensitic (400 series) stainless steels, duplex stainless steels or the more complex high nickel chromium alloys. With apologies to the manufacturers of austenitic stainless steels, it is unlikely they would have the resistance required for the very worst conditions. Inconel alloysâ&#x20AC;&#x2122; oxidation and corrosion-resistant properties make them the material of choice for many severe service applications. They are invaluable in natural gas applications likely to involve sour, corrosive gases such as hydrogen sulphide. However, whilst smaller valves can be cast in Inconel, the cost is frequently prohibitive for larger valves, which is where weld overlay cladding proves its cost effectiveness. When repairing equipment, the affected areas can in many cases be premachined and, using automated weld overlay cladding or specialised
66 Oil Review Africa Issue Two 2013
An example of Arc Energy's weld overlay clad product.
manual welding, rebuilt with a corrosion resistant alloy (CRA) such as complex nickel aluminium bronze. Typically, the repair will even be superior to the original metal!
After first identifying the surfaces that need to be protected, engineers can choose from a number of welding processes and a wide range of cladding alloys Welding processes After first identifying the surfaces that need to be protected, engineers can choose from a number of welding processes and a wide range of cladding alloys. Weld overlay cladding technology presents the materials engineer with a wide choice of welding processes that offer immense flexibility. An almost infinite range of component shapes and sizes can be protected, with an equally wide range of base material/cladding alloy alternatives. The GTAW (TIG) process can be used in bores as small as 20mm, and is ideally suited for components of varied geometry, where the position of the welding head requires frequent adjustment. These could range from a simple flange that needs to be clad through the bore and across the sealing face, to a complex valve body with several interconnecting bores. This flexibility also lends itself to the cladding of irregular shaped components, such as pump and valve internals. GMAW (MIG), submerged arc and electroslag welding processes are used where large areas and thicker deposits are required. Fast deposition rates mean these methods also offer cost savings. A wider selection of consumable materials, which may not be produced in the standard solid wire form, is also available. Selection of the most appropriate welding process is largely dependent on factors such as the size of the clad area; access to the area to be clad;
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Weld Overlay Cladding
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In many environments weld overlay cladding offers clear advantages because protection can be applied specifically to the areas under attack
Arc Energy Resources are capable of restricted access weld overlay cladding to a minimum of 20mm diameter.
alloy type, specified clad thickness; chemical composition limits; welding position; and NDT acceptance standards. Automated or mechanised processes generally offer the best deposition rates and provide the most consistent quality of deposit, which enables adherence to the results provided during procedure qualification testing. Mechanised equipment can be designed to access areas that simply cannot be reached by manual methods. Using this process, the chemical composition of the welding consumable can be achieved at 2.5mm from the base material/cladding interface (this can be reduced to 1.5mm in the case of 300 series stainless steels, where over alloyed wires are available). Submerged arc welding is used where larger surfaces are clad and access is easy. Traditionally larger diameter (2.4mm +) consumables have been used for this process, again resulting in the need for fairly thick substrates to accept the high heat inputs and large weld deposits. Recently, procedures have been developed using 1.2mm wires, allowing use on thinner section components and giving more controlled thickness of deposit, while maintaining deposition rates in the region of five kilograms per hour. There are consumable/flux combinations available that make single layer deposits viable. This is particularly true with duplex and ferritic/martensitic stainless steels. When weld overlay cladding was first employed, re-machining after cladding was the norm, but as techniques and equipment have improved the ‘as welded’ finish has become much smoother, to the extent that many areas of clad equipment are now left as clad. This would not apply to the sealing/gasket areas, which have to be produced to the very finest of tolerances. The fact is that weld overlay clad parts are now widely used in the oil and gas, power generation, chemical and marine industries because the process has proved to be a fast, flexible and cost effective remedy to the effects of corrosion and wear. The choice of coating chemistry is legion; and the processes available extend from the lowly manual metal arc to multi-head hot wire TIG to laser and beyond. Many previously ‘difficult to weld’ materials are now commonly welded with consistent success. And the development of the cladding process is such that the market acceptance standards for the cladding material (a cast structure) are now identical to the acceptance levels for the base material. The acceptance and viability of weld overlay cladding in oil and gas environments has been proven extensively by Arc Energy. managing director, Alan Robinson, has been at the forefront of weld overlay cladding development for over 25 years, and the company is experienced in cladding bores ranging from 20mm up to four metres in diameter and up to six metres in length.
