Oi Review Africa 2012 issue 2

ORA 2 2012 COVER_cover.qxd 12/04/2012 12:54 Page 1

■ Geology - p36 ■ Gas - p38 ■ Exploration - p46 ■ Technology - p56

Volume 7 Issue Two 2012

www.oilreviewafrica.com

Africa

Covering Oil, Gas and Hydrocarbon Processing

Europe m10, Ghana CD18000, Kenya Ksh200, Nigeria N330, South Africa R25, UK £7, USA $12

Oil Review Africa - Issue Two 2012

GNPC gears up for Ghana O&G sector Determining the maritime boundaries Angola’s clean alternative to flaring Technology driving Africa’s LNG Changing the face of real-time remote pressure management Africa’s subsea market hots up Meeting the deepwater challenge Vsats - how much should one pay?

www.oilreviewafrica.com

Joe Udofia, MD-CEO of Vandrezzer Energy Services Limited, Nigeria See page 6.

Angola...old challenges remain

REGULAR FEATURES: ■ News ■ Contracts ■ Events Calendar ■ IT update ■ Company profiles ■ Products & Innovations

S01 ORA 2 2012 Start_Layout 1 12/04/2012 14:21 Page 2

...Africa is our home

Block 1

OML 130

S

outh Atlantic Petroleum has made significant contributions to the development of oil and gas in the Gulf of Guinea. This has been through our participation in the Total-operated Akpo and Egina developments in OML 130 deep offshore Nigeria, as well as the upcoming redevelopment of the SAPETRO-operated Sèmè oil field offshore the Republic of Benin. We are also actively exploring our Juan de Nova and Belo Profond assets in the Mozambique Channel deep water frontier. Our over 12,000km of 2-D seismic data in these assets employs a new, state-of-the-art solution which has been deployed in Africa for the first time and is the largest such survey in the world at present.

As we continue to expand our footprints in sub-Saharan Africa, we look forward to developing further partnerships.

South Atlantic Petroleum • Nigeria

• Benin • France • Madagascar www.sapetro.com

Juan de Nova (France) & Belo Profond (Madagascar)

S01 ORA 2 2012 Start_Layout 1 12/04/2012 14:21 Page 3

■ Geology - p36 ■ Gas - p38 ■ Exploration - p46 ■ Technology - p56

Contents

Volume 7 Issue Two 2012

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

GNPC gears up for Ghana O&G sector Determining the maritime boundaries

Columns

Angola’s clean alternative to flaring

Industry news and executives’ calendar

Technology driving Africa’s LNG

4

Changing the face of real-time remote pressure management Africa’s subsea market hots up

Analysis

Meeting the deepwater challenge

Oil producers’ group responds to consumer fears

Vsats - how much should one pay?

10

Diving profits: E&P deep undersea

12

Risk management offshore

16

Angola...old challenges remain

Joe Udofia, MD-CEO of Vandrezzer Energy Services Limited, Nigeria See page 6.

REGULAR FEATURES: ■ News ■ Contracts ■ Events Calendar ■ IT update ■ Company profiles ■ Products & Innovations

Country Focus Ghana

Southey regularly exercise ultra high pressure water blasting, painting and general maintenance contracts in Nigeria, Cameroon, Gabon, Congo and Angola, seen here painting the Gorilla VII port aft hull anchor.

18

Assessing risk for investment in Ghana GNPC gears up for Ghana oil and gas sector growth Determining the maritime boundaries Nuclear power positive for Ghana’s electricity needs

Angola

30

A clean and beneficial alternative to flaring - Angola LNG Angola’s Sonangol coming of age, but old challenges remain

Geology & Geophysics Developments

36

Gas Developments

38

Technology evolution drives Africa LNG market growth

40

South Africa’s shale gas: abundant, affordabale and acceptable?

44

E&P Developments

46

A round-up of recent exploration and production activity from around the region.

Health & Safety Strengthening operational integrity

Editor’s note TECHNOLOGICAL ADVANCES, ENORMOUS finds and high oil prices are driving the growth of a deepwater E&P market that not long ago was largely unviable.

The world’s largest energy companies have big plans for Mozambique, where, in the last 10 years, companies like ExxonMobil, BG and Eni have used the latest technologies, including advances in deep-sea drilling, to find new natural gas resources that are turning Mozambique into the centre of an energy boom. The East African country is not alone in its newfound energy wealth. Countries like Tanzania and Kenya also are attracting billions of dollars in investment from the world’s largest energy companies as they search for new oil and gas reserves.

Meanwhile in West Africa, GNPC is gearing up for Ghana’s oil and gas sector growth, where key operators such as Tullow and Kosmos are now pledging many billions of dollars of new investment.

Now there is a clean and beneficial alternative to flaring. The LNG world has been transformed in the past decade or so by improvements in technology, right across the supply chain. Angola LNG operates one of the world’s most modern LNG processing facilities and the first cargo is due soon. In Mozambique, Anadarko is also planning an onshore liquefaction plant.

54

How recommendations for health and safety following specific incidents have informed KCA Deutag’s polilcies.

66

Technology Innovations Drilling

56 58

Changing the face of real-time remote pressure management.

Subsea technology

66

The African subsea market continues to hot up.

Meeting the deepwater challenge.

Pipelines

72

Is the gas pipeline industry out of its depth?

Information Technology VSATs - are you paying too much for your satellite service?

78

Emerson’s subsea network answers many of operators’ questions relating to subsea operations.

Managing Editor: Zsa Tebbit - Zsa.Tebbit@alaincharles.com Editorial and Design team: Bob Adams, David Clancy, Andrew Croft, Prabhu Dev, Immanuel Devadoss, Ranganath GS, Prashanth AP, Genaro Santos, Ewan Thomson, Nicky Valsamaki and Julian Walker

Africa

Covering Oil, Gas and Hydrocarbon Processing

Publisher: Nick Fordham

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Serving the world of business

Oil Review Africa Issue Two 2012 3

Industry News & Events

S01 ORA 2 2012 Start_Layout 1 12/04/2012 14:21 Page 4

Executives Calendar 2012 APRIL 23-26 24-25 26-27 30-3 May

Oil & Gas Libya 2012 MMEC 2012 5th Annual Sub-Saharan Africa Oil & Gas Conference, 2012 OTC

TRIPOLI MAPUTO HOUSTON HOUSTON

www.montgomerylibya.com www.mozmec.com energyandcorporateafrica.eventbrite.com www.otcnet.org

AIOGACE 2012 LNG 2012 Agrikexpo OGAFIC 2012 4th African Gas-LNG Conference MOC 2012 5th Nigerian Upstream Conference 3rd East Africa Oil, Gas and Energy Week 2012 13th South African Oil, Gas & Energy

LUANDA LONDON LAGOS ABUJA LONDON ALEXANDRIA LONDO NAIROBI JOHANNESBURG

www.aiogace.com www.lng-europe.com www.agrikexpo.com www.ogafic.com www.petro21.com www.moc-egypt.com www.petro21.com www.petro21.com www.petro21.com

25th World Gas Conference WAMPEX The Oil Council’s Africa Assembly TOG 2012 4th MidEast North African Upstream Conference GOG 15 ZIMEC 2012

KUALA LUMPUR ACCRA PARIS TRIPOLI GENEVA MALABO LUSAKA

www.wgc12.com www.cvlc.co.za www.oilcouncil.com www.wahaexpo.com www.petro21.com www.cwc-news.com www.zimeczambia.com

Gastech 2012 Mauritanides 2012 Artificial Lift Conference and Exhibition 18th African Oil Week

LONDON NOUAKCHOTT CAIRO CAPE TOWN

www.gastech.co.uk www.mauritanides2012.com www.spe.org www.petro21.com

MAY 7-9 9-10 15-17 22-23 22-24 22-24 24 26-28 29-30

JUNE 4-8 6-8 12-13 18-20 19-20 19-21 19-22

OCTOBER 8-11 8-11 22 - 25 31-4 Nov

Readers should verify dates and location with sponsoring organisations, as this information is sometimes subject to change.

Aker Solutions wins surface well contract in Egypt INTERNATIONAL OIL SERVICES group Aker Solutions has signed a two-year frame agreement with Egyptian oil giant Badr Petroleum Company (Bapetco). Aker Solutions will be the sole supplier of all of the oil company’s surface wellhead equipment, installation and lifecycle services operations in the Western Desert of Egypt.

Dave Hutchinson, president of Aker Solutions in Asia Pacific, said: “We are very excited about this award, as it marks the successful entry of our surface business into the Egyptian and North African markets. Our ambition is to grow Aker Solutions’ operations in the Middle East and North Africa.”

The contract will be delivered out of Aker Solutions’ surface products manufacturing centre in Batam, Indonesia, which was established in 1992. In 2009, Aker Solutions upgraded the Batam facility in order to increase its production capacity. As a result, manufacturing capacity for production and assembly of surface wellheads and trees has increased by more than 50 per cent, or equivalent to 300,000 man hours.

Aker Solutions is one of the world’s leading oilfield products, systems and services companies. The company has 23, 500 employees in 30 countries worldwide.

The contract was signed and booked as order intake in the first quarter of 2012.

The contract party is Aker Solutions Singapore Pte.

4 Oil Review Africa Issue Two 2012

Libya to revitalise its energy sector OIL & GAS LIBYA 2012 – the International Exhibition for the Regeneration of Libya’s Oil, Gas and Petrochemicals Sector – is set to take place 23-26 April 2012 at Tripoli’s International Fairground.

The Organisers, Montgomery Libya Ltd, are in consultation with the Libya National Transitional Council, now internationally recognised as the legitimate conduit to the country’s future governance. The Council has established immediate priorities which include rebuilding the country’s oil, gas and petrochemicals sector which has suffered a lack of investment in recent years and considerable damage during the conflict.

Libya is calling on the international export community to bring much needed expertise and technology to revitalise its energy sector in the following areas: 6 Exploration & Production 6 Pipelines 6 Refining and Petrochemicals 6 HSE 6 Training The exhibition will play a vital part in bringing expertise and technology to help in the up-grading of Libya’s strategically important oil and gas industry.

The conference will allow the Libyan authorities to set out their priorities and requirements for the country’s energy sector and suppliers of technology and services to recommend solutions.

The highest level of support will be encouraged from private and public sector planners, specifiers and procurement officials both as visitors to the exhibition and delegates to the conference.

The recent freeing up of US$100bn of Libya’s previously frozen assets will immediately contribute to the country’s energy redevelopment plans.

Oil & Gas Libya 2012 follows the success of previous exhibitions organised by Dar Alarab in association with Montgomery Libya Ltd, including Project Libya.

S02 ORA 2 2012 News_Layout 1 12/04/2012 14:23 Page 5

Industry News & Events

S02 ORA 2 2012 News_Layout 1 12/04/2012 14:23 Page 6

Madagascar Oil resolves block issues with Government MADAGASCAR OIL HAS successfully resolved the outstanding issues with the Government of Madagascar surrounding its three exploration blocks.

Following a recent Management Committee Meeting with OMNIS, the state regulatory agency responsible for overseeing the country's oil and gas operations, the validity of the Production Sharing Contracts (PSCs) for Blocks 3105, 3106 and 3107 was confirmed and the forward work programme and budgets for the blocks were approved.

This means that Madagascar Oil and the Government have now resolved the outstanding issues surrounding the exploration Blocks and there are no further disputes with the Government of Madagascar regarding the company's licenses.

The company and OMNIS also approved formal amendments to the PSCs which recognise and adopt the minimum work programme for the remainder of the exploration term, and allow for the 15 month delay since December 2010 to be added to the end of the exploration period for each of the exploration Blocks.

With the approval of the amendments and the work programmes, activity will begin immediately to initiate a planned airborne gravity gravimetric survey of approximately 21,000 km at a total cost of approximately US$3.3mn for the three blocks.

Madagascar Oil announced that the Force Majeure event on the exploration Blocks has now terminated.

Ocean Rig books UDW drillship OCEAN RIG UDW has received a Letter of Award for its ultra deepwater drillship Ocean Rig Olympia (UDW drillship), from a major oil company. The Letter of Award is for a three year contract for drilling offshore West Africa, with an estimated backlog of approximately US$652mn. The Letter of Award is subject to completion of definitive documentation and receipt of regulatory approvals.

The contract is expected to commence in direct continuation of the Ocean Rig Olympia's existing contract in West Africa.

The customer would have the option to extend the contract for two periods of one year each, with the first option exercisable within one year from the commencement date under the drilling contract, and the second option exercisable within one year after the date of exercise of the first option.

With this latest fixture, Ocean Rig no longer has any rigs available in 2012.

Nigeria’s 1st EPCI company

Oil salaries higher in Nigeria

VANDREZZER ENERGY SERVICES Ltd is a world-class Engineering, Procurement, Construction and Installation Company (EPCI) with vast experience in upstream projects for the oil and gas sector in Nigeria and the West African A wellhead jacket recently built by Vandrezzer Energy Services Ltd in Nigeria, a unique project designed, Sub-region. fabricated and constructed by an indigenous provider of Vandrezzer has been energy services. at the forefront of this industry for over five years and the vast experience of the company's highly skilled project professionals includes oil and gas production technologies, extensive harsh environment design, construction experiences and construct-ability expertise.

Its integrated EPCI approach to project execution, global procurement reach and unparalleled safety record for oil and gas projects allow Vandrezzer Energy to successfully manage the aggressive schedule and rigorous cost demands associated with challenging upstream projects.

This is the first EPCI company in Nigeria and its mission is to raise a people-oriented company using cutting-edge technology to provide superior engineering solutions in a cost effective manner, within a stipulated time, while meeting clients' specifications and standards, thus standing out as the best, in the quest for global and renewable energy.

NIGERIA HAS EDGED out Egypt, Libya and Kurdistan on a list of oil and gas producing countries where energy majors pay the most supplementary pay to senior staffers, according to executive recruitment firm The Curzon Partnership.

Attracting talent to frontier countries such as Nigeria remains a challenge for the oil and gas industry. The average general manager in the West African country can receive a country premium up to 45 per cent of base pay, bringing total salaries to approximately US$460,000 a year.

‘The growth in exploration and production across frontier markets over the last 15 years has created a global fight for talent among oil and gas businesses,’ said Helen Di Mauro, partner at The Curzon Partnership. ‘There are still roles in more mature regions like the North Sea, but frontier markets will represent an ever bigger slice of the pie in the future.’

Di Mauro said companies are willing to dole out country premiums because it is harder for expats, and especially those with families, to maintain the same lifestyles they would enjoy in the US or the UK in frontier markets. Those general managers or equivalents working in the North Sea, can make approximately $238,000 a year.

The Curzon Partnership attributes Nigeria’s high pay premiums to not only cultural adjustments, but local skills shortages and the number of talent needed on projects.

“Nigerian oil projects are booming, with a number of new entrants targeting opportunities which is generating a lot of demand for senior talent,” Di Mauro said. “Some oil and gas executives and their families perceive frontier markets like Nigeria as riskier than other markets and the high country premium reflects that.”

Comparatively, premiums in countries such as Egypt, Libya and Kurdistan are lower amounting to 30 per cent of base pay. General Managers in these countries stand to make between $309,000-371,000 a year. Di Mauro attributes this to a well-established expat community in Egypt and lower demand for senior staff in Libya and security improvements in Kurdistan.

