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■ Geology - p28 ■ Gas - p30 ■ E&P - p32 ■ Technology - p44
Volume 8 Issue Four 2013
www.oilreviewafrica.com
Africa
Covering Oil, Gas and Hydrocarbon Processing
Europe m10, Ghana CD18000, Kenya Ksh200, Nigeria N330, South Africa R25, UK £7, USA $12
Namibia: more than just gas Libya - great energy expectations National content in Equatorial Guinea Risk management in sub Saharan Africa Fire prevention and protection Environmental issues Bringing simplicity to subsea operations Virtual flow metering How to combat cybercrime
XFIELD, a new geophysical software modelling tool enables explorationists to seamlessly integrate and analyse potential field data alongside their seismic data. See page 70
Extending the life of ageing fields
REGULAR FEATURES: ■ News ■ Contracts ■ Events Calendar ■ IT update ■ Company profiles ■ Products & Innovations
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S01 ORA 4 2013 Start_Layout 1 19/08/2013 16:42 Page 3
■ Geology - p28 ■ Gas - p30 ■ E&P - p32 ■ Technology - p44
Contents
Volume 8 Issue Four 2013
www.oilreviewafrica.com
Africa
Covering Oil, Gas and Hydrocarbon Processing
Europe m10, Ghana CD18000, Kenya Ksh200, Nigeria N330, South Africa R25, UK £7, USA $12
Namibia: more than just gas Libya - great energy expectations National content in Equatorial Guinea
Columns
Risk management in sub Saharan Africa
Industry news and executives’ calendar
4
Fire prevention and protection Environmental issues Bringing simplicity to subsea operations
How to combat cybercrime
Energy consumption growth slows significantly
10
Oil remained the world’s fuel of choice in 2012, but structurally and regionally the energy markets have continued to change.
XFIELD, a new geophysical software modelling tool enables explorationists to seamlessly integrate and analyse potential field data alongside their seismic data. See page 70
Extending the life of ageing fields
REGULAR FEATURES: ■ News ■ Contracts ■ Events Calendar ■ IT update ■ Company profiles ■ Products & Innovations
Refurbishment of support structure, spot blasting on an offshore platform in Congo-Brazzaville.
Risk Management Sub Saharan Africa: a diverse and challenging operating environment 14 A look at the overall security context in sub Saharan Africa and the operational and security implications.
Editor’s note
Country Focus Namibia
16
Drillers are re-thinking Namibia after the discovery offshore of non-commercial quantities of light oil earlier this year.
Libya
20
Greater energy expectations hinge on much-needed stability.
Equatorial Guinea
24
The government here is about to implement some new national content regulations.
E&P News and developments
32
A round-up of recent exploration and production activity from around the region.
Technical Focus Fire prevention and protection on oil rigs
40
Great gains have been made in rig design, the materials used and in the training of rig personnel in order to tackle and reduce the inherent risks of the oil and gas industry.
Extending field life
AFRICA’s OIL AND gas industry is poised for momentous growth. Large gas finds in Mozambique and Tanzania‚ and oil potential in Uganda and Kenya‚ have sparked a flurry of exploration activity across Africa. In Namibia, drillers are re-thinking after the discovery offshore of noncommercial quantities of light oil earlier this year. Given its proximitiy to oilrich Angola and the presence of one of Africa’s largest offshore gas fields, Kudu, there are strong hopes that there is more than gas in the region. In addition, governments around Africa are reviewing or developing their energy policies. Many countries are investigating changes in the government take‚ taxation regulations and state participation. In this issue we look at Equatorial Guinea, where the Ministry of Mines and Energy is in the process of passing a new national content law. North of the Sahara, we look at post-conflict Libya, whose great energy expectations hinge on much-needed stability. Extending the life of a field through enhanced oil recovery techniques is becoming increasingly relevant to Africa with many techniques now being deployed in established territories such as Nigeria to give ageing assets a new lease of life.
50
44
How the oil industry is extending the life of ageing fields in Africa.
Subsea operations
46
Bringing simplicity to Africa’s subsea operations.
Environmental issues
50
Processing drilling wastes at source.
Virtual flow metering
56
Virtual flow metering empowers global success.
Innovations
60
Introducing some of the latest technology for the oil and gas sector.
Information Technology Combatting cyber crime
66
How prepared is the energy sector in combatting cyber crime and how prepared does it need to be?
TWMA's TCC RotoMill has been adopted by the international offshore oil & gas market, driven partly by evolving drilling waste disposal legislation, but also by operators consistently adopting drilling waste management best practices wherever they work.
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Virtual flow metering
Analysis
Industry News & Events
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Executives Calendar 2013/14 SEPTEMBER 2013 3-6 10-12 16-18 19-21 24-26
Offshore Europe The International Forum for QHSE Technology Libya Forum 3rd Tunisia Oil & Gas Summit 3rd U & D Oil & Gas Summit
ABERDEEN CAIRO TRIPOLI HAMMAMET ABUJA
www.offshore-europe.co.uk www.qhseegypt.com www.cwc-libya-forum.com www.tunisiaoilandgas.com www.oilandgasexpos.com
Oil & Gas Marrakech Power Nigeria East Africa Oil & Gas Summit Somalia Oil & Gas CIOME 2013 AfricaTech The Ghana Energy Local Content Forum North African Downstream Summit Nigeria Oil & Gas Trade and Investment Forum 2013 NOCs & Governments Summit
MARRAKECH LAGOS LONDON LONDON N'DJAMENA CAPE TOWN ACCRA TUNIS ONNE LONDON
www.oilgas-marrakech.com www.power-nigeria.com www.eastafrica-oil-gas.com www.cwc.com www.ciome-chad.com www.europetro.com www.hialphaevents.com www.wraconferences.com www.nigeriaoilandgasinvest.com www.nocs-governments.com
GOG 2013 NAPE 2013 International Conference 8th LPG Trade Summit 3rd Practical Nigerian Content Natural Resources Development 16th Africa Oil Gas Mine Trade & Finance Angola Recruitment Summit Africa Oil Week
ABIDJAN LAGOS DOHA YENAGOA NIAMEY NIAMEY LONDON CAPE TOWN
www.cwcgog.com www.nape.org.ng www.cmtevents.com www.ncipnc.com www.ogtfafrica.com www.ogtfafrica.com www.eliteic.net www.petro21.com
Offshore West Africa
ACCRA
www.offshorewestafrica.com
Nigeria Power Nigeria Oil & Gas 2014
ABUJA ABUJA
www.nigeria-power.com www.cwcnog.com
Ghana Oil & Gas Summit 2014
ACCRA
www.cwcghana.com
OCTOBER 2013 1-3 2-4 7-10 7-10 8-11 9-10 21-22 21-22 24-25 28-30
NOVEMBER 2013 6-8 10-14 18-20 19-21 20-23 20-23 22-24 25-29
JANUARY 2014 21-23
FEBRUARY 2014 24 24-27
APRIL 2014 8-10
Readers should verify dates and location with sponsoring organisations, as this information is sometimes subject to change.
Africa Oil Week celebrates 20th anniversary AFRICA OIL WEEK, the world’s longest standing and leading meeting for Africa’s oil and gas industry, celebrates its 20th anniversary, as over 1,250 delegates from six continents attend the Conference (Cape Town, 25-29 November). Over 100 speakers from leading corporates, governments, national oil companies, licensing agencies, independents, banks, service and supply, analysts and institutions and will attend and give an insight into the continent’s future. As the Conference Chairman, Dr Duncan Clarke remarked: “With a consistent record of oil and gas discoveries, and rising oil and gas reserves across its hydrocarbon terrains, growing oil & gas production, new ventures and discoveries, and several LNG developments, with large oil and gas potential in the north, and the world-class onshore/offshore discoveries in the fastemerging east coast, Africa remains one of the
4 Oil Review Africa Issue Four 2013
key regions in the global oil and gas game.” The 20th Africa Oil Week, organised and hosted by Global Pacific & Partners, is the landmark occasion for Africa’s energy industry, a meeting with an established global reputation and one of the top world-class conferences held annually in the international oil and gas industry calendar. The conference provides the highest levels of networking across the oil and gas-LNG and energy industry on the continent. Delegates obtain unrivalled insights on Africa’s fastmoving oil and gas game, exploration strategies, corporate assets/portfolio, bid rounds, open acreage, investment potential, emerging technologies and key themes, with discussion panels for direct interface between senior executives, governments and stakeholders. The Programme for this year’s Africa Oil Week includes the 15th Scramble For Africa Strategy Briefing on November 25th, the 10th Africa
Independents Forum on 26 November, the 20th Africa Upstream Conference during 2729 November, with Annual Board Awards, and the 54th PetroAfricanus Dinner on 25 November. During the Scramble for Africa Strategy Briefing, Dr Duncan Clarke provides original insights on the continent’s competitive upstream oil and gas game based on in-depth tracking of changing competitor maps across Africa for oil and gas-LNG companies and state oil entities, built on seasoned insights and interpretations of around 750 players, thus drawing a unique image of Africa’s emerging and fast-changing petro-cartography. In 2013 the conference takes place at a new venue: the Cape Town International Convention Centre, able to accommodate 1,500 delegates in the auditorium, and with added capacity for exhibition stands, corporate showcases and parallel sessions which feature special themes. www.oilreviewafrica.com
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Industry News & Events
S02 ORA 4 2013 News_Layout 1 19/08/2013 16:38 Page 6
Angola to seek new forms of contract IN ORDER TO spur investment, Sonangol is expected to use Risk Services Agreements (RSAs) to promote exploration of its southern territory in the medium term, according to research and consulting firm GlobalData. According to the company’s latest report, although Production Sharing Agreements (PSAs) will continue to be the preferred form of contract in Angola, the number of RSAs is likely to increase because of the advantages of direct negotiations with potential operators. Sonangol has awarded its first RSA to investors in recent years, most notably for blocks 9 and 21, which were originally offered under PSAs in the country’s aborted 2008 licensing round. PSAs are an agreement between the government and the oil company where the profits from the oil production are split between both parties. RSAs are partnerships wherein the government pays the oil company a fee to explore an area, and if commercial production is viable, the government pays the firm for its extractive services but they are not entitled to what is produced. As Angola begins to license its ultra-deepwater areas in the medium term, incentives are likely to be required to counter the increased costs and risk associated with drilling in these areas, states the report. “There are ways to increase the attractiveness of PSAs for this, but Sonangol could also opt to spearhead exploration under RSAs,” stated John McCormack, GlobalData’s lead analyst for sub-Saharan Africa, “though under any contract local content requirements, which push up costs, are still likely to be applicable.”
6 Oil Review Africa Issue Four 2013
SPE Offshore Europe looks to the future ELEVEN KEYNOTE SESSIONS will give visitors to the SPE Offshore Europe 2013 conference unprecedented access to hear the views of top industry executives, government ministers and discipline specialists. These sessions respond to the conference theme, ‘The Next 50 Years’, and they form just one part of the event, which will be held in Aberdeen 3-6 September 2013. Egbert Imomoh, SPE President for 2013, said: “This outstanding four-day conference provides an excellent opportunity for the exchange of ideas and information as well as networking with our colleagues from around the world. SPE Offshore Europe provides a rich environment that will spark the curiosity, thought processes, research and activities that will assist us in meeting the growing global demand for energy resources.”
A top line up of industry and government speakers is confirmed to debate the keynote session topics which are relevant to anyone connected with the industry either in the UK or internationally. Conference delegates will have the opportunity to put their questions to the speakers at the end of each session. These include: 6 Oil and gas in the future energy mix 6 The global opportunity: exporting oil and gas services, goods and expertise 6 The independent oil company – mighty oaks from little acorns grow 6 Industry progress since Macondo 6 Taking operations to frontier areas 6 Decommissioning and value extraction for end of life 6 Financing investments in the oil and gas industry: challenges and opportunities.
Oil & Gas Libya exhibition set against strong market recovery FOLLOWING THE SUCCESS of Oil & Gas Libya 2013, plans for the sixth event in the series - Oil & Gas Libya 2014 - are set for 12 15 May 2014 at the Tripoli International Fairground under the joint patronage of Libya’s Ministry of Oil & Gas and National Oil Corporation (NOC). Confidence in Libya’s oil and gas sector has grown in line with the new wave of optimism which is prevalent following the recent democratic elections. Oil output has now risen above pre-conflict levels and is on stream to meet the NOC’s target of 2.2mn bpd by 2020. Gas output is also set to increase from its current level of 12 bcm to 15 bcm by 2020. The strong recovery in oil and gas
production is a reflection of Libya’s energetic plans for huge economic development which is backed by long term budgets totalling US$500bn over the next 25 years. This will be spent on the regeneration and construction of the country’s infrastructure immediately starting with the upgrading of existing vital services such as telecommunications, power, water and transportation, all of which are sectors vital to Libya’s oil and gas industry growth. The 2013 edition of Oil & Gas Libya, which was officially opened by Libya’s Oil Minister Dr Abdulbari Al-Arusi, attracted over 3,000 oil industry professionals who visited the exhibition to meet with 120 exhibitors from 18
countries. Major national exhibit presentations included France, led by Total in association with GEP, France’s oil industry organisation; Turkey, led by Turkish Petroleum Corporation; and China, led by China Petroleum Technology and Development Corporation. 90 per cent of exhibitors achieved their participation objectives and are planning to return in 2014 in order to maintain the momentum of their market development. Libya is calling on the international community to bring much needed technology and expertise to revitalise its energy sector including exploration, production, pipelines, refining & petrochemicals, HSE and training.
Deep, ultra-deepwater capex growth predicted INFIELD SYSTEMS’ NINTH Global Perspectives Deep and Ultra-deepwater Market Report to 2017 sees capex in those depths grow over the next five years. The forecast is for water depths of 500 metres and more. Demand is pushing exploration further offshore into harsher and deeper waters, says Infield. Deepwater reserve additions are expected to remain a marginal proportion of overall global production; rising from a seven per cent cumulative share of global reserves in 2012 to 10 per cent by 2017. In capex terms, the deepwater market, which requires higher capital expenditure than its shallow water counterparts, is expected to rise from a 38 per cent share in 2012 to a 53 per cent share of global offshore capex by 2017. Even with attention centered on the “Deepwater Triangle” of Brazil, West Africa, and the Gulf of Mexico, Infield sees support coming from less traditional deepwater arenas such as Southeast Asia, Australasia, and Europe. Substantial growth is also predicted for the Middle East and Caspian.
Advances in technology make ultra-deepwater drilling possible.
Brazil is expected to lead the deepwater market with spending on the Lula and Franco developments. While West Africa will continue to lead the continent, deepwater activity should increase offshore East Africa, particularly the Prosperidade complex offshore Mozambique. www.oilreviewafrica.com
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W African banks to service E African oil finds
COTE D’IVOIRE’S MINISTRY of Petroleum & Energy, PETROCI and International Gas Union will host the CWC Group's 16th Gulf of Guinea Oil & Gas Conference (GOG16) in Abidjan in November . The event is one of the longest running and most recognised platforms to focus on West Africa's energy sector and confirmed to be inaugurated by the country’s Minister of Petroleum & Energy, HE Adama Toungara. Both Toungara and Petroci’s Director General, Daniel Gnangni have been personally involved in inviting energy ministers from across the region. According to Daniel Gnangni, "Petroci are very pleased to be co-hosting the 16th edition of CWC’s Gulf of Guinea Gas Conference (GOG16), recognised as the most senior and established forum to focus on West Africa’s thriving gas sector. This strategic conference will gather representatives from governments, national oil and gas companies and leading operators to exchange ideas, share experiences, and devise future strategies to increase the participation of indigenous players in gas activities and promote industrial and economic development.” The event provides an unrivalled opportunity to network and participate in a variety of meetings and discussions regarding the industry's future. This year’s event will have a special focus on the Gulf of Guinea’s hydrocarbons industry and will examine options of gas monetisation, future intra-regional collaborative projects and the role of gas as an economic driver for the region. For more information see www.oilreviewafrica.com
OIL AND GAS finds in East Africa have become very attractive to West African financial services firms with these firms starting up divisions there. With this move, West Africa’s financial services firms want to capitalise on insuring and financing oil and gas projects in East Africa. South Africa’s banks and insurance companies had also identified this opportunity a little more than three years back. Insurance firms Ghana Re and Nigeria’s Continental Re have launched new wholly-owned firms in Nairobi in the past 12 months, paying more attention to the oil and gas sectors. Old Mutual Kenya, a wholly-owned subsidiary of the London and JSElisted life insurer Old Mutual, has introduced its products in Kenya. It is not clear if it will expand to other parts of East Africa. Nigeria’s lender, GT Bank, recently said it was acquiring a 70 per cent shareholding in Kenya’s Fina Bank with the aim of providing finance in the oil and gas sectors. Another West African lender, Ecobank, has seen its Kenyan unit, Ecobank Kenya, say it will start an investment bank in the next two months to lend in these sectors. In 2008, South Africa’s Standard Bank acquired Kenya’s CfC bank with the aim of exploiting imminent opportunities in the country. In 2011, FNB, a wholly-owned subsidiary of FirstRand, South Africa’s third biggest bank, set up its first branch in Dar es Salaam. The bank, which already has a presence in Kenya, has plans to expand to Uganda and Rwanda. It is believed that Kenya and Uganda have about 2.5bn barrels in oil resources while Tanzania has unprocessed gas resources amounting to 33 tcf. East Africa’s financial services firms have been slow to take up these opportunities because they are not well capitalised and lack appropriate skills.
www.oilreviewafrica.com
Oil Review Africa Issue Four 2013 7
Industry News & Events
GOG16 comes to Abidjan
Industry News & Events
S02 ORA 4 2013 News_Layout 1 19/08/2013 16:38 Page 8
BP in Angola subsea award BP's PSVM FPSO off Angola.
WOOD GROUP KENNY (WGK) has recently been awarded a new contract containing two engineering services scopes with BP Angola under the BP Global agreement awarded to WGK in 2007. The contract involves subsea operations support: one is for work associated with the Block 18 Greater Plutonio Operations group; the other is for work associated with Block 31 PSVM (Plutao, Saturno, Venus and Marte fields) operations group. The US$18mn contract secures the provision of Wood Group Kenny’s Subsea Engineering and Project Management Services (EPMS) for an initial 12 month period in one of BP’s key ultra deepwater provinces. Wood Group Kenny CEO, Steve Wayman said: “The award of this significant contract enables us to extend our long-standing relationship with BP Angola for whom we have previously worked for a number of years. We are proud to continue our work with BP in this important region and look forward to using the knowledge we have built up in the project development phase, and applying it to BP Angola’s benefit in the production arena.
Ocean Rig wins $1.3mn award for newbuild
Swala to sell its shares to local communities
OCEAN RIG UDW has received a letter of award from a major oil company for the Ocean Rig Skyros (UDW drillship), which is currently under construction. The letter of award is for a six-year contract with a backlog valued at approximately US$1.3bn for drilling offshore West Africa. The letter of award is subject to the completion of definitive documentation and receipt of regulatory approvals. The six-year contract is expected to begin immediately following a contract with Total E&P Angola. Ocean Rig also reported that it had signed a definitive agreement with Total for the rig. Total will use the Ocean Rig Skyros for a five-well or minimum 275-day drilling programme offshore West Africa; the contract will begin after the drillship’s delivery from Samsung Shipyard in South Korea in October 2013. The Total contract will begin in late December 2013 and run through early October 2014 at a day rate in the low US$580,000s. Ocean Rig estimates the Total contract to have an estimated backlog of around US$190mn. Ocean Rig said the letter of award brings its total contracted backlog to approximately US$6.1bn. The company owns and operates 10 ultradeepwater units, including two semi-submersibles and eight drillships. Three of these rigs are scheduled for delivery this year and one for delivery in 2015.
AN OIL AND gas exploration and production company in Tanzania plans to offer for sale to local communities some of its shares to help them have a stake in the ownership of the company. "We invite expression of interest for the management of the 3.27mn shares that we set aside when the company was established in July 2011 for the benefit of local communities who often see little of the value that can accrue to investors in natural resources," the Swala Oil & Gas (Tanzania) Ltd Chairman, Mr Ernest Massawe said. Mr Massawe said that they have spent a long time assessing how best to maximise the value of their activities to the country and had recently demonstrated their dedication to sustainability through education by sponsoring geology students at the University of Dar es Salaam. "When we established Swala, we deliberately ring-fenced equity to be set aside for the benefit of the local people in the areas where we operate. In effect, this gives a degree of local ownership that is unprecedented in East Africa and we aim in this way to bring some of the benefits that accrue to investors in oil and gas companies to the local communities," the Chief Executive Officer, Dr David Ridge said.
Offshore drilling expenditure to climb THE GBI REPORT, recently released, put yearly offshore drilling expenditure in the Middle East and Africa at US$17bn by 2016. According to the report, an increase in offshore discoveries has been prompting a surge in exploration activities across the Middle East and Africa and driving up the expenditure on drilling. GBI Research forecasts offshore drilling expenditure to climb steadily from US$13.56bn in 2012 to US$17.03bn in 2016. The report disclosed that drilling outlay is expected to grow across all major nations in the region, with those in West Africa leading in terms of exploration activity.
8 Oil Review Africa Issue Four 2013
“Escalating activity in countries relatively new to the offshore drilling industry, such as Sierra Leone and Liberia, may prove to be future competition for the more established nations of West Africa.” GBI expects Ghana to emerge as one of the most prominent countries in West Africa for the exploration of oil and gas, with 16 offshore discoveries made between 2008 and 2012 - second only to Angola, where 22 discoveries were made during the same period. It stated: “In terms of drilling expenditure, Angola is expected to remain the biggest spender in the region by some
margin, over the next few years at least. Research expects drilling expenditure in the Southern African country to continue climbing in the near future, hitting US$6.67bn in 2016. Nigeria and Egypt are forecast to place second and third, with totals of US$2.26bn and US$1.52bn, respectively. The report provides an in-depth analysis of the offshore drilling market in the Middle East and Africa region and highlights the various concerns, shifting trends and major players in the region. Also, the Organisation of Petroleum Exporting Countries
(OPEC) has identified fossil fuels as dominant in meeting global energy demand for the foreseeable future. The OPEC Secretary General, Salem El-Badri, who made this disclosure recently at the 2nd Gas Summit of the Gas Exporting Countries Forum in Moscow, added that biofuels and nuclear currently account for 87 per cent of global energy demand, and will still make up 82 per cent by 2035. According to him, of all fossil fuels, natural gas is expected to witness the fastest growth rate, at close to 2.5 per cent annually, “And its overall share in the fuel mix rises from 23 per cent today to 26 per cent by 2035”. www.oilreviewafrica.com
S03 ORA 4 2013 Analysis_Layout 1 19/08/2013 16:42 Page 9
Energizing a refinery to protect its most valuable resources. People.