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Arc Energy has developed a wide range of base material/cladding combinations, qualified to standards including ASME, NACE, DNV and ISO. The weld overlay cladding techniques have been tried and tested, and are widely implemented by a wide variety of market sectors. To summarise, in many environments weld overlay cladding offers clear advantages because protection can be applied specifically to the areas under attack, eliminating the need to produce a whole component or item of plant from an expensive corrosion resistant material. However, the overwhelming advantage is its versatility. Whatever the shape or size of the equipment or component there is a process that can be applied and an alloy to counteract the different levels of corrosive attack. Weld overlay cladding is a proven and recognised cost saving technology that is already well established and engineers in extreme environments are sharing the significant benefits, both practical and financial, of increased life expectancy. And finally a caveat: the development of today’s cladding technology is so tightly defined that it is important to use a cladding provider that maintains the best quality structure and technical support. At the very least, the provider should hold ISO 3834-2 (Comprehensive Quality Requirements for Fusion Welding of Metallic Materials) and employ the services of a European Welding Engineer. ■
Arc Energy has developed a wide range of base material/cladding combinations.
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ICT
The choice of communications services open to the oil and gas industry is growing — and could soon accelerate. Various new satellite services and spectrum are available or on their way to offshore or remote installations — as are fibre optic links. In our second look at the topic, Simon Bull of COMSYS* tells Vaughan O’Grady that new services will open up new — and possibly much cheaper — possibilities.
Offshore communications: more, faster
better and cheaper? I
N PART ONE of this feature we discussed the arrival of the Epic satellite platform from Intelsat, a major provider of satellite services. This is a ‘game-changing’ approach to satellite-based communications according to Simon Bull, senior consultant with specialised telecommunications consultancy COMSYS. Epic could, in theory, offer end users more bandwidth at a lower price and a higher power than before, enabling smaller antennas on the ground. It could also do so in the Ku and C bands that many oil companies favour but where spectrum has been limited in recent years. However, that revolution, if it happens, is a few years off. But it won't be alone. Systems like O3b and Iridium NEXT are going to bring even more options. O3b describes itself thus: “O3b Networks delivers broadband connectivity everywhere on Earth within 45° of latitude north and south of the equator. Our vast coverage area includes emerging and insufficiently connected markets in Latin America, Africa, the Middle East, Asia and Australia, with a collective population of over three billion people.” Hence O3b, or ‘other three billion’. One of the reasons O3b is going to bring “significantly more bandwidth at a decent price and with low latency”, as Bull puts it, is that its satellites are in a lower earth orbit than those of many other systems so can offer reduced round-trip data transmission times. “Of course,” he adds, “that also means it’s more limited. It can only go 45º north, 45° south; you need at least two tracking antennas [on board your vessel or rig] — and possibly lots more.”
Deck real estate is an issue on ships and rigs. Photo: Schlumberger
More satellites involved Also as an MEO (medium earth orbit) system, it will involve more satellites. Most GEO (geostationary earth orbit) systems are at such great distances from the earth that only three are needed for global coverage. Initially O3b is launching 12 satellites of which the company needs eight for coverage “but it’s not total coverage”, says Bull. That 45-° north and 45-° south restriction could limit the amount of business on offer. However, there are still numerous opportunities. For example O3B has recently announced a contract with Royal Caribbean — the largest cruise ship in the world. This is a way of ensuring an attractive extra offering of guaranteed broadband to customers as part of the overall cruise price. West Africa Telecom, one of Liberia’s leading internet service providers, has also signed up. Could oil rigs join them? O3b is certainly targeting the energy sector with its promise of low latency and
70 Oil Review Africa Issue Two 2013
O3b is going to bring significantly more bandwidth at a decent price and with low latency.
unlimited, moderately priced bandwidth. That promise, incidentally, includes the possibility of personal communications for the crew. Crew welfare and retention is certainly likely to be improved if crew members feel less isolated at extreme distances offshore.