6 Oil Review Africa Issue Two 2012

S02 ORA 2 2012 News_Layout 1 12/04/2012 14:23 Page 7

Industry News & Events

S02 ORA 2 2012 News_Layout 1 12/04/2012 14:23 Page 8

Red Spider announces West Africa deal

Kosmos pens PSCs offshore Mauritania

RED SPIDER, THE Remote Open Close Technology (ROCT) specialist delivering multi-million pound savings and reduced risk to the oil & gas industry, has completed its first work in West Africa and secured additional contracts in the region.

The success follows Red Spider’s recent announcement of the appointment of an agent in West Red Spider technician works on eRED-FB Africa to support its expansion in tool on the production line. the region.

Work involving eRED, Red Spider’s breakthrough ROCT product, was completed in Equatorial Guinea. The success is expected to lead to further runs of the tool in a number of West African countries, with significant interest expressed by operators in Gabon, Ghana, Angola and Nigeria. Further work involving one of Red Spider’s latest products, eRED-FB, is scheduled with an operator in Equatorial Guinea by the middle of 2012. Deals completed for work so far in West Africa have a value of US$604,000.

Red Spider’s Africa sales manager Barry Killoh said: “We knew the West African market had huge opportunities for our technology and to have this level of interest from the outset is very encouraging. Our tools are proven to help operators reduce risk and deliver major cost savings, particularly during deepwater operations, so they are ideal for the market.”

KOSMOS ENERGY HAS signed three Production Sharing Contracts (PSCs) with the Government of Mauritania for Blocks C8, C12, and C13 offshore Mauritania. The contracts will take effect upon formal ratification by the Government of Mauritania. The blocks, which are contiguous, range in water depth between approximately 1,600 and 3,000 m, and have a combined acreage extent of approximately 27,200 sq km.

Kosmos will be operator of the three blocks with a 90 per cent interest.

The national oil company, Société Mauritanienne des Hydrocarbures (SMH), will hold a carried interest of 10 per cent.

In the initial exploration phase under each of the contracts, Kosmos plans to acquire 2D and 3D seismic data. The company targets first drilling as early as 2014. The execution of the PSCs represents Kosmos' initial entry into Mauritania and significantly expands the company's exploration footprint.

Brian F. Maxted, Chief Executive Officer, commented, "With our exploration programme focused on unlocking new petroleum systems by drilling multiple basin-opening wells on an annual basis, the offshore Mauritania opportunity fits very well strategically with Kosmos' existing portfolio. We have now captured approximately 9.7mn hectares of highimpact exploration potential, with additional new venture initiatives ongoing to selectively further our opportunity set. The new blocks captured reside in the proven offshore Mauritania salt basin and include the outboard fairway of the under-explored Upper Cretaceous stratigraphic play concept, Kosmos' core exploration theme. We look forward to initiating a seismic programme over the blocks towards the end of this year or early next year."

No shortage of oil and gas in Angola, a country with great potential DESPITE GLOBAL ECONOMIC challenges, there is a real sense of optimism across the oil and gas industry, with renewed confidence around the world.

International demand for oil and natural gas means that commodity values continue to remain high, despite political tensions in a number of regions, increasingly demanding exploratory environments and the resultant impact of rising costs on operators.

Regardless of these factors, the industry is nothing short of vibrant.

Africa is a region that continues to show great promise. Whether in mining or oil and gas, nothing is done in half measures, with countries such as Angola, Nigeria and Ghana all considered major regional players.

Security concerns are still present, but international confidence in the region is undoubtedly on the rise. This may be the result of a number of super-majors willing to accept the risks that are an inherent part of the potential rewards that are on offer.

Successes are already evident. Particularly of note is Total’s Pazflor project offshore Angola, which came on stream in August last year. The project encompasses the Perpetua, Acacia, Zinia and Hortensia reservoirs in the offshore Gulf of Guinea.

Pazflor covers an area of more than 600 sq km – six times larger than Paris – with a

8 Oil Review Africa Issue Two 2012

water depth of about 1,200 m and has estimated proven and probable reserves of 590mn barrels. It is a major development for Angola, and is expected to increase the country's production by approximately 220,000 bpd.

BP too has been involved in Angola for almost 40 years with a long-term commitment to the country; the result of substantial deepwater interests, while Chevron’s wholly owned operating unit, Cabinda Gulf Oil Company Limited (CABGOC), is a major presence in Angola’s energy market.

Unlike countries such as Nigeria, Angola boasts strong manufacturing and fabrication services to support energy-related projects, while better education and technical training has been recognised as a core requisite.

Workforce development is a long-term approach for many companies in the country.

ExxonMobil for example, strategically implements development programmes to both meet local hiring objectives and overcome challenges related to the availability of experienced candidates and incountry training capabilities.

Meanwhile, BP has a working relationship with Agostinho Neto University in Luanda to help increase the number of qualified engineers and geoscientists that graduate

each year.

The country is not without its challenges, however. Poor amenities, threats to personal security, and the high costs of living are all factors to take into account, particularly for companies looking to relocate employees to Africa.

The most recent workforce survey produced

by OilCareers and Air Energi suggests that, as with other countries in the region, what appears sound on paper may vary widely from the reality. It reports that, despite the intent of local officials or foreign investors, something in the deal inevitably goes wrong.

Were Angola and Nigeria not sitting on 40 per cent of the continent’s oil and 67 per cent of its gas, and if the price of oil wasn’t so positive, the occurrence of backhand dealings may not have been tolerated for so long, according to the report.

Instead, Angola’s massive pre-salt deposits will continue to be explored, while a gas liquefaction plant is scheduled to be commissioned this year, keeping FEED, subsea and safety personnel in high demand.

With announcements pouring out of Angola as rapidly as the oil itself, there appears to be no shortage of work ahead for the country.

Mark Guest, Managing Director, OilCareers.com

S02 ORA 2 2012 News_Layout 1 12/04/2012 14:23 Page 9

SCHLUMBERGER HAS AGREED to acquire SPT Group, a software company specialising in dynamic production flow modelling in the oil and gas industry.

The agreement was made with SPT Group's owners, Altor Fund II. SPT Group provides a combination of software and consulting services for multiphase flow and reservoir engineering applications.

“The dynamic modeling and reservoir optimisation software of SPT Group will complement the existing Schlumberger production software portfolio,” said Tony Bowman, President, Schlumberger Information Solutions (SIS).

'In combination with the Petrel E&P software platform and other SIS technologies, this will enable customers to further optimise production from reservoir performance to processing facilities.'

“This is a great testament to our employees and a remarkable opportunity for the company,” commented Tom Even Mortensen, CEO of SPT Group.

HB Rentals completes project in W Africa OFFSHORE AND ONSHORE accommodation specialist, HB Rentals has completed a two-building accommodation project in West Africa, announced Regional Sales Manager Mike Bradley.

The package included one 12-man module and a recreation room. The buildings were installed onto beams that were welded on the deck to support the extra weight of the buildings. The enhanced design of the 12-man module was intended to ensure efficiency during offshore hook-up and installation.

“HB Rentals is committed to delivering the highest quality accommodations for our customers internationally, and these projects reflect our superior products and extensive project management capabilities,” said Bradley.

ITF boosts membership with leading service companies ITF, THE OIL and gas industry technology facilitator, has announced new membership agreements with two major global service companies. Through their membership, Petrofac and Siemens will join other high profile energy players in supporting new technologies through the ITF model to tackle global industry challenges.

Neil Poxon, managing director at ITF, said: “Welcoming two of the world’s largest service companies is a great coup for ITF as they bring a wealth of knowledge and industry expertise which will further strengthen the resources

available to us. Our growing international membership is absolutely crucial to funding some of the game-changing technologies that will secure hard-to-reach reserves and support exploration in new frontier regions.”

ITF members share funding and risk on bringing forward new solutions through Joint Industry Projects (JIPs). Developers can secure up to 100 per cent funding and retain full intellectual property rights. To date, ITF has launched more than 180 JIPs from early stage projects through to field trials and commercialisation.

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Plus, connecting your operations with our reliable, high-performance communication services will help improve the daily operations of your exploration and production assets, enhance the HSE (Health, Safety and Environment) impact of your business and improve crew morale by keeping your remote workers connected.

It’s all possible when you choose the world’s leader in voice, video and data services for your remote oil and gas operations. No matter where on Earth your operations take you, we’ll make the connections, we’ll make them powerful and we’ll make them simple. www.harriscaprock.com/energy-ora

RELIABILIT Y NEVER REACHED SO FAR ™ © 2012 Harris CapRock Communications, Inc. All rights reserved.

Oil Review Africa Issue Two 2012 9

Industry News & Events

Schlumberger acquires SPT Group

S03 ORA 2 2012 Analysis_Layout 1 12/04/2012 16:48 Page 10

Analysis

“Security of demand is as important as security of supply” said OPEC’s Secretary General in March just as its latest MOMR report was being released. The IEA has been giving its views on “the big picture” too.

Oil producers’ group responds to

consumer fears N

OT OFTEN DO top representatives of the main producer and consumer groups comment simultaneously on major supply/demand issues surrounding oil. But such an occasion took place last month at the 13th International Energy Forum Ministerial in Kuwait. The issue of the moment is of course the continuing rise of prices, with WTI increasing by five per cent in February alone; that’s up 20 per cent this year. Neither side is happy with this.

The International Energy Agency’s views are well known and were the subject of a special feature, “Excellent prospects for Africa’s oil”, in the last ORA (Issue One). We update this with a summary of Executive Director Maria van der Hoeven’s views, as stated in the Gulf, below.

Mitigating volatility But what of the main producers’ grouping OPEC, to which so many of Africa’s key producers belong? Secretary General Abdalla S El-Badri provided a concise summary of the complex situation described in full in the Organization’s March Monthly Oil Market Report. In just two words his address was about the necessity for “Mitigating volatility”.

Mr El-Badri stressed that this is an age-old problem, and that without drawing on OPEC’s own spare capacity – an excellent example was seen just after the Forum closed – the tightening of supplies, which brings such angst to most IEA members, would have been even sharper. In other words a lid is being kept on price rises occasioned by such various factors as uncertainty over Iran and the impact of central Europe’s exceptionally harsh winter.

OPEC’s top executive pointed out that prices swung violently in 2008, from nearly US$150/bbl to just $30 at one point; noone can plan to balance supply and demand in circumstances like these.

“Security of demand is as important as security of supply.”

The “financialisation” of oil markets was blamed for this, and Mr El-Badri cited specifically the entry of “new players” such as index funds and sponsors of exchange trade funds. Their strategies include hedging against inflation, exploiting arbitrage opportunities and plain old-fashioned speculation. He mentioned unwanted “herd behaviour” too.

“This leads to the question: Do futures prices still reflect the physical supply and demand fundamentals, or are they mainly driven by financial motivations?

“At OPEC we believe that massive and rapid in- and out-flows of financial investments into oil markets can alter price dynamics away from fundamentals.

This can exaggerate price swings, both up and down, in the short-term, and, if persistent, in the medium- to long-term…

“Security of demand is as important as security of supply.”

To mitigate against this unwelcome new factor, the Organization, like the IEA itself, projects its supply/demand calculations ahead to cope with a number of different scenarios. Thus, “between higher and lower economic growth scenarios [just one of the variables allowed for, transportation technology changes being another] there is an almost 20mn bpd difference [through 2035].”

Mr El-Badri concluded: “We cannot avoid speculation and volatility altogether. It is part of the market. However, it is essential to mitigate extreme volatility and excessive speculation, which are detrimental.

“Thus, it is important we look to well-designed regulatory reforms, continually

10 Oil Review Africa Issue Two 2012

Africa as a whole contributes far more crude to the world economy than it consumes.

improve the quality and timeliness of data, and strengthen JODI*, advance academic research, and further enhance the producer-consumer dialogue.” Of which the latest IEF Ministerial was of course an excellent example.

For its part the IEA is still fearful of a coming supply shortfall, its own March Oil Market Report describing a “Heady brew of both real and anticipated supplyside risks, alongside a very evident tightening in actual market fundamentals…

“It seems appropriate to stand back and acknowledge a big picture …”

Escalating supply-side risks are mentioned as a key part of this.

In her own address to the IEF the Agency’s senior spokesperson pointed out that global expenditure on crude oil last year was in excess of five per cent of the world’s total GDP, an unsustainable situation last seen back in troubled 2008 when deep near-global recession - most of Africa escaped was one of the results.

“We should all be worried about recent increases in prices,” she concluded.

The IEA expects global demand to rise by 0.9 per cent this year, almost precisely the same as OPEC’s latest forecast.

Good news from Africa There is serious concern on both sides of the argument therefore,, but all welcome the good news that continues to come out of both North and sub-Saharan Africa.

Africa as a whole contributes far more crude to the world economy than it consumes, and the gap is growing. This continent continues to feature six of the world’s 10 fastest-growing countries, with SSA alone exceeding East Asian growth over most of the last decade. And several African stock markets, such as the JSE, are now exceeding the world’s rapidly-improving norms.

Further, the Euro did not collapse as some predicted, although it has belatedly lost a lot of its value this year. And demand for oil in China seems to be moderating at last, with a record trade deficit being recorded in February.

So, as we headlined in the last issue, it all continues to point to “Excellent prospects for Africa’s oil”. ■

*Joint Organisations Data Initiative ORA HSE March 2012

S03 ORA 2 2012 Analysis_Layout 1 12/04/2012 14:26 Page 11

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Analysis

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Technological advances, enormous finds and high oil prices are driving the growth of a deepwater E&P market that not long ago was largely unviable. And, says Vaughan O’Grady, a new report suggests that the continuing deepwater boom is going to encourage massive expenditure — much of it linked to Africa.

Diving profits:

E&P deep undersea L

ARGE-SCALE DEEPWATER exploration and production has long been an aim of the oil and gas industry. However, only 20 years ago deepwater E&P was often too expensive and technically difficult to pursue. In some cases, more energy might have been expended to reach oil and gas reserves than would result from the finds themselves. And, at that time, onshore supplies were, if not plentiful, available in reasonable quantities.

All this has clearly changed. Driven by diminishing onshore opportunities, multi-billion barrel deepwater finds and technological advances that have enhanced the technical and economic feasibility of oil production at great depths, deepwater is today a vast, multi-billion dollar business.

Business research group Douglas-Westwood has examined this progression and attempted to predict how it will develop. The World Deepwater Market Report 2012-2016* examines the present state of play and outlook for the deepwater sector. The oil price, clearly, will continue to drive much deepwater exploration. Indeed Douglas-Westwood believes future price shocks are likely. As the company points out: “This will impact on deepwater developments to the extent that they will become even more economically viable as the oil price rises”.

More eonomically viable However, given the price reversals of previous decades, is this time really going to be different?

Steven Kopits, managing director of DouglasWestwood’s New York office, thinks it is: “The supply-demand balance is quite different from ‘those other times’,” he argues. “The oil supply has barely budged; China is prepared to take huge volumes of oil over the next decade. So we anticipate continued excess demand over supply, which implies strong pricing in general. Of course, there can be oil shocks and recessions in between, but the dynamics are exactly reversed from, say, 1979.” Having said which, he adds (this comment was made in January), “The global economy is pretty much at its carrying capacity for the price of oil. We peg that at US$95 / barrel for the US; $110 for China. So $125 Brent may well prove unsustainable on the demand side over the longer run. The US, for example, is shedding demand rapidly. January 2012 demand was down 4.7 per cent from January a year ago.”