Follow the Charge Safe, dependable power is critical to a successful refinery operation. Equally critical is the safety of the crews working in these highly powered environments. That’s why Valero, a leading manufacturer of petrochemical products, made personnel safety a top priority when they chose to upgrade one of their more complex, 24/7 process refineries. And they chose Eaton to help. Valero demanded proven arcpreventative motor control center technology to lower the probability of electrical shock and reduce incident arc flash energy during
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maintenance. Eaton rose to the challenge. For this critical project, Valero chose Eaton’s FlashGard ® motor control centers (MCC). The first MCC designed specifically to prevent arc flash. Unlike conventional designs, FlashGard allows for closed-door maintenance operations. Providing a much-needed barrier to protect personnel and equipment from the dangers of arc flash. The heavy power capabilities and safety systems needed to fuel tomorrow’s world, calls for solutions today. Eaton is already there.
S03 ORA 4 2013 Analysis_Layout 1 19/08/2013 16:42 Page 10
Analysis
Oil remained the world’s fuel of choice in 2012, but structurally and regionally the energy markets have continued to change.
Energy consumption growth slows
significantly H
IGH PRICES WERE partly responsible for slowing of global energy consumption in 2012, said BP’s Group Chief Executive Bob Dudley in his introduction to the IOC’s latest “Statistical Review”*. World primary energy consumption grew by just 1.8 per cent in 2012, which was well below the average observed over the last 10 years of 2.6 points. Consumption in the OECD (heavily industrialised) countries fell by 1.2 per cent, with the USA well ahead in this trend (down 2.8 per cent, despite the rising availability of what everyone else calls low-cost gas). But even in emerging countries energy consumption grew by less than the 10-year average amount, at just 4.2 per cent. “Regionally, growth was below average everywhere except Africa”, the introduction to this year’s Review concludes. So the last calendar year saw a slowdown in the growth of all-forms energy usage for the world as a whole, with major consuming countries such as EU members, China, India and the USA all seeing below-average increases. Supply-wise the main development continued to be a widening of the shale (both oil and gas) revolutions; US oil output is now the focus, and this registered its largest gain ever. As expected all the net growth in energy consumption took place in emerging economies, a group which of course includes most of Africa. Energy consumption within the OECD group may possibly have peaked, as oil usage did nearly 10 years ago. As usual China and India accounted for most of this increase. Despite the overall slowdown in growth both consumption and production reached record levels for oil, gas and most other fuels.
Regionally, growth was below average everywhere except Africa. Crude oil prices peaked in March last year, but despite this the year’s average for Brent reached a record level in current-dollar terms – although only just, at US$111.67/barrel. The loss of Iranian supplies was more than offset by growth elsewhere, including a strong recovery in Libyan output. Global output increased by 2.2 per cent, that’s an extra 1.9mn bpd, three-quarters of this being accounted for by OPEC members, of which there are four here in Africa. Libya’s (exceptional, because it was all recovery) increase matched that of the USA. Major unexpected outages occurred in Sudan/South Sudan, neither of which belongs to the major producers’ Organisation; these cost the world market a massive 340,000 bpd. Meanwhile global consumption of crude grew by less than one per cent, that’s 0.89mn bpd. Usage in OECD countries – that’s now almost exactly one-half of the total – again fell, by 1.3 per cent in 2012. China recorded the largest increment, at a full five points up, although Japan’s growth rate (accounted for the special conditions brought about by the nuclear disaster there) was actually higher. The bottom line of all this was that global oil trade (ie, international movements) increased by only 1.3 per cent last year, which equates to 0.7mn bpd. “The relatively small global increase hides large regional changes,” the BP team said. For example, net imports by the USA, a major customer for Africa’s OPEC oil in particular, are now 36 per cent below their 2005 peak. Meanwhile China’s net imports grew by 0.61mn bpd, accounting
10 Oil Review Africa Issue Four 2013
In terms of finding new reserves Angola’s E&P specialists did better than any other countries within the continent last year.
for a massive 86 per cent of the global increase. North African net exports generally have done particularly well.
Angola’s new reserves And in terms of finding new reserves Angola’s E&P specialists did better than any other countries within the continent last year. Meanwhile, “The differential between Brent and WTI reached another record premium,” the Review says, although it points out that this difference (highly significant for Africa’s producers of light sweet crude, such as Nigeria) did begin to close later in the year as US market conditions changed. Most global gas prices continued their recent and long-term rise, except in North America where further growth in US output pushed prices down to record discounts against those of both the crude oil and international gas markets. Total world consumption increased yet again, by 2.2 per cent this time (significantly more than this within Africa, although most of this comes from domestic output of course). The net result was that global all-forms gas trade registered almost no growth at all, while international LNG business in tonnage/volume terms actually fell for the first time ever; the Asian markets remaining the strongest. Frustratingly for customers elsewhere the soft price trend for North American gas continues to fail to travel, putting a major brake on business in all its forms in most other markets outside Asia.
Oil still the leading fuel The BP statistical team pointed out that, despite all these shifts, oil remains the world’s leading fuel, accounting for just under one-third of global energy consumption. However, “its current market share is the lowest in our data set, which begins in 1965.” So, to sum it all up in Mr Dudley’s own words, the year highlighted “the flexibility of the world’s energy market and the innovative approaches that consumers and producers take in response to change.” ■
* BP Statistical Review of World Energy June 2013; www.bp.com/statisticalreview www.oilreviewafrica.com
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S04 ORA 4 2013 Fire Protection_Layout 1 19/08/2013 16:48 Page 12
Programme of Events are:
Aberdeen, 3rd – 6th September, 2013
NIGERIA OIL INDUSTRY PARTICIPATION AT OFFSHORE EUROPE 2013
Offshore Europe Conference & Exhibition holds every 2 years and attracts a global audience of engineers, technical specialists, industry leaders and experts, to share ideas, debate the issues of the moment and to create common agendas for the future of the upstream industry. It is another opportunity to showcase your company's technical capabilities during the conference. Be a part of the Offshore Europe 2013 and make your company and services known to the largest single gathering of the highest level decision makers in the Nigerian and world wide Oil & Gas industry.
• Exhibition: Nigerian pavilion, number 1G49 • Appreciation/Award Dinner: Norwood Hall Hotel (Strictly by Invitation) The Secretariat The Petroleum Technology Association of Nigeria (PETAN) 35 Trans Amadi Industrial Layout, Port Harcourt. Phone: Mobile:
084461179 08037255190 08060703398
Email: adejumoke.oyedun@petan.org cyprian.emuchay@petan.org
Official Sponsor: Baywood Continental
S04 ORA 4 2013 Fire Protection_Layout 1 19/08/2013 16:48 Page 13
Program of Activities for OTC 2014 1. Exhibition: Nigerian Pavilion (Booth 1462, 1463, 1466, 1467, 1563 and 1567) at the Reliant centre, Monday, May 5th – Thursday May 8th, 2013. 2. Luncheon/Panel Session: Tuesday, May 6th, 2013. Time: 11.30AM Crowne Plaza Houston – Reliant Park, 8686 Kirby Dr. Houston, TX 77054 (Kirby & South loop) (TEL: 713) 748 3321 3. NNPC/PETAN - Nigeria Industry Award Dinner Cocktail & Dinner: Tuesday, May 6th, 2013 Time: 6.00pm Hilton America-Houston Hotel 1600 Lamar, Houston, Texas, 77010, USA (713-739-8000) 4. PETAN/ANPPA joint Technical Workshop Wednesday May 7th, 2013 Time: 11.30AM Crowne Plaza Houston – Reliant Park, 8686 Kirby Dr. Houston, TX 77054 (Kirby & South loop) (713) 748 3321 5. Golf Tournament Thursday, May 8th, 2013: 12:00PM Sugarcreek Country Club 420 Sugar Creek Boulevard Sugar Land, TX 77478 (281) 494-9131
OTC 2014 Short Course • Finance For Non – Financial Oil & Gas Personnel • New Trends in Economics & Technology of the Crude Oil, Natural Gas & LNG Value Chain • Fundamentals of International Joint Ventures and Partnerships • Risk Management & Strategic Decisions Making in the Oil & Gas Industry • Comparative Study of Petroleum Contracts & Fiscal Terms • Effective Office Management and Administration Skills Venue:
Date:
The Crowne Plaza Hotel, Opposite the Reliant Stadium, Houston Texas May 1st to 3rd 2014 Time 9:00am each day
For Participation & Sponsorship contact: The Secretariat The Petroleum Technology Association of Nigeria (PETAN) 35 Trans Amadi Industrial Layout, Port Harcourt. Phone: 084461179 Mobile: 08037255190, 08060703398 Email: adejumoke.oyedun@petan.org, cyprian.emuchay@petan.org
Risk Management
S04 ORA 4 2013 Fire Protection_Layout 1 19/08/2013 16:48 Page 14
Ed Butler and Ollie Sheinwald at Salamanca look at the overall security context in Sub Saharan Africa and discuss the operational and security implications.
Sub Saharan Africa - a diverse and challenging
operating environment
The need for international companies to really understand political dynamics in potential new markets in SSA has never been greater.
S
UB SAHARAN AFRICA (SSA) offers huge opportunities for international oil companies (IOCs), but it remains a diverse and challenging operating environment. The onshore risks associated with operating in SSA are relatively fluid since local and regional politics vary enormously across the region. But certain trends, namely the persistence of international tensions, the development of transnational extremism and the continuing uncertainty around elections, demand intelligencedriven responses from IOCs which are similar across continental SSA.
Local engagement At the local level, IOCs can face challenges thrown up by their own presence in a country. Recent discoveries of oil in Uganda and Kenya have inspired huge local optimism, but the region will likely experience many of the negative effects of oil production that have affected West Africa. While difficult to forecast, the increase in upstream oil activity in East Africa is likely to have widespread social and political implications. The first signs of this are already being felt in Tanzania, where government decisions over where to allocate oil and gas investment have inspired popular protests in the south of the country. Managing relations with local groups requires an in-depth understanding of local dynamics and constant interaction with local stakeholders. In the short term, developing good community and labour relations through corporate social
14 Oil Review Africa Issue Four 2013
responsibility programmes and civil society engagement are recommended measures. They are a key part of creating solutions which are light-footed and affordable. In the longer term, monitoring local political dynamics through political risk reporting can help IOCs assess how their operating environment is changing and react to threats as they emerge. Wherever they are active on the continent, IOCs operate in the context of transnational threats, national politics and local ethnic and civic dynamics. The core of risk management strategy is developing and nurturing relationships with local partners, whether these are state security structures, local business partners or civil society groups. These relationships are most effective when they are informed by local intelligence, either through stakeholder mapping or political risk reporting. Such tools can help IOCs understand the connections, reputations and motives of potential local partners, whether they are engaging a security partner or building a school.
Political risk and domestic dynamics The need for international companies to really understand political dynamics in potential new markets in SSA has never been greater. In the last year, there have been coups in Guinea Bissau and the Central African Republic. Unrest surrounding recent elections in Kenya and Liberia serves as a reminder that even more stable states can be shaken by internal tensions. Monitoring national political dynamics around flashpoints such as
Managing relations with local groups requires an in-depth understanding of local dynamics and constant interaction with local stakeholders. elections, referendums and prominent political trials continues to be important for anticipating instability. Companies operating in stable states with wellentrenched regimes and power structures face a subtle set of challenges. Negotiating the business landscape in countries such as Angola, Nigeria and Equatorial Guinea requires an appreciation of the complex links between politics, business communities and international companies. In jurisdictions with poor transparency, enhanced due diligence can allow IOCs to build a picture of a prospective partner’s reputation and business practices. Stakeholder mapping helps companies assess if a local partner is linked to politicians or other public figures. Together, these allow IOCs to develop relationships which facilitate business in a difficult environment, while maintaining high standards of corporate governance.
Understand inter-state dynamics Despite the decline in large-scale international and civil wars, inter-state tensions are still big drivers of conflict on the continent. Poor bilateral relations fuel conflict between non-state actors, which pose specific local threats to IOC operations and hamper state
www.oilreviewafrica.com
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provide a secure space in which multinational companies can operate. Understanding the significance of transnational threats, which are often beyond the capability of one state’s control, is key to developing appropriate security solutions and mitigating risk. In a poorly developed state security apparatus, IOCs cannot rely on domestic authorities to alert them to fluid transnational threats. Security reviews must accordingly have a wide scope, as instability in one country can quickly develop into a regional threat. Wherever they operate, IOCs should plan to receive regular updates on security developments, and be ready to adapt their procedures in light of these.
Monitor transnational threats Even when inter-state relations are amicable, some regimes are unable to project force throughout their territories, leading to transnational threats including criminal trafficking and terrorism. In West Africa and the Sahel particularly, a legacy of conflict and porous borders has led to a proliferation of small arms which the Arab Spring uprisings have only exacerbated. This has been felt most acutely in Mali, where conflict was fuelled by drug and human smuggling, radicalisation and food scarcity. Mali in turn was a worrying echo of Somalia, where crossborder activity by al-Shabaab has been suppressed only after a multilateral military campaign. State security services in these states were unable to
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The threat posed by extremism Nowhere in sub Saharan Africa is the threat posed by non-state actors better portrayed than in northern Nigeria, where recent gains by Boko Haram, an Al Qaeda-linked militant group, have led the Nigerian government to declare a state of emergency in several northern states. The risks posed to IOCs have been heightened by the emergence of Ansaru, an even more hardline splinter group which targets Europeans and North Americans working in Nigeria. Ansaru’s ability to conduct successful operations against workers living in protected compounds demonstrates the heightened threat posed by
extremist groups, as compared to traditional criminal elements. So far, Nigerian security services have been unable to carry out the kind of intelligence-led and political operation that is necessary to defeat an insurgency. In such contexts, standard hard security solutions may be insufficient to mitigate the threat, and targeted decisions over where to operate and where to avoid are necessary. While it boasts a well-developed private security sector, Nigeria is also a case study in the dangers of relying on untested local contractors. Following a 2009 amnesty in the Niger Delta, many former militants went into business offering to protect infrastructure they had formerly attacked. These are often poorly trained, and extensive links still exist between the private sector, security services and militant groups. In these situations, the use of established risk management partners can help IOCs navigate the problems of a domestic security market.
Understand environment, manage risks Sub Saharan Africa has experienced huge growth, democratisation and increasing stability, and its resources and markets continue to offer great rewards. The better IOCs understand the environment they are operating in, the better placed they will be to mitigate threats and respond to events as they arise. ■
Oil Review Africa Issue Four 2013 15
Risk Management
security services. For example, in Sudan and South Sudan, internal tensions have not eased with the latter’s secession and both sides have fuelled a proxy war between rebel groups in the border regions. IOC security arrangements are typically effective when they are developed in response to these dynamics. Companies operate in a context of heightened uncertainty, where a slight shift in bilateral ties can have huge knock-on effects at the local level through the actions of non-state actors. Monitoring political developments and gaining targeted intelligence on how they are playing out at a local level can help IOCs plan for crises.
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Namibia
Drillers are re-thinking Namibia after the discovery offshore of non-commercial quantities of light oil earlier this year.
Namibia:
more than just gas T
HOUGH NAMIBIA HAS yet to see any real impact in terms of actual production, there is at least an uptick in investor interest in this largely forgotten southwestern corner of Africa. Actually, the fact that Namibia remains something of a backwater is quite odd, given its proximity to oil-rich Angola, and the presence of one of Africa’s largest offshore gas fields, Kudu, which has sat dormant since its discovery almost 40 years ago. Not that companies haven’t tried hard to make the Kudu economics work, a feat that - for now, at least - continues to elude even the most capable of planners, financiers and engineers. Tullow Oil plans three subsea wells in this field, which is in 170-metre water depth offshore Namibia, tied back to a floating production system. Genesis Oil and Gas Consultants has recently won a subsea front-end engineering and design (FEED) contract for the Kudu gas-to-power project offshore Namibia. Gas will be processed offshore to the required specification for export through a 170-km pipeline to a power station onshore at Uubvlei. Genesis’ scope includes the flowlines, risers, subsea structures (including a subsea isolation valve), controls, umbilicals, the export pipeline, and a beach valve station. FEED work is expected to be completed later this year. Still, the Kudu gas deposit, estimated to contain 1.3 trillion cubic feet (tcf), but potentially much more, up to 9 tcf, illustrates the presence of hydrocarbons in the area. The Namibian coast consists of four continental sedimentary basins: Namibe, Walvis, Lüderitz and Orange. All are lightly drilled and considered frontier areas but with good potential for oil and natural gas finds.
Light oil find And now Namibia’s proved resources include crude oil following a recent discovery by Brazilian explorer, High Resolution Technology (HRT). The Wingat-1 well identified source rocks and quantities of high quality light crude at 32° to 42° on the American Petroleum Institute (API) scale. The find is not thought to be commercial but it puts the country’s offshore sector in a whole new light. As important as gas finds are - huge offshore
16 Oil Review Africa Issue Four 2013
Offshore Namibia remains exceptionally under-explored.
gas discoveries have propelled Tanzania and Mozambique to the forefront of Africa’s energy sector in recent years - there is nothing that galvanises the drillers more than oil. Although the HRT find was small there could be much more to play for. In seven of the company’s drill prospects, specialists estimate potential upside of 10bn barrels of oil equivalent. If a fraction of this is borne out through subsequent drilling then Namibia’s status as an oil and gas producer could surely be transformed. Still, offshore Namibia remains exceptionally under-explored, with just 12 wildcat wells drilled along a coastline of 1,570 km; and one of the key uncertainties remains the distribution of mature oil prone source rock. The Wingat-1 well, however, provides evidence that oil has been generated and migrated, and is especially encouraging in identifying not just one but two source intervals. But it has certainly not been all plain sailing for HRT, which recently brought in Galp Energia to join its oil search on three of its offshore blocks. The company’s first three wells have effectively failed to generate any commercially viable quantities of oil, something that has not pleased the group’s investors back home. To keep the momentum up, it has now commenced drilling work on another well, Murombe-1, on petroleum exploration licence 23. The Murombe-1 well is located 220 km northwest of Walvis Bay in 1,391 metres of water depth, and sits just 15 km east of the Wingat-1 discovery.
It’s a decisive moment for HRT, which is taking encouragement from the findings of the previous well. “The fact that the source rock is in the ‘oil window’ and generating liquid hydrocarbons of excellent quality confirms the source potential of the basin,” HRT said in a statement.
Take heart Other investors have also taken heart from recent drilling activity including UK-based Chariot Oil & Gas, which has interests in five areas across the length of the country’s coast. At the company’s annual meeting in May, chief executive Larry Bottomley underlined that “Namibia remains a priority for us” and that the country “remains a highly prospective region”. Chariot is now monitoring third party drilling activity in the area to help firm-up its own prospects and targets. It then plans to secure a farm-in partner with the aim of drilling a Namibian well in 2014. Another UK-listed player, Tower Resources, also expressed “significant encouragement” from HRT’s Wingat well, specifically for its own planned Welwitschia-1 well, scheduled to be drilled in the first half of 2014, by operator, Repsol. Wingat-1 is located some 200 km south of Tower's multi-billion barrel Welwitschia-1 prospect. Tower holds a 30 per cent working interest in a licence comprising three blocks offshore Namibia through its operating subsidiary, Neptune Petroleum.
www.oilreviewafrica.com
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Namibia
A new entrant is LABAT Africa, a mining enterprise looking to diversify into the oil sector. It recently signed a deal with Amicitia Holdings to acquire its Palatina Petroleum unit, which would give it a share of five Namibian exploration blocks. Like others, it too will be watching developments at the Murombe-1 well site closely.
Kudu rides again
HRT spuds second well offshore Namibia.
Jeremy Asher, Tower’s chairman, said after the Wingat find that the presence of more than one mature source rock interval significantly reduces the overall risk for the basin, and should therefore encourage additional exploration activity. “We hope this result, along with additional evidence from seeps and other offset data, such as the [1911-15/1 well drilled in 1994] Norsk Hydro well, will also dispel the myth that Namibia is solely a gas province. We look forward to the result of HRT's next well in the Walvis Basin, Murombe-1.” Other niche players in Namibia include Polo Resources unit, Signet Petroleum, which has a 75 per cent stake in Block 2914B in the Orange basin, to the south-west of the Kudu deposit, and adjacent to HRT-operated areas.
But whatever this surge in interest in Namibia’s nascent oil sector amounts to there is still uncertainty as to how the nation will exploit its undoubted gas wealth. In March, the head of National Petroleum Corporation of Namibia (Namcor) said the stateowned company was ready to divest some of its 54 per cent interest in the Kudu field. In 2010, Russia’s Gazprom agreed to establish a special purpose company with Namcor to work on the Kudu gas project, although this appears to have made little headway. In typical Gazprom style, the deal appears more an attempt to tie up overseas reserves in a bid to exert greater control over hungry European markets. Namcor’s managing director Obeth Kandjoze said recently the company wants to tie up a deal sooner rather than later. When it does, it could provide fresh impetus into monetising this long stranded asset, especially in light of the resurgence of oil drilling.
Repsol Namibian well to spud in 2014 SUB-SAHARAN AFRICAfocused Tower Resources has reported that drilling of the Welwitschia-1 well in the Walvis Basin, offshore Namibia, is now planned to begin in mid-February 2014. The company confirmed a firm rig is in place, a drilling location agreed, a site survey largely completed and the longest lead items are being manufactured. Tower said Repsol, the operator, will take delivery of the Rowan Renaissance (UDW drillship) in December this year when it will move directly to Namibia. Metocean and surface wave data have been acquired at the well location, final subsea data is to be collected and the final report of the site survey is expected in August 2013. Tower CEO Graeme
Westbridge adds new Namibia blocks
The Rowan Renaissance UDW drillship.