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ICT
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So new installations and those further offshore could offer an opportunity for systems like O3b.
These developments are nevertheless going to make things interesting for oil and gas operators, even if how is not precisely clear. However, while low latency and high bandwidth are important, Bull points out that “deck real estate is an issue on ships and rigs. These antennas are not small or cheap — and you need at least a couple of them because you’ve got to track satellites; you hand off [from one satellite to another] as the satellite goes overhead.”
A game changer? However, says Bull, such a system could still, like Epic, be game changing. For example, there are multiple production platforms off the Gulf of Mexico connected by an expensive floating fibre system. He explains the options thus: “If I said “You don’t have to spend US$100mn on fibre; you can put a US$100,000 antenna system on each of those platforms and pay a few million a year and have capacity and low latency,” would that be worth doing?” Future shallow water rigs might therefore save money by going for satellite broadband rather than fibre. However, places like deepwater Nigeria and
Angola may be a better target for broadband satellite: fibre hasn't reached there yet and may be economically unviable. In any case, deepwater Brazil, Eastern Australia or West and East Africa may not have to worry about fibre at all if Epic and O3b can do the job. Essentially fibre is no longer the only broadband game in town. Iridium NEXT is a different approach. It’s an L band and Ka band system with a staggering 66 low-earth orbit satellites and 15 more as back-up. However, it’s not going to be a broadband power to rival O3b. It offers the following sales pitch: “Iridium NEXT is designed to accommodate secondary payloads. Real-time data feeds anywhere on Earth, plus secure tasking, command and control, and opportunities for payloads such as climate change surveillance, low-resolution Earth imaging, and space weather.” And of course, L and Ka mean small terminals on board. “It’s going to be expensive, but as a backup to a VSAT service it could be very interesting,” suggests Bull. The NEXT launch programme begins in 2015, as does the Epic launch programme. O3b’s launch programme begins this year. As Bull puts it, “There’s a lot happening in the market which is interesting for both the oil and gas community and the operators that service that industry.” But how necessary in reality is all this communications choice to oil companies? To an extent it depends on where they are searching for oil and gas. For example, the likes of Shell have spent millions on fibre optic connections not too far offshore that link back to the mainland and that, arguably, exceed their needs. Fibre optic links may have seemed necessary when it was calculated that many important staff offshore might be allowed to move back onshore. However, regulation has made it difficult to run rigs with tiny staff numbers. So the potential 100 meg per second offering isn’t actually sending that much data back. The amount of data coming off a rig has nevertheless been growing quite significantly: go back a few years and a rig would typically have a 512kb link. Today it is one to two megs. “But it’s not 10 megs and generally they don’t see themselves as needing 10 megs,” Bull points out. “They’re quite happy with one or two.” So new installations and those further offshore could offer an opportunity for systems like O3b. However, the system’s owner, O3b Networks, will have to pre-book enough capacity to make the oil
industry a worthwhile target. It is by no means clear yet whether that will happen. These developments are nevertheless going to make things interesting for oil and gas operators, even if how is not precisely clear. Bull sums up, “What the oil and gas operator is looking at is new services and new capacity coming on line almost every year over the next three-to-five years. And it gives a great deal more possibility, both in terms of casual bandwidth and mission-critical bandwidth.” That brings us back to O3b’s point about crew retention. The cheaper the service the more purposes it could be used for. For example one approach might be to use more than one communications source: one — say fibre or O3b — for business and technical needs, another — say GSM on board with VoIP L-band satellite backhaul for personal use (this is already making an impact on container ships; see http://www.globewireless.com/solutions/ifusion). Latency would vary depending on the importance of the link; a minuscule delay would be less of an issue for personal communications. Meanwhile of course there’s a growing tendency to launch Ka band satellites and offer Ka band services — although not to offshore Brazil, Nigeria, or Angola as Ka band attenuation is still hard to avoid in rainy areas like these. But does that always matter? A modestly priced Ka band system could be used solely for the crew, suggests Bull. In such a case, as we noted above, occasional rain fade wouldn't be a major issue and the crew would get a decent link most of the time. “And equally,” he adds, “there are some places in the world — Australia may be one, Saudi and the Middle East may be another – where atmospheric attenuation is not the issue. Could they use Ka band? Absolutely.” The economic benefits may take a long time to filter through to the oil and gas sector but one thing seems certain: more communications competition is on the way. It’s going to be an interesting few years. ■