For oil companies the overall outlook for 2012 is for greater expenditure; one estimate of

12 Oil Review Africa Issue Two 2012

Deepwater basins remain an important focus area for development.

For now, Africa, and in particular West Africa, is the main focus of deepwater activity worldwide E&P budgets, from Barclays Capital, suggests they will increase by 11 per cent. The longer-term outlook indicates that subsea, predominately deepwater, developments will continue to play a strong role in the portfolios of the major independent oil companies and some national oil companies, such as Petrobras of Brazil and Norway’s Statoil. Of course, “most deepwater plays are long-term commitments by definition,” Kopits points out.

As for the regions that will be the primary focus of activity, Eastern Europe and the FSU is predominately a shallow water region, although it is likely to dominate global trunkline expenditure over the 2012-2016 period. The Macondo spill is likely to impact North American installations in 2012 due to the 18 to 24-month lead-time for such projects. However, the outlook for 2013-2016 looks promising, unless new safety and environmental regulations delay recovery of activity in the Gulf of Mexico.

Despite a significant decline in activity during the global recession, deepwater basins remain an important focus area for development in Asia, notably deep and ultra-deep fields in India, Malaysia and Indonesia. Australasia’s focus will largely be on its massive offshore gas supplies.

Which leaves what are, at present, the two most

important deepwater regions of all: Africa and Latin America. Latin America is currently the second biggest deepwater region by total capex after Africa. Douglas-Westwood notes: “Continuing development of the pre-salt basins off Brazil by Petrobras should see this region overtake Africa in 2013.”

For now, however, Africa, and in particular West Africa, is the main focus of deepwater activity.

Angola in particular has made a name for itself as a leading area for deepwater E&P, with an estimated output of 1.7mn bpd in 2011. Recent onstream projects include Pazflor and Platina, while developments of the Canela and Kaomba fields are planned or ongoing. Ghanaian activity focuses on the vast Jubilee field (which was producing 70,000 bopd in May 2011) and further development is on the way, including integration with other discoveries. Other planned projects in Ghana include Tweneboa and Enyera. Nigeria is of course Africa’s largest oil producer and already has an established deepwater oil and gas industry.

Production is underway from the Agbami, Akpo and Erha projects and development is underway at Usan. Planned projects include Bosi and Chota.

Outside these three countries Egypt’s West Nile Project and Mozambique’s Windjammer are also noteworthy.

It all seems promising but are there any downsides compared to, say, Brazil? Kopits notes, “I have heard that, in some cases, they [African countries] are considered easier than Brazil, as the local government has less expertise and is thus more dependent on the oil company.” However, he adds, “Corruption is, of course, an issue. Africa is considered worse than Brazil.” There is a more positive message in Kopit’s assessment of West

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Analysis

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Africa’s ultra-deepwater potential: “The basin should be the mirror image of Brazil”. As for how long Africa’s three oil giants can keep up production, he simply says “A long time.”

Optimism for global equipment Not surprisingly, then, the global equipment forecast is overwhelmingly positive. The deepwater market brings together a number of sectors, all of which offer opportunities for vendors, among them drilling and completion, floating production systems and, of course, pipelines. However, subsea hardware will be a large part of E&P, and therefore economic, activity. Douglas-Westwood’s suggested shopping list for deepwater exploration includes production hardware such as subsea trees, control systems, templates and manifolds, flying leads and jumpers; subsea construction, umbilicals, risers and flowlines; and processing hardware (such as boosting/pumping, separation, compression and multiphase metering).

Of course where and how this equipment generally, and pipelines in particular, may have a role depends on the context. As Kopits says, “Distance to shore and depth can both influence the attractiveness of pipelines. Shuttle tankers are typically used where pipeline networks are not available. This applies to both Brazil and West Africa.”

14 Oil Review Africa Issue Two 2012

“The [West African] basin should be the mirror image of Brazil” However the oil companies’ money is spent the amount that is spent is going to rise: Douglas Westwood forecasts a global capex of over $232bn for the 2012-2016 period. This is, the company adds, 90 per cent more than the amount spent in the preceding five-year period. The company concludes: “In the global context, the overall outlook for the global deepwater business is clearly one of significant long-term opportunity with substantial growth in activity in West Africa, Brazil and Asia.”

Production at unimaginable depths Astonishing engineering feats and amazing technical progress have taken oil and gas production to previously unimaginable depths. It is not uncommon to hear talk of drilling and production nearing 3,000 m, and the economic landscape will be affected as deepwater projects become increasingly capital-intensive. E&P companies will be further challenged to build a

profitable business despite tight margins. And, as we have seen, this implies a significant role for the international oilfield service and equipment vendors that can help them to do that — and perhaps research and development. Not that we can expect sudden leaps forward. As Kopits points out, “Subsea processing is the most compelling technological topic regarding breakthroughs. But there remain issues. There are incremental improvements all the time, but no game-changers I’m aware of.”

Still as the industry closes in on 3,000m depths one is bound to ask how far is too far offshore? And how deep is too deep? On distance, Kopits is clear: “There is no such thing as too far offshore.” And depth? “To the best of my knowledge, Perdido [in the Gulf of Mexico] is the deepest oil development, the deepest drilling and production platform, and will produce from the deepest subsea well in the world: 2,800m. But if the oil’s there, I see no reason to think the industry couldn’t go deeper.” ■

*The World Deepwater Market Report 2012-2016 is the latest in a series of business studies by Douglas-Westwood an independent company and the leading provider of business research & analysis, strategy and commercial due diligence on the global energy services sectors. For prices and further information, see www.douglaswestwood.com/shop

S03 ORA 2 2012 Analysis_Layout 1 12/04/2012 14:26 Page 15

Analysis

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Operating risks are never absent on a prospecting or producing rig, especially when the location is offshore. Full assessment of major accident hazards and pre-planning of mitigation measures by engineers, technicians and HSE personnel working as a team is the norm these days.

Risk management

offshore D

EALING WITH ‘MACRO’ offshore emergencies such as a major spill is well covered by specialist private operators like OSRL and the internationally funded IPIECA. Both are well known in Africa’s deep and shallow waters. However, when it comes to the ‘micro’ scale – reacting to a failure of safety-critical equipment, for example – the rig operator is largely dependent on his own resources, initially anyway. This is where in-advance operational risk assessment (ORA) comes into its own.

ORA is based on the development of robust procedures for the implementation of adequate assessments for dealing with all the abnormal situations that can be reasonably anticipated.

Full assessment of anticipated operational risks prior to implementing adequate mitigating measures is essential to ensure accident prevention and safe operations offshore. Potential accident hazards must first be identified and recorded by competent personnel so that all associated safetycritical elements can be fully evaluated and signed off, both on the rig and at the operating headquarters.

Complete risk elimination too much to ask Complete elimination of all risk is too much to ask; keeping risks “as low as reasonably practicable” is the usual objective of both on- and off-site duty holders.

These include qualified individuals who are either directly responsible or accountable for all operations, including dealing with accidents, and those who are remotely consulted about how to respond to them. There is usually a separate tier of senior management that has to be kept informed about what is going on, including what mitigating measures have been put in place.

On the rig itself these duty holders usually include offshore installation managers, HSE advisers, technicians and engineers, and verifiers; equipment vendors’ own personnel are often available on the site too. If not they are usually invited in once a relevant incident has occurred or a major accident hazard has been identified.

These measures need to be reviewed whenever specific investigating, drilling or producing operations extend beyond whatever is ‘normal’ for the site. And equally when the usual protecting or monitoring devices such as safetycritical equipment (e.g. fire-control pumps) are out of action for some reason. Whenever this happens the pre-planned operational risk assessment process should swing smoothly into operation, which may and may not result in full

16 Oil Review Africa Issue Two 2012

OPITO offers all its international clients and their duty holders a structured standard-based risk-assessment framework which stretches from basic offshore safety through a range of specialised response roles.

Keeping risks ‘as low as reasonably practicable’ is the usual objective of both onand off-site duty holders. shut-down procedures being implemented.

The same thing happens before re-starting production or maintenance operations. All this can be triggered by something as simple as malfunctioning of a cooling system within an oil/gas processing module or the failure of a well barrier.

Major risk assessment steps The major risk-assessment steps that need to be taken will nearly always include: 6 ensuring rapid and appropriate initial response takes place, automatically if possible 6 accurate identification of anticipated follow-on hazards 6 accurate logging of the failure of all safetycritical elements 6 full evaluation of the resulting risks, including the probability of foreseen equipment failures and the ranking of resulting risks, including those anticipated down-the-line 6 deciding by competent personnel whether to shut down the whole complex or just the affected plant, and whether or not to end

reliance on automatic remote monitoring equipment 6 assessing residual risk after the primary incident has been satisfactorily dealt with 6 ensuring the “as low as reasonably practicable” level of follow-on risk has been returned to 6 recording the whole incident and gaining approval for mitigating measures taken 6 arranging for a final inspection once repairs have been completed.

One organisation that can help materially with the very obvious training needs of all this is OPITO International (www.opito.com/international).

Extensively experienced with risk anticipation in the Middle East, North Sea and Far Eastern oil and gas provinces, this not-for-profit safety body recently announced the extension of its training for offshore emergency response activities to the US Gulf. It now offers response training services out of Houston too, especially handy for operators in North and West Africa.

OPITO offers all its international clients and their duty holders - mandatory in some territories a structured standard-based risk-assessment framework which stretches from basic offshore safety through a range of specialised response roles. Integration based on international experience is the key, and this framework replaces the sometimes fragmented procedures used elsewhere.

“Raising the bar on safety” is how its activities are described by Gulf of Mexico VP Albert Skiba. ■

S04 ORA 2 2012 Ghana_Layout 1 12/04/2012 14:33 Page 17

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Ghana

The Africa Forecasting Division, led by Natznet Tesfay, has calculated Ghana’s overall country risk score to be 2.4 (High Risk) for the one-year outlook. While Ghana’s risk score is lower than that of other oil producing sub-Saharan nations (see table), there are still risks that investors and businesses need to understand when operating in the country.

Assessing risk for investment

in Ghana I

N DECEMBER 2011, the government submitted the draft Local Content and Participation Bill for the energy sector to Parliament. The bill sets a highly ambitious 90 per cent local content and participation in all aspects of the value chain by 2020, and stipulates that all major stakeholders consider Ghanaian companies and operators first in the awarding of contracts. However, due to a lack of domestic expertise in the energy sector, firms are unlikely to be able to comply with proposed targets, heightening contract and bribery risks as the government is likely to use the policy as leverage.

Given that E&P firms have already shown commitment to compliance by offering training opportunities to local employees, the government is likely to target first energy service firms for full compliance.

While extensive parliamentary debate on the bill is likely, the adoption of clauses within the bill is likely before the vote given broad consensus exists among key influence groups. This includes the initial 30 per cent provision of local staff, the five per cent local equity stake in service contracts, and the awarding of contracts in non-technical aspects to local firms. The law is driven by the increasing social demands for greater benefits from Ghana's resource wealth, hence the ruling NDC party's desire to adopt the law ahead of the December 2012 elections.

As a new oil producer, Ghana lacks the requisite human resource knowhow to manage the value chain in the three-to-five-year outlook. Also, energy firms will face financial and technical challenges stemming from the inability of local sub-contractors and suppliers to meet capital and operational requirements set by the industry. If the local procurement provision is enforced without a transitional phase, it is likely to jeopardise health and safety standards and quality control of

Sub-Saharan Africa Risk Score Table for oil producers.

18 Oil Review Africa Issue Two 2012

operations. Furthermore, despite the recapitalisation of the insurance sector to the minimum of US$1mn in core capital and the syndicated local insurance of the FPSO's, an EA source reported that the capacity of the local insurance industry did not seem adequately prepared to underwrite some of the high-capital risks, especially with new projects coming on stream.

Risks of industrial action will also increase amid mounting reports of depressed wages for local workers. On 30 November 2011, local employees of US firm Weatherford protested in support of a 25 per cent salary increment. The local labour quota requirements will give Ghanaian workers more bargaining power, which is likely to embolden local staff to make greater wage demands.

However, the risk of strikes and disruptions at mines and ports is likely to recede in the three-year view as the economy improves, inflation goes down and the government loosens fiscal austerity measures. In January 2010, the government increased the minimum wage by 17 per cent, in line with inflation.

Financial and technical challenges Protests are likely to be more sophisticated in 2012 as local groups increase co-operation with foreign counterparts. Foreign oil companies will be under greater scrutiny, and political pressure will push the government to increase Ghana National Petroleum Corporation's (GNPC) shares in projects: it holds 13.75 per cent in the Jubilee oil fields. Tullow, and partners, and new entrants are at risk. However, GNPC abandoned its attempt to obtain Kosmos Energy's 23.49 per cent stake in the Jubilee oil field, with Kosmos pledging to develop the asset after the government cancelled its proposed sale to ExxonMobil. Further, if the Local Content and Participation Bill becomes law, as is likely, foreign energy companies, especially first energy service

firms, will be at increased risk as the government is likely to use the policy as leverage over operators unable to comply.

Bribery and corruption risks Ghana is EITI compliant, yet the risk of corruption is likely to increase in the nascent oil sector, despite government anti-graft measures. A number of recent scandals have heightened concerns over corruption in Ghana and undermine the country's previously high standing on governance in the region. In September 2009, UK engineering company Mabey and Johnson was convicted of paying bribes in the 1980s and 1990s to Ghanaian politicians. This has led to the resignation of two serving ministers.

The current NDC government is pursuing corruption investigations involving contracts signed under the former administration. Energy-sector contracts awarded to the US' Kosmos Energy and Norway's Aker are the subjects of investigations launched in 2009 after accusations of favourable conditions and strong associations between local partners and former President John Kufuor. The government is also investigating the favourable revenue share awarded to Kosmos and local partner EO Group under the Kufuor administration. The government is likely to renegotiate certain highprofile contracts as a result, particularly in the energy sector.

On 2 March 2011, Parliament passed the Oil Revenue Management Bill, which is expected to increase transparency in the sector and decrease sovereign non-payment risks. An independent regulator and increasing local-content provisions are expected as well as an independent revenue body.

Ghana reached EITI compliance in October 2010.

However, the opposition continues to delay passage of the Oil Exploration and Production Bills that would be key to preventing corruption as oil production gathers pace. The opposition has 109 of parliamentary seats so it is difficult to pass anything without their approval. Further, if the December 2011 Local Content and Participation Bill becomes law, as is likely, foreign energy companies will be at increased risk. These foreign operators are unlikely to be able to comply with proposed local content and participation targets, heightening bribery risks as the government is likely to use the policy as leverage. Energy service firms, such as Baker Hughes, ABB, ASCO, Halliburton and Schlumberger are most at risk. â–

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Ghana

A profile on Ghana National Petroleum Corporation (GNCP).

GNPC gears up for Ghana

oil and gas sector growth F

OR MANY YEARS, officials from the Ghana National Petroleum Corporation (GNPC) toured the world’s oil capitals in the hope of drumming up investment in the country’s upstream sector.

At that time, it was a hard sell.

Back then, Ghana was viewed as little more than a backwater, in the shadow of its west African peers, notably the region’s biggest oil producer, Nigeria.

But that all changed in 2007 when big oil was discovered with the Mahogany-1 well in the country’s largely untested deepwater.

That discovery, in the West Cape Three Points licence, was the trigger for a succession of oil finds that have since helped propel Ghana to the forefront in the battle for investment dollars.