Thomson commented in a company statement: "Preparations for the Welwitschia-1 well are progressing at an accelerating pace. Based on Tower's updated CPR, the Welwitschia-1 well will target risked prospective resources of 496mn boe net to Towers' 30-per cent interest in
18 Oil Review Africa Issue Four 2013
State utility Namibia Power Corporation (Nampower) has also resurrected plans to build a new, large gas-fired power plant to draw on the Kudu resource. The group has issued a tender for an 800megawatt plant, expected to cost up to US$1bn. Previous plans to build a gas-to-wire plant, dating back to the 1990s - and even to run a gas pipeline direct to South Africa - effectively came to nothing. Nampower says it hopes to issue an engineering, procurement and construction (EPC) contract for the power plant next year. It is also seeking an equity partner to help it develop the scheme. The presence of a big offtaker, like Nampower, to purchase Kudu gas could be enough to make the development economics more favourable. Zambia’s Copperbelt Energy Corporation is among those keen to soak up some of the surplus power generated by the new plant. Development agencies and commercial banks are also talking over financing options. But Namibia has been here before, many times, in fact, and there’s still no certainty yet that Kudu will fly at all. What is more certain is that if any of the country’s growing ranks of drillers can prove the existence of commercial oil, then that’s a game-changer for this African energy backwater. ■
Licence 0010 across multiple reservoir horizons. "The drilling cost equates to about five cents per risked barrel of oil equivalent. Drilling is now scheduled to be starting earlier, in mid-February 2014. We look forward to further updates as we move quickly to drill on this giant prospect."
CANADIAN EXPLORER WESTBRIDGE Energy has picked up an additional four blocks off Namibia after closing its acquisition of a 75 per cent stake in Ropat Petroleum Investments. The Vancouver-based player is set to almost triple its acreage holdings off the South-west African country with the addition of exploration blocks 1910A, 1911A, 1912B and 2011A in the Walvis basin to its portfolio, which already includes its operated Block 1811B. The deal, for which a value was not disclosed, makes Westbridge the secondlargest acreage holder in the prospective yet underexplored basin with 22,484 sq km of contiguous turf. Chief executive Tosan Omatsola said the new blocks host an earlier well that revealed oil shows and its acreage is about 180 km north of a recent technical discovery in the basin that “demonstrates a potentially extensive and working petroleum system between the two wells”. "Namibia is experiencing a resurgence of interest from major oil companies and junior explorers alike with near-term, multiple drilling campaigns proximate to Westbridge's blocks,” Omatsola added. www.oilreviewafrica.com
S05 ORA 4 2013 Nambia_Layout 1 19/08/2013 16:49 Page 19
Vaalco hires Emas for $120m job off Gabon
STATE-OWNED OIL India Ltd (OIL) has announced its first oil strike in Gabon. OIL’s Lassa-1 well is in the onshore bloc Shakthi (G4-220), which OIL leased from the government of Gabon for exploration in April 2006 after forming a joint venture. OIL has a 45 per cent share in G4-220, as does partner Indian Oil Corporation Ltd, with Singaporebased Marbis holding the remaining 10 per cent stake. OIL is also the operator. A senior OIL executive said, “This is a new chapter in the history of OIL.” He continued, “The locations, which were released by the Gabon government in mid-December 2011, were staked in deep forest where there was no communication. OIL personnel had to walk several kilometres inside the dark and deep forests. Operations in Lassa-1 started on May 19 and the final depth, 1,800 metres, was reached on June 29.” The find is good news for Gabon, whose oil production peaked in 1997. Since then Gabon’s oil output has declined by one third, as the country’s large oil fields have matured, causing Gabon to fall from being sub-Saharan Africa’s third largest oil producer to sixth place. Oil is critical to Gabon's economy, accounting for 65 per cent of government revenue and 75 per cent of export revenue. The G4-220 concession block is nearly 80 km long and 45 km wide and is situated roughly 250 km from Gabon’s capital Libreville. After the joint venture secured the concession in April 2006, aeromagnetic and seismic surveys were carried out in December 2011. The joint venture’s total allocated budget for carrying out exploration in the the G4-220 concession bloc is US$97.5mn. According to OIL, the Lassa-1 well has recorded a flow of crude oil at the rate of 220-225 bpd and natural gas at the rate of 4,330 scmd.
VALCO ENERGY HAS chartered the Emas deep-water offshore construction vessel Lewek Constellation on a US$120mn job at the Etame Marin field off Gabon. The Singapore-headquartered contractor said the scope of work for its subsea subsidiary EMAS AMC involved engineering, procurement, installation and commissioning of rigid pipelines as well as transportation and installation of flexible pipelines and two fixed production platforms. EMAS AMC chief executive CJ D’Cort said the maiden charter for the high-spec newbuild encompassed many of the contractor’s core strengths including SURF, heavy lift, and rigid pipelay. The Lewek Express pipelay vessel will also carry out part of the contract. Project management and engineering are to begin immediately at EMAS AMC’s Houston office, with offshore activities starting early next year. Due for delivery next year, the Lewek Constellation is an ice-class multilay offshore construction vessel with heavy-lift capabilities that is equipped to carry out pipe-laying in ultra-deepwater.
The Lewek Constellation.
Gabon
Oil India Ltd strikes oil in Gabon
S06 ORA 4 2013 Libya_Layout 1 19/08/2013 16:52 Page 20
Libya
Post-conflict Libya, the holder of the globe’s eighth-largest oil reserves, is at a crossroads and faces stiff challenges of reconstruction, on the scale and costs unprecedented in its history. Moin Siddiqi reports.
Great energy expectations hinge on
much-needed stability D
ESPITE AMPLE FINANCING capacity, physical infrastructure remains in a dire state, with power generation, transportation, telecoms, water and sewerage systems in poor condition by regional standards of North African countries. Even its hydrocarbons sector, the jewel of its industrial base, is almost obsolete, reflecting decades of under-investments. As in Angola after the ending of the civil war in 2002, where oil revenues facilitated the country’s reconstruction efforts. Therefore, Libya’s rapid resumption of production along with national security and stability ostensibly bodes well for economic revival. Nuri Berruien, chairman of National Oil Company (NOC), explained: “In our new Libya we are looking forward to building a new oil and gas industry built on trust. NOC’s primary objectives are now to develop and maintain hydrocarbon reserves and deploy new enhanced recovery techniques in the upstream. The country would also upgrade its refining and petrochemical industries.” With the extremely attractive low cost of oil recovery and superior reserves of light (high API gravity) and sweet crudes (low sulphur content) – hence easily refined into petroleum products – Libya is a popular ‘hot spot’ for foreign energy groups. So far, only one-quarter of its vast territory has been explored for hydrocarbons. The International Energy Agency (IEA) reckons ‘fully explored’ Libya could yield a further 100bn barrels of oil equivalent – making it among the top-five investment destinations. But the main question for international oil companies (IOCs) is when new development projects as well as incentives regarding the oil exploration - all stopped since the revolution - will restart.
Upstream revival Oil production has defied expectations and has already regained pre-conflict levels of 1.6mn barrels per day (bpd), thus Libya’s all-important sector – which accounts for 65 and 95 per cent, respectively, of gross domestic product (GDP) and government revenues – had escaped projections of large-scale destruction. Referring to its rapid recovery, the US’s Energy Information Administration (EIA), noted: “When juxtaposed against the challenges faced by authorities and operators, the initial scepticism of most outside analysts, and other countries' past experience with restoring production after a significant disruption.” NOC aims to reach 1.7mn bpd by end-2013. The
20 Oil Review Africa Issue Four 2013
80 per cent of Libya's oil fields are located in the Sirte Basin near the country's Mediterranean coast.
Oil production has defied expectations and has already regained pre-conflict levels of 1.6mn bpd.
country also produces about 140,000 bpd of noncrude liquids, including natural gas liquids (NGLs) and condensate. In the near-term, raising oil capacity to 1.8mn bpd requires investments in new field development, reservoir management, drilling, and enhanced oil recovery (EOR) and improved oil recovery (IOR) techniques, production/pressure maintenance technology and stream injecting, as
Table 1. LIBYA'S Hydrocarbons Endowments at a Glance PROVED OIL & GAS RESERVES
Crude oil [billions barrels] As per cent of: Africa's Total * OPEC Total Natural gas (trillion cm) As per cent of Africa Total # PRODUCTION Oil (mn bpd), incl. NGLs As per cent of: Africa Total OPEC Total Natural Gas (billions cm) As per cent of Africa’s Total
2002 36
2004 39.1
2006 41.5
2008 43.7
2010 47.1
2012 47.1
R/P ratio 2012// 100 +
35.4 4.1 1.31 9.5
34.3 4.3 1.49 10.4
35.4 4.4 1.32 9.3
34.8 4.5` 1.54 10.5
35.5 4.0 1.50 10.3
35.6 4.0 1.50 10.3
41.2 avg 91.5avg 100+ 71.7avg
1.37
1.62
1.83
1.82
1.66
1.45
17.2 4.5 5.9 4.3
17.5 4.7 8.1 5.2
18.3 5.1 13.2 6.8
17.7 5.0 15.9 7.5
16.4 4.8 16.8 7.8
13.4 4.3
// Reserves-to-production ration, measured by years of exploration & production (E&P). * The largest proved reserves in Africa. # Libya ranks fourth in terms of gas reserves, after Nigeria, Algeria and Egypt in Africa. Source: BP Statistical Review of World Energy and OPEC databases.
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S06 ORA 4 2013 Libya_Layout 1 19/08/2013 16:52 Page 21
Libya
S06 ORA 4 2013 Libya_Layout 1 19/08/2013 16:52 Page 22
Libya has long inspired to achieve sustainable productive capacity of 3mn bpd (from currently 1.85mn bpd), making it Africa’s largest producer. well as importing transformers/transmission equipment. Moreover, boosting production to between two and three million bpd would require additional pipeline capacity for exports. With over 9,500 km of pipeline already built-in, a market exists for the supply of maintenance services, corrosion prevention, pigging and instrumentation. However, years of reservoir mismanagement and severe damages to mature fields require the technical assistance of oil majors. The annual ‘natural’ decline rate is estimated at 7-10 per cent. A greater use of EOR and IOR techniques will help to mitigate ongoing depletion of ageing fields, notably Deffa, Messla, Nafora and Sarir, and could add another seven to 10bn to Libya’s existing proved reserves of 47bn barrels, according to NOC.
Libya has long inspired to achieve sustainable productive capacity of 3mn bpd (from currently 1.85mn bpd), making it Africa’s largest producer. Tripoli reportedly needs about 40 oil rigs over the next few years to support exploration and development (E&D) programmes of IOCs. Before the revolution, NOC and partners had pledged to share a US$46bn investment commitment over a five-seven year period. Refining: Libya has five domestic refineries, with a combined nameplate capacity of 350,000 bpd, of which the largest is Ras Lanuf situated on the Gulf of Sirte. Refineries require sophisticated equipment to reduce higher sulphur content in refined products (gasoline, kerosene and lubricants) and to comply with international environmental standards. Currently, Libya imports over 75 per cent of its gasoline. Libya's refining capacity was severely impacted by UN sanctions (until mid-2000s), specifically UN Resolution 883 of 11 November 1993, which banned exports of refinery equipment and replacement parts.
Untapped gas resources Libya (like some core oil-exporters) has largely neglected its natural gas (natgas) sector, which
Table 2: Projects Planned or Underway in Libya, in US$ millions Project name Development Ghadames Basin (Area 47) Azzawiya refinery expansion Upgrade of lube oil blending & gas turbine plant at Azzawiya Mabruk field Dahra & Garian reservoirs (phase-1) Upgrade of Abu Kammash chemical facility Block NC 186 oil field developmen Structure A (offshore) platform & (onshore) gas production upgrades Zueitina to Brega pipeline
Project owners Medco Engeri/Libyan Investment Authority/ Verenex Energy National Oil Corp (NOC) Azzawiya Oil Refining Co.
Sub-sector Upstream oil
Est. Cost 800
Status FS
Refining Construction
700 300
FS Construction
Mabruk Oil Operations
Upstream oil
300
Main contract PQ
General Co. for Chemical Industries Repsol YPF
Petrochemicals
200
FS
Upstream oil
160
FS
Mellitah Oil & Gas
Upstream & 150 Downstream gas Midstream oil 140
FS
Zueitina Oil Co.
FS= Feasibility study; PQ= Prequalification. Source: MEED Projects.
22 Oil Review Africa Issue Four 2013
Construction
explains for low output – averaging 12.6bn cubic metres (cu m) per annum over 2004-11, according to BP. However, natural gas reserves are considerable at between 53 and 70 trillion cubic feet (tcf), or even higher – enough to sustain production for more than 100 years. The IOCs are less involved in natgas production, though Italy’s ENI is a notable exception due to its stake in the large Western Libya Gas Project (WLGP). The latter – operated by ENI and NOC through the Mellitah Oil & Gas joint venture – accounts for most of Libya’s gas production growth since mid-2000s. The bulk of gas produced from WLGP-operated ‘offshore’ Wafa and Bahr Es Salam fields is exported via the GreenStream pipeline to southern Europe, with small volumes also shipped in the form of liquefied natural gas (LNG). Libya exported 352bn cubic feet of natgas in 2010, relatively unchanged from 2007-2009 levels. Libya plans to boost natgas output for exports to 40-50bn cu m annually within ten years and to upgrade the country’s only LNG plant, which is limited to one liquefaction train at Marsa ElBrega (built in the early 1970s) with a nameplate design capacity of 3.2mn tonnes per year, according to PFC Energy. One reason for sustained low capacity is that the facility lacks requisite technology to separate NGLs from the LNG stream, which also limits the number of receiving terminals that can process it. Prior to the revolution, Royal Dutch Shell was contracted to upgrade the LNG plant. For decades, associated gas has been simply flared-off. Thus, increased exploration and production of those untapped reserves will provide cheap feedstock for power stations and the petrochemicals industry, while expanding existing piped and LNG exports, as well as supporting EOR programmes (through gas reinjections). However, like all prospective energy plans in Libya, optimal development of its gas sector depends upon government support, foreign capital and expertise, new favourable contract terms, and industry oversight. In sum, Libya, over the medium to long-term, offers tremendous possibilities for reserves and output expansion within both petroleum and gas sectors, thus making it Europe’s vital energy supplier. Nonetheless, technological transfers and higher investment are needed for joining the ranks of world’s leading producers. The underutilised oil/gas industry is the engine of future growth. But for Libya to maximise its oil potential - hence its economic potential - “the state must, as a matter of some urgency, develop initiatives to foster commercial confidence, within a stable environment supported by strong regulatory and legal frameworks,” advised the International Monetary Fund (IMF). Given new investments and expertise of oil majors, the country’s ‘black gold’ should shine and provide increased revenues in the postGaddafi era. Existing bottlenecks offer growing opportunities for engineering, procurement construction (EPC) contractors in upstream, midand-downstream sectors. ■ www.oilreviewafrica.com
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OMV resumes production Libya
OMV, THE AUSTRIAN oil and gas company part-owned by Abu Dhabi, has reported that production has resumed at its Libyan operations. After most of the company's production was shut-in in June, production operations have resumed with production now stabilised at normal levels, said the firm. In 2012, Libya contributed approximately 30,000 barrels of oil equivalent per day to OMV's total production of 303,000 boepd. Earlier this year, strikes in Libya also contributed to an overall drop in the country's production to 1.2mn bpd from recovery levels of 1.6mn bpd. "We benefited from the return of production in Libya," said Gerhard Roiss, the chief executive of OMV. "We managed to deliver a record financial performance while successfully progressing our strategy."
Libya’s oil output bounces back to 1.3mn bpd
Deputy oil minister, Omar Shakmak.
LIBYA’s OIL OUTPUT levels have climbed back up to 1.3mn bpd, according to the country’s deputy oil minister. National Oil Company (NOC) had said that that crude oil production — which excludes 60,000 barrels a day of condensates output — had fallen below one million bpd amid protests a few weeks earlier. Deputy oil minister Omar Shakmak, however, said, “As of recently, production was 1.3mn bpd, including both crude oil and condensates.” The second Libya Forum – Oil, Gas and Sustainable Growth will take place on 1618 September 2013 in Tripoli, with the official endorsement and full support of the National Oil Corporation and will bring together ministers, top level NOC officials and key personnel from Libya’s oil industry with high ranking representation from international partners and new potential investors. The forum will showcase Libya’s many opportunities available to investors and address key industry issues. www.oilreviewafrica.com
Oil Review Africa Issue Four 2013 23
Equatorial Guinea
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Equatorial Guinea is the third largest oil and gas producer in sub-Saharan Africa, and after more than 22 years of production, it has less than five per cent local participation in the oil and gas sector. This has been very worrying for the government, which has decided to take steps to correct it. Led by the Ministry of Mines and Energy and its national content director, the government is about to implement some new national content regulations that will address these issues.
Noble Energy’s Aseng field came online in 2011 and is now producing 60,000 bopd.
National content in
Equatorial Guinea E
QUATORIAL GUINEA IS the third largest producer of oil and gas in sub-Saharan Africa after Nigeria and Angola. The country started production in 1991 from the Alba field with Walter International, which was later taken over from by CMS Nomeco. In 2001, Marathon Oil bought all of CMS Nomeco’s assets, taking over the field and immediately starting an expansion programme of the assets, leading to a production of 42,000 barrels per day (bpd) of condensate. The Alba field is Equatorial Guinea’s largest gas field and is part of the Punto Europa Gas Complex, which includes an LNG plant (EGLNG Train 1), a methanol plant (AMPCO), a gas processing plant which produces 6,000 bpd of condensate and an LPG plant which produces 21,000 bpd of propane and butane. Producing 120,000 bopd, the Zafiro field has been operated by ExxonMobil since its discovery in 1995 and Hess, which operates the Ceiba and Okume fields, produces about 85,000 bopd. Recent discoveries include Noble Energy’s Aseng field which came online in 2011 and is now producing 60,000 bopd. The company’s second field, Alen, will come online towards the end of 2013 and is expected to produce 37,500 bopd. Other companies are at the exploration phase, which means, depending on the success of each company, the current level of 420,000 bopd will rise further. Geptrol is the national company in charge of all the country’s commercial activities, including awarding blocks, exploration and production, trading crude oil and providing oil and gas services. A total of nine new production sharing contracts (PSCs) were signed in 2012 alone. Sonagas, meanwhile, is the national company in charge of all Equatorial Guinea’s gas activities and is a shareholder in the EGLNG plant. The Ministry of Mines is in charge of the regulation of the oil and gas industry and is headed by its young and dynamic award-winning minister, Gabriel Mbaga Obiang Lima.
Existing legislation and regulation The oil and gas industry in Equatorial Guinea is governed by its Hydrocarbons Law, which covers several areas of vital importance in the hydrocarbon sector, including legal, technical and commercial aspects. These include the monetisation of gaseous hydrocarbons; an increase in state participation; development of the petrochemical sector; and a focus on national
24 Oil Review Africa Issue Four 2013
The oil and gas industry in Equatorial Guinea seems to be creating more jobs outside the country than in the country. content, which encompasses elements or factors to propel the national economy and promote the improvement of technical capacity among citizens of Equatorial Guinea, thus optimising the benefits from the sector. In the hydrocarbons law, the articles listed below are the ones that focus on national content. 6 Article 88 - IOCs contribution to Hydrocarbon Technological Institute of Equatorial Guinea. 6 Article 89 - Ministry shall adopt measures to guarantee, promote and encourage investment in the hydrocarbon Sector by Equatoguinean companies. 6 Article 90 - Contractors and their associates shall co-operate with the Ministry to carry out public benefit activities to promote socio-economic development. 6 Article 91 - Contractors and their associates must give preference to the use of goods, services, human resources and capital of Equatoguinean origin. 6 Article 92 - Contractors shall train and integrate national personnel into all levels of their organisations in accordance with this law and the terms of their contracts. In addition to the above, each contractor will likewise contribute to the training of Ministry personnel. 6 Article 93 – Project and public benefit The production sharing agreements also have articles that focus on national content, including: 6 Article 23 - Local Content and Social Programmes, covering: 6 23.1 Preference to Equatoguinean services 6 23.2 Employment and training of Equatoguineans 6 23.3 Provide reasonable assistance to National Technology Institute www.oilreviewafrica.com
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Equatorial Guinea
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The government has realised that regulation and legislation alone is not enough to ensure compliance with national content policies. Challenges facing the industry It is a great concern for the government of Equatorial Guinea that after 22 years of oil and gas production, less than five per cent of the annual spend on oil and gas services is spent locally. At least 95 per cent of the US$2bn spent annually in the oil and gas industry in Equatorial Guinea leaves the country through goods and services procured outside the country. The oil and gas industry in Equatorial Guinea seems to be creating more jobs outside the country than in the country. There are several reasons for this, including: 6 Equatorial Guinea national content laws are not stringent enough, so they are open to different interpretations by the IOCs. 6 Lack of implementation of the existing laws by the regulatory bodies, which means that the IOCs self-regulate themselves in Equatorial Guinea. 6 A lack of enough skilled local manpower across the value chain of the oil and gas industry in Equatorial Guinea, from technical to managerial personnel. 6 Lack of local companies with the competence and know-how to provide services to the oil and gas industry. 6 Lack of access to financing by local companies from the local banks, who do not have experience in or understand the oil and gas industry, with the exception of Ecobank. 6 Language difficulties for many locals as the official language in Equatorial Guinea is Spanish, but the oil and gas industry is dominated by the English language, hence the sector is a barrier to many locals due to few people speaking or writing in English.
The Alba field is Equatorial Guinea’s largest gas field.