*COMSYS is a specialised telecommunications consultancy company with a core expertise in satellite and VSAT systems. The Comsys Maritime VSAT Report 3rd Edition has recently been published. It includes coverage of the oil and gas sector. For more information go to www.COMSYS.co.uk
Expro wins award for no leaks safety video LEADING INTERNATIONAL OILFIELD services company, Expro, has won the ‘Best Audio Visual Employee Communication’ prize at this year’s Scottish Communications Awards. The No Leak is Acceptable video was part of an internal safety campaign focused on teamwork and communication as effective ways of reducing hydrocarbon releases. Improving asset integrity performance by preventing all hydrocarbon releases is a primary goal for all Expro employees. The No Leak is Acceptable campaign video is
72 Oil Review Africa Issue Two 2013
based on a football team’s training day in preparation for a big match. The award jury stated that ‘the Expro video was perfectly pitched for the target audience and handled the issue of health and safety in a different way’. ‘No Leaks’ beat off stiff competition in a very competitive sector. The Awards are run by the Institute of Internal Communication Scotland (IoIC) , which exists to deal with common issues and concerns within the industry, to share best practice and to encourage excellence
in all aspects of internal communications. The IoIC is the UK’s leading professional body for all those involved in internal communications. Keith Palmer, Expro’s Europe CIS region director, said: “Rarely does a health and safety video win a best employee communication award so it’s great to be recognised. “Safety is of paramount importance to us and this original initiative highlights Expro’s commitment to safety and the prevention of hydrocarbon leaks.” www.oilreviewafrica.com
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TDW OFFSHORE SERVICES (TDW) , for the first time, is offering its SmartTrack™ remote tracking and pressure-monitoring system for use in the global marketplace. Until now, this proprietary technology has been used exclusively by TDW to carry out pipeline pressure isolation operations in conjunction with the company’s SmartPlug® isolation system. TDW has executed several hundred isolation operations with the SmartTrack system in a wide variety of pipeline contexts. The success of these operations demonstrates not only its ability to remotely track inline tools and monitor pipeline pressure, but underscores its versatility and reliability. “The SmartTrack system is a critical component of our pressure isolation service capability,” said Enzo Dellesite, Director – Global Market Development Offshore for TDW. “It helps us to isolate pipelines successfully, whether the job is to facilitate pipeline repairs or clean a line choked with debris. Given its versatility and success in the field, we made the decision to make the SmartTrack system readily accessible to operators and service companies that The SmartTrack remote tracking and pressure-monitoring system module.
want to avail themselves of the wide-ranging benefits it offers,” he added. As operators move into remote territories to unearth new sources of oil and gas, unique challenges in the installation and maintenance of complex pipeline networks arise. These challenges demand more innovative technology, such as remote-controlled systems to inspect the pipelines and to isolate pressure during repair operations. Critical to these isolation procedures is the ability to control, track, and monitor pressure isolation tools. TDW responded by developing the SmartTrack remote tracking and pressure-monitoring system. The SmartTrack system can track a wide range of devices in almost any environment. For example, the system’s flexibility came in a pipeline cleaning and pressure isolation operation carried out offshore the United Arab Emirates. The high friction pig train remained in the line for seven days while maintenance was conducted. Working from an offshore platform 200 meters away, technicians reviewed a continuous flow of data from SmartTrack transponders attached to the pigs. “We are delighted by how these operations, and countless others carried out offshore and onshore, have demonstrated just how effective the SmartTrack system is,” said Larry Ryan, Director of Operations for TDW Offshore Services. “In view of its performance in the field, we are confident that we offer operators the most reliable means of tracking and locating any sort of device within a pipeline, in any environment.” The SmartTrack system can be used nearly anywhere to track any device within pipelines up to a thickness of 50mm. It is also an effective means of tracking specially designed pigs in sequences used to flood, clean, and gauge pipelines during pre-commissioning. For subsea operations, transceivers can operate in depths to 3,000 meters with a maximum cable length of 1,200 meters, and acoustic links can be established on transceivers contained within subsea skid packages.