A year ago, international operators Tullow Oil and Kosmos Energy launched first production from the area, now known as the Jubilee field, which also straddles the Deepwater Tano licence.

Jubilee started pumping crude in December 2010 but a target of 120,000 barrels per day (bpd) was delayed in 2011 by technical problems.

In 2011, gross production from the Jubilee field averaged 66,000 bpd, according to project leader Tullow, just over half the plateau target.

At the start of March, Kosmos said that by the end of the year, it anticipates gross production at the site to average between 70,000 and 90,000 bpd, still some way below the hoped for output figure. Plateau production is now being targeted for 2013, Tullow reported in March, after an extensive work programme planned for this year.

GNPC role Despite these production teething troubles, it means Ghana is now an oil exporter of some note - as GNPC bosses had long claimed it would once be - and on the ascendancy, with more drilling underway, and further production expected from the many oil fields now discovered.

This dramatic turnaround in the fortunes of Ghana’s oil sector has had profound implications for the country - a long-term fuel importer - and for GNPC itself, the national oil company.

Founded in 1983, the state oil concern hopes to become a leading global oil and gas company, partnering international operators like Tullow, for the benefit of all Ghana and its people.

GNPC chief executive, Nana Boakye AsafuAdjaye, says the company intends to develop its operating capabilities further for achieving the vision of a nationally led oil and gas sector that

20 Oil Review Africa Issue Two 2012

contributes and enhances positively to national development. Furthermore, he believes that recent offshore drilling success is just the tip of the iceberg.

“Despite the recent exploration and production successes, the country’s sedimentary basins remain under-explored,” he says.

“A number of interesting leads and prospects with good potential for oil and gas accumulation still remain.”

Investment Since the discovery of oil, Ghana has become an attractive investment destination for energy companies and their suppliers, with a probusiness, open door policy and a stable, democratic political backdrop to work from.

It means GNPC is well positioned to enter strategic alliances with more oil companies to explore and develop the nation’s hydrocarbon potential further for mutual benefit.

Just as Ghana itself is often viewed as a model for stability and prudent management across the West African sub-region, GNPC hopes to leverage these strengths in its nascent oil and gas industry.

“We seek companies that are technically and financially capable,” says Asafu-Adjaye. “They must have systems and processes and a longterm commitment to stay in Ghana.”

This is already becoming evident with GNPC forging positive alliances not only with existing operators active in the country, but with other international companies too.

Last year, it teamed up with PetroSaudi, an international oil company from Saudi Arabia, the world’s biggest oil producer, for a strategic alliance to explore joint ventures in exploration, development and production, oilfield services and infrastructure and national capacity building.

Upstream 2012 Meanwhile, key operators such as Tullow and Kosmos are now pledging many billions of dollars of new investment in Ghana.

More than 90 per cent of the US$600mn Kosmos Energy 2012 capital budget is earmarked for Ghana, for instance.

This is broadly split between new exploration activities and development work, with plans to participate in nine new wells in 2012.

Multiple flow tests and reservoir studies, and appraisal wells, are planned for the Teak, Mahogany, Akasa, and Banda discoveries on the

Nana Boakye Asafu-Adjaye, GNPC’s Chief Executive.

The dramatic turnaround in the fortunes of Ghana’s oil sector has had profound implications for GNPC. West Cape Three Points Block this year.

On the Deepwater Tano Block, there are plans for two appraisal wells, as well as flow tests at the Enyenra and Ntomme oil discoveries.

A development plan for the Tweneboa, Enyenra, Ntomme (TEN) area is expected to be submitted for approval during the year, that will further boost Ghana’s production numbers.

The intention is to develop the three accumulations in an integrated subsea cluster using a single floating production storage and offloading (FPSO) vessel.

New exploration targets include the Deepwater Sapele, Wawa, and Turonian Deep (also known as ‘Tweneboa Deep’) prospects on the Deepwater Tano Block, which have net unrisked mean resources of more than 100mn barrels of oil equivalent combined.

In addition, the extension of the Jubilee field will gather momentum, with the Phase 1A development sanctioned in January 2012, while the drilling of the first production well commenced on schedule in February.

This initiative, to be conducted over an 18 month period, will cost around $1.1bn.

S04 ORA 2 2012 Ghana_Layout 1 12/04/2012 14:34 Page 21

Gas sector

Region of Ghana. It is currently assessing work that will include the construction of several key gas pipeline facilities.

These include: a 12” 50 km pipeline from the termination point to the Domunli processing site; a 12” 38 km pipeline to transport dry gas from the gas processing plant to Effasu; and a 20” 100 km pipeline to move dry gas from the processing plant to the Aboadze thermal power station.

Other facilities on the agenda include the construction of a riser platform at up to 80 m

water depth to gather gas from the other petroleum developments from the Tano and Cape Three Points Basins; plus a 6.5 km pipeline and installation of an export buoy in approximately 30 m of water offshore of the gas processing plant.

These are big challenges for the state oil company as it grows together with the nation’s upcoming energy sector and the leading operators it is now partnering.

GNPC, like Ghana’s oil sector, is finally coming of age. ■

Tullow finds oil at Enyenra-4A well in Ghana TULLOW OIL HAS announced that the Enyenra-4A appraisal well, in the Deepwater Tano license offshore Ghana, has successfully encountered oil in very good quality sandstone reservoirs. The firm also reported that good evidence of communication with the Owo-1 discovery wells and the Enyenra appraisal wells confirms the significant extent of the Enyenra light oil field.

Located just under seven km south west of Enyenra-2A and almost 21 km south of the Enyenra-3A well which defined the northern end of the Enyenra oil field, the Enyenra-4A well was drilled to define the southern extent of the field.

Results of drilling, wireline logs, samples of reservoir fluids and pressure data show that Enyenra-4A has intersected 32 m of net oil pay. Pressure data from the oil leg has demonstrated that the oil is in static communication with the oil seen in the other wells in the field and indicates a continuous oil column of approximately 600 m.

The Ocean Olympia drillship drilled Enyenra-4A to a total depth of 4,174 m in

water depths of 1,878 m. Wireline logging has been completed and injectivity tests are under way to provide important data for the design of the water injection system. On completion of operations, the well will be suspended for later use. The drillship will return at a later date to the Deepwater Tano block to perform a drill stem test on the oil zone in the Ntomme-2A well.

"This bold step out is an excellent result which is further enhanced by the quality and thickness of the reservoirs found at this downdip location," said Tullow Exploration Director Angus McCoss.

"Proving a 600-m oil column over a distance of 21 km with three appraisal wells is a significant achievement which was only possible through the use of highly refined geophysical techniques. The appraisal of the Enyenra field will now continue with the monitoring of the pressure gauges deployed in several wells to determine the level of dynamic connectivity within the system and to further refine the estimates of oil in place."

Oil Review Africa Issue Two 2012 21

Ghana

There is also the makings of a nascent natural gas industry as well. The Jubilee operators are seeking to utilise associated gas from the offshore oil field for use onshore in power plants and in industry, with GNPC playing a key facilitating role.

The state company is proposing a Gas Infrastructure Project to transport gas from the Jubilee FPSO gas export termination point to a processing plant at Domunli in the Western

S04 ORA 2 2012 Ghana_Layout 1 12/04/2012 14:34 Page 22

Ghana

Ghana's discovery of oil on its border with Côte d'Ivoire is testing the long-standing relationship between the two nations. The long running dispute over oil has led to Côte d'Ivoire's Director General of Hydrocarbons and Petroci unveiling a new maritime border with Ghana in November 2011, that includes some of the massive oil wealth in the western region, Ghana's Jubilee oil fields. Jon Offei-Ansah reports.

Determining the

maritime boundaries T

HE UNITED STATES is interested in the outcome of the boundary dispute between Ghana and Côte d’Ivoire over parts of the Jubilee Oilfields. The two countries are locked in talks aimed at resolving a maritime boundary dispute sparked by fresh oil discoveries. Côte d’Ivoire is claiming that oil currently being explored by neighbouring Ghana lies in its territorial waters in a dispute that has intensified as prospectors inch closer to a successful find.

“The United States has, as we say, no dog in the fight. We are very interested to find out the results,” US deputy assistant secretary for African Affairs, William Fitzgerald said in a recent teleconference with international journalists.

American oil company Kosmos, which is a partner in the Jubilee Field with an 18 per cent stake, has expressed anxiety over the future of a portion of its licence in the Deepwater Tano Block if the dispute remains unsolved. “Uncertainty remains with regard to the outcome of the boundary demarcation between Ghana and Côte d’Ivoire and we do not know if the maritime boundary will change, therefore affecting our rights to explore and develop our discoveries or prospects within such areas,” Kosmos said in a statement last year.

The Ghanaian authorities have, however, allayed stakeholders’ fears with the chief executive of the Ghana National Petroleum Corporation (GNPC), Nana Boakye Asafo-Adjei, saying claims of ownership of some of its oilfields by the Côte d’Ivoire do not have merit. Fitzgerald said it was up to the governments of the two countries to solve the problem, but was ‘not sure what the timeline is to make a decision between the two countries.’

Both the Ivorian president, Allasane Ouattara, and his Ghanaian counterpart, John Atta Mills, have met over the matter. “I know that President Ouattara and President Mills have met and discussed this and given the work over to a commission between the two countries to try and solve it in a equitable way,” Fitzgerald said.

Ghana officially entered the league of oil producing nations in December 2010 after the discovery of the offshore Jubilee Field three years earlier. The new exploration ground lies 74 nautical miles off the country’s western coast and promises an additional US$1bn a year in revenue to the national purse.

Before the Jubilee Field came on tap in 2007, Ghana and Côte d’Ivoire respected a median line as the maritime border, but the promise of more huge oil and gas deposits beneath the seas appears

22 Oil Review Africa Issue Two 2012

Oil and gas allocations along the Ghana-Côte d'Ivoire border

Uncertainty remains with regard to the outcome of the boundary demarcation and we do not know if the maritime boundary will change. to have raised the stakes for resource control. In 2010, the Côte d’Ivoire petitioned the UN to complete the demarcation of the Ivorian maritime boundary with Ghana after exploration firm Vanco discovered oil in its Dzata-1 deepwater-well.

Simmering tensions were exacerbated by Côte d’Ivoire’s disputed elections of November 2010 in which Ghana was seen as being a sympathiser of former president Laurent Gbagbo. In March of that year Ghana began initiatives to safeguard its borders against what it termed as ‘intrusion’, setting up the Ghana Boundary Commission to enable it to negotiate proper demarcation of its land and maritime borders.

The new commission began talks with a delegation from the Côte d’Ivoire led by its interior minister, Desire Tagro, in the hope of amicably resolving the row. Although details of the

negotiations are scanty, reports indicate that the Côte d’Ivoire mapped out a new maritime border, which covers part of Ghana’s prolific oil fields.

Production partners kept on the edge The developments are keeping production partners in Ghana on the edge as they have expressed fears that any changes resulting from the outcome of discussions could affect their operations. These developments, international relations experts say, must be handled with careful diplomacy so as not to further strain relations between the two countries. Vladimir Antwi Danso, a fellow at the University of Ghana’s Centre for International Affairs, also pointed out that reckless handling of the issue by the media could inflame passions.

“There is no need to go to war on this, the bodies are there to solve the problem,” he said. “Either the border commission that we have set up will be able to solve the issue or, if one side is not ready to listen to the result, we will have to take it up with the United Nations.”

Questioning why Côte d’ivoire was now raising the border issue when it remained silent over the Jubilee Field discovery in 2007, Antwi Danso added, “We must interrogate all these things and our diplomats must be very careful as to how to go about negotiating because if we don’t take care, tempers will flare up.”

S04 ORA 2 2012 Ghana_Layout 1 12/04/2012 14:34 Page 23

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S04 ORA 2 2012 Ghana_Layout 1 12/04/2012 14:34 Page 24

Kwesi Aning, a security analyst at the Kofi Annan International Peace keeping Centre, believes the government should nevertheless take a firm stance.

“More often than not, when these problems arise, there is a certain naivety on the Ghanaian side, a certain humanitarian approach, saying we are all brothers,” he said. “We are not brothers. The Ivoirians… have made their calculations and they are willing to push this demand as far as possible to get what they want.” He argued that a bi-partisan group of technical experts with the requisite knowledge on issues of such magnitude was key to ensure that relations between the two countries do not degenerate, pointing out that the Ivoirians had a presented ‘well structured and co-ordinated case’ that put them ‘miles ahead’ of Ghana as far as the arguments for demarcation is concerned.

“The Ivoirians have been structured, they’ve been co-ordinated and, irrespective of their own internal political crisis, they have the vision to make the Côte d’Ivoire a richer country irrespective of whether it is stable or not,” he stated. “In their struggle with us over where the boundaries are, the Ivoirians are miles ahead of us. I hope… a bi-partisan group of technical experts is put together, the money is found to support their work, they are given the independence of purpose to bring Ghana’s interest onto the table so that the [oil] find can be used to improve the lives of the people of this country.”

According to Aning, if tensions between the two counties worsened, Ghana and Ivory Coast could replicate the conflict that ensued between Nigeria and Cameroon over the Bakassi peninsula.

Although the border was never permanently delineated, Bakassi was considered part of Nigeria until it began attracting interest from oil exploration companies. In 2008, following intervention by the International Court of Justice, the territory was formally ceded to Cameroon, but as yet no oil has been found.

Over 30mn barrels already produced Meanwhile crude lifted from Jubilee Field midMarch crossed over the 30-millionth barrel of Jubilee Oil, since the field started production on November 28, 2010. The 30 millionth barrel pumped from the field was reached following the successful lifting of the 31st cargo of about 990,000 barrels of the light sweet crude oil from the field by Anadarko & Sabre Oil and Gas, bringing the total crude lifted from the field to over 30,300,000. Jubilee operator Tullow Oil’s lifting of 996,358 barrels on 2nd March, brought the total lifting to 29,327,955 and with a favourable world crude price hovering above the $120.00 per barrel mark, partners have been lifting around their maximum allowable cargo of 997,500.

Ghana has so far lifted 4,926,673 barrels and therefore its sixth cargo would bring the country’s total lifting to date to about 5,924,173 barrels. Field Operator, Tullow Ghana Limited, has so far lifted the highest quantity of Jubilee Oil of 10,609,113 barrels, followed by Kosmos Energy with 6,901,950 barrels, with the Anadarko – Sabre Oil & Gas Holdings group raking in 6,890,219. Production from the field, which started at a daily rate of less than 40,000 bpd rose steadily to 85,000 bpd sometime last year, before it declined to below 80,000 bpd rate, registering a shortfall of a third of the projected plateau for 2011.

Jubilee Operator, Tullow Ghana Limited in November 2011 reported that ‘production rates have been below expectations due to mechanical issues in certain wells related to the design of the well completions,’ adding that such problems were not unusual for a new field development of this type and remedial work was ongoing. The Jubilee Field is currently produced by the floating production, storage and offloading FPSO Kwame Nkrumah MV 21 vessel, owned by the partners. The Jubilee partners are already implementing Phase 1A development of the field, to boost production to the 120,000 bpd capacity of FPSO Kwame Nkrumah MV 21. ■

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24 Oil Review Africa Issue Two 2012

S05 ORA 2 2012 Ghana 02_Layout 1 12/04/2012 14:37 Page 25

S05 ORA 2 2012 Ghana 02_Layout 1 12/04/2012 14:37 Page 26

Ghana

The country’s long-term energy needs require proper planning for the future. Emmanuel Yartey looks at the possibility of nuclear power.