After receiving feedback from all industry stakeholders... the Ministry of Mines and Energy is in the process of passing a new national content law this year
Increasing national content The government decided that it had to do something about the current low level of participation of nationals and local companies in the oil and gas industry, hence the appointment of new national content director Cesar Hinestrosa. The Ministry of Mines and Energy, through Hinestrosa, organised a national content seminar and distributed a draft of a new national content bill it wants to put in place. After receiving feedback from all industry stakeholders and some modifications to the original document, the Ministry of Mines and Energy is in the process of passing a new national content law this year. Its aim is to reinforce the national content regulations in the current hydrocarbon law, which it deems not stringent enough. From the draft that we saw distributed at the national content seminar, the regulation will address the shortcomings of the national content clauses in the Hydrocarbons Law. Among the issues it will address are the following: 6 Ensuring compliance with Equatorial Guinea’s current national content
law and regulations. Increasing the domiciliation of materials, equipment and services utilised in the oil and gas industry in Equatorial Guinea. 6 Ensuring adequate and acceptable local participation in projects executed in the oil and gas industry in Equatorial Guinea, without compromising on standards, while developing indigenous capabilities and ensuring economic development. 6 Promoting the transfer of technology and skills training, enabling meaningful participation of local citizens in the hydrocarbon sector of Equatorial Guinea. 6 Encouraging investment through a meaningful and balanced approach by taking into consideration the national context. 6 The Ministry of Mines, Industry and Energy will establish a fund in order to finance the implementation of local content development. The government has realised that regulation and legislation alone is not enough to ensure compliance with national content policies, so the new national content regulation will go further while invoking some of the existing legislation. It will also apply sanctions and penalties for noncompliant companies, which could include the following: 6 In accordance with Law No. 8/2006 of Hydrocarbons in Articles 108 and 109, establish penalties for regulatory violations by the IOCs and service companies. 6 Publish the names of the exploration and production companies, contractors and subcontractors, expressly identifying which of these have complied and which have not complied with the new law. 6 Suspension of contracts. 6 Modification of existing contracts. ■ Alfredo Jones
6
The Punto Europa gas complex houses the Alba field.
26 Oil Review Africa Issue Four 2013
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S07 ORA 4 2013 Equatorial Guinea_Layout 1 19/08/2013 16:56 Page 27
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Geology
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Gulfsands launching seismic in Morocco GULFSANDS PETROLEUM HAS contracted Romanian firm Prospectiuni to undertake seismic programmes on the Rharb and Fes permit areas in Morocco. A high fold 3D seismic survey covering an area of about 220 sq km is being carried out over the south-western part of the Rharb permit area to assist in the further delineation of drilling targets for Gulfsands’ upcoming nine-well drilling programme. The company has engaged COFOR SAS, a drilling contractor and subsidiary of France’s Vinci group of companies, to provide an onshore drilling unit suitable for the drilling of a minimum of nine exploration and development wells in the Rharb Basin area. The second seismic programme, which will capture approximately 650 km of 2D data, is designed to assist in the identification of additional drilling targets on the Fes permit and to more accurately define existing drill targets identified using the results of an earlier gravity survey programme and legacy 2D seismic data. The cost of capturing and processing this seismic data is an estimated US$14.5mn. Gulfsands is planning to drill one well (and possibly a second) on the Fes permit area during 2014 using the data captured in this 2D seismic survey, which data should be available prior to the end of the current year. The first well in this proposed three-well programme is planned to commence drilling during Q2 2014. Mahdi Sajjad, the company’s CEO commented: “We are very pleased that the company has been able to begin its operations in Morocco so soon after the acquisition of these assets which was only completed in mid-January 2013.”
Swala starts seismic survey in Tanzania SWALA ENERGY HAS started the acquisition of 100 line km of 2D seismic over the Kilosa Basin in the Kilosa-Kilombero oil and gas licence in southern Tanzania. Kilosa is believed to host both Karoo (Permo-Triassic) and Neogene sediments, the latter of which represents the oil play system in the East African Rift System. The seismic is designed to identify the main structural lineation in the basins and has the potential to identify structural leads for follow-up infill seismic and/or possible drilling. Upon completion of the programme, the Polaris seismic team will mobilise to the Kidatu Basin due south of the Kilosa Basin for the second of five seismic programMEs in the Kilosa-Kilombero and Pangani licences that will be completed in the next three to four months.
Seismic data review reveals prospect off Liberia AFRICAN PETROLEUM EXPECTS to receive reprocessed data imminently from a 2010 3D seismic survey offshore Liberia. This covered 5,100 sq km over blocks LB-08 and LB-09. Drilling to date has led to discovery of oil in the Narina field and BeeEater-1, which was drilled in February. Post-drill studies are almost completed to integrate results from this well. The 3D data is being re-mapped for the Campanian interval. A new prospect named Night Heron has been identified in the Turonian interval. African Petroleum will use the reprocessed data to further assess identified leads and prospects.
Fugro awarded contract in Angola
Bell Geospace to conduct FTG survey in Kenya
FUGRO HAS BEEN awarded a large three-year contract by Chevron’s subsidiary Cabinda Gulf Oil Company Ltd, to support its development programme at Block 0, off the coast of Cabinda province, Angola. The contract includes the provision of offshore positioning services and accurate navigation systems for Chevron’s drilling units, vessels and structures, together with both onshore and offshore survey services. Fugro’s offshore geophysical data acquisition services will be supplemented by data processing, interpretation and reporting. At Chevron’s onshore facilities in Malongo, Fugro’s survey services will include subsidence evaluations, topographical surveys, chart production, interpretation and reporting.
ERHC ENERGY KENYA Ltd has contracted Bell Geospace to acquire an airborne Full Tensor Gravity Gradiometry (FTG) survey of Block 11A in northwestern Kenya. The selection of Bell Geospace follows a competitive bidding process. This survey aids significantly in the structural mapping of prospective hydrocarbon basins. Using a converted DC-3 aircraft, Bell Geospace will fly a dense grid of flight lines to measure small changes in gravity caused by changes in density of subsurface rocks. This survey method has been used successfully in Africa and contributed to recent oil discoveries in Uganda and Kenya. "Bell Geospace has impressed us with their expertise and experience, and we are excited to be moving forward with this airborne gravity gradiometry survey, a crucial element of ERHC's oil and gas exploration work programme in Kenya," said Dr Peter Thuo, general manager of ERHC Energy Kenya Ltd. "When combined with other existing geologic data, this FTG survey will be used to further assess the geological structure of the area, which helps us to identify potential leads and prospects. Subject to certain contingencies and governmental approvals, the survey is expected to be flown through this summer according to a pre-determined timeline. The information gathered will enable ERHC to focus on the most promising areas for acquisition of 2D seismic data, which is the next step in the work programme for the Kenya Block. The combined results of the FTG and seismic work will then determine the nature and location of any drilling in the Block. Block 11A is in the vicinity of blocks operated by one of the most prolific oil and gas explorers in Africa. The proximity and in-trend relationship of the Lotikipi plain - the main surface feature of Block 11A - with those blocks as well as the Abu Gabra Rift basins of southern Sudan, which are established petroleum provinces, suggest a high prospectivity for hydrocarbons. In addition to Kenya Block 11A, ERHC's oil and gas exploration interests extend across the African continent.
Circle farms into Beni Khaled license onshore Tunisia CIRCLE OIL HAS agreed to farm into the Beni Khaled production license in Tunisia. The company will acquire an initial 30 per cent interest in the license from Exxoil in return for the funding of a 49-sq km 3D seismic data acquisition programme and one well. 3D seismic data acquisition is planned to start in late 2013/early 2014, with a first drill expected during the second half of 2014.
28 Oil Review Africa Issue Four 2013
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S08 ORA 4 2013 Geology & Gas_Layout 1 19/08/2013 16:58 Page 29
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Gas
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Aminex gets Tanzanian nod AMINEX HAS BEEN given the goahead to drill an appraisal well at a gas discovery off East Africa. The London and Dublin-listed junior also said it remains in negotiations with an unnamed party or parties about possibly farming out some of its holding in the Ruvuma block off Tanzania. Granting of an appraisal licence by Tanzanian authorities will see Aminex complete another round of seismic on the block as well as drill an appraisal hole at the Ntorya-1 discovery well. The appraisal licence has a duration of two years with extension options. The new seismic programme is anticipated starting in the autumn. In May Aminex said it had secured consent from state oil company Tanzania Petroleum Development Corporation for a deferral of drilling due to be carried out during the first exploration period that expires at yearend until the second period expiring in late 2016. The change to the terms of the Ruvuma production sharing agreement gave Aminex breathing space as it pursues ongoing talks with “a number of parties” for a farm-in deal on the block, where it currently holds 75 per cent as operator with partner Solo Oil on 25 per cent. The block covers about 6,000 sq km mainly onshore Tanzania, while also encompassing shallow-water sections and a deep-water part close to the coastline, and is estimated to hold around 178 bcf of discovered gas in place. Aminex estimates the potential for a total prospective recoverable resource of over four trillion cubic feet in all the prospects already identified within the block.
PetroSA plans $510mn S Africa LNG terminal SOUTH AFRICA’S STATE-OWNED oil company is planning to build an LNG terminal off the nation’s south coast that may cost as much as US$510mn. PetroSA contracted WorleyParsons to conduct a frontend engineering design study for the project that’s expected to be finished in September. A final investment decision is due in the fourth quarter of next year, and the project will be handed over by contractors to PetroSA by the first three months of 2018.
30 Oil Review Africa Issue Four 2013
BG Group upgrades Ngisi gas discovery AFRICA-FOCUSED OPHIR Energy has announced that the Ngisi-1 appraisal well, operated by BG Group, has successfully found further gas pay in Block 4, offshore Tanzania. The Ngisi-1 well was drilled by the Deepsea Metro 1 (UDW drillship) approximately three miles northeast of the Chewa-1 well. The Ngisi-1 well was designed to appraise the Chewa
gas discovery drilled in 2010 and to penetrate the Ngisi exploration prospect. Ophir reported that gas pay was encountered in the Ngisi prospect within a high net-togross reservoir interval, while penetration into the Chewa reservoir also encountered gas pay as predicted and confirmed widespread, excellent reservoir characteristics.
As a result, said Ophir, the mean recoverable resources of the Chewa-Pweza-Ngisi hub have been increased from 3.7 tcf to 4.5 tcf. Ophir added that the drilling result has also further demonstrated the feasibility of drilling highly-deviated wells, which will be incorporated into development planning of the assets. Ophir and BG Group successfully drilled their first deviated well in December 2012 in the Jodari Field. Ophir CEO Nick Cooper commented in a company statement: "The successful Ngisi drilling results provide critical mass for the aggregation and development of the gas discoveries in Block 4. These will be piped ashore and combined with the Block 1 resources for Tanzania's LNG development." The Deepsea Metro 1 drillship will now drill the Mkizi-1 exploration well in Block 1. Mkizi is a 0.6 tcf prospect of Tertiary age.
CNPC and Eni sign Mozambique gas deal CHINA NATIONAL PETROLEUM Corporation (CNPC) and Eni have signed a US$4.2bn deal to acquire a 20 per cent stake in Mozambique’s offshore natural gas field Block 4 Paolo Scaroni, chief executive of Eni, said that the partnership with CNPC was the company’s strategy to scale up its Africa production. “We are, by far, the largest producer in Africa and there’s a lot more room for further agreements between us,” Scaroni added.
The Italian oil and gas firm currently controls a 50 per cent share in the block and would continue to do so, company sources said. Meanwhile, CNPC’s contribution to construct LNG plants in the southeast African country would allow both companies to start exporting LNG by the end of the decade. This is China’s biggest investment so far in an overseas natural gas field and its first foray into East Africa’s huge gas discovery.
Mozambique plans LNG exports by 2018 MOZAMBIQUE HOPES TO export its first cargoes of LNG by 2018, President Armando Emilio Guebuza said at a recent conference in Aberdeen. "We are doing our best to make sure that by 2018 the first trains are delivered to the market," said Mr. Guebuza, promoting Mozambique's nascent oil and gas industry. The East African nation is on the cusp of becoming one of the continent's biggest energy producers following the discovery of giant natural gas
fields in the deep waters off its northeast coast. However, before any exports can begin, billions of dollars will have to be spent building the giant refrigeration tanks needed to cool the gas for shipping and developing port facilities big enough to house LNG carrier vessels. Mozambique expects it will cost at least US$40bn to develop its natural gas infrastructure, including a plant capable of exporting 20mn metric tons of LNG and a local distribution hub
that will service its domestic energy needs as well as those of its near neighbors, said Minister of Mineral Resources Esperenca Bias. "It will be the largest ever in Africa," said Ms. Bias. However, it remains unclear which international companies will build the terminal. "It is up to the concessionaires [Eni and Anadarko] to decide," said Arsenio Mabote, chairman of the state-owned National Hydrocarbons Co, adding that he expects the talks to conclude in the next few months.
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Cairn takes stake in Mauritania project OIL DRILLER CAIRN Energy has expanded its African empire by taking a stake in a project to explore off the coast of Mauritania. The Edinburgh-based firm has entered into a "farm-in" agreement with Chariot Oil & Gas that gives it a 35 per cent share of an offshore exploration block measuring more than 12,000 sq km and close to where oil has been found. Cairn is paying US$26mn for the stake and will meet just under 39 per cent of further exploration and development costs - reflecting a 10 per cent stake for which the Mauritanian state oil company does not pay. The move adds diversity to Cairn's activities along a vast swathe of the eastern Atlantic. Known as the Atlantic Margin, the company is already searching for oil and gas off the coasts of Greenland, Ireland, Morocco and Senegal. Chief Executive Simon Thomson said: "The opportunity in Mauritania presents an attractive country entry, building on our existing Atlantic Margin portfolio in Senegal and Morocco. "By developing an increased strategic presence in the under-explored and highly prospective new plays in this region, we can generate both operational and geological synergies and fully apply our proven frontier exploration skills." Although it usually carries out its own exploration, the interest in the Mauritanian block will be non-operated. However, the terms of the agreement leave open the possibility that Cairn could take a majority stake and become operator. Earlier this month Cairn hedged the risk on some of its work in Senegal by selling a stake to US giant ConocoPhillips for an undisclosed sum.
32 Oil Review Africa Issue Four 2013
Shell moves to buy Chevron oil blocks OIL GIANT, THE Royal Dutch Shell Plc has notified the Nigerian government that it would like to buy some of Chevron Nigeria’s licences. A report by the Wall Street Journal quoted an unnamed senior Nigerian government official. The paper said it would be a rare acquisition by an international energy company in Nigeria, where oil companies have in recent years generally exited acreage amid mounting security risks. It could also herald Shell’s exit from long-dormant oil assets in the Ogoniland region, where strident local opposition to its presence has prevented the company from producing oil since the 1990s. Buying Chevron’s blocs would effectively allow Shell to reduce its presence in the more challenging areas, while retaining enough assets to feed Shell’s existing pipelines. Shell has already sold off other assets in the Niger Delta, where it has maintained the longest presence of any foreign oil company. Shell’s local joint venture doesn’t want to leave the Delta region, however, said a person familiar with Shell’s thinking. The Shell-led joint venture, Shell Petroleum Development Company of Nigeria, could put Chevron’s assets in the region to good use, he said. “Chevron’s fields are better secured and still have plenty of oil in them.” Shell has said that it is carrying out a “strategic portfolio review” that could lead it to sell leases in the eastern Niger Delta that currently give the company between 80,000 and 100,000 bpd of oil equivalent. Shell Chief Executive Peter Voser said that while Shell would reduce its presence in some parts of the Delta, particularly the east where “sabotage is clearly a great concern to us,” it would still invest in others. “We will not leave the onshore completely,” said Mr. Voser. “In the more pure oil play, in the eastern part, we will be less represented over time, but it doesn’t mean we go out of onshore.”
Tullow Oil moving ahead off Guinea TULLOW OIL HAS notified authorities in Guinea of its intent to move into the third and final three-year exploration phase at its acreage offshore the west African country. The explorer is planning a wildcat on a deep-water fan prospect during the first quarter of 2014, junior partner Hyperdynamics said. As part of the new licence running from 21 September this year to 21 September 2016, Tullow Oil will also relinquish a quarter of the 25,000-sq km patch back to Guinea, the US independent added. Tullow Oil operates the licence on a 40 per cent stake with Hyperdynamics on 37 per cent and Dana Petroleum on 23 per cent. Originally the operator, Houston-based Hyperdynamics was unsuccessful with the first wildcat on the acreage, Sabu 1, which ran into difficulties that ramped up costs and ultimately saw Tullow Oil brought in after a November 2012 farmout.
Eni important oil and gas discovery offshore Congo ENI HAS MADE an important oil and gas discovery in the Nene’ Marine exploration prospect located in the Marine XII Block offshore Congo approximately 17 km from the shoreline. The company estimates the volume of the discovery proved with the two wells so far drilled at around 600mn barrels of oil and 700 bcf of gas in place. The structure has considerable additional upside that will be evaluated with further delineation wells. The discovery was made through the well Nene’ Marine 1, which has been drilled in 24 metres of water to a depth of 3,013 metres. The well encountered a significant wet gas and light oil accumulation in the pre-saline clastic sequence of Lower Cretaceous age. The Nene’ Marine 2 well was drilled two kilometres away from the discovery well and confirmed the significant hydrocarbon accumulation and the continuity of the reservoir. During production tests both the wells flowed at a commercial rates oil at 37° API gravity. Eni will continue the appraisal phase of the discovery while starting the studies for the commercial exploitation of this significant hydrocarbon accumulation with the partners of the Joint Venture.
Caracal gets going in Chad CANADA’S CARACAL ENERGY has spudded a pair of wells in Chad with another planned for later in the year: the Krim exploration south-west of the Mangara field development, which is estimated to hold between 29mn and 64mn barrels of unrisked prospective resources; and the Badila-4 appraisal well north-west of the primary Badila field which contains a trio of development wells. The well is set to take
between 20 and 25 days to drill. The whole field is estimated to contain total possible reserves of 40mn barrels. Once Badila-4 has been drilled to total depth, the rig will move onto the Bitanda prospect which has estimated unrisked prospective resources of 277mn to 648mn barrels. It should spud late in the third quarter or early in the fourth and take 35 to 45 days to drill. The Badila-3 well was recently
drilled to a total depth of 2,150 metres and cased to produce from two separate Cretaceous sand reservoirs. Tests indicated the well might produce 2,400 bpd once water-handling facilities are installed. Caracal continues to progress a transportation agreement with the ExxonMobil-operated pipeline facility, TOTCO-COTCO, which routes crude through Chad to the export terminal at Kribi in Cameroon.
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Genel eyes Ethiopia farm-in GENEL ENERGY HAS reached an agreement with New Age (African Global Energy) to gain a 40 per cent stake in the Adigala Block, onshore Ethiopia. Genel did not place a value on the deal but said the consideration to earn a 40 per cent non-operated interest would involve a payment in respect of back costs and a contribution to the cost of a 2D seismic survey which is planned before the end of the year. Genel said 520km of existing 2D seismic had been reprocessed last year and augmented by a full tensor gravity survey which provided evidence that all the elements of a working petroleum system exist within the block. Genel noted that oil seeps and surface outcrops supported the presence of a mature and active Jurassic oil prone system. "The Adigala Block farm-in is a natural extension of our exploration strategy, which seeks to acquire material equity positions in hydrocarbon basins with significant potential, as well as complementing our extensive interests onshore Somaliland where drilling is planned for 2014,” Genel's head of exploration, John Hurst, said. “We look forward to working with our new partners to highgrade the prospectivity on the block and add further depth and materiality to our exploration inventory."
Africa Oil to speed up East Africa exploration AFRICA OIL HAS begun drilling a new well in Kenya with its partner Tullow Oil, as the two companies speed up exploration efforts in the East Africa region. East Africa has become a hotbed of exploration after oil discoveries in Kenya and Uganda and huge gas finds in Tanzania and Mozambique. However, Kenya has yet to determine whether it has commercially viable quantities of hydrocarbons. Drilling of the Ekales-1 well, located within Kenya's Lokichar basin, has started. Its planned depth is 2,500 metres and it will take approximately two months to drill and evaluate its content, according to Africa Oil. "The Ekales prospect is probably one of the lowest risk prospects in our inventory. The proximity and similarity to the existing Ngamia and Twiga
discoveries give us a high degree of confidence that we will find oil and continue to build the discovered resources necessary for a commercial volume threshold," Keith Hill, Africa Oil's chief executive, said. Earlier this month, Tullow said it saw a flow rate potential of 5,000 bpd based on Ngamia-1 and Twiga-South-1, and estimated combined mean associated resources for the discoveries were 250mn barrels of oil, a forecast it said could increase further after appraisal. The Ekales-1 prospect is located approximately 15km northwest of the Ngamia discovery and seven kilometres south of the Twiga discovery. Ekales-1 on onshore block 13T is a joint venture between Tullow, the well operator with 50 per cent of the exploration licence, and Africa Oil.
Tullow drills for Ethiopia’s first oil TULLOW OIL, THE British explorer that found Kenya’s first crude a year ago, is about to find out whether the resources extend into neighboring Ethiopia, a nation dependent on agriculture that’s yet to discover any petroleum. Tullow, Africa Oil and Marathon Oil plan to complete their Sabisa well
in western Ethiopia’s South Omo Block this quarter. “The first discovery would be big news,” said Martin Mbogo, Tullow’s manager for Kenya, where its Ngamia well struck oil in March. “That would be historical for Ethiopia.” Tullow is targeting East Africa’s
Tertiary Rift, a geological fault that’s yielded oil in Uganda as well as Kenya. For the company, an Ethiopian find may prove a new oil province. For the country, evidence of crude could help the government curb energy imports and diversify an economy that relied on coffee for about a quarter of export earnings in 2011. “We are importing every drop of oil and gas,” Ethiopian Mines Minister Sinknesh Ejigu said last week. Licenses won by Tullow and Africa Oil in Kenya and Ethiopia cover an area almost as large as the North Sea. Only 11 wells have been drilled there so far, compared with more than 2,400 wells in the sea. While gas has been found in eastern Ethiopia, the partners are focusing on the western Omo region in the hope it will prove the extension of the petroleum system from Kenya.
Hoifu gains Madagascar stake HONG KONG-LISTED Hoifu Energy has gained a 100 per cent interest in the exploration, exploitation and operations rights, as well as the profit sharing right, of Block 2101 in Madagascar. Hoifu picked up the stake by acquiring the entire issued share capital of Madagascar Northern Petroleum Company which held the rights.