Peak launches SIM FloWell for formation damage removal BPEAK LAUNCHES SIM FloWellTM for Formation Damage Removal that Kick-Starts Well Productivity 20 march + pics SPECIALIST DOWNHOLE TOOL provider, Peak Well Systems has added a new addition to its proprietary SIM System range for well remediation and flow control. SIM FloWell is slickline-set remedial technology capable of removing formation damage within selected downhole zones and thus improving well productivity. SIM FloWell is designed to improve well productivity by being able to remove certain
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types of formation damage (eg, crushed zones in perforation tunnels, tenacious filter cakes and scales) in both oil and gas wells that are wireline-perforated. The condition of the nearwellbore region is critical to the production of hydrocarbons, and the perforating process is one major contributor to skin damage. The severe compressive force of perforating can reduce the permeability of the surrounding rock, which in turn reduces productivity. Like the rest of the products within the SIM System range, SIM FloWell is run, set and retrieved on slickline. Used in conjunction with Peak’s SIM Plug Systems to provide
selective isolation of the zone to be treated, SIM FloWell induces a sudden pressure drawdown in a wellbore, and hence causes a surge of fluid inflow from the reservoir.
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Innovations
TDW Offshore Services offers Smarttrack monitoring system to global market
Technology
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CPTDC offers in-time and all-round service CHINA PETROLEUM TECHNOLOGY & Development Corporation (CPTDC) is a wholly-owned subsidiary of China National Petroleum Corporation (CNPC). CPTDC engages in the provision of petroleum and petrochemical materials and equipment to the world market. By the end of 2012, CPTDC has provided its products to 78 countries and regions across the world. CPTDC has obtained strong marketing capabilities, with 67 marketing facilities in 51 countries. Maintaining a mature marketing network covering the world major oil production countries, CPTDC is fully capable to provide customers professional, in-time and all-round service. CPTDC has established stable largescale markets in Central-Asia-Russia, Africa, Americas, the Middle East and Asia-Pacific Areas and maintained close relationships with over 700 customers including NOCs, IOCs and world-famous service companies, providing 70 kinds of main products in 8 categories. CPTDC has been acknowledged as China’s largest supplier of petroleum and petrochemical material and equipment to the world market.
Full-field 3D compex reservoir models BAKER HUGHES HAS announced the availability of its JewelSuite™ 3D geomechanics software system, designed to promote better complex field development strategies by enabling users to quickly and accurately predict full-field geomechanical behavior under drilling, stimulation and production scenarios. These strategies are essential in helping oil and gas operators reduce costs and improve hydrocarbon recovery in complex reservoirs and fields. The system combines Baker Hughes’ JewelSuite reservoir modeling software with Abaqus Finite Element Analysis (FEA) software, a robust finite-element mechanical simulator from Dassault Systèmes. The Abaqus simulator uses proven algorithms to simulate the non-linear stress, large deformation, compaction and subsidence that can occur during production from hydrocarbon-bearing reservoirs. The resulting JewelSuite 3D geomechanics software system enables users to quickly build highperformance numerical simulations that support parametric studies, help identify uncertainties in reservoir development models, and condense large full-field 3D reservoir views into more manageable high-resolution geomechanical simulations. Users can also integrate seismic, structural, geological, geomechanical and fluid-flow models into a single, multidisciplinary workflow that helps reduce uncertainty and increases confidence in modeling results. In addition, users can more accurately calculate deformations within and around a reservoir, as well as anticipate the necessary steps to mitigate subsidence; and it offers the ability for users to quantify stress changes, the impact on production, long-term completion stability and fault activation, minimising risk and facilitating improved hydrocarbon recovery.
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