Nuclear power positive for

Ghana’s electricity needs T

HE PROJECTION BY the government of Ghana to increase power supply by 2015 due to the discovery of huge deposits of natural gas at the Jubilee Offshore Oil Field is welcome news. It must also be remembered, however, that this resource is finite and therefore a better alternative power source is needed to act as a long lasting complement. This source could come in the form of nuclear power.

Ghana’s Vice President, John Dramani Mahama, recently announced that the country will increase power generation to ensure a reliable power supply and become a net exporter of power in the West Africa sub-region by 2015. Solar and biomass were other sources of energy mentioned by the Vice President to be explored but he remained silent regarding nuclear energy.

Nuclear energy originates from the splitting of uranium atoms in a process called fission. At the power plant, the fission process is used to generate heat for producing steam, which is used by a turbine to generate electricity.

Ghana’s electricity consumption has been growing at 10 to 15 per cent per annum for the last two decades and it has been projected that the average demand growth over the next decade will be about six per cent per year. According to energy experts, electricity accounts for about 11 per cent of the nation’s final energy consumption and with a customer base of approximately one to four million, it has been estimated that 45-47 per cent of Ghanaians, including 15-17 per cent of the rural population, have access to grid electricity, with a per capita electricity consumption of 358 KWh. All the regional capitals have been connected to the

grid. Electricity usage in the rural areas is estimated to be higher in the coastal (27 per cent) and forest (19 per cent) ecological zones than in the savannah (4.3 per cent) areas of the country.

A positive idea It is a positive idea for the government of Ghana to resolve to diversify the power sector away from a complete reliance on hydroelectric power towards thermal fuel sources. The hydroelectric power plants at Akosombo and Kpong all in the Eastern Region, which over the years have been the main source of power generation in the country, are prone to seasonal variations in water levels creating periods of severe electricity crisis like the experiences the country went through in 1983, 1993, 1980, 1999 and 2006-2007.

These difficult periods, according to experts, enabled the nation’s major power house, Volta River Authority (VRA), in 1997 to build a number of diesel and crude oil – fired thermal plants to meet peak power demand and to provide backup in the event of occasional shortfalls in hydroelectric power. But thermal power generation has proven to

The government of Ghana has resolved to diversify the power sector away from a complete reliance on hydroelectric power towards thermal fuel sources.

Nuclear power holds promise for 10 African countries in pursuit of building their own nuclear plants. Wind and solar solutions aren't reliable enough, planners say, nor do they offer adequate electricity. Koeberg nuclear power station near Cape Town.

26 Oil Review Africa Issue Two 2012

be expensive in Ghana with the high price of crude oil on world markets. Using the under-construction Ghana Gas Plant in Takoradi in the Western Region to help increase megawatts of electricity is laudable but policymakers must complement the gas factor with sustainable nuclear power.

Some energy experts are playing down the idea of nuclear power saying that it is unreasonable to delve into nuclear at this time since the country has discovered huge deposits of natural gas. But it is important to remember that the country’s longterm energy needs require planning properly for the future and assessing options so as to avoid being taken by surprise by events.

Abhorrence of nuclear power stems from certain disasters associated with it in the past for some, one example being the March 2011 Fukushima nuclear energy disaster in Japan, but Professor Edward Akaho, Executive Director of Ghana Atomic Energy Commission (GAEC) noted that nuclear energy is a proven technology, being used by many different countries over 50 years and that its accompanying allied technologies have the potential to promote economic development in the country.

In 2007 when Ghana experienced an energy crisis, the then President John Kufuor inaugurated a Nuclear Power Committee whose responsibility was to prepare pre-feasibility studies on the country’s chances of expanding its power generation by including nuclear energy. The committee, which was chaired by Professor Daniel Adjei Bekoe, former chairman of the Council of States under the Kufuor’s administration, presented to the government after nearly five months a roadmap for adopting nuclear power by 2018.

Focus now on gas resources No mention has been made of this nuclear power roadmap since and the overriding focus is now on the country’s gas resources, with the government prepared to tap it to the fullest for the country’s power requirements as well as for the petrochemical industry.

As pointed out by Professor Akaho, in the early part of 2011 in an interview with Public Agenda a privately-owned weekly newspaper, “Atomic energy experts from the International Atomic Energy Agency (IAEA) are expected in the country soon to discuss the location characteristics of the proposed Ghana nuclear electricity plant, and the visit will provide a further boost to the country’s agenda to explore nuclear energy for electricity generation by 2018 to augment the existing source of power generation in the country.”

S05 ORA 2 2012 Ghana 02_Layout 1 12/04/2012 14:37 Page 27

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S05 ORA 2 2012 Ghana 02_Layout 1 12/04/2012 14:37 Page 28

Ghana

It is time the Ghana Government considered the nuclear power idea.

The IAEA, the world’s regulatory body responsible for nuclear and atomic energy activities, promotes the safe, secure and peaceful use of nuclear technologies. With regard to the implementation of the roadmap that will lead to Ghana producing nuclear electricity by 2018, there is little left for the experts to do for now; what remains is a sustained political will to carry the project through.

Now that Ghana is producing oil and gas in commercial quantities, the economy will definitely be expanding. Coupled with a growing population, it is automatic that the country will be facing major challenges in providing the required energy in a reliable and sustainable manner.

Peak power demand Public Agenda again reports, “The peak demand for power for the domestic market is projected to 3,000MW and 4,000MW in 2015 and 2020 respectively. The existing installed capacity for electricity generation is 2,044MW made up of 58 per cent hydro, 37 per cent thermal plants and five per cent diesel generators.

“The capacity would have to double by 2020 in order to meet the peak power demand, and available renewable energy resources other than hydro can at best provide 10 per cent of the national demand at competitive prices by 2020.

The country’s long-term energy needs require planning properly for the future.

The total available hydro power potential, including the under developed sites, could only continue up to 44 per cent of total demand by 2020.

“Some 30 countries around the world, including South Africa, Brazil and Mexico, generate electricity through 440 nuclear plants. Nigeria has also identified four locations for its future nuclear electricity plant.”

It could be argued, therefore, that it is time Ghana Government considered the nuclear power idea and began to implement what is in the

roadmap before it is too late, and a situation arises that costs the nation a lot of money to execute.

Preservation and management of nuclear knowledge in Ghana has emerged as a growing challenge to the sustainability of nuclear programmes and activities in the country, and for this reason, the Ghana Atomic Energy Commission is continuing to upgrade and expand nuclear facilities, It is also conscious of the fact that the accumulation of knowledge based on technical information in the form of scientific analysis of engineering systems also includes tacit knowledge embodied in people.

Ghana will be better placed to introduce nuclear power to solve our electricity generation and supply problems if human resource development and strengthening of basic infrastructure in nuclear science and technology are successful. ■

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S06 ORA 2 2012 Angola_Layout 1 12/04/2012 14:41 Page 29

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S06 ORA 2 2012 Angola_Layout 1 12/04/2012 14:41 Page 30

Angola

Angola LNG operates one of the world’s most modern LNG processing facilities in Soyo.

The project is expected to facilitate continued offshore oil development while reducing gas flaring in Angola. First LNG is planned for 1st quarter 2012. Jon Offei-Ansah reports.

A clean and beneficial alternative

to flaring D

ELAYS HAVE STRUCK Angola’s new liquefied natural gas (LNG) terminal in Soyo – the single largest investment ever made in the country - at the country’s northernmost coastline. The exportoriented plant had been scheduled to come on stream in March this year but has now been put back to mid-May. State oil company Sonangol has blamed the delay on the need for more testing of the plant. At nearly US$10bn, the total construction costs of the project are almost double the annual total GDP of Malawi.

One of the primary reasons for developing the Angola LNG project was to provide a clean and beneficial alternative to the practice of venting or flaring. Gas flares, visible from space, cause significant damage to the environment – pumping various toxins into the atmosphere, causing corrosive acid rain, and polluting the surrounding soil.

Gas flaring in Nigeria has wreaked havoc on the communities within the Niger Delta region contributing to the gradual destruction of the agricultural viability of the region and resulting in numerous associated health concerns including respiratory infections, and skin and eye conditions caused by the fumes.

The massive expansion of the Angolan oil industry witnessed since the end of civil war in 2002 coincided with a resurgent international interest in natural gas. Throughout the 1980s and 90s, with cheap oil flooding international markets, the development of the oil-associated natural gas industry was considered economically unviable.

The steady rise in oil prices since 2003, due to the huge increases in demand caused by the rapid growth of countries such as China and India, combined with worldwide production stagnation, has resulted in renewed popularity of the natural gas industry.

Natural gas demand to outrstrip that for oil Worldwide consumption of natural gas is estimated to increase from 100 trillion cubic feet (tcf) in 2004 to 163 tcf in 2030. The World Bank now estimates that global demand for natural gas will outstrip demand for oil by as soon as 2025.

Yet the recent volatility of the international energy market looks set to continue. Instability in the Middle East and North Africa, combined with the aggressive tactics of the Russian gas monopoly, Gazprom, have left many states eyeing up the potential of Sub-Saharan Africa as an important energy source.

30 Oil Review Africa Issue Two 2012

Angola LNG is a liquefaction project that is set to commence production in April of this year.

One of the primary reasons for developing the Angola LNG project was to provide a clean and beneficial alternative to the practice of venting or flaring.

The United States has taken a particularly special interest in Angola as a vital source of energy. The Angola LNG project demonstrates the increasingly close commercial ties between the two countries. Angola LNG originated from a joint-feasibility study conducted by Sonangol and Chevron (the second largest oil company in the United States after ExxonMobil in 1999). Chevron now holds the largest stake in Angola LNG at 36.4 per cent, followed by Sonangol at 22.8 per cent (British Petroleum, France’s Total and Italy’s ENI each hold 13.6 per cent). North American energy companies have largely missed out on Sub-Saharan Africa’s other natural gas giant, Nigeria LNG, potentially offering some explanation to why Chevron has been at the forefront of the industry in Angola.

Construction began in November 2008 with the US engineering company, Bechtel Corporation, alongside US based multinational energy corporation, ConocoPhillips overseeing the project.

Having just completed a similar LNG facility in Equatorial Guinea, Bechtel and ConocoPhillips were perfectly suited to take responsibility of the plant.

ConocoPhillips, with over four decades of industry experience, is considered a global leader in LNG innovation, while Bechtel have engineered numerous other mega-structures including the Hoover Dam in 1930.

It was originally believed that once completed and operational, the primary customer of Angola LNG would be the Gulf LNG Terminal in Mississippi in the United States from where it will supply natural gas to consumers and industrial users throughout the southern states of America.

However, Angola LNG is looking to sell its LNG to non-US buyers after prices there plummeted due to an increase in domestic gas production. ‘Our project was based, four years ago, on US sales, but since the LNG market is not very good, we are looking for other opportunities,’ Antonio Orfao, chairman of Angola LNG, told an industry conference in Australia earlier this year.

Angola LNG's plans to turn its focus away from US buyers occurs in the wake of a rapid increase in shale gas production brought about by new drilling and extraction technologies which will bring US gas production to a record high this year. US LNG imports have halved since 2007 with some import terminals re-exporting cargoes as the country's demand is increasingly met by domestic gas production.

S06 ORA 2 2012 Angola_Layout 1 12/04/2012 14:41 Page 31

Angola

LNG carrier British Trader will be used to transport LNG from the Angola LNG Project

New marketing entity being created To market its gas, Angola LNG is creating new LNG marketing entity that will look to sell its gas to the most competitive markets, Orfao said, but would not specify which markets Angola LNG was targeting. ‘We look for the best markets, it can be any place - our team is looking at different options,’ Orfao said, adding that although there were no signed sale contracts yet, he expected sale agreements to be made in the next several months. Rapidly increasing Asian LNG demand and higher prices for the fuel in the region have pulled supplies of the gas from the Atlantic region in the last few months.

Despite being a hub for the Angolan oil industry for some time now, construction of the LNG plant has irreversibly changed Soyo. Once chosen to site the LNG plant, large-scale dredging began under the auspices of a joint venture between the Dutch construction company Boskalis International, and Belgian company Jan de Nul. 125 hectares of land on Kwanda Island was raised while a further 65 hectares of new land was created in the Congo River estuary.

A workforce from all four corners of the globe flies in and out of the small provincial airport each day. The national policy of Angolanisation ensures that the project is contributing towards a growing highly-trained Angolan workforce involved in all disciplines – from senior management to design engineering to accountancy and human resources. Foreign companies are dependent on Angolan workers to manage operations in the country. 90 per cent of Chevron’s professional, technical and managerial staff are Angolan.

The rising influx of a large international workforce has resulted in a rapid growth of service industries including hotels and restaurants. Once a collection of numerous small villages, Soyo is now a bustling town. Rapid urbanisation is not without consequences. Yet thus far, local inhabitants appear to have weathered the changes well.

Prior to the commencement of construction a comprehensive Environment, Social and Health Impact Assessment was conducted in the region. Education outreach programmes were conducted to raise awareness in the region of the effects that this mega-structure is likely to have. An information centre in the Soyo town is open to all people living in the region and provides advice on the local impact of the LNG plant and the development projects it supports.

The Angola LNG project symbolises the rapid development of Angola today. Less than twenty years ago Soyo was the scene of fierce fighting when UNITA rebels launched an all-out offensive and managed to capture many of the oil facilities. Today it hosts one of the largest construction projects on the continent.

While oil production in Angola expands so will the volumes of the oilassociated natural gas. This gas can either be used productively or it can be vented or flared. Angola LNG indicates the Angolan government’s and international oil companies’ determination to make use of this hitherto considered by-product of oil and turn it into a major source of local employment, domestic energy consumption and export revenue. ■

Oil Review Africa Issue Two 2012 31

S06 ORA 2 2012 Angola_Layout 1 12/04/2012 14:41 Page 32

Angola

Angola’s state-owned oil company Sonangol is making moves to bolster its reputation, both at home and overseas.

Angola’s Sonangol coming of age, but

old challenges remain N

OW THAT THE country vies with Nigeria for the title of Africa’s greatest oil producer, Angola is looking to push on, to enhance local industrial development and grow a more sustainable domestic energy sector.

And this charge is being led by Sonangol, the nation’s energy champion, as it seeks to make a dent in chronic poverty levels.

An estimated two-thirds of Angola's 16.5mn people still live on less than US$2 per day, despite the nation’s huge oil wealth.

At the same time, it also means raising Angola’s profile beyond its oil-rich shores.

Like Nigeria, the country is now a member of the Organisation of Petroleum Exporting Countries (OPEC), a membership that conveys status among an elite group.

Sonangol is also blazing a trail with exploration interests in Iraq, Venezuela and Brazil.

The group operates across the oil and gas chain, though it is predominantly known for its involvement in Angola’s own upstream sector, partnering international firms in their exploration and production ventures.

It also has subsidiaries engaged in storage plus the marketing of crude oil and refined petroleum products, with offices in London, Houston, Beijing, Singapore and Rio de Janeiro.

Profit boost With oil still accounting for over 90 per cent of Angola’s export income, but employing less than one per cent of its people, Sonangol is in the front line of national development efforts.

But with profits soaring, it is well placed to build on all these strategic initiatives.

The company posted a 32 per cent rise in net profit in 2011, based on strong revenues accrued from higher oil prices, which offset slightly weaker production numbers.