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Block 2101 covers 10,400 sq km in the northern part of Madagascar but no exploration work has been carried out on the block. Hoifu did note, however, that five exploration wells had been drilled in areas surrounding the block between 1964 and 1992. It added that signs of oil and gas were found in those wells using legacy
technologies, but not in amounts deemed to be commercial. Madagascar Northern Petroleum holds the rights to engage in oil and gas exploration on Block 2101 for eight years, with possible extensions of two years and five years for oil and gas respectively. It also holds the rights for exploitation and operation of oil from the block for
25 years, with a possible five-year extension, and gas for 35 years, with a possible 10-year extension. Hoifu said it planned to appoint “professional institutions” to start the relevant work needed to commence exploration and exploitation operations at the block once it completed its acquisition of Madagascar Northern Petroleum.
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Somalia signs 0&G exploration deal SOMALIA’S GOVERNMENT HAS signed an oil and gas exploration deal with a newly formed British company, the first such agreement by a central government in Somalia following decades of conflict. The deal with Soma Oil and Gas allows the company to conduct seismic surveys in Somalia’s territorial waters and in limited onshore regions. The company agreed with Somalia to gather data from offshore areas and “limited” inland acreage. It plans to build a data bank on behalf of the government. The company’s chief executive, Robert Sheppard, said that Somalia remains significantly underexplored in the oil and gas sector despite recent discoveries across East Africa. “Depending on the data we find we will decide which blocks to apply for exploration and drilling rights”, Sheppard said. Somalia’s Mogadishu-based government said it expected the deal would attract new development “in an area of immense economic potential” for the nation.
Apache makes Egypt finds APACHE CORP HAS unveiled a plethora of oil and gas discoveries across a quartet of basins in one region of Egypt. The oil giant has already flowed oil and gas from one of the finds, all of which have been tested and are in the Western Desert. Riviera SW-1X well on the southern flank of the Abu Gharadig basin has flowed 5,800 barrels of oil and 2.8 mcfd of gas intesting from a Lower Bahariya sand with 24 feet of net pay. It is currently producing at 2,000 bpd with gas being monitored. “The discovery extends to the known southern limit of the play in the Abu Gharadig basin,” Apache said. In the Faghur basin, the WKAL-T-1X well hit 32 feet of net pay in the Safa formation. It flowed 2,900 bpd and 2.8 mmcfd in testing. Also in the basin, the WKAL-N-3X appraisal well successfully extended the WKAL-N field to the west, testing at a rate of approximately 3,500 bpd and 3.2 mmcfd from the Safa Formation. In the same basin, the SIWA-R-1X, located in the Siwa concession tested 1,900 bpd from the Safa sandstone hitting 73 feet of net pay. A fourth discovery in the Faghur basin was at the Buchis W-2X well, which tested a threeway closure adjacent and up-thrown to the Pepi oil field with multiple Cretaceous, Jurassic and Paleozoic objectives. www.oilreviewafrica.com
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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.
JULY 2013 - LAND & OFFSHORE JULY 13 Country Land & Offshore ALGERIA 49 ANGOLA 11 CAMEROON 3 CHAD 2 CONGO 4 EQUATORIAL GUINEA 1 GABON 6 GHANA 2 COTE D'IVOIRE 0 KENYA 6 LIBERIA 0 LIBYA 16 MOZAMBIQUE 2 NIGERIA 17 TANZANIA 1 TUNISIA 3 UGANDA 1 D R CONGO 1 NAMIBIA 1 SOUTH AFRICA 0 MAURITANIA 1 ETHIOPIA 1
JUNE 13
VARIANCE
JULY 12
Land & Offshore 48 13 3 2 4 2 6 1 0 5 0 15 2 20 1 5 1 1 1 1 1 1
From Last Month 1 -2 0 0 0 -1 0 1 0 1 0 1 0 -3 0 -2 0 0 0 0 0 0
Land & Offshore 45 6 0 2 2 1 6 3 1 2 1 9 2 17 2 2 3 1 0 0 0 0
JUNE 12 Land & Offshore 41 12 0 2 1 2 4 4 0 2 1 10 1 19 2 2 3 0 0 0 0 0
VARIANCE From Last Month 4 -6 0 0 1 -1 2 -1 1 0 0 -1 1 -2 0 0 0 1 0 0 0 0
HRT spuds ultra-deep Namibia well BRAZIL INDEPENDENT HRT said it has spud an ultra-deep water well in a exploration programme off Namibia, hoping the third time will be the charm after two of its prior wildcats did not find commercial oil. Moosehead-1 will target the oil potential of
Barremian-aged carbonate reservoirs in hopes of finding an analog of Brazil's bounteous pre-salt. The wildcat is on PEL 24 in the region's Orange basin and is expected to be drilled to 4,100 metres over 53 days. The site is 197 km south-west of Luderitz,
Namibia in 1,727 metres of water. HRT is the operator while Portuguese player Galp is a 14 per cent partner. HRT found oil shows but no commercial reservoir in the Walvis basin at its Wingat-1 well, while the Murombe-1 probe was dry.
M&P increases Namibia footprint MAUREL & PROM HAS increased its stake in an offshore sub-Saharan African play. The explorer has exercised an option to increase its holding in exploration licences (PEL) 44 and 45 off Namibia to 42.5 per cent after taking 5.5 per cent from partner AziNam. “The exercising of this option provides further confirmation of the significant prospectivity of these blocks, particularly after the discovery of a mature Aptian marine source rock in both of the recent (Brazilian independent HRT Oil & Gas) exploration wells located adjacent to the licence area,” AziNam said. In late July HRT threw up dust at the Murombe wildcat on Block 2212A in the Walvis basin. Murombe was drilled to a final depth of 5729 metres and just 15 km west of Wingat, the company’s first dry well in Namibia. The main objective of Murombe was to test the resource potential of Barremian turbidite rocks, but wireline logs indicated poor results. HRT also did not find commercial oil at its first Wingat-1 wildcat in
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Namibia but said oil shows bolstered the area's geologic potential. The Brazilian has, since those two commercial dusters, spudded the Moosehead-1 wildcat which will target the oil potential of Barremianaged carbonate reservoirs in hopes of finding an analog of Brazil's bounteous pre-salt. The wildcat is on PEL 24 in the region's Orange basin and is expected to be drilled to 4100 metres over 53 days. Despite HRT’s travails, AziNam managing director David Sturt said: “The two recent HRT wells have significantly advanced our understanding of the hydrocarbon potential of our exploration licences. We now have a proven laterally extensive mature oil source rock along the offshore margin where our exploration licences are located. Data collected from recent drilling demonstrates that the offshore Namibian Basins contain all the ingredients of a working hydrocarbon system.” www.oilreviewafrica.com
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South Sudan looks to EAC for pipeline options SOUTH SUDAN HAS moved closer to its target of gaining access to a pipeline to export its oil to the south. The presidents of Uganda, Kenya and Rwanda have agreed to build two pipelines across East Africa. One would run from South Sudan to the Kenyan port city of Lamu and the other would stretch from Rwanda to Mombasa. Currently, South Sudan exports its oil through Sudan and supplies are often disrupted as the two countries disagree over pricing and security issues. This caused considerable loss to the South Sudan economy in terms of redu ced foreign exchange earnings. The three-way agreement between the presidents was confirmed by Uganda's foreign minister, Sam Kutesa. Recently, Sudan's President Omar Hassan al-Bashir threatened again to stop oil flows across its border with South Sudan, unless South Sudan stops supporting rebels operating across the shared frontier. South Sudan denies supporting rebels and, in turn, accuses Khartoum of backing insurgents on its soil. When South Sudan became independent nearly two years ago, it took 75 per cent of the oil reserves of Sudan. However, Sudan retained the pipeline infrastructure, as well as the refineries and export terminal at Port Sudan on the Red Sea. East Africa is experiencing an energy boom at the moment, after oil and gas discoveries in Kenya, Uganda and Tanzania. Kutesa said the three countries had also agreed to build a railway line from Kenya through Uganda to Rwanda. "It was agreed to revamp the existing railway network and also construct a standard gauge railway line in Kenya and Uganda and also extend it to Rwanda," he said.
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Petroleum refinery upgrade needed urgently THE KENYA PETROLEUM Refinery (KPR) needs US$ 1.2bn for the upgrade of its outdated technology. Kenya’s Energy and Petroleum Cabinet Secretary DAVID Chirchir said that the refinery’s products contain more sulphur than imported oil, requiring urgent modernisation. Oil industry players have been calling for its dismantling arguing that most of the products consumed in the region are imported. However, the recent entry of Kenya as an oil producer has called for the upgrading of the Mombasa-located facility. “Introduction of new technology will enable the plant to increase its capacity and adequately serve Kenya, Uganda and South Sudan”, observed Mr. John Mruttu, a former general manager and now an elected governor. With the upgrade of the facility, Kenya will be able to
refine crude oil from the region and export it at a higher price, according to Mr. Mruttu. The refinery is the only such facility in the East African region and its development would add value to the region. The company has an installed capacity of four million metric tonnes per annum but only processes 1.6mn of imported crude oil annually. It also produces an average of 30,000 metric tonnes of Liquefied Petroleum Gas (LPG) It has a 9.5 MW power plant to provide electricity to the refinery. It also runs on heavy fuel oil that cost an estimated US$13.5mn. The refinery directly employees 250 workers and offers another 750 jobs indirectly to contractors. Mwangi Mumero
Angola LNG production underway CHEVRON SUBSIDIARY CABINDA Gulf Oil Company has confirmed that initial production of LNG has commenced at the Angola LNG project. Angola LNG is one of the largest energy projects on the African continent. "First gas at Angola LNG is an important milestone in support of our strategic plan to grow our production," said George Kirkland, vice chairman of Chevron Corporation. "This project will commercialise natural gas resources in western Africa to meet growing demand in the region and internationally." The US$10bn project will collect and transport natural gas from
offshore Angola to an onshore liquefaction plant on the coast near the Congo River. The project has the capacity to produce 5.2mn metric tons per year of LNG, 63,000 bpd of natural gas liquids for export and 125 mmcfd of natural gas for domestic consumption. "The project represents the first LNG project in Angola, and it is expected to contribute to the development of Angola's natural gas industry," said Ali Moshiri, president of Chevron Africa and Latin America Exploration and Production Company. Angola LNG plans to use associated natural gas produced
from existing crude oil operations operated by Chevron and other partners as well as new nonassociated gas from other offshore fields. The project is expected to reduce natural gas flaring and greenhouse gas emissions from offshore producing areas, and support continued offshore oil field development. Chevron's subsidiary, Cabinda Gulf Oil Company Ltd, has the largest interest in the joint venture.
Perenco’s pipeline installation in Cameroon AFTER SIX MONTHS of engineering work, Perenco has completed its first pipeline installation over eight kilometres between the Ebome platform and the KB wells in Cameroon. Completed in only two and half days in 30m of water, the task was completed using the DP2 multipurpose vessel, Anna B. During the laying of the S-lay Reinforced Thermoplastic Pipeline (RTP), over 5,400 concrete sinkers, equating to 300 tonnes of concrete, were clamped onto the pipe to ensure its stability. Already used by Perenco Congo on the Emeraude field, the RTP system is fully corrosion resistant internally and externally and is a proven solution to corrosion issues caused by high H2S or CO2 content, as found in the KB well fluids. While steel pipe has a large submerged weight, RTP floats even when water filled, hence sinking the pipe onto the seabed requires certain adjustments to the standard pipeline installation methods.The spooling and welding by electrofusion of the pipeline were performed onshore in only two weeks using a nine metre diameter and
four metre height carrousel. The 50 t reeled pipe was then lifted from the dock to the vessel. During the offshore installation, the pipe was rolled out from the carrousel through a five tonne tensioner before passing through the 15-m firing line, where the concrete shelves were simultaneously clamped onto the pipe on five sinker assembling stations. A system of electrical lifting hoist, conveying rails and inclined roller ramps, allowed a continuous feeding of the assembling tables with concrete blocks coming from the storage unit onboard at an enhanced laying pace (4.5 km/day). This was a major time and cost saving in comparison to the previous deployment concept, where one pipeline section is laid at a time, in an assembly-line method and with in-line couplers needing to be applied on the spot. These innovative concept, engineering, preparation works, supervision and field operations were made possible only as a result of the close collaboration and team spirit that exists between Perenco HQ and the subsidiary project teams. www.oilreviewafrica.com
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Technology
Over the past two decades, great gains have been made in rig design, the materials used and in the training of rig personnel in order to tackle and reduce the inherent risks of the oil and gas industry. Nicholas Newman reports.
Fire prevention and
protection on oil rigs D
RILLING FOR OIL and gas, whether onshore or offshore, can be a dangerous business, with the risk of explosions and fires leading to damage and even loss of life. The Piper Alpha disaster marked the beginning of risk assessments, and protection against fire of equipment and personnel. According to Baker Hughes, the number of rigs operating worldwide in May 2013 was 3,178. North America accounted for the majority of rigs onstream, with some 1,954, while Africa accounted for 124, with the remainder scattered across the world. West Africa had a total of 72 drill wells in operation, mainly in Nigeria and Angola. However, given the recent discoveries in Lake Albert, Tanzania, Mozambique, Namibia and South Africa it is likely that more rigs will be coming to Africa. Normally when one thinks of rig accidents, BP’s Deepwater Horizon disaster in the Gulf of Mexico comes to mind. However, fire incidents and explosions also happen in Africa. In Nigeria, Chevron’s offshore jack-up North Apoi oil platform caught fire some 10km from the coast on 16 January 2012. The North Apoi field was producing approximately 2,000 barrels of oil per day (bopd) when the incident occurred. The fire at the rig is thought to have been caused by gas pressure buildup in the well, with the resultant flames reaching as high as five metres in a 40-metre wide area surrounding the rig. It took a month for the fire to burn itself out. Following the incident, the oil giant was said to have reduced the bonus of CEO John Watson by 13 per cent (US$520,000) to US$3.5mn. Oil and natural gas are highly flammable, with a tendency to combust and explode, making working on an oil or gas platform an extremely hazardous workplace environment. There is much the industry has learned in the past 100 years to reduce the dangers of working on rigs, but accidents still happen. Stakeholders, including operators, designers, regulators and labour unions, are constantly looking at ways to reduce the potential of such hazardous events from occurring.
Rig design Oil and gas rig platform designers will employ engineering safety consultants such as Nowatec or Scandpower, which use risk analysis modelling software to determine the drivers behind fire hazards and analyse different safety design features. When Nowatec CEO Jurek Czujko was asked what the main differences were between the past and today, he said “the requirements for safety are twice as large”. While strict regulations and health
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Human error was a contributory factor in the Deepwater Horizon explosion in 2010.
Human error is estimated by Danish risk consultancy company DNV to be responsible for at least 80 per cent of the oil and gas industry’s accidents. and safety aspects are commonplace for rig platforms, operating rigs are usually designed to the latest in European and American standards. It is interesting to note, however, that there appears to be no African-based centre for risk management or engineering expertise devoted to fire prevention and protection. Rig designers employ two strategies for the prevention and control of fires: passive protection and active control and protection. Passive fire protection (PFP) is defined, in the recently issued ISO standard (ISO 1999), as ‘a coating, cladding or freestanding system which, in the event of a fire, will provide thermal protection to restrict the rate at which heat is transmitted to the object or area being protected’. Such materials, including firewalls provided by Invicta Protection, are used to prevent escalation of the fire caused by progressive release of
oil or gas. By separating the different fire risk zones, protecting critical structural items such as escape routes, staff refuges and equipment with fire resistant materials, it is possible to protect employees awaiting evacuation by helicopter or ship. Given the cost of rig platforms, designers and constructers routinely employ fire-resistant materials to protect essential safety items and critical operating components such as separators, risers and topside emergency shutdown valves. Current common fire protection applications include spray-applied epoxy intumescent and subliming coatings, supplanting cementitious materials which were widely used in the past. Problems associated with passive fire protection materials include the time taken to apply them, the additional weight (several tonnes) and hence the additional cost when constructing the rig platforms. The second strategy, called active ‘fire protection’, consists of several systems that may necessitate human intervention to start the process of protection. These include ecologically sustainable development (ESD) and blow-down mechanisms, water deluge and foam systems, monitors, inerting systems and fire extinguishers to name but a few. The primary form of active fire protection for hydrocarbon processing areas is fixed deluge. This method may be used to control pool
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Technology
Rig designers employ two strategies for the prevention and control of fires, namely passive protection and active control and protection.
fires and thus reduce the likelihood of escalation through cooling of the equipment. In addition, the method enables the application of foam to extinguish hydrocarbon pool fires and limit the effects of fires (eg, radiation, smoke movement) and to facilitate emergency response and evacuation, escape and rescue (EER) activities.
The human factor It is clear from the evidence found in the Deepwater Horizon disaster that human error was a contributory factor behind the event. Human error is estimated by Danish risk consultancy company DNV to be responsible for at least 80 per cent of the oil and gas industry’s accidents. Human error includes poor corporate culture, incorrect procedures and management decisions by operators, managers and other employees. Examples of commonplace human error include allowing routine essential maintenance to fall behind (or to be skipped in order to save money), poor monitoring of safety procedures and having a corporate culture that discourages feedback from workers seeking to alert the company to problems. As one industry source said recently, “Many corporate executives, when they go under inspection tours of rigs, are so blinkered they fail to see the reality of the dangers, which are so apparent to everyone else on the rig.”
fire prevention, safety and fire management courses to its students. Henry Ezdkwzre, business development manager of the company said, “Oiltrain.org trains around 100 students a month and plans to increase that number by providing courses for candidates living in rural parts of Nigeria. The facility also offers courses for graduates and employees of energy companies needing continuing professional development (CPD).” Meanwhile in Cape Town, South Africa, an organisation called Safety at the Sea South Africa is offering an eight-day ‘STCW 95 (Offshore) – Oil Rigs, Ships, Support Vessels & Other Platforms’ course designed for crews wishing to work in the offshore industry, which is recognised by the International Maritime Organisation and valid for five years.
It is interesting to note that there appears to be no African-based centre for risk management or engineering expertise devoted to fire prevention and protection.
Rig fire prevention training With the increasing number of rigs employed in African territories for exploration and development of new oil and gas fields, health and safety issues, fire prevention and protection issues have gained salience. There is an increasing insistence by several national governments that local citizens should be employed in the energy industry. To satisfy this concern, rig operators are compelled to train local employees up to the standard required by the industry. This includes, in the interests of developing a positive health and safety culture, educating newly recruited staff in fire safety procedures. New training establishments have been set up in such countries as Nigeria and South Africa to equip graduates with the latest in industrially recognised skills. One such example is Oiltrain Human Resources Management Ltd which, established just over three years ago and based in Port Harcourt, Nigeria, offers industry-recognised
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In addition, there are an increasing number of distance learning courses available for both new entrants and those needing to regularly update their skills while working. Among the distance learning providers operating in the African market are SMTS Ltd, which offer National Examination Board in Occupational Safety and Health recognised courses. In addition, it also provides onsite HSE related courses including fire safety from their offices in Accra, Ghana, Lagos, Nigeria and Sasolburg, South Africa.
Conclusion It looks increasingly likely that, as a result of the increasing number of discoveries being made every month in Africa, that the demand for HSE fire training and prevention courses will increase. Also, we should expect to see the establishment of African-based risk management engineering consultancy expertise in the next few years. ■
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Technology
How the oil industry is extending the life of ageing fields in Africa.
Turning back
time
Technicians on the Kitina platform, Republic of Congo.
I
N MATURE PRODUCING countries like Nigeria - where the prolific coastal Niger Delta region has been active for more than half a century - it’s not always about finding exciting new oil deposits. It’s nice when drillers unearth a new billion barrel pool offshore, of course, but industry economics means that extracting the most benefit from any known reservoirs is just as important. Anything else is simply throwing money away. About 70 per cent of the oil world’s oil produced today comes from fields over 30 years old, placing the focus of interest for much of the industry squarely on mature fields. This is less true for much of sub-Saharan Africa, where new producers like Angola, Equatorial Guinea and, most recently, Ghana have come through the ranks, but very much the case in developed regions such as the USA and the North Sea. In the super-giant multi billion barrel fields of the oil-rich Middle East it’s almost routine.
Compelling argument Extending the life of a field through enhanced oil recovery (EOR) techniques, including targeted horizontal drilling, water injection, or other modern technology, is now big business, and it’s become increasingly relevant to Africa. Many of the techniques gleaned from older oil producing regions like the Middle East are now being deployed in established territories such as Nigeria to give ageing assets a new lease of life. As well as allowing the best return on investment, any life of field extension can also
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reduce the overall environmental impact and maximise employment for local communities. This is important anywhere but especially so in Nigeria - where Shell pioneered production in 1958 from the Oloibiri field in the Eastern Niger Delta - and other poor countries.
Any life of field extension can reduce the overall environmental impact and maximise employment for local communities.
Congo success Certainly, the economics make for a compelling case. According to oil industry services giant Schlumberger, just a tiny one per cent improvement in recovery from known reservoirs could add around 10bn barrels of oil equivalent to world reserves. The company is an expert in increasing recovery from mature fields in declining production, known as brownfields. Within Africa, Schlumberger has helped Italian oil company Eni lift production from the mature Kitina field, offshore the Congo coast, among other assignments. It helped raise output from re-completed cased hole wells from 590 bpd to 1,905 bpd, with a variety of techniques, that involved hydraulic fracturing, which has been used onshore with good results, but less commonly applied offshore. Eni’s success led it to deploy the same technology on a virgin reservoir in the adjacent offshore Foukanda field.
Gabon turnaround Along the coast, Total’s re-development of the Anguille field in Gabon is currently one of the country's largest upstream investments. The French company has pledged to spend US$2bn in the coming years in an attempt to
curb declines and maintain plateau production at Anguille and other fields. Gabon’s production has declined perilously for more than a decade now. Total oil production has slumped from around 370,000 bpd in 1997 to 244,000 bpd in 2012. The Anguille project has been conducted in three phases with a total of 41 wells. Total expects new production from the last phase to start this year. Additional life extension projects at the Torpille and Avocette fields have also offset natural declines from other sites. Re-development projects by various smaller companies, such as Addax, at the Tsengui and Obangue fields, and Vaalco Energy, at the offshore Etame field, are also expected to help in offsetting declines at some of Gabon’s mature fields.