The company's new chief executive, Francisco de Lemos José Maria - appointed when his predecessor Manuel Vicente moved to a key job in government - told a press briefing in March that net profit tallied $3.32bn, up from $2.52bn in 2010.

Sales were up 14 per cent, at $33.78bn in 2011, he added, due to higher oil prices in international markets.

Angola’s crude oil production fell, however, from 1.76mn barrels per day (bpd) in 2010 to 1.66mn bpd last year, due to technical problems at some fields and maintenance at others.

The government expects this to rebound to 1.8mn bpd during 2012 as additional production comes onstream and maintenance work is completed.

José Maria, cited by state news agency, Angop, said Sonangol’s own direct production fell 6.9 per cent, while production by international firms dropped 18.2 per cent.

Downstream diversification

Sonangol’s new chief executive, Francisco de Lemos José Maria.

32 Oil Review Africa Issue Two 2012

One of Angola’s primary diversification strategies is the move to monetise gas associated from the nation’s huge offshore oil production.

Sonangol is playing a central role in the nation’s largest current investment project, to produce and sell liquefied natural gas (LNG), which will help diversify income for the developing West African state.

After many years in the making, this project is almost complete with first exports of LNG anticipated around May, according to Sonangol officials.

The 5.2mn tonnes per annum project is being led by Sonangol, which has a 22.8 per cent interest and Chevron, which holds 36.4 per cent.

Other partners include Italy's Eni, Total of France and BP, which each hold a stake of 13.6 per cent.

Elsewhere, plans to expand domestic refining capacity are still being held up, however, with the country struggling to find suitable foreign partners and financing.

Sonangol is lining up a $8bn new refining project in the port city of Lobito in southern Angola although this initiative has been beset by delays.

Sonangol is in the front line of national development efforts.

The state company had originally hoped to have the facility operational by 2011.

Officials are in talks with some of the Angola LNG partners, including Eni, Total and BP, about working jointly on the project, although there is still no realistic timeframe for start-up.

Sonangol’s existing Luanda refinery last year posted a 26 per cent rise in output to 41,600 bpd, although this is still less than current market demand.

The company’s imports of refined products rose 15 per cent to 3.27 million tonnes during 2011.

International aspirations But it is clear that Sonangol’s ambitions are far greater than building up Angola’s oil and gas industry back home.

Like other national oil champions, it is keen to venture further afield, with a smattering of upstream projects on its books already, and marketing activities globally.

More is to come with Sonangol looking to buy a direct stake in Portugal’s refiner and explorer, Galp Energia, according to reports.

Sonangol is negotiating to buy half of Italian group Eni's 33.3 per cent stake in the Portuguese energy group, which also holds interests in four oil blocks offshore Angola, including a slice of the prolific Chevron-operated block 14.

S06 ORA 2 2012 Angola_Layout 1 12/04/2012 14:41 Page 33

S06 ORA 2 2012 Angola_Layout 1 12/04/2012 14:41 Page 34

Angola

Some of the old challenges for the country - and for the company itself - still remain.

Sonangol reported $33bn earnings, $3.3bn profits for 2011.

Sonangol already holds a 15 per cent indirect stake in Galp through its 45 per cent holding in Portugal's Amorim Energia, which controls a third of Galp.

Debt-stricken Portugal is believed to be receptive to any deal, courting investment from its oil-rich former colony in a bid to revive its flagging economy.

The Portuguese government also plans to sell its 7 per cent stake in Galp this year under a privatisation programme dictated by the terms of an international bailout package.

34 Oil Review Africa Issue Two 2012

The acquisition would also land Sonangol further upstream exposure in Brazil, where Galp partners Petrobras in 20 projects across seven basins.

Challenges ahead Despite a small drop in oil output last year, Sonangol continues to lead from the front in Angola.

But some of the old challenges for the country and for the company itself - still remain.

This includes raising transparency and accountability levels, a common criticism, among international watchdogs.

Transparency International ranks Angola as among the most corrupt countries in the world, with the government long accused of mismanaging oil revenues and avoiding genuine public scrutiny.

Critics have also urged Angola to reduce the huge influence of Sonangol, calling for an independent agency to ensure oil income filters through to the poor.

In December, New York-based watchdog Human Rights Watch urged Luanda to account for US$32 billion in missing government funds, thought to be linked to Sonangol, which were spent or transferred from 2007 through 2010, citing an IMF report.

The government denied the funds are missing and said the discrepancy resulted from insufficient record-keeping.

These are allegations that have long plagued Angola, and ultimately Sonangol itself.

Despite progress on the ground, including the long-awaited start-up of Angola LNG, and a growing roster of international projects, these are issues that will need to be addressed, especially if Sonangol hopes to grow its world stature further. â–

S07 ORA 2 2012 Geology_Layout 1 12/04/2012 14:44 Page 35

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Geology & Geophysics

S07 ORA 2 2012 Geology_Layout 1 12/04/2012 16:23 Page 36

Soco to survey Congo oil block SOCO INTERNATIONAL HAS been given permission to carry out aerial surveys of a Congolese oil block where exploration was suspended last year due to concerns over environmental damage.

Soco has rights to Block V but exploration has been halted as the block sits partially in Democratic Republic of Congo's Virunga National Park, which is Africa's oldest, and home to some of the world's last remaining mountain gorillas.

"We're delighted to have clearance to proceed with the aerial survey over Block V," said Soco's deputy CEO Roger Cagle.

Cagle added that work could begin in the second quarter of the year.

Congo's government last year suspended exploration after pressure from conservation groups and the World Bank. The company says it would have a beneficial impact on the area.

Ophir sees presalt analogies to Brazil offshore Gabonine OPHIR ENERGY SAYS the focus of exploration on its Ntsina and Mbeli concessions off Gabon has turned to the presalt play. Until now, poor seismic imaging has limited exploration of the presalt play in the North Gabon basin, but recent advances now allow effective mapping of presalt traps.

Ophir says seismic and gravity gradiometry surveys have revealed a potentially significant presalt play system in its blocks. The main focus has been over the Padouck Deep prospect which could hold around 1.3bn bbl.

Across the conjugate margin from Gabon is Petrobras’ Carmopolis field, with in-place reserves estimated at 1.7bn barrels.

Petrobras has farmed into 50 per cent of both Mtsina and Mbeli, and is funding the cost of a new 2,200-sq km seismic survey acquired early this year by PGS, which is intended to image the presalt system. The data will undergo pre-stack depth migration processing.

The pre-salt play has more limited extent southward into Ophir’s Manga and Gnondo concessions, where the focus is on the postsalt stratigraphic section.

Discoveries off Brazil such as Petrobras’ Barra in 2010-11 suggest this play could have analogues in the North Gabon basin.

Ophir has acquired 3D seismic already this year over Manga to assess the potential west of the Loiret Dome, where it has identified stratigraphic onlap plays and leads, of which Afo could be significant. The play system extends into the southern part of the Ntsina block and therefore the 3D survey has continued into this concession.

Processed data should available in early 2013. Once this has been interpreted, Ophir plans to seek a farm-in partner for next-phase work which could lead to drilling during the first half of 2013.

S07 ORA 2 2012 Geology_Layout 1 12/04/2012 16:24 Page 37

Serica’s seismic survey contract with Polarcus

VANCOUVER-BASED VANOIL Energy has begun the first phase of a 400-km 2D marine seismic shoot in the East Kivu Graben block of northwestern Rwanda.

The high-resolution low-penetration survey forms part of Vanoil's 2012 work programme that will be included in The Basins of Kivu Graben. upcoming Production Sharing Contract negotiations with the Ministry of Natural Resources of Rwanda, the company said in a statement.

A team from Syracuse University in the US is running the shoot as part of their long-running scientific investigations of Africa's Great Rift Valley, Vanoil said.

The current survey extends across an area of 1631 sq km on Vanoil's exclusive license in the East Kivu Graben block.

Vanoil said the block’s prospectivity is “further enhanced by the presence of long-chain hydrocarbons in the lake bottom sediments, indicative of possible existence of an active petroleum system”.

SERICA ENERGY PLC has signed a contract with Polarcus Seismic utilising the 10-streamer vessel Polarcus Nadia for an extensive 3D seismic acquisition survey in Serica's Luderitz Basin Blocks 2512A, 2513A, 2513B and 2612A (part), located offshore Namibia.

The survey, planned to commence in early April and cover an area of up to 4,150 sq km, will considerably exceed Serica's obligations for seismic acquisition under the license terms. It is aimed to achieve three objectives: 6 to delineate one of the three large four-way dip closed structures already identified on the blocks, 6 to identify the potential for stratigraphic pinch-out prospects which are likely to have formed in conjunction with large channel sand features present in the blocks, and 6 to seek to demonstrate the presence of hydrocarbon indicators.

The full cost of the survey is to be met by BP who will earn a 30 per cent interest in the License under a farm-out agreement with Serica. Following completion of the seismic survey the interests in the License will be held by Serica Energy Namibia BV, Exploration (Luderitz Basin) Ltd (a wholly owned subsidiary of BP), National Petroleum Corporation of Namibia (Pty) Ltd and Indigenous Energy (Pty) Ltd. Serica will continue to be the operator of the License for the seismic survey.

Tony Craven Walker, Serica's Chairman and Interim Chief Executive said, "This is a very significant seismic contract and we are pleased that we have been able to arrange it so soon after being awarded the blocks in December. The large size of the survey and the fact that we have been able to make such an early start will assist us and our partners in bringing forward the decisions required prior to commencing a drilling programme. The prospective nature of the underexplored deep water basins offshore Namibia offers great opportunity and Serica is pleased to be a playing significant part of this expanding effort."

Geology & Geophysics

Vanoil kicks off Rwanda shoot in

S08 ORA 2 2012 Gas_Layout 1 12/04/2012 14:47 Page 38

Gas

Rialto probes for gas off Côte d’Ivoire THE JACKUP TRANSOCEAN GSF Monitor has started drilling the Gazelle-P3 production well for Rialto Energy on the CI-202 block off Côte d’Ivoire. The location is on the northern flank of the Gazelle structure, 43 km southwest of Abidjan.

The well is due to reach a TD of 3,400 m MDRT and should require 60-70 days to drill and test. This is the first of a three-well campaign on the block which should take six months to complete, including testing.

Gazelle-P3, which is being drilled from the Gazelle subsea template, is designed as a deviated hole targeting oil in already tested sands over the Upper Cenomanian reservoirs. It will also be deepened to test a potential gas prospect,

Condor, and a combination structural/stratigraphic trap in the Lower Cenomanian not previously drilled.

Assuming a success, the second well will appraise Condor, while the third well in the programme will target the Chouette exploration prospect, 13 km from the Gazelle template.

Rialto has a gas memorandum of understanding with the government of Côte d’Ivoire, and appraisal drilling success will allow development of Gazelle to move forward, leading to a production start by end-2013.

Initial production rates should be 8,000 bpd of oil and 100 mmcfd of gas.

Aminex, Solo Oil discover gas pay at Tanzania Ruvuma well JOINT VENTURE PARTNERS Aminex and Solo Oil have made a gas discovery at the Ntorya-1 exploration well in the Ruvuma Basin, onshore Tanzania.

Further to the companies' update earlier this month, which reported strong gas shows in a good quality Cretaceous reservoir sand at a depth of 2,660 m, the open hole has now been logged from total depth of 2,750 m across the zone of interest.

Aminex chief executive Stuard Detmer said that following recent high-profile exploration successes in the offshore Ruvuma Basin of Tanzania and Mozambique, the Ntorya-1 well has established, for the first time, the presence of reservoired hydrocarbons onshore.

"Given current plans to develop major gas

infrastructure on the coast just 25km away, this has the potential for commercial development and opens new possibilities in the underexplored onshore regions of our Ruvuma block PSA," said Detmer.

Evaluation of electric logs from the well revealed a gross sand interval of 25m between 2,660m and 2,685m, with a three metre net gas bearing pay zone in sandstones.

Aminex said the sandstones show 20 per cent porosity at the top and a 16.5m thick lower sandstone interval with further possible gas pay.

The company noted the presence of reservoired hydrocarbons in Cretaceous sands in Ntorya-1 opening up the potential for additional plays in thick Mesozoic sandstones that were encountered

by the company and its partners in the Likonde-1 well, 14km north of the Ntorya-1 well.

Aminex plans to run a 7-inch liner to total depth and the well by a further 250m to investigate a prominent seismic event at 3,000m.

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38 Oil Review Africa Issue Two 2012

S08 ORA 2 2012 Gas_Layout 1 12/04/2012 14:47 Page 39

Anadarko successfully completes planned appraisal drilling programme

Anadarko's position in Offshore Area 1 of the Rovuma Basin, including the Prosperidade complex

vast extent of this accumulation and will be key in achieving third-party reserve certification, as we advance the partnership's world-class LNG project

toward FID (final investment decision)," Anadarko Sr. Vice President, Worldwide Exploration, Bob Daniels said. "The selection of Prosperidade as the field name is certainly appropriate, as it symbolises the partnership's expectations for this area and the opportunities it represents for the people of Mozambique. Our next step is to mobilise the drillship to the northern section of our block to begin testing additional high-potential exploration prospects that may expand the resource even further and provide tieback opportunities for future LNG hub facilities."

The Barquentine-4 well is the northernmost well in the Prosperidade complex, approximately 30 km north of the Lagosta discovery well located on the southern end.

It is located in water depths of approximately 1,650m. Once operations are complete at Barquentine-4, the drillship will be moved to the northern part of the Offshore Area 1 block to top-set the Atum prospect, and then begin drilling the Golfinho prospect. The partnership's second drillship operating in the area is continuing to carry out an extensive testing programme within the Prosperidade complex.

New success for Eni in Mozambique ENI HAS ANNOUNCED a new giant natural gas discovery in Area 4, offshore Mozambique, at the Mamba North East 1 exploration prospect.

The results of this well, drilled in the Eastern part of Area 4, are of special importance since they increase the resource base of Area 4 by at least 10 tcf of which 8 tcf of these contained in reservoirs exclusively located in Area 4. This new discovery further improves the potential of the Mamba complex in Area 4 offshore Mozambique now estimated to have at least 40 tcf of gas in place.

Mamba North East 1 is located 50 km off the Capo Delgado coast in a water depth of 1,848 m and reaches a total depth of 4,560 m. The well was drilled approximately 15 km north east of the Mamba South 1 giant discovery and 12 km south west of the Mamba North 1 giant discovery.

The discovery well encountered a total of 240 m of gas pay in multiple high-quality Oligocene and Eocene sands and proved reservoir continuity and pressure communication with Mamba South 1 and 493 - Oil & Gas Ad Adapt.ai 1 11/30/11 4:46 PM Mamba North 1 wells.

Oil Review Africa Issue Two 2012 39

Gas

ANADARKO PETROLEUM HAS announced that with the success of its Barquentine-4 appraisal well, the partnership has completed the drilling portion of its planned appraisal programme in the discovery area offshore Mozambique. The Barquentine-4 well, located in Offshore Area 1 of the Rovuma Basin, encountered approximately 160 m of natural gas pay, and became the Anadarko partnership's ninth successful well in the complex.

Additionally, the company announced that sixth- and seventh-grade students at Escola Unidade and Escola Primaria 16 de Junho in Palma Village, Mozambique recently selected "Prosperidade" (Prosperity) as the name for the discovery area in the Offshore Area 1 block. Prosperidade includes the Windjammer, Barquentine, Lagosta and Camarao discoveries, as well as the five subsequent appraisal wells in the block. As previously announced, Prosperidade is estimated to hold recoverable resources of 17 to 30-plus tcf of natural gas.

"Our appraisal drilling programme in the Prosperidade complex offshore Mozambique delivered outstanding results that provide significant confidence in the

S08 ORA 2 2012 Gas_Layout 1 12/04/2012 14:47 Page 40

Gas

The LNG world has been transformed in the past decade or so by improvements in technology, right across the gas supply chain.

Technology evolution drives Africa LNG

market growth F

ROM IMPROVEMENTS IN upstream technology, through to downstream processing and transportation, the LNG industry has seen huge and unprecedented change.

It has enabled pioneers such as gas giant Qatar to massively ramp up LNG supply to customers all over the world, as economies of scale have brought costs down. And it has come at just the right time with gas demand on the rise and oil prices running high.

Now, Africa could be at the forefront of the LNG technology evolution as operators seek to monetise new gas deposits away from established infrastructure.

This includes exploiting huge new deepwater gas finds off Tanzania and Mozambique’s prolific Rovuma basin.

Anadarko Petroleum is currently contemplating a large LNG plant in Mozambique, a project that could cost US$25 bn, more than twice the country’s gross domestic product.

BG will also soon start to ponder monetisation options for its offshore Tanzanian finds.

With more projects in the planning in Nigeria and Angola as well, Africa is likely to be a test ground for some of the very latest LNG technology.

Conceptual Mozambique LNG Project.

With more projects in the planning, Africa is likely to be a test ground for some of the very latest LNG technology.

FLNG One option that could be tested in Africa before long is the floating LNG (FLNG) concept, which Shell is pioneering far off in Australia.

The company said last year that it is committed to building the first-ever offshore facility to cool processed natural gas to liquid at sea.

The 600,000 ton FLNG vessel would measure about 1,600 feet, making it the largest floating offshore facility in the world.

It would first be deployed to the Australian waters of Shell's Prelude natural gas field.

If the concept works, then the idea could easily be rolled out to other offshore areas.

Namibia has long been linked to the FLNG concept as a means to exploit the stranded Kudu gas deposit, which has sat idle for decades.

Malcolm Brinded, Shell's executive director of upstream international, has called FLNG a “game changer” for the LNG industry.

The company expects the demand for natural gas to double by 2030 and sees demand for LNG doubling within the next 10 years.

40 Oil Review Africa Issue Two 2012

Market potential Although the Prelude vessel would be the first floating production facility, a number of countries have already deployed offshore LNG receiving terminals.

China - one of the world’s high growth markets for LNG - is currently developing its first floating receiving and storage facility near the northern city of Tianjin.

The US is also utilising floating LNG import terminals offshore because of limited land availability and strict onshore environmental regulations.

These floating import docks could be useful for bringing in short-term gas supplies for countries in Africa facing shortages.

South Africa has long contemplated developing a large, land-based LNG terminal to bring in additional volumes of gas.

Mozambique LNG Despite the fascination with FLNG, in Mozambique, it is likely to be a more

conventional land-based terminal that operator Anadarko opts for, despite the deepwater and offshore challenges involved.

The US-based company says the estimated recoverable resources of the area, between 1530 trillion cubic feet (tcf), are ideally suited for a large-scale LNG development, which will likely represent the largest foreign investment ever made in Mozambique over the life of the project.

Anadarko and its partners are currently designing the onshore facility to consist of at least two trains with the flexibility to expand to six trains.

The company also plans to leverage its international experience, gained from extensive worldwide deepwater projects including Independence Hub, to overcome some of the logistics challenges entailed.

This includes the design and construction of a flexible offshore production system to collect gas from the wells approximately 56 km offshore and tied back to the liquefaction plant onshore.

A final investment decision is anticipated by the end of next year, with first production by 2018.

New frontier Other partners on the Mozambique project include local state-owned oil company ENH, Bharat Petroleum, Videocon, Mitsui & Co and Cove Energy, currently the subject of a takeover bid by Shell and others.

S08 ORA 2 2012 Gas_Layout 1 12/04/2012 14:47 Page 41

Gas

S08 ORA 2 2012 Gas_Layout 1 12/04/2012 14:47 Page 42

If Shell gains access to the project, via Cove, it would also bring to bear its own weighty LNG credentials.

According to leading energy lawyers, King & Spalding, eastern Africa has become the world’s most promising LNG frontier in 2012.

The law firm says the area is well positioned to serve the high growth Asian market and, like gas leader Qatar, European consumers as well.

“This region could also become a major competitor of Australia and other exporting countries, as both Mozambique and Tanzania look to join the ranks of the world’s LNG exporting nations,” the law firm states in a March report, ‘The Top 10 Issues Facing the LNG Industry in 2012’.

The LNG carrier British Trader will be used to transport LNG from the Angola LNG Project, which will establish Angola as a major competitive source of LNG.

With scores of gas flares encircling the oil derricks offshore, the area is rapidly becoming one of the world’s most visible and active fields for gas development.

Angola LNG launch The next project up to make it, however, is likely to be Angola’s long-awaited and much-delayed LNG venture (see pages 30-31 for full information).

There are hopes that the scheme, which groups most of the country’s top upstream operators, could be ready to launch this year, despite cost over-runs and seemingly endless and unexplained delays.

The Angola LNG plant will have a capacity of 5.2mn tons per year.

Stake holders include: Sonangol (22.8 per cent), Chevron (36.4 per cent), Total (13.6 per cent), BP (13.6 per cent), and ENI (13.6 per cent).

The project, which was originally designed to supply the US market principally, has also had to reassess its marketing options, given the shale gas boom in North America.

Project officials have conceded that cargoes will have to be redirected to Asia.

Like the Mozambique concept, the project

gathers gas from deepwater offshore to a land-based terminal at Soyo in Angola.

The LNG is made from previously stranded methane that can now be brought ashore.

With scores of gas flares encircling the oil derricks offshore, the area is rapidly becoming one of the world’s most visible and active fields for gas development.

Within months, the flares will begin to flicker, as more and more of their methane fuel, now simply burned off, is put to better use.

US-based engineer Bechtel built the actual LNG liquefaction train, plus storage tanks, and the supporting facilities under a four-year lump-sum contract.

When the project finally launches this year, as is hoped, it will be another big leap for Africa and its growing high technology LNG sector. ■

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42 Oil Review Africa Issue Two 2012

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S09 ORA 2 2012 Gas 02_Layout 1 12/04/2012 14:57 Page 43

S09 ORA 2 2012 Gas 02_Layout 1 12/04/2012 14:57 Page 44

Gas

There is an energy shortage facing Africa’s largest economy, but there is also the prospect of an abundant, affordable but controversial resource that might be used to meet the country’s future needs. Stephen Williams examines the debate surrounding South Africa’s shale gas prospects

SA’s shale gas: abundant, affordable

and acceptable?

M

ANY OF SOUTH Africa’s energy experts are calling for the shale-gas resources that are believed to exist in the semi-arid Karoo region, between Johannesburg and Cape Town, to be explored and exploited. They make a compelling case for the government to lift the year-long moratorium it placed on shale gas exploration drilling.

South Africa is a net importer of energy, and still needs 56GW of new electricity generation capacity by 2030 as energy demand is forecast to grow even faster than the global average. It is also widely accepted that the continued economic growth of the country is absolutely dependent on stable and affordable energy supplies.

Currently, 70 per cent of South Africa’s primary energy is derived from coal and 90 per cent of South Africa’s electricity is coal generated. The net result is high carbon emissions even if only 80 per cent of South Africans enjoy access to grid electricity. The government’s objective is that, by 2030, at least 95 per cent of South Africans will have access to electricity.

Compared to the ubiquitous coal-fired power stations that South Africa is so heavily dependent on, gas-fired power stations are about 40 per cent more energy efficient and emit 50-70 per cent less CO2.

Furthermore, carbon capture and storage (CCS) retrofit costs, per MWh of power produced, are similar – and, it is argued, gas is a better complement to power derived from renewables such as wind power. So both conventional and unconventional recoverable gas reserves are part of a new energy mix that South Africa is now considering.

Replacing coal with gas for electricity generation is the cheapest and fastest way to meet South Africa’s CO2 reduction targets. The Combined Cycle Gas Turbine (CCGT) power station is both less expensive to build than a coal station, and cost competitive on a total cost basis (i.e. capital, fuel and operating costs).

That is why many experts are now calling for the Karoo’s shale-gas resources to be explored and exploited. At today’s gas price, the shale gas supporters say, between US$12.8bn (R80bn) and $32bn (R200bn) could be added to the country’s annual GDP – assuming just 20 trillion cubic feet (tcf) were extracted over 25 years, or 50 tcf over the same period, respectively. These figures represent four per cent and 10 per cent of the Karoo’s estimated resource size, currently put by the US Energy Information Agency as being 485 tcf.

But the benefits do not just end there, according to the shale gas lobby. There is the

44 Oil Review Africa Issue Two 2012

The footprint of a development in the Karoo would be very small.

prospect that around half a million jobs could be created by what would be an entirely new industry.

In addition, energy security would be significantly increased with the estimated resource base having the energy equivalent of 400 years of South Africa’s current total fuel consumption.

Shell the main advocate The lead proponent of the Karoo Shale Gas’ exploitation is Royal Dutch Shell. The group is on record as committed to spend up to US$200mn in a prospecting programme, involving the drilling of up to 24 exploration wells in a 30,000sq kilometer area of the 90,000sq kilometre Karoo – despite the fact that in the US, where shale gas exploitation has been ongoing for many years, there has been a shift of emphasis. Shell now intends to focus on shale oil in North America as gas prices have fallen so significantly.

Just as in the US, where shale gas exploitation has some heavyweight supporters – including President Barrack Obama who has promoted US shale gas technology on visits to China, India and Poland – there is vocal opposition to the hydraulic fracturing process, or ‘fracking’, that is required to access the gas that lies under the vast wilderness that is the Karoo. In fact, the Treasure the Karoo Action Group (TKAG) has formed a strategic alliance with Water Defense, the leading opposition group to fracking in the US. Fracking involves injecting water, chemicals and sand at very high pressure deep underground to create hairline cracks in rocks and release the trapped, or ‘tight’, gas. After fracking, much of the water at each well returns to the surface mixed with toxic chemicals.

Large-scale shale gas production by fracking did not occur until Mitchell Energy and Development Corporation experimented during the

1980s and 1990s to make deep shale gas production a commercial reality in the Barnett Shale in Texas, USA. Since then, the development of shale gas has become a ‘game changer’ for the US natural gas market.”

“We believe that there is the technology to extract shale gas in a way that is entirely safe,” Obama said in a speech in May 2011 in Poland at the US embassy in Warsaw at an international shale gas conference. Yet opposition to fracking is based on a number of concerns including land and water use; the contamination of aquifers; the noise and traffic involved; and deteriorating air quality due to emissions.

Speaking at the 14th Omega Euro-African Trade and Investment Summit, Martin Bell, the surface technical lead and water manager for Shell’s Karoo Project, tried to allay some of these worries by spelling out the commitments his company had made.

He said that Shell would not compete with the people of the Karoo for their water needs, and nobody would go short of fresh water because of drilling operations. Shell would, in short, conserve and recycle the water they used, as well as disclose the fracturing fluids the company was injecting at each drilling location.

Bell also drew attention to the shale gas landscape that Shell had created at Groundbirch, Canada, where well locations are no closer than five kilometres apart. He pledged this type of separation would be replicated by Shell if hydrocarbons are discovered and developed in the Karoo.

That is because, he explained, up to 32 horizontal wells can be drilled from single wellhead. “The footprint of a development in the Karoo would be very small,” he promised. “There are challenges, but risks can be mitigated through best industry standards and strong regulatory oversight.

S09 ORA 2 2012 Gas 02_Layout 1 12/04/2012 14:57 Page 45

The key challenge

Gas

“The key challenge in the Karoo is access to water,” he continued. “The water required for fracking may be brought in by rail from the coast, or drawn from aquifers far below the ones that supply water for farmers. The company will tap into the aquifers that farmers use only if it can prove no adverse impact.

Drilling waste, which could be especially toxic because the area is high in uranium deposits, will be shipped to disposal plants by pipes or by rail,” Bell added.

Yet fracking’s detractors cite the fact that in July last year, the Advertising Standards Authority of South Africa, an independent agency that sets guidelines for media companies, ruled that several of Shell’s advertised claims, including one that said fracking had never led to groundwater contamination, were misleading or unsubstantiated and should be withdrawn.

Jan Willem Eggink, Shell’s South Africa General Manager for upstream operations reiterates what Bell says. “We will not operate wells where isolation of our completion and production activities from potable ground water cannot be achieved. And, wherever possible, we use non-potable water, including the recycling and reusing of water from our operations. Nobody will go short of fresh water because of our operations; either in the exploration phase, or if there is any further development. This is a legally binding commitment.”

South Africa needs to get moving on exploring the potential of its suspected shale gas fields in the Karoo, according to a top economist.

Shell would not compete with the people of the Karoo for their water needs, and nobody would go short of fresh water because of drilling operations.

Shell wants to drill at least half a dozen shale gas exploration wells over the next three years in the Karoo, and if the gas reserves appear viable, it will start production with at least 1,500 wells several years later.

Speaking at the 2012 Africa Energy Indaba in Johannesburg in February, Eggink described the US experience as the “best analogue” for South Africa’s shale gas industry.

“Something like 10 years ago,” he told the Indaba delegates, “the US was tendering to import gas and the building of LNG terminals.

Then shale gas was discovered, and today the US is self-sufficient in gas. Within the next 10-20 years they believe they will be self-sufficient in energy, if the growth in gas continues. That country’s energy landscape has really changed, and it is something that could happen in South Africa too.” ■

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Oil Review Africa Issue Two 2012 45

S10 ORA 2 2012 E&P_Layout 1 12/04/2012 15:02 Page 46

E&P

Tullow draws up Jubilee expansion plans PHASE 1A DEVELOPMENT drilling started in February on the Jubilee field off Ghana, according to operator Tullow Oil. Under the US$1.1-bn programme, eight new wells will be drilled comprising five producers and three water injectors. The first of these wells should come onstream in late June.

Phase 1 remedial work continues – measures will include acid stimulations and recompletions of some underperforming wells. This overhaul, and the additional Phase 1A wells, should allow production to build toward the FPSO’s design capacity of 120,000 bpd.

Tullow expects Jubilee’s production to average between 70,000 and 90,000 bpd in 2012, depending on the well performance achieved from the Phase 1 recovery program and the execution schedule of the Phase 1A wells.

In the Deepwater Tano license containing Jubilee’s western portion, studies continue on the Tweneboa, Enyenra, and Ntomme fields oil and gas/condensate fields, now known collectively as TEN. Tullow expects to develop all three accumulations via an FPSO under an integrated subsea cluster development scheme. FEED work started last August, and a design competition is under way involving three FPSO contractors. Subsea FEED is nearing completion and tenders for this work are being prepared.

Tullow expects to submit the TEN Plan of Development (PoD) soon and a formal declaration of commerciality to Ghana’s Government. It anticipates achieving first production from TEN 30 months after government sanction.