Technology Technology is playing a central role in all of these re-development schemes that will ultimately prolong the life of Africa’s vital upstream assets. Other industry service providers such as Halliburton and Wood Group are equally active on this front. www.oilreviewafrica.com
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Shell has also invested time and money to prolong the life of the Bonny field, which commenced production in 1973. Located just 6km northeast of the Bonny crude oil terminal, the field had a peak production of 40,000 bpd in 1976, but declined to around 5,000 bpd. The re-development plan included new horizontal wells, as well as vertical and deviated wells, all targeting just a few of the 25 hydrocarbon bearing reservoirs in the field.
More to come Nigeria boost In Nigeria, itself, sub-Saharan Africa’s biggest oil producer, there are plenty of examples where industry has come together to improve the lifespan of maturing fields. Mobil Producing Nigeria, a part of the ExxonMobil empire, is one of Nigeria’s big joint venture oil companies, and has been active since the 1950s. One major focus area in more recent times has been field life extension. Its East Area Additional Oil Recovery project, for instance, represents a major investment in a mature operation to extend field life, increase recovery rates and eliminate non-routine gas flaring by injecting produced gas.
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As more of Africa’s fields mature, and as the continent itself matures as a regional producer in the world, it seems likely that extending field life will take on even great prominence. This is already being borne out by corporate activity as multinationals, independents and state-owned operators invest big in maintaining and maximising upstream wealth. One company that specialises in prolonging the life of oil fields is the UK’s EnQuest, which only recently dipped its toes into the African market. In May, the North Sea operator took over various Tunisian assets from PA Resources, including the Didon oil field and the Zarat Field. The acquisition of the fields, all located in
Technology
New tools are also available for engineering an entire field. Acquisition of repeat seismic surveys, called a time-lapse seismic study, can provide valuable information for field optimisation. Changes in fluid saturation or composition, for instance, or the lack of change, can indicate areas of the field that would benefit from more wells, or wells that need workovers. It can make all the difference in squeezing additional barrels of oil out of reservoirs, or extending the overall life of the field.
Shell and Schlumberger have signed a multi-year research technology co-operation agreement focusing on improving the recovery factor of oil and gas reservoirs and extending the life of existing oil and natural gas fields.
the Gulf of Gabes, are part of the EnQuest strategy to create value from maturing assets as well as new developments. EnQuest's chief executive Amjad Bseisu said the acquisition will “allow us to deploy our operating and development expertise in these permits”, with a programme of two infill wells expected to add additional reserves in the near future at the Didon field will. At a time when oil prices are high, and reserves are scarce, it’s a strategy that could well be adopted and mirrored by other new entrants too. ■
Oil Review Africa Issue Four 2013 45
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Technology
There’s no doubt that the African subsea market is continuing to grow. By Nitin Patel & John Spain, Quickflange
Bringing simplicity to Africa’s
subsea operations D
RIVEN BY THE need to develop fields in deeper waters and in more challenging locations, industry analysts Douglas Westwood forecasts a 90 per cent growth in worldwide deepwater expenditure between 2012 and 2016 with 72 per cent of this targeted at Africa and the Americas. According to energy analysts Infield Systems, there are 139 shallow water and 59 deep water fields currently on-stream in West Africa and six shallow water projects that are producing offshore South and East Africa. And these numbers are only likely to increase as exploration activities offshore Kenya, Tanzania and Mozambique come to fruition. Infield also noted an increased demand for subsea trees in West Africa as well as a growth in subsea processing. Yet just as fields and accompanying subsea infrastructures have become more complex, paradoxically so has there been an increased need for simplicity in subsea operations. The key drivers for this include the currently complex nature of subsea infrastructures and the high costs of subsea intervention. It is this current complexity of African subsea production systems which is driving the need for low impact and flexible technology solutions that can navigate around existing infrastructure. Similarly, unscheduled and unplanned subsea interventions can come with significant operating expenses, limited diver intervention opportunities and highly negative effects on production. The result is that operators are looking for a greater degree of simplicity in their operations.
Subsea pipeline and mechanical connectors While development tie-ins of new fields to new pipelines tend to incorporate hyperbaric welding, many repairs and immediate pipeline requirements are achieved through mechanical connectors. This is due to hyperbaric welding spreads not being so numerous, and the fact that welding is often unavailable for quick deployment on immediate repair scenarios. In such situations, operators tend to look towards mechanical sleeve connectors. Traditional mechanical sleeve connectors are connectors that dispense with the ignition sources and flames associated with welding and deliver a secure and leak-free mechanical and pressure-tight connection. Many such connectors use gripping mechanisms or special seals to ensure maximum integrity. For all their potential benefits, however, and their importance for immediate repairs, the pipeline
46 Oil Review Africa Issue Four 2013
Figure 1. The Quickflange Subsea connector.
Operators are looking for a greater degree of simplicity in their operations. and mechanical connector market has been characterised for many years by high subsea intervention costs and complex and highly engineered solutions. Whether it be emergency or contingency pipeline spool repairs, pipe lays, decommissioning or just pipeline modifications, such solutions often come with unnecessary complexity. They can be cumbersome to install with the need for specialist diver training, require significant diver time, come with long lead and delivery times, and often have significant availability issues.
The moves towards simplicity It’s against this backdrop that Quickflange has developed an alternative to traditional subsea welding and sleeve connectors – a subsea connector known as the Quickflange Subsea (see figure 1). The connector comes with its own significant benefits over traditional mechanical sleeve connectors, enabling operators to enjoy, for the first time, low impact, flexible and cost effective subsea pipeline repairs that are also highly reliable and robust.
The Quickflange Subsea follows an extensive testing programme in partnership with the Norwegian Research Council, the University of Agder, the National Hyperbaric Centre in Aberdeen and Brazilian operator, Petrobras. In its simplest form, the subsea connector is a modified weld neck flange, with patented internal grooves machined in such a way that the flange can easily slide onto the pipe. A simple hydraulic tool is then used to fit the flange onto the pipe by a process which flares the pipe into the Quickflange grooves. Figure 2 illustrates the installation process. The process is completed within minutes with the resulting connection qualified to be every bit as robust as a welded connection as well as being less onerous in installation compared to other more cumbersome mechanical systems. The new solution can be utilised in a number of subsea scenarios, such as pipe lay; decommissioning; pipe work and new spool tie-ins; the replacement of existing flanges; subsea repairs such as for emergency spools; or for repair contingency purposes. Initial testing of the connector took place in partnership with Petrobras where the goals were to verify the suitability of the connector under subsea operations and meet key criteria, such as speed of installation and ease of use. Initially, the Quickflange solution was deployed and activated within a specialist water tank with divers
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Technology
S12 ORA 4 2013 Technology_Layout 1 19/08/2013 17:08 Page 48
The case for simplicity – both topside and subsea – is too big to ignore for operators today. that the flange has no moving parts, grips or other components, ensures that less can go wrong. The second key benefit is the connector’s flexibility and easy activation. The increased safety and low impact nature of the solution means that it is easier to install than many mechanical connection solutions. There is little required paperwork and existing platform personnel can be trained up to deploy the connector with little need for increased staffing levels and extra platform space. As it is up to 60 per cent shorter than other pipe-end connectors, the flange is easier to handle with straightforward diver operations and no specialist diver training required. The activation tool can also be used on multiple pipe ranges with the installation being fully retrievable and reusable, thereby making it ideal for emergency repair and contingency repair systems. Finally, there are reduced costs – so important in subsea intervention today. It is these fast delivery times and easy implementation that can reduce costs with a lowering of required diver time, and less pipe preparation, such as coating removal and deburial. Finally, the easy installation and simplicity is unlikely to have a negative effect on other subsea activities or production which can again directly affect the bottom line. As African operators move into deeper waters, there is also a need to move from divers to remote operations. To this end, we are already looking at ROV-enabled options.
Rising to the challenge Figure 2. The installation process.
supporting the installation process. From start to finish, installation times were as little as 50 minutes. The connector was also tested at the National Hyperbaric Centre in Scotland.
Robustness, flexibility & reduced costs It is through this design and the connector’s simplicity that operators can enjoy a number of
benefits in their subsea pipeline operations. Firstly, there is increased robustness and reliability. The cold-forging connector forces the pipe wall into the grooves, resulting in a joint equivalent to a weld. Third party testing has also demonstrated that the solution is every bit as robust as other alternatives in terms of pressure retention and load resistance. Furthermore, the fact
It’s clear that the case for simplicity – both topside and subsea – is too big to ignore for operators today. Such simplicity can have an enormous impact on the cost of doing business and seamless operations. It’s therefore encouraging to see that some technologies are rising to the challenge, through simple, low-impact, flexible, reliable and cost effective subsea pipeline repairs. As the African subsea market continues to grow, this focus on simplicity is likely to bring with it more and more benefits. ■
BP orders deepwater sampling kit for offshore Angola fields BP HAS CONTRACTED Proserv to design and manufacture a subsea sampling system for the PSVM multi-field deepwater development offshore Angola. The system will be designed to work at a maximum water depth of 2,500 m as well as interfacing with twoand four-slot subsea manifolds. It will be fully compliant with NACE and API standards. The equipment will interface with the PSVM subsea production system to support monitoring of PVT properties in the production
48 Oil Review Africa Issue Four 2013
fluid as there is potential for flow assurance issues such as scale build-up. Proserv’s manufacturing centre close to Aberdeen will produce cylinders for the sampling system, which will be manufactured and assembled at the company’s Birchmoss facility in Aberdeenshire, Scotland. Proserv has provided two similar subsea sampling systems previously for BP Angola on block 18 via FMC Technologies.
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EXPRO CELEBRATED ITS 40th anniversary at this year’s OTC by showcasing its investment in new technology and innovation. As part of that commitment Expro launched the proto-type HawkEye V downhole camera, new high pressure/high temperature (HP/HT) Drill Stem Testing (DST) BigCat™ packer, and Expro Annulus operated circulating and test (ExACT™) tool. The new HawkEye V downhole camera offers market-leading imaging capability and information, to develop cost-effective remediation solutions for complex wellbore flow restrictions, obstacles and reservoir management. HawkEye V features 300°F capability, bi-directional side view rotation/scan (snapshot) in single degree increments, with enhanced quality picturing and software. A range of Expro’s cameras, calipers and logging tools were also on show, to assist in demonstrating Expro’s global wireline intervention capabilities and its ability to offer blow out preventer and riser inspection services. Expro also showcased the new DST BigCat packer, which provides a high strength, single-trip retrievable alternative to seal-bore packers in HP/HT well tests. The fully annulus-operated ExACT tool - which is the most advanced tool of its kind - combines downhole shut-in and circulating functionality. Rated at 15K psi and temperatures of up to 450°F, ExACT features minimal, fast-cycling to position the ball and ports in the required position. Expro’s enhanced DST capabilities provide technology and specialist data services from reservoir to disposal, to provide an integrated well test solutions package across the exploration and appraisal (E&A) phase of the well. This includes tubing conveyed perforating, data acquisition, surface read-out through cableless telemetry, fluids sampling and analysis, compact well testing solutions and enhanced flow measurement.
Wärtsilä GasReformer - transforming flare gas to fuel for efficient power generation WITH THE GASREFORMER, Wärtsilä now provides a convenient moneysaving option to utilise flare gas for highly cost-efficient power production in the oil and gas industry. The product was awarded the Offshore Technology Conference (OTC) 2013 Spotlight on New Technology Award, which recognises innovative new products that provide significant impact for offshore exploration and production. The Wärtsilä GasReformer is an innovative new product that enables gases produced during oil production, which by nature are rich in heavy hydrocarbons, to be converted into a methane rich product for utilisation in Wärtsilä gas fuelled engines operating at full performance levels. Typically, associated gas as such is not suitable for use as fuel, but fed through the GasReformer, a unit the size of a container, it can power Wärtsilä gas fuelled engines on oil rigs and oil fields. The GasReformer can also be used to recover the Volatile Organic Compounds (VOCs) emitted when handling crude oil. The traditional way of dealing with associated gas in oil production is to use either flaring or venting, to burn the gas in boilers or use it as fuel for gas turbines. Gas turbines have high operational costs and low efficiency compared to Wärtsilä gas fuelled engines, which can now provide power using this gas.
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The 'raw' associated gas is a mix of various amounts of heavier hydrocarbons - such as ethane, propane and butane, pentane, hexane etc, in addition to clean methane. Associated gas with a significant amount of heavy hydrocarbons has a low methane number (MN), indicating a high tendency to cause engine ‘knock’. When the gas has a lower methane number, the engine has to be derated or operated using less cylinder compression, in order to avoid this knocking. This again reduces the efficiency of the engine. A minimum methane number of 80 is desirable. With a methane number between 60 and 80, one can still use an engine de-rated to some 75 - 80 per cent, and instead add cylinders as needed.
Below 60, the GasReformer provides the best solution for fuelling a power station. With the GasReformer, Wärtsilä now provides a convenient money-saving option for power production for the oil and gas industry. Peik Jansson, GasReformer product manager at Wärtsilä Ship Power, said: "After a number of years of developing the product, the decision to industrialise the GasReformer was made in 2010. This process included a detailed system design taking into consideration all safety aspects and classification requirements. The Wärtsilä GasReformer is the first of its kind in the world and has been developed and designed to meet the standards of the oil and gas industry."
Innovative automatic mooring system MAMPAEY OFFSHORE INDUSTRIES has developed a magnetic mooring system. The “Docklock” has four hydraulic arms with magnetic coupling components that automatically connect and adapt to the mooring situations at hand. Initially, the first prototype series has been built for ship-toship mooring and will be trialtested on a bunker vessel: the MTS Valburg. Normally a bunker vessel will moor alongside a client vessel by means of ropes. This process is tedious and unsafe for deck crew and line handlers. The constant movement and rising of the bunker vessel due to offloading product, also requires constant re-fastening of the secured ropes. The Docklock will cancel out this process and safely couple the vessels through the automated mooring arms placed on deck. Once the bunker vessel has come alongside the vessel in need of service, the system will be activated from the wheelhouse leading to an automatic mooring procedure, where the arms will approach and detect the hull, establish contact and initiate magnetic coupling. The magnetic modules are designed to only ‘grab’ the hull, which means there will be no flux acting on any instrumentation or load. After making a safe mooring connection all arms will react to movement and continuously adapt to ensure a safe mooring situation. The arms operate individually while simultaneously taking the situation of the system’s remaining arms into account. This can be monitored in realtime and controlled at all time. This new way of mooring can potentially cut a significant amount of time out of the bunker process, which benefits both the client and the operator of the bunker vessel, and additionally creates a far safer mooring procedure, freeing deck crew from dangerous and straining work. Oil Review Africa Issue Four 2013 49
Innovations
Range of new product lines from Expro
S12 ORA 4 2013 Technology_Layout 1 19/08/2013 17:08 Page 50
Technology
In a climate where the global demand for hydrocarbons is putting pressure on operators to increase production schedules, economic factors are also driving more efficient operations.
TWMA cutting to the core of
environmental issues G
OVERNMENTS THROUGHOUT THE world are offering a wide range of incentives in an effort to support regional production levels and the resulting widespread technological advances are driving increased investment and recovery rates. But sweeping variances in environmental regulation and legislation from region to region – and even country to country – present complex challenges that need to be overcome if projects are to be successful. And more frequently, governments are reassessing the criteria and setting more stringent standards operators must comply with. As a result of these factors, onshore and offshore drilling practices are front of mind, with new technologies and advances in drilling fluids allowing operators to optimise their drilling programmes.
Growing demand It is against this backdrop that demand for environmental solutions such as those offered by TWMA are becoming more sought after than ever before. The company has extensive experience in providing advice and assistance to the energy sector in respect of global and regional environmental issues and provides a variety of solutions that can be implemented throughout the full-cycle of a project, from initial conception to decommissioning. Over the past decade TWMA has developed a range of solutions to minimise environmental risk from drilling operations all over the world. Its services include skip and ship, bulk transfer and advanced solids control for the recovery and transportation of drilling wastes – but it is its onshore and offshore thermal processing capabilities which are coming under greatest demand from the global energy sector. Two areas of focus for the company are the Middle East and West Africa, where TWMA is working closely with separate operators on two high-profile projects. Both contracts have seen the company work closely with operators to address the issue of what is commonly referred to as drilling waste in their respective regions. But by utilising TWMA’s expertise, drill cuttings and associated materials can be recovered, treated and separated into their constituent parts of oil, water and solids for re-use or safe disposal - dramatically reducing, and in many cases eliminating, the volume of end-waste produced. In West Africa TWMA has been working closely with Glencore Cameroon Ltd in support of its regional drilling campaign. This contract has seen the company deliver its first offshore processing project to the energy industry in West Africa.
50 Oil Review Africa Issue Four 2013
TWMA's TCC RotoMill has been adopted by the international offshore oil & gas market, driven partly by evolving drilling waste disposal legislation, but also by operators consistently adopting drilling waste management best practices wherever they work.
Its onshore and offshore thermal processing capabilities are coming under greatest demand from the global energy sector. These are just two examples of projects where operators are recognising the value of proactively seeking solutions to minimise or prevent drilling waste and as a result exceeding the expectations of regulators.
Tailored solutions And for each project TWMA has put a dedicated team in place to ensure tailored solutions are provided for the operator – both of which incorporate the TCC RotoMill thermal processing technology. By utilising the TCC RotoMill, base oil recovered from the drill cuttings can be recycled back into the drilling mud system, generating significant cost savings to operators. The TWMA TCC RotoMill can be used in any location, either onshore or offshore, at a rig site or central processing facility, to effectively treat drill cuttings and associated materials at source. TWMA’s TCC RotoMill is available in a number of variations, including the truck-mounted TCC RotoTruck for
remote land-based projects, skid-mounted or containerised for offshore operations, and bespoke solutions have also been developed for one-off applications. The units can be operated by a diesel engine, or where available an electric motor of varying sizes and capacities, from 250kw units offering processing speeds of 1.5 MT per hour, to 1,400kw units processing drill cuttings at up to 9 MT per hour. The level of retained hydrocarbons in the solids phase is negligible, with proven results showing a concentration level of less than Europe’s OSPAR regulated level of one per cent by weight and typically 0.1 per cent. The water phase also has minimal oil content, again with proven results showing figures of around 15ppm, while the recovered oil retains the same fingerprint as original base oil and is therefore suitable for re-use. But there are challenges in implementing such a strategy. In establishing a solution for Glencore Cameroon Ltd, for example, TWMA had to overcome a series of obstacles within a short period of time. Due to the rig’s proximity to shore and shallow water location, the operator was concerned about the potential environmental impact of its operations. Utilising the TCC RotoMill, TWMA treats all non-aqueous base fluid (NABF) drill cuttings on board the jack-up drilling rig, with zero impact on the environment. The size of the rig combined with deck loading
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Tackling the issue at source One of the main benefits of processing drilling wastes at source is that it eliminates the need to transport large volumes of materials to shore for treatment and disposal, therefore minimising the associated vessel logistics, truck transportation and crane and forklift movements, and significantly reducing the risk of environmental impact from drilling operations. Increasingly TWMA can demonstrate significant cost savings to operators by adopting a fully integrated drilling waste management solution that processes wastes at source. To take the process a step further, TWMA has the capability to integrate its solutions into new build rig designs. As global environmental legislation evolves, operators are increasingly looking for rigs with integral waste processing capabilities offshore. Operators now have the opportunity to ensure that the onsite waste management solution specifically matches the project requirements.
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Changing attitudes There has been a seismic shift in attitudes towards handling and treating drill cuttings and more frequently companies are contacting TWMA in the early project stages to develop the optimum project solution, where previously this was often an afterthought. This has been driven by two factors – the increasingly stringent legislation being put in place by Governments and a growing trend for operators electing to implement best practice for their drilling operations. Failure to put adequate measures in place at an early stage can leave operators with limited options to effectively handle and treat drilling waste, reducing the efficiency and increasing the costs of their operation. TWMA has been building experience and knowhow through continual development of its solutions and has worked in desert to sub-zero conditions with its TCC RotoMill and associated services. In total, the company has processed more than 600,000 MT of drill cuttings to date. Demand for the company’s services is continuing to grow globally – particularly in the US, Africa and the Middle East. This underpins the value of the TCC RotoMill, delivering an efficient and costeffective method when handled by experts, and results highlighting the significant business advantages of adopting thermal processing.
Technology
restrictions and a very tight design cycle made the project challenging from the outset. In order to meet the project deadlines, TWMA’s engineering team travelled to Houston to complete a fast-track FEED phase with the client before finalising and delivering the full engineering design package within a three-week timeframe in order to obtain the client’s approval prior to mobilisation.
Operating TWMA’s TCC RotoMill.
The demand for effective waste management techniques and technology from the industry is undoubtedly increasing. The determination of operators to explore the final frontiers of the Arctic will only further enhance the need to ensure waste is managed effectively and efficiently. ■
Oil Review Africa Issue Four 2013 51
Power Generaatioin
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The question rent-or-buy? is faced by most managers who deal with capital equipment. In the case of a costly genset the decision is complicated by the issues of security and versatility.
Generating good
business A
COMMON PROBLEM facing equipment managers is – rent or purchase? And in Africa where power supplies so frequently fail the dilemma concerns costly diesel generators more than most. We checked manufacturers’ websites in the 103000 kVA range and found that many confront the issue head on, providing sound cost-based arguments for both options. Many operate a separate rental division. At the same time we noticed the general equipment rental industry, which also deals in gensets, argues convincingly from its own point of view, providing a series of handy online calculating tools that support this case. The key point is that a genset is, to many users, not like any other piece of equipment. Whether installed for prime or standby service (and this usually means quite different specifications) its output is often indispensable in an emergency. In general, machinery maintenance departments opt for rented equipment to meet infrequent but not standby demand. So an engine generating set will be hired when the workflow increases predictably and temporarily, as when a weaving mill receives a large batch order from overseas. This is a pre-planned and fully costed operation, with rental arrangements made in advance on an ‘if and when’ basis. But what if the need for more, or any, power is unplanned? Many Nigerian industrialists will identify with this. The solution to this problem is to examine the key components and shortfalls of each option. First, on the basis of previous experience (it helps enormously if records of power outages are logged; this aids negotiations with the powerco too), how long and often will the genset likely be needed? And what is the range of these cuts? If the equipment will be used regularly over its 20-years or so of estimated life (a large machine) to return the cost of acquiring it then the case for purchase will be strong. And strengthened further by the other benefits that will accrue, such as increased versatility over use of other resources which would otherwise be idle. The key to making the right decision with a genset is to have on hand accurate information about past demand patterns and reliable estimates about future use. The key point about an engine generator in a mains-served location like Ikeja or Nairobi is that it is a large item of capital plant that will not be used often, but in many cases needs to be available immediately when a complete outage/brownout arises. When it’s a case of healthcare, or communications, or workforce/public safety, or
52 Oil Review Africa Issue Four 2013
Business is booming for manufacturers of diesel and gas generators in Africa.
The key to making the right decision is to have on hand accurate information about past demand patterns and reliable estimates about future use. even significant lost opportunity cost in manufacturing or warehousing, then there’s no ‘needs’ about it. In these cases it must be available on the site at all times. Who actually owns it is the thorny question that then has to be answered. Good accountants will look at the problem objectively, in terms of business risk and cost comparisons, with any suggestion of high risk usually indicating the purchase option (or on-site permanent serviced rental) is best. The steps required for each decision are: 6 Obtaining basic information about all the costs including expected life of the genset, initial purchase and rental costs, expected usage in hours per year, and access (pickup) cost in the case of small rented plant, say less than 100 kVA. 6 Calculation of full costs of ownership (below). 6 Calculation of full and comparable variable costs of operation, including fuel and maintenance, under both options. Large genset rental usually means that a specialist team will be provided at the right time, at no extra cost. 6 Comparing the total costs to own and rent over the expected lifetime of the equipment. Suppliers can advise via their agents in detail on this.
6 Deciding on the optimum solution, building in weighting factors for versatility (flexibility of operations) and security (guaranteed power availability). In the case of generating sets these are more important than with most other machines. The other possibility is temporary defined-period or open-ended rental, a good example of which is quoted with reasoning in the box below. Of course a third option may turn out to be the very best one, and that is to acquire good-quality used equipment. Gensets of most sizes used in manufacturing premises turn up regularly in the catalogues of capital equipment auctioneers. So, what are these total costs associated with actually owning an engine generating set, referred to above? They include the items you commit to when you make a purchase, regardless of how many hours you will require it to run. They incorporate the capital and opportunity costs of spending that sum, the resale value lost each year as the set ages, and the additional costs incurred if you resort to external financing. Most of these overhead costs are eliminated if you rent. Other components of the total package include ongoing costs such as plant insurance and annual overhaul and maintenance staffing, and financing the support equipment/facilities needed to keep the set in top order. In the case of a genset this will likely mean a dedicated plant room or a special building sited away from the main facility. A separate secure fuel tank will almost certainly have to be provided, too. Rented sets usually come with most of these items supplied. Then there are the variable operating costs that have to be taken into account. Most of these are
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maximum capacity. Diesel gensets usually perform best when run like this. But in the special case of these particular machines the buy-or-rent calculation is seriously complicated by the fact that so often in Africa the installation has to be on a standby basis. Finally, remember that ownership or permanent rental increases the nagging uncertainty about what happens if there’s a downturn in your business. If you own the machine or have acquired it on an unbreakable long-loan basis then you are stuck with it if bad times come along. Rent it as
and when needed and your worries about this disappears; see our story about TANESCO below. The choice is yours. ■
Agreeable experience in Tanzania A CLEAR CASE for renting a pair of very large (50MW) diesel gensets occurred last year when East African utility Tanzania Electric Supply Co found itself running out of hydro-generated power in the Tegeta and Ubungo regions. The company already had satisfactory experience of renting sets on a temporary basis from Aggreko plc, back in 2006-2008. So this supplier was approached on a competitive-bid basis and a US$37mn contract was signed, to include ‘pass through’ fuel management services, a complicated variable cost. The cause of the problem was of course the
ongoing drought which seriously affected most of Eastern Africa last year, and went on doing so long after the two mains-power facilities were successfully up and running. The rental option was chosen here because, firstly, no long-term change in Tanzania’s power-supply situation was envisaged, until local offshore gas is more widely available anyway. More than two-thirds normally comes in hydro form. So a temporary emergency had to be bridged. The crucial point is that no-one knew how long the crisis would last. Secondly, it normally takes considerably less
time to adequately size and install two such stations when they are supplied on a rental basis than if they arrive fresh from the factory. Many manufacturers offer completely separate ranges of equipment for the rental and directsale markets, the former being specially supplied with sturdy sound-attenuated housings that are relatively easy to move around, for example. Maintenance requirements differ too. Saving time like this made sure that Tanzania’s much-commented on economic growth hardly missed a beat last year despite the alarmingly low level of the rivers concerned.
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Power solutions represent the pinnacle of engineering and reliability and are trusted by Angola’s leading businesses and institutions every day.
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Oil Review Africa Issue Four 2013 53
Power Generaatioin
common with rented plant. Diesel is the obvious one but don’t forget the cost of necessary lubricants and both air and fuel filters. There are others such as availability of maintenance technicians who will need an adequate tool kit with spares and, if working on more than one site, transport facilities, too. With rented plant these can be left out of the variables calculation. The near-bottom line is that with most types of factory or warehouse equipment ownership is usually only justified when the machine is used to its
Technology
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In this article Alfredo Jones, managing director of Alduco Energy, an asset integrity management company providing field life extension solutions in the Gulf of Guinea, discusses the approach that should be taken when planning the life extension of an oil & gas field, through ensuring that the integrity of the field’s structures are maintained.
Extending oil & gas
field life D
EVELOPMENTS IN E&P technology and economic pressure, have led to new offshore oil & gas discoveries or oil & gas being extracted for longer periods in mature fields, which has meant that oil & gas fields are being kept in operation longer than their expected life. This has given rise to some important challenges, which are how to keep the field infrastructure, including platforms, FPSOs, pipelines, manifolds and flow lines in a safe and operating condition, as many of them are past or approaching their design life of 20 years; but the asset owners want to continue to use them for another five to 20 years beyond their original planned life. In this type of case, there is a need to manage material deterioration, ie, fatigue cracking and corrosion, and demonstrate the ongoing integrity and safety of the ageing infrastructure to its owners, stake holders, host countries and regulatory bodies. Existing rules and standards typically address the expected ageing effects for pre-determined design life (time span) at the new phase. For example corrosion management is covered in: DNV offshore standards OS-C401, OS-C101, OS-C1O3, OS-C104, OS-C107 covering corrosion control, and fabrication and installation of corrosion protection systems ie, coatings, anodes, and Impressed Current Cathodic Protection (ICCP) systems. To name some specific requirements: 6 In general, corrosion protection systems should prevent structural deterioration over a structure’s operating life. 6 The rules assume hard coatings are supplemented by Cahodic Protection, but alternatives are excluded. 6 The rules state that the owner is responsible for maintaining the unit in accordance with the design. However recent inspection experiences of offshore oil & gas structures have revealed a higher number of facilities in operation with severe corrosion and fatigue problems. General lack of inspection and poor maintenance culture by asset owners attributed to either a greater deterioration than expected or the asset has been operating for longer than expected. An approach needs to be taken to extend the life of the assets of mature oil & gas fields.
6 Corrosion control survey (Cathodic Protection & Visual) of the structure/
Holistic approach is needed
6 Engineering design of retrofit Cathodic Protection (CP) systems based on data
Corrosion protection systems should prevent structural deterioration over a structured operating life.
There is a need to manage material deterioration and demonstrate the ongoing integrity and safety of the aging infrastructure. There are four main steps that need to be taken in oil & gas field life extension: facility.
The above inspection experiences identify the need for a holistic approach on the life extension of an operational oil & gas field. To be effective, such an approach should ideally take into account extended life expected and reduce risk of failures and maintenance and inspection costs, at the same time support the continuation of the structures operations.
obtained from the surveys.
6 Installation and commissioning of the designed retrofit CP system on the structure/facility.
6 Routine monitoring after installation of the CP system.
Corrosion control survey Corrosion control surveys are company-wide and a regulatory requirement in the global oil & gas industry. The reason for this is that the structures must be fit for purpose, to save life, protect the environment, stop loss of revenue, reduce maintenance cost and avoid accidents. Typical survey methods could be CP and/or visual surveys. CP surveys could be done from the topside or surface through a drop cell (CP) survey or subsea CP survey either through divers or assisted by ROV. Visual inspections are also carried out either from the topside and/or from the subsea of the structure being inspected.
Engineering design of CP retrofit systems The high and inhibitive costs of carrying out CP retrofits for oil & gas field life extension led Deepwater Corrosion Inc in Houston to come up with innovative engineering designs for carrying out the lowest cost CP retrofit solutions in the world. These solutions are used for the life extension of mature oil & gas fields.
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Technology
The cost of installation of CP retrofit systems is the main factor that drives up the budgets for this type of project. If the installation time can be reduced then the costs are reduced. Deepwater designs don’t only reduce the installation time of CP retrofits systems for mature offshore oil & gas structures, but are also very easy to install and in some cases don’t need to be connected directly to the structure. They can be connected via a cable, with the CP system resting on the seabed instead of on the structure. The advantage of this is that you are not adding more weight to an already old structure. For example, an anode which is used to mitigate corrosion on an offshore structure could easily weigh up to 500 kg each, so you can imagine the result of additional weights on the structure if you had to add several anodes to it, to protect it against corrosion - its structural integrity could be compromised.
Installation and commissioning of designed retrofit CP systems Deepwater patented solutions for field life extension include new and innovative designs of ICCP and Sacrificial Anode systems. These solutions include the Retrobuoy which is an ICCP system, and the Retropod which is a sacrificial anode system both used to extend the life of FPSOs, platforms etc. Other solutions include the smart mat which is a pipeline sacrificial anode CP retrofit system, which is very easy to install. Some of these innovative CP retrofit systems have been installed in the Gulf of Guinea, by Alduco Energy & its technical partner, Deepwater Corrosion, assisting major oil & gas companies to extend the life of their fields.
The splash zone.
Deepwater patented solutions for field life extension include new and innovative designs of ICCP and sacrificial anode systems
Routine monitoring after installation of CP systems After commissioning of a CP life extension solution or system of oil & gas field structures, the corrosion control systems should be monitored for performance. This can be done from topsides with the drop cell method, or from subsea
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typically by divers or ROV measurements of the level of protection. This ensures that the necessary data is available on how well or not the CP system is working, so that if any corrective action is needed it can be taken. ■
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Technology
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Nearly 10 years ago BP launched its Field of the Future programme to bring to reality the aspiration of safely operating assets at the technical limit of efficiency, recovery and cost. Richard Heddle, John Foot and Hugh Rees from BP discuss the project and its benefits.
Virtual flow metering empowers
global success M
OST OF THE technologies developed under the Field of the Future programme have been digital in nature and focussed on enhanced surveillance, alerting and control. The intention was not only to create a portfolio of technologies, but also to advance their deployment across most of the company’s operated fields. One such technology which has been deployed at scale and pace is the company’s Integrated Surveillance Information System (ISIS). This is a browser-accessed online application for the surveillance of entire subsurface systems. A core module integrated with other surveillance tools within ISIS is the Rate&Phase virtual flow metering (VFM) system. The VFM system estimates the production rates of individual wells using hydraulic models and requires only the instrumentation typically installed on new wells. It enhances surveillance and understanding, making operations safer, increasing production, improving reservoir management and highlighting wellwork opportunities. Currently more than 400 producer and injector wells in 20 assets across four continents, from the UK North Sea to Angola, and the Gulf of Mexico to Indonesia, benefit from the rate estimation by the VFM system. These systems have been deployed in the past five years and so far have produced far in excess of 10mn well rate estimates. The system was in place to monitor first oil of two new fields which started up in 2012. The numerous benefits of the VFM system include: 6 The availability of well production rate estimates in near real time allows better understanding of changes to well performance assisting production optimisation across the field. 6 Daily production reconciliation factors are typically much closer to unity than previously and there is a significant reduction in the effort required to compute them. 6 Pressure transient analysis can more accurately estimate inflow performance parameters such as skin because the well rates are known prior to shut-in. 6 Engineers can be confident that operation is within equipment integrity limits because
56 Oil Review Africa Issue Four 2013
Figure 1. Schematic of a well showing instrumentation and the different physical models used by BP ISIS Rate&Phase to estimate production rates.
of the high quality rate estimates.
condensate producer wells and water and gas injector wells. Figure 1 shows a sketch of a well with the model elements and typical instrumentation. Hydraulic well models based on the physics of multi-phase flow and calibrated to actual operating data are often able to extrapolate beyond the envelope of conditions experienced in the past better than systems simply based on statistical functions generated from past operating data. The VFM uses the same models that the engineers use regularly and all results can be verified manually offline. Where sufficient measurements are available it is possible to combine the separate model components. Thus they can, for example, not only infer possible oil rates for the well, but also infer other operating or performance factors such as a phase parameter (watercut or GOR) and/or a reservoir performance parameter (reservoir pressure or productivity index/skin). Where instrumentation is lacking the system may only be able to determine the oil or gas rate
6 The reliability and consistency of the VFM estimates can alert engineers to inaccurate measurements. 6 Well testing can be focussed on those wells where performance has changed which reduces both risk and production deferral. 6 Reservoir management benefits from the more accurate allocation of production because this yields improved reservoir simulation models. The system applies exactly the same procedures that an engineer would follow when calculating rates manually, and uses the same modelling software that is used for other petroleum engineering activities within the company. The results obtained have been excellent.
Currently more than 300 producer and injector wells in 20 assets across four continents benefit from the rate estimation by the VFM system.
Go with the (virtual) flow The Rate&Phase VFM system is based on hydraulic models calibrated to past production data. The oil or gas rate is computed so as to honour both the physics and the conditions measured across the well. The components of the well model represent the inflow from the reservoir, flow in the tubing and flow through the choke. The Rate&Phase procedure requires no additional instrumentation than that which is routinely installed on new wells. The system is applicable to oil, gas and retrograde
Figure 2. Treemap representation of the core modules of the ISIS Integrated Surveillance Information System.
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OMEGA MARTIME & ENERGY LIMITED
HERE, COMPETENCE MEETS SAFETY. Oil & Gas Ser vices: Cementing Directional Drilling Well Completion Work Over Coiled Tubing Pumping and other Drilling Services
Mud Engineering Services Production Drilling Casing/Tubing Running Mud logging services Surface well testing Slick line services
Marine Ser vices: Remote Operated Vehicle V s (ROVs for Deep Water Services)
Dredging Shore Protection Canalization Land reclamation
Omega Maritime and Energy Ltd.
email: info@omegamaritime.com
Plot 154, Off Joe Eboje Road, Trans Amadi Industrial Layout Port Harcourt River State Nigeria
website: www.omegamaritime.com www.omegamaritimeenergy.com phone: +234 8099 284653 +234 8034 597983
Technology
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Figure 3. Comparison of Rate&Phase VFM results with the measured export rate for a field in GOM
process schematics are pre-configured and customisable to provide rapid access to relevant information, while an events and alerts management system provides 24/7 monitoring of key parameters. The web service interfaces also permit remote configuration and management of the calculation modules. Modules integrated with the Rate&Phase VFM system within ISIS include those to perform pressure transient analysis, manage well testing and monitor well integrity. Operation of the Rate&Phase and other modules are computationally intensive and so a service orientated architecture (SOA) has been adopted. The various modules of ISIS are shown in Figure 2. ISIS handles all the data required by the VFM and makes calls for rate estimation for all online wells several times each hour. A configurable rule-based system within the ISIS system selects a ‘composite’ rate from the values computed by the hydraulic models. Then, commencing from the well rates, ISIS computes the flow along all flowpaths (pipelines, headers, risers etc.) through to the separator. Finally, the well and flowpath rates are reconciled against all meters in the system to minimise errors and provide a final production allocation for the field. The VFM also calculates other parameters valuable in integrity monitoring such as velocities in the tubing and bottom hole pressure (with correction for friction and hydrostatics below the downhole gauge). All calculation results are stored in the production historian for offline trending and analysis and for access by any other modelling and reporting systems which require them.
Gulf of Mexico success Figure 4. ISIS trend of VFM estimates (green) and Multi-Phase Flowmeter measurements (red).
and the quality of the estimates may be reduced. Innovative multi-variable root-finding schemes have been applied to locate solutions quickly and handle discontinuities. As an example, the procedure applied to an oil producer well with known watercut but unknown gas oil ratio (GOR) and reservoir pressure would be to use the tubing model to deduce the oil, gas and water rates from the change in pressure and temperature in the tubing. The rate can be confirmed using the choke model and then the current reservoir pressure to be estimated by the inflow model (assuming an unchanging mechanical skin).
Model calibration The system is based on models which incorporate multi-phase flow correlations. These require routine revalidation and recalibration when conditions change significantly, or well performance changes. This activity requires a measurement of the oil,
58 Oil Review Africa Issue Four 2013
gas and water production rates and it is therefore necessary to have the means to perform this measurement. Typically this requires that the well be routed to a test separator or a multi-phase flow meter for a period of time every month or so. The VFM is often required to estimate rates over a range that extends from near shut-in to maximum. Experience has shown that the models are only accurate over such a wide range of conditions if data is obtained from multiple tests. The factors commonly adjusted within the models to calibrate the well model are the choke performance curve, tubing friction and hydrostatic coefficients and the inflow productivity index.
Streamlined system ISIS provides a single browser-accessible interface to most subsurface sensor data and surveillance information required by engineers managing the fields. Trends, tables and
The VFM system has identified two wells in Africa where the GOR or Watercut change significantly after start-up. In normal operation, the accuracy of production allocation is quantified by a reconciliation factor which is the comparison of the total flow rate from all wells with the fiscal/export flow meters. Without a VFM system many assets struggle to maintain the reconciliation errors lower than 10 per cent. Assets with ISIS Rate&Phase typically achieve better than five per cent. The VFM estimated daily pre-reconciliation oil production for one Gulf of Mexico field over a twelve month period is compared with the export rate in Figure 3. As can be seen the reconciliation was usually between 0.95 and 1.05 and rarely worse than 0.90 or 1.10. The reliability and quality of the estimates
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Conclusion
Figure 5. Comparison of measured and VFM calculations after start-up of two wells.
allows assets to control well flow rates to minimise vibration and erosion on subsea pipelines and risers. Others are able to minimise the risk of damage to sand screens because the flux through cased and perforated completions is continuously estimated.
Accuracy in Africa The absolute accuracy of the ISIS Rate&Phase flow estimates for individual wells has also been assessed by comparison with flow meter measurements. The excellent agreement over a range of conditions shown in Figure 4 is
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typical or many wells. (The relevant periods when the well was routed to the seabed multiphase flow meter (MPFM) are those with the pale background). The VFM system has also identified two wells in Africa where the GOR or Watercut change significantly after start-up. The wells are instrumented with working pressure and temperature sensors downhole and at the wellhead and are regularly routed through MPFM. Figure 5 shows data exported from the historian for periods after start-up. The good agreement between the estimated phase
ISIS and the Rate&Phase VFM system has been deployed widely across BP-operated assets including many major oil and gas fields. Benefits have been realised from the ability to efficiently monitor well stock, manage fields better and allocate production more accurately. Production gains have been realised through assets operating closer to constraints because of the assurance of flow rate estimation. Rate&Phase exploits commonly used modelling tools, is designed to be easy to deploy/configure and is integrated with other surveillance tools. Acceptance of the system has been hastened because it is not regarded as a black box and all results can be reproduced manually offline. Current production and performance information is readily available and changes over time can be easily trended. â–
Field of the Future is a registered trademark of BP
Oil Review Africa Issue Four 2013 59
Technology
parameters and the measured values has been seen on numerous recent start-ups of these wells.
Innovations
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Jotachar JF750 - the time saving solution FOLLOWING AN EXTENSIVE development and testing programme, the launch of Jotun’s new meshfree PFP helps owners, fabricators and applicators save time, lower costs and reduce risks compared to systems that require mesh reinforcement. According to Andy Czainski, Jotun’s global PFP sales director, Jotachar JF750 is the only mesh-free epoxy intumescent coating solution available to the market where jet fire protection is required for safety-critical steel structures, divisions and vessels. A majority of offshore assets require some degree of jet fire protection, with many onshore owners now also demanding PFP materials that can demonstrate Jet fire capability to ISO 22899. “The formulation of Jotachar JF750 incorporates an advanced fibre matrix system in the material” he explained. “This technology, combined with a robust and temperature-stable insulating char, eliminates the need for additional mesh reinforcement, reducing complexity and making it significantly faster to apply, hence saving time and cost.” John Warner, Jotun’s category manager for intumescent coatings added that in addition to lowering costs related to application, Jotachar JF750 helps owners avoid risks associated with complex mesh reinforced systems that often result in project delays. More importantly, incorrect installation can impact fire performance and therefore the safety of
personnel and integrity of assets. “Anyone working with mesh requiring systems knows that installation is a time and labour intensive process. Mesh installation involves stringent certification rules such as overlap measurement and installed depth within the system. There are many additional challenges related to installing mesh on complex structures eg, poor mesh to mesh adhesion where overlaps are required” he said. “Because Jotachar JF750 is mesh-free, fabricators and applicators can work faster, especially on complex structures. The product also makes maintenance and repair much simpler, requiring significantly less time and cost.” Whilst Warner acknowledged that the mesh free breakthrough in Jotachar is groundbreaking technology, he was quick to point out that Jotun has decades of experience protecting offshore assets with Jotun’s robust epoxy based technologies, as well as supplying intumescent cellulosic fire protection coatings for the construction industries for many years. “Another major breakthrough with the technology is the avoidance of boric acid, a harmful substance classified by the EU’s REACH as a ‘substance of very high concern’. This harmful substance is incorporated into many competing materials as a flame retardant” he said. “The
avoidance of harmful substances such as Boric Acid is consistent with Jotun’s GreenSteps programme to improve the environmental and safety impact of their products.” Jotachar JF 750 has been extensively and independently fire tested to all key industry standards, demonstrating structural fire protection for up to three hours. Steel sections and divisions are tested to the industry recognised ISO834/BS476 Part 21 “hydrocarbon curve”, proving protection from hydrocarbon pool fires. Importantly, Jotachar JF750 also demonstrated exceptional jet fire performance in the ISO 22899 test without additional mesh reinforcement for up to two hours. This ISO standard simulates the highly erosive, high heat flux and rapid temperate rise experienced within a jet fire. JF750 has been tested and passed a four bar blast overpressure, again without any need of additional reinforcing mesh. Warner said that with the introduction of Jotachar JF750, Jotun is now able to offer a combined coating and fire protection solution to the oil, gas and energy industries. “Jotun is already recognised as a global supplier of premium corrosion protection coatings” he said. “With the launch of Jotachar JF750, our customers can now benefit from the clear advantages a new era of mesh-free epoxy PFP technology brings.”
SPEX secures contract for revolutionary new product SPEX GROUP, AN Aberdeen-headquartered provider of innovative technology solutions and services to the global oil and gas industry, has secured a further multi-million dollar contract with Shell for the development of a subsea tool. The revolutionary Emergency Severance Tool (EST) is due to undergo final field tests in the Gulf of Mexico later this year. SPEX plans to make the tool commercially available in 2014. The EST operates at depths up to 3,000 metres, and forms an integral part of the drilling riser - the large diameter pipe that connects the rig to the seabed. The EST is positioned just above the blow-out preventer (BOP). All drilling wells feature BOP safety valves, but there is a limit to their shearing capacity, and they are often unable to shear through large diameter of heavy-walled items being run into the well – items the industry has termed non-shearables. If there is an uncontrolled event, similar to the Macondo incident, the EST is trigged and will sever the non–shearable item that is otherwise obstructing the BOP, allowing the severed drillstring to fall into the well, and enabling the BOP to safely close and seal As well as fully designing, manufacturing and testing the EST on behalf of Shell Houston, once the product is commercial, SPEX is licensed to manufacture, sell and service the EST on a global basis. The company has invested significantly to expand its engineering and technology innovation capability to partner with clients to develop and deliver the next generation of smart tools that solve some of the industry’s biggest problems. The EST is one of a number of innovative projects SPEX is currently working on. Chief operating officer Nadir Mahjoub said: “Shell looked to us for a solution to further reduce risk offshore and help safeguard the environment if there was an incident. Our team came up with the EST.
60 Oil Review Africa Issue Four 2013
“It is one of a number of innovative projects SPEX is working on at present and has been taken from concept trial to field trials in little more than two years. Because we have exceptional people, equipment and infrastructure all under the one roof, we can work extremely quickly to help solve client problems and challenges.’’ Other game-changing products being developed with Shell are: Collapsible Insert Device (CID) - the CID forms part of the well casing and uses propellant to collapse a liner sleeve to significantly reduce the uncontrolled release of hydrocarbons in the worst-case event that the wellhead or BOP is damaged or breached. Riser Severance Tool (RST) - an ROV or surface deployed tool that uses explosive technologies to sever the complete riser in the event that the rig unexpectedly drifts. By severing the riser, the rig can move off-station without causing damage to the subsea BOP or wellhead, thus ensuring the well can be safely and quickly brought back under control.
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Innovations
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Halliburton adds new feature to its Foray service HALLIBURTON'S FORAY 3D microseismic fracture matching analysis service is now available as a real time application. A component of Halliburton’s Knoesissm service, the Foray service provides a new method of fracture diagnostics that uses microseismic event data as it is generated in real time to develop an image of the fracture network being created in the formation. Advanced algorithms continuously analyse the constant flow of new data and update the fracture network being created with new or higher confidence interval planes as the analyst monitors the treatment. The information generated can be leveraged to design treatments that provide increased connected fracture areas. Fracture treatments that maximise connected fracture areas provide greater increases in production. Prior to the real-time capability, Foray service analysis could be performed only after a treatment in order to help optimise the next treatment. Real-time analysis provides the technical team with the knowledge it needs to make changes to treatments during the job. Every fracturing treatment can be tailored for maximum effectiveness. This capability is particularly important for fracturing treatments in shale formations. Foray service can help to reduce the cost per barrel of oil equivalent and maximise asset value for an operator through improving fracturing treatment design and execution.
Aker Solutions acquires managed pressure drilling specialist MPO AKER SOLUTIONS HAS acquired Managed Pressure Operations International Ltd (MPO), a company that has successfully developed the next generation of continuous circulation, riser gas handling and managed pressure drilling systems. The acquisition places Aker Solutions at the forefront of technology development in the market for managed pressure drilling (MPD) which is seen as a key technology enabling better drilling performance and safety. MPO has also developed a new generation riser gas handling system to capture and safely handle gas in the riser. MPO provides in-depth knowledge and technologies within the emerging MPD segment. The main rationale for using managed pressure drilling is to improve safety and efficiency, enable access to new fields with challenging drilling conditions, and enhance the life of mature fields. Aker Solutions aims to integrate the MPO MPD system in its rig design and will supply the equipment as part of complete drilling packages to offer clients state of the art solutions. "Managed pressure drilling is a key safety technology for exploration drilling, high pressure high temperature prospect development, ultra deepwater of pre-salt carbonate reservoirs, as well as a drilling efficiency tool when used consistently like other game changing technologies like the top drive," said Charles Orbell, who co-founded MPO in 2008. MPO's riser gas handling system will improve the safety and performance of current floating rig drilling technologies.
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Quality at your feet SAUDI LEATHER INDUSTRIES Company (SLIC) produces a variety of footwear, including safety, military and casual shoes, all of which have been awarded quality certification. New products from SLIC include a women’s safety shoe, which has a composite toecap www.saudileather.com and conforms to the EN 345 standard, and a security belt. The company also offers puncture-resistant footwear with a steel midsole, conforming to the international standard EN 345 S3 and protecting against sharp metallic objects. SLIC’s custom-made products include the six-inch foundry boot with metatarsal guard; the 30-cm boot for molten metal operations; the caster boot for casting operations; electrical footwear for 18 KV; and work shoes for airline crew, security guards and the hospitality industries. The company became a member of the UK-based SATRA footwear testing centre in 2000, while its quality management system has been accredited to the ISO 9001 certificate since 1996. It is also affiliated with the FDDI (Footwear Design and Development Institute).
Crestchic showcased loadbank offering at NogTech Rockwell tools simplify machinery safety AN INTERNATIONAL LEADER in load testing solutions with a global network of sales and rental offices, Crestchic recently attended the NOGTech Oil & Gas Technology Exhibition in Lagos. NOGTech is Nigeria’s leading oil and gas technology event, now in its fourth year. The event is strategically positioned in the commercial centre to bring together government ministries, industry stakeholders and key oil and gas professionals. The 2013 conference and exhibition continued to demonstrate how the adoption of new oil and gas technology can improve cost reduction, drive efficiency and increase production. Paul Brickman of Crestchic explained: “This event in Nigeria provides Crestchic with the opportunity to capitalise on the increase in demand for loadbank testing systems as markets expand in this region of the world. This is especially evident in the areas of onshore and offshore, and independent power. Crestchic currently has two high profile contracts with Wartsila – the global leader in complete lifecycle power solutions for the marine and energy markets - in Gabon and West Africa.” Crestchic loadbanks are primarily sold and rented to customers operating in the oil and gas, marine, data centre and power generation sectors. Through its industry-leading loadbanks solution, Crestchic provides a means to commission, test and service all types of power sources, including generators, turbines, batteries and fuel cells. The company manufactures a wide range of AC and DC loadbanks for both resistive only and resistive-reactive applications. Loadbanks vary in size from 30kW to 6000kVA and are designed to operate a 3 phase, 50 or 60Hz. The larger units are containerised and transportable, and can be linked together to provide loads of 50MVA and above. Crestchic has a full diary this year regarding attending major power exhibitions, which include both POWER-GEN Europe and NOGTech Lagos in June. The company had already successfully showcased its loadbank offering in April at POWER-GEN India & Asia 2013, Power China 2013, and at the Russia Power conference and exhibition in March. www.oilreviewafrica.com
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Innovations
Functionality for flow assurance engineers KONGSBERG OIL & GAS Technologies AS (KOGT), a wholly owned subsidiary of Kongsberg Gruppen ASA, has announced the latest release of LedaFlow (1.3), the new transient multiphase simulator for wells and pipelines. Continuing with KOGT’s ambition to provide greater detail and accuracy to multiphase simulation in the oil and gas industry, this release of LedaFlow contains significant additions and improvements that will be welcomed by flow assurance engineers. Some examples of the new functionality included are a new separator model, the bypass pigging capabilities, black oil PVT definitions, dead oil circulation using custom fluids, standard volume flowrates and emulsion models. KOGT has also worked hard to increase the speed of LedaFlow solutions and is pleased to be able to report an average 70 per cent speed increase using multi-CPU capabilities, making LedaFlow a far more productive tool. As always with LedaFlow, all new and existing functionality is available as part of the standard license agreement.
Dockwise inks $175m deals HEAVY-LIFT SPECIALIST Dockwise has scooped a plethora of marine contracts worth a combined US$175mn. The ship owner is to install the topsides for Statoil’s Aasta Hansteen development in the North Sea through a dual-barge float-over in 2015. Statoil has also signed up Dockwise to transport a fixed production structure from South Korea to Norway the following year. Those contracts were two of four long-term deals with another being the transportation of a jacket and topsides to Malaysia with installation of the 15,000-tonne topsides in 2015. Dockwise will also use its vessel Dockwise Vanguard to transport a floating production, storage & offloading unit from the Far East to West Africa in 2016. Other short-term contracts include the transportation of numerous jack-ups with one newbuild coming out of Singapore to Brazil in 2013 or 2014.
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Project Databank Compiled by Data Media Systems
OIL, GAS AND PETROCHEMICAL PROJECTS Project Summary Project Name
MOG - NC-118 Field Development - Central Production Facility (CPF)
Name of Client
Mellitah Oil & Gas Company
Budget ($ US)
1,000,000,000
Award Date
Q3-2014
Facility Type
GOSP
Status
EPC ITB
Start Date
Q1-2012
End Date
Q3-2018
Location
Wafa - Melitah, Libya
Project Backgrounds The Mellitah Oil & Gas Company plans to develop the NC-118 field, which is situated approximately 250 km South West of Tripoli and about 300 km north-east of the Wafa Field.
Project Status Jul 2013
Tender for EPC contract still not yet issued due to political issues.
Apr 2012
The client intends to issue tenders to submit pre-qualification documents for the EPC contract.
Project Summary Project Name
MOG - NC-118 Field Development - Pipelines and Flow-lines
Name of Client
Mellitah Oil & Gas Company
Budget ($ US)
1,000,000,000
Award Date
Q3-2014
Facility Type
Pipeline
Status
EPC ITB
Start Date
Q1-2012
End Date
Q3-2018
Location
Wafa - Melitah, Libya
Project Backgrounds The Mellitah Oil & Gas Company plans to develop the NC-118 field, which is situated approximately 250 kilometres South West of Tripoli and about 300 kilometers north-east of the Wafa Field.
Project Status Jul 2013
Tender for EPC contract still not yet issued due to political issues.
Apr 2012
The client intends to issue tenders to submit pre-qualification documents for the EPC contract.
S15 ORA 4 2013 ICT_Layout 1 20/08/2013 10:06 Page 65
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CONTACT US Tel: +973 1740 5590 Fax: +973 1740 5591 info@dmsglobal.net www.dmsprojects.net
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ICT
In our first article on cyber security we looked at the main threats facing the oil and gas industry. But who are behind these threats? And how can they be combated? Michela Menting of ABI Research tells Vaughan O’Grady how prepared the energy sector is to combat cyber crime — and how prepared it needs to be.
How can you combat
cyber crime? C
YBER CRIME IN the oil and gas industry is back in the news again. In mid June Mohammed Atif, managing director of DNV KEMA, a leading name in risk management along the energy value chain, was quoted as pointing out that investments in cyber defense in the Middle Eastern energy sector have been planned but, unlike Europe and the US, there is no cyber security strategy implemented yet. The Middle East situation is certainly worrying, given last year’s incidents at Saudi Aramco and Qatar’s RasGas in which viruses spread via office computers. And Atif also pointed out that regional cyber attacks, notably on energy supplies and transiting routes, could have an impact well beyond the Middle East. Which is true. However, pinpointing the Middle East’s failings does not mean that the rest of the oil and gas industry is a great deal readier to fight off cyber attackers. As ABI Research senior cyber security analyst Michela Menting pointed out, most of the energy sector is not adequately prepared — at least where industrial control systems (ICS) are concerned. As she said, “A serious lack of drive exists in tackling the problem of ICS vulnerabilities in any comprehensive or thorough way.” She continued, “The industry perception that cyber risks are low because few and limited attacks have occurred on ICS is not just misguided, but highly dangerous.” There may not currently be a major onslaught by hackers to take down and seriously disrupt ICS, but the slow response of the industry to the need to address cyber security issues is, said Menting, “a grave mistake”, and one that could cost billions of dollars in the long run. But the message does seem to be slowly getting through. As Menting says, “The oil and gas sector has been shaken more roughly [than other energy sectors] in the past year. The damage caused by the Shamoon virus at Saudi Aramco has jump-started fears about the potential damage that could result from a large-scale cyber attack on the industry.” Of course dealing with a threat also means trying to understand the motives of cyber attackers. Shamoon, for example, appears to have been used by anti-Saudi forces. Is a disruptive or terrorist attack the norm? Or could there be financial motives? Which rationale is the most likely? In fact, said Menting, “The most obvious and immediate threat is undeniably the insider: a disgruntled employee with malicious intent, or even a poorly trained employee inadvertently causing an accident.” Terrorists groups are the
66 Oil Review Africa Issue Four 2013
“The industry perception that cyber risks are low is highly dangerous.”
Dealing with a threat also means trying to understand the motives of cyber attackers. second most likely threat, however — and not just the generally politically motivated groups of the left or right but also environmental militants. Menting explained, “While eco-terrorism is not widespread, there have been past cases of pipeline and well sabotage by individuals like Weibo Ludwig [a Netherlands-born Canadian convicted of oil and gas well sabotage in the late 1990s] or groups like the Earth Liberation Front [an apparently leaderless international movement whose tactics seem to involve economic sabotage and guerrilla warfare].”
Politically motivated terrorism But politically motivated terrorism is a more immediate and real danger. Terrorist groups like AlQaeda have been targeting the Western-run oil industries for some time. The more recent cyber attacks against Saudi Aramco in September 2012 involving the Shamoon virus are believed to have been instigated by a state-sponsored group intent on disrupting hydrocarbon production. Izz ad-Din alQassam is one such; this group of self-proclaimed cyber fighters become widely known recently through its attacks on US banks.
As well as these leading threats, a growing number of perpetrators are hackers. They are not a unified body; they have different motivations and use varying tactics to get access to systems. Menting explained, “Their goals can be intrusion for the purposes of control, data theft or espionage.” Which brings us back to our earlier point. If oil and gas is not as ready as it should be how ready is it? What sort of shape are cyber protection systems in? What can be done — or needs to be done — to improve them? Despite the relatively gloomy outlook a number of tools do exist to counter cyber attacks directed at the oil and gas industry. “Risk mitigation should be envisioned on two separate levels: at the corporate network level and at the ICS level,” Menting explained. The good news is that, for the corporate network, commercial offthe-shelf (COTS) IT threat prevention and management mechanisms are available and adequately suited. Thus you can get your hands on solutions including antivirus software, anti-spam filters, backups, encryption, firewalls, intrusion detection systems/intrusion prevention systems (IDS/IPS), and unified threat as well as identity management solutions, among many others. Another piece of positive news is that often the corporate network serves as the buffer between an ICS and the Internet. Therefore, a solid cyber security policy at the corporate level can help deter the majority of potential malware targeting ICS
www.oilreviewafrica.com
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ICT
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The energy industry has woken up to the threat of cyber crime.
The oil and gas industry is at last starting to take cyber security very seriously. vulnerabilities. “Nonetheless,” Menting warned, “COTS solutions are not well suited to the specific ICS environment.” What can oil and gas do about this? “Broadly speaking, two ways exist for managing risks that should be considered in the oil and gas industry,” Menting suggested. “The first is to control the threat by reducing the likelihood of occurrence; this is done by patching vulnerabilities and strengthening security mechanisms. The second is to ensure that response mechanisms are resilient and robust, and able to ensure business continuity and reduce the impact of downtime. These methods require the use of preventive and reactive security tools as well as deployment of proactive counter measures.” And, apparently, energy companies are now willing to buy those tools and take those measures. As we noted in the first of these two articles, in a
review of oil and gas industry cyber security spending ABI Research’s Cyber Security and Smart Grids Research Services* suggested that realisation of the financial implications of persistent cyber threats will boost cyber security spending on critical infrastructure in the oil and gas industry; it will reach US$1.87bn by 2018. What, then, will the industry be buying? And which sectors will do the spending? “While the private sector will be the primary driver of cyber security spending, the government side will make some dedicated efforts to invest heavily in securing the oil and gas sector, due in part to its status as a critical infrastructure,” suggested Menting. Of course this should hardly be surprising given that quite a few of the top oil and gas producers are essentially government-owned.
Spending on IT The largest amount of spending will be for IT network, ICS, and data security. “This is due to the fact that preventive and reactive measures still form the largest part of cyber security spending for an organisation,” Menting explained.
The second spending category will be on policies and procedures, including, for example, personnel training and obtaining security certification. In fact audits and standardisation will become increasingly important upstream and downstream in the value chain. As Menting pointed out, “The oil and gas industry is a massive sector, with individual companies dealing on a daily basis with numerous contractors, some of which may offer an unsecured backdoor for attackers. This is especially true in cyber espionage, where attackers will spend a considerable amount of time scoping all possible points of entry into a particular target company.” The oil and gas industry is at last starting to take cyber security very seriously. However, cyber threats are going to become more sophisticated in the future. As Menting pointed out, “There is a thriving underground economy which is making a lot of money from this”. And not just underground; nation states are now increasingly involved in cyber espionage. So the energy industry has woken up to the threat of cyber crime — and not a moment too soon. However, there is no room now for turning back or relaxing — as Menting made clear. “As companies and states ramp up security,” she said, “cyber attackers will continue to develop ever more sophisticated tools to get around that security.” ■
*ABI Research is a market intelligence company specializing in global technology markets. For more on ABI’s cyber security research service, go to : http://www.abiresearch.com/research/service/cyb er-security/ and see the Michela Menting whitepaper PetroSecurity in the Digital Era: Legacy Systems vs. Cyber Threats (http://www.abiresearch.com/whitepapers/petrose curity-in-the-digital-era/)
Petrel 2013 sofware plaform for improved E&P decisions SCHLUMBERGER HAS RELEASED its 2013 Petrel* E&P software platform delivering integrated analysis from exploration to production. Petrel 2013 brings advances in integration, multiuser collaboration and applied science, including improved petroleum system modeling, structural interpretation and production analytics—as well as additional workflow improvements and productivity enhancements. “The Petrel multidisciplinary platform incorporates scientific principles, risk analysis and shared knowledge capture across the asset lifecycle to exploit complex reservoirs,” said Uwem Ukpong, president, Schlumberger Information Solutions. “This enables our customers to standardise workflows from exploration to production— and make more informed decisions with a clear understanding of both opportunities and risks.” The Petrel 2013 platform delivers enhanced integration to address key challenges, for example accurate delineation of subsurface features in pre- and sub-salt reservoirs. The release brings improved salt interpretation workflows, augmented seismic imaging through pre-stack wide azimuth analysis, and improved links with Omega seismic data processing software.
68 Oil Review Africa Issue Four 2013
The introduction of a volume-based modeling approach supports precise representation of geological complexity—to more accurately predict hydrocarbon accumulations. Geomechanical reconstruction validates interpretations in complex depositional environments. Further, geoscientists can now model 1D petroleum systems to determine charge maturity and risk. The Petrel platform leverages advanced Schlumberger numerical simulators, which now include 3D geomechanical modeling of subsurface stresses, salt tectonics and wellbore stability, providing efficient 3D preproduction geomechanics and 4D modeling of producing fields. Reservoir engineering capabilities support complex well modeling to keep pace with completion design evolution. New production-analytics capabilities enable well performance analysis to diagnose production events and trends.
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ICT
SkyVision launches new satellite services at NOGTech 2013 SKYVISION GLOBAL NETWORKS, a global provider of IP connectivity over satellite and fibre optic systems, announced the upcoming launch of its new corporate voice, data and video services at NOGTech 2013, held recently in Lagos. The event brought together government ministries, industry stakeholders and key oil and gas professionals. Participation in this important event is part of SkyVision’s efforts to expand its corporate services in the fastgrowing oil and gas industry in Africa, and in particular, in Nigeria. For over a decade, SkyVision has focused on the Nigerian market, with the establishment of hubs and PoPs in Lagos and Abuja to provide seamless fiber/VSAT connectivity for customers in the region. “As a longstanding local provider, SkyVision is proud to be participating in this important industry event in Lagos,” commented Doron Ben Sira, SkyVision CEO. “We welcome this opportunity to strengthen our support for local oil and gas customers in the region, and enable them to improve their productivity and network security. This exhibition provides the opportunity to showcase our latest services and further SkyVision’s commitment to reliable network coverage in Nigeria,” he added. At NOGTech 2013, SkyVision’s Nigerian team showcased SkyVision Active – business continuity series and other new solutions suited to the oil and gas industry as well as other corporate markets. With the promise of quality connectivity, SkyVision Active will provide these large corporates with costeffective and reliable connectivity services for on-demand bandwidth. This includes licensed satellite services and fibre optic communications for enhanced voice, data and video for services, both onshore and offshore service with ad hoc fly away and stabilised antennas.
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Oil Review Africa - Issue Four 2013 www.oilreviewafrica.com