The company has identified further exploration prospects in the license. Wells that could be drilled are Wawa-1, targeting hydrocarbons that may have moved to a trap up-dip from the TEN fields; Sapele-1, immediately south of the Jubilee, testing a prospective turbidite lobe; and Tweneboa Deep-1, a prospect underlying the TEN fields.

African Petroleum wins Côte d’Ivoire block WEST-AFRICAN-FOCUSED explorer African Petroleum has been awarded an exploration permit over Block CI-509, off the Côte d'Ivoire.

Under its agreement with the government and state-run company Petroci, African Petroleum will operate the 1091 sqkm permit area and hold a 90 per cent stake, with Petroci holding the remaining 10 per cent.

The agreement follows African Petroleum’s recent award of a 90 per cent stake in offshore Block CI-513 in December of last year.

The company said its exploration programme off the Côte d'Ivoire would target deep-water Upper Cretaceous sub-marine fans which were considered to have similar potential as discoveries in the Tullow Oil operated Jubilee field off Ghana and Anadarko Petroleum’s Mercury discovery off Sierra Leone.

It added that it expected to kick off a 3D seismic programme over both blocks in mid-April.

46 Oil Review Africa Issue Two 2012

African Petroleum signs contract with Ocean Rig UDW for two wells in Q4 2012 AFRICAN PETROLEUM HAS hired the services of Ocean Rig UDW a global provider of offshore deepwater drilling services, for a two-well programme with the “option” for a third well, to “continue” its drilling programme in Blocks 8 & 9, Liberia.

The West African-focused explorer said that the contracting of the Eirik Raude “demonstrates” the company’s “ability” to secure deep water drilling rigs in a very “tight rig market” and The Eirik Raude semi-submersible. also “ensures that it can deliver its extensive exploration programme”.

The Liberian Narina-1 discovery was drilled to a TD of 4,850 m in 43 days with no operational issues in a water depth of 1,143 m at a cost of US$55mn, African Petroleum said.

The well, it continued, encountered a total of “32 m net oil pay” in two different reservoirs including a Turonian submarine fan and an Albian zone.

The prospective size of the Turonian reservoir is 250 sq km based on 3D seismic interpretation but ultimately will have to be confirmed through this upcoming appraisal drilling campaign.

The programme will be completed using the Eirik Raude, a deepwater 5th generation semi-submersible, drilling rig and it is expected to commence operations in Q3 or Q4 2012.

Mobil completes platforms for 20 new Nigerian oilfields BARELY THREE WEEKS after the Federal Government renewed the oil leases of Mobil Producing Nigeria (MPN), operator of the Joint venture (JV) with the Nigeria National Petroleum Corporation (NNPC) for another 20 years, the company has completed three wellhead platforms constructed locally for the development of 20 new oil fields.

President Goodluck Jonathan recently in Lagos commissioned two of the platforms, which were constructed by Nigerdock Nigeria Plc at the Snake Island Integrated Free Zone.

Mobil's feat is a landmark achievement in the Nigerian Content development as the facilities are the largest fabrication contracts carried out in the country by Nigerian companies for the NNPC/MPN Joint Venture.

The project, which is under MPN's Satellite Fields Development Programme phase 1 (SFDP-1), is intended to develop the resources of over 20 discovered but undeveloped oilfields in the NNPC/MPN) Joint Venture acreage. Phase one of the project (SFDP-1) comprises Abang, Oyot and Itut (AOI) fields located in Oil Mining Leases (OMLs) 67 and 70, offshore Nigeria.

The project sought to recover more than 100mn barrels of oil and over 20mn boe of natural gas liquids.

Nigerdock was contracted to fabricate the Abang and Itut wellhead platforms, piles, coating and corrosion protection; installation of mechanical/electrical equipment skids, testing, sea-fastening and load-out, while Dorman Long Engineering Limited was also contracted to fabricate the Oyot wellhead platform.

Mobil's SFD-1 project involves engineering, fabrication and installation of a wellhead platform in each of the three fields with production gathering pipelines and tie-ins to existing production facilities as well as drilling of oil wells.

Executive Director of MPN, Mrs. Gloria Essien-Danner stated that the three completed platforms would soon depart from Nigerdock Nigeria Plc and Dorman Long Engineering Limited's fabrication yards for the Abang, Oyot, and Itut oil fields. According to her, the platforms are a major achievement for Nigerian Content as they are the largest fabrication contracts carried out in-country by Nigerian companies for the NNPC/MPN Joint Venture.

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Global Oceon Engineers is a Nigerian Offshore engineering design company, established in 2007 and promoted by Petrolog group, a US mudlogging giant, which has been operating in Nigeria for more than 30 years.

T

HE NIGERIAN GOVERNMENT’S Local Content laws re-defined the industry and legislated the increased local participation in Nigeria. The government has put its weight behind the development of Nigerian Companies and International Oil Companies (IOCs) have to collaborate to develop local talent, while fulfilling their own legitimate commercial aspirations.

International oil companies accustomed to working with global players expect the quantity and quality of work done by the indigenous companies to be of a similar standard. Oceon now offers that service that is expected by IOCs operating in West Africa’s offshore fields.

Global Oceon is focused on offshore engineering and has built strong capabilities in Subsea and pipeline engineering. Oceon is committed to providing innovative solutions for clients, satisfying the oil and gas sector needs using resources developed in Nigeria and by Nigerians.

Oceon offers comprehensive engineering services from definition engineering through to construction support which includes: Feasibilities, Preliminary Engineering, Conceptual Studies, Front End Engineering & Design (FEED), Detailed Engineering Design (DED), Project Management, Fabrication & Construction Support, Procurement, and Asset Integrity Management.

Oceon’s exhibits capabilities in Pipeline engineering which includes deepwater and shallow water pipelines and risers, route selection & pipeline alignment drawings, on bottom analysis, reports, specifications, MTO, data sheets, pipeline wall thickness, corrosion protection & weight coating, expansion, span &

stress analysis, pipeline expansion, pipelay installation analysis, upheaval and lateral buckling, pipeline crossing, shore approach and landing, pipe installation analysis: J-Lay, S-Lay & reel lay, static and dynamic analyses, initiation & abandonment analyses.

One of Oceon’s strength is its Structural Engineering comprising topsides & appurtenances design, fixed platform design, Seafastening analysis &design, barge design and structural analysis, installation aids design, PLET/PLEM design, sub-sea manifold design, flare tower design, heavy lift analysis and transportation analysis.

Another example is Piping Engineering which includes piping and equipment layouts, general arrangement drawings, pipe stress analysis, development of isometric drawings, material take offs (MTOs) for piping and valves, specifications, safety equipment location plan, piperacks and pipe support, wall thickness calculations, valve data sheets, line lists, asbuilt documentation & data collection.

Oceon is also noted for its Computer Aided Design & drafting which includes Installation Procedures Sketches, Installation Aids, Filed Layout, fabrication Drawings, Sea Fastening etc.

The company’s Process Engineering does design reports and philosophies, P&IDs and PFDs, line list, HAZID and HAZOP, sizing of pressure vessels, process control, process modelling & simulation, topside modelling & simulation, steady-state & transientstate flow assurance analyses, hydraulic studies, multiphase flow troubleshooting, operating philosophies & support for plant start-up, warm-up, cool down, flowline sizing & insulation and 14c compliance.

These are just a few of the strengths the company possesses.

Project experience As testimony to the confidence that IOCs have in Global Oceon, since it was formed four years ago, Global Oceon has worked on numerous projects including: OSO RE for Mobil (platform modifications, transportation analysis, construction support) Pazflor for Total (pipelines design) EGP3B for Chevron (pipelines and risers, modification of existing offshore fixed facilities) EESP for Chevron (offshore pipeline systems with PLEM and SPM loading buoy, cost estimate and schedule estimate) KIZOMBA C for Mobil (marine transportation design) AGBAMI for Chevron (design of offshore installation aids) EPC2B for Mobil (offshore platform modifications) BONGA for Shell (structural failure analysis) and Satellite Field Development Project Phase 1 for Mobil.

Global Oceon is boldly becoming the foremost engineering design company in Nigeria, with roots that are authentically Nigerian, recognised for the quality of its people, the quality of its designs and the strength of its overall performance. ■

E&P

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Sonangol in talks to widen Galp stake ANGOLA’S SONANGOL IS in talks on increasing its stake in Portugal's Galp Energia in a deal that would give it a larger slice of four oil blocks and a gas export project offshore Angola.

The state player is negotiating to buy half of Eni's one-third stake in the mostly downstream company, board member Sebastiao Gaspar Martins told Reuters on the sidelines of the International Energy Forum in Kuwait.

Crisis-hit Portugal has been courting investment from its oil-rich former colony in a bid to revive its flagging economy.

Sonangol holds a 15 per cent indirect stake in Galp through its 45 per cent stake in Portugal's Amorim Energia, which controls a third of Galp, but wants a direct stake.

"We are working on that deal. We will go ahead ... I think the deal will be done," he said of the talks.

The Chevron-operated block 14 located 80 km off the coast of the south west African country is the only asset currently producing oil for Galp in Angola.

Afren wells follow Okoro test AFREN WILL DRILL two production wells at its Okoro East oil discovery, offshore south east Nigeria, after testing confirmed a high quality oil find at the project, the company has told the London Stock Exchange.

Afren said it expected future horizontal production at the Okoro East wells would yield between 4,500 and 7,000 bopd per well, based on data from three drill stem tests undertaken since 17 January.

The tests revealed oil reserves at between 38°API and 40°API as well as multi Darcy permeabilities and average porosity of between 30 per cent and 35 per cent, in what the company said were “excellent reservoir sands”.

The wells would be drilled in the second half of this year using the free well head slots on the existing Okoro platform.

They would be tied back to the Armada Perkasa floating production, storage and offloading vessel, a move Afren chief executive Osman Shahenshah said would ensure a high return.

“The well has also opened up follow-on prospectivity on the block that we will continue to evaluate,” he said.

Anguille offshore drilling platform in place THE LATEST STAGE of Total’s Anguille field redevelopment off Gabon is in the final construction, hookup, and testing phase.

21 Phase 3 wells will be drilled from the new AGMN wellhead platform, which was An operator on an offshore platform in the Anguille completed in France field, off the coast of Gabon. late last year. The platform arrived in Gabon in January, with the three main sections — jacket, deck, and vent stack — assembled early February.

Elsewhere in Gabon, Total says construction continues of the power plant at the onshore PG2 site which will supply the Anguille and Torpille fields. The 1,000 metric-ton subsea electric cable connecting the plant to the offshore facilities was laid in January and February.

At the offshore Torpille field, the TRM34 well entered production last month.

Total’s capital expenditure in Gabon last year totalled US$758mn, up from $296mn in 2010. This was directed mainly at the continued redevelopment of Anguille field, with completion of the AGMN wellhead platform, and replacement or installation of flowlines and offshore pipelines.

Other capex items included a program to replace obsolete electrical systems on the Anguille and Torpille fields and drilling of wells on these fields and the offshore Girelle field.

48 Oil Review Africa Issue Two 2012

Afren confirms high quality oil at Okoro East discovery

Afren and its partner in development licence OML212, Amni International Petroleum Development Company, would now consider development options for the project, he said.

Up to eight production wells would be drilled there under a full field development scenario.

The well was spudded in December by the Transocean jack-up Adriatic IX, which the company used to search for oil near its producing Okoro field.

Chariot signs up Maersk Deliverer for Namibian well CHARIOT OIL & GAS has signed a contract with AP Moller Maersk for a one-well drilling slot using the Maersk Deliverer (UDW semisub) rig offshore Namibia. The firm expects to spud its first exploration well in the country imminently, after the anticipated arrival of the rig on location at the end of March.

The Tapir South prospect, which Chariot is targeting, is part of the Tapir trend and is located in Chariot's Northern Block 1811A, which is 100-per cent owned by the firm. The prospect, said Chariot, has a 25 per cent change of success and gross un-risked mean prospective resources estimated at 604mn barrels.

The well will be located 80 km offshore Namibia in 2,108 m of water, with a drilling depth of approximately 5,100 m total vertical depth subsea. It is expected to take around two months to drill and is the first well in Chariot's four-to-five well exploration programme that is planned to take place in 2012 and 2013.

"We are extremely pleased to have concluded this drilling rig contract with Maersk and to provide an anticipated spud date for our first exploration well offshore Namibia. Despite the tight rig market we have secured an excellent drilling rig for the Tapir South prospect with a highly reputable contractor," said Chariot CEO Paul Welch. "This will be only the second well ever to have been drilled in the Namibe Basin and we look forward to commencing our operations and updating the market with our progress in due course."

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S10 ORA 2 2012 E&P_Layout 1 12/04/2012 16:36 Page 50

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.

MARCH 2012 - LAND & OFFSHORE THIS MONTH Country ALGERIA (1) ANGOLA CAMEROON (1) CHAD (1) CONGO DRC (1) EQUATORIAL GUINEA (1) ETHIOPIA (1) GABON GHANA (1) IVORY COAST (1) KENYA LIBERIA LIBYA*** MAURITANIA (1) MOROCCO (1) MOZAMBIQUE (1) NIGERIA SENEGAL SOUTH AFRICA TANZANIA (1) TUNISIA UGANDA (1) TOTAL

Land OffShore Total 32 0 32 1 11 12 0 0 0 2 0 2 2 2 4 0 0 0 0 2 2 0 0 0 5 0 5 0 2 2 0 0 0 1 0 1 0 1 1 5 0 5 0 0 0 0 0 0 0 2 2 4 13 17 0 0 0 0 0 0 0 2 2 2 0 2 0 0 0 54 35 89

VARIANCE From Last Month 0 2 0 0 -1 0 0 0 1 1 0 0 0 5 0 0 0 -1 0 0 0 1 0 8

LAST MONTH Land OffShore Total 32 0 32 1 9 10 0 0 0 2 0 2 2 3 5 0 0 0 0 2 2 0 0 0 4 0 4 0 1 1 0 0 0 1 0 1 0 1 1 0 0 0 0 0 0 0 0 0 0 2 2 5 13 18 0 0 0 0 0 0 0 2 2 1 0 1 0 0 0 48 33 81

LAST YEAR Land OffShore Total 24 0 24 0 5 5 1 1 2 2 0 2 1 1 2 0 0 0 0 0 0 0 0 0 6 1 7 0 3 3 0 0 0 1 0 1 0 0 0 0 0 0 0 0 0 0 0 0 1 1 2 6 8 14 0 0 0 0 0 0 0 1 1 2 0 2 0 0 0 44 21 65 Source: Baker Hughes

ADX Energy to test Sidi Dhaher oil discovery in Tunisia ADX ENERGY IS set to test its Sidi Dhaher1 well in the Chorbane Exploration Permit onshore central Tunisia.

The 2,428 sq km Chorbane permit, near the port city of Sfax, is surrounded by several oil producing fields and oil and gas pipelines.

ADX expects to sign the contract for the Dietswell Rig imminently while scheduling to move the rig and auxiliary equipment to the well site is currently underway.

Key site personnel are already in place and an operational work programme has been agreed and finalised by the joint venture with testing operations expected to commence within three weeks.

Initial results are expected to be available shortly.

ADX is also preparing to undertake an extended well production test to establish long-term flow performance in the event of a successful test, on behalf of the joint venture.

The company's previous estimates have indicated the mean contingent oil in place.

50 Oil Review Africa Issue Two 2012

Sunbird spuds in South Africa AUSTRALIA-BASED SUNBIRD Energy has spudded its first well at its Ermelo coal bed methane project in South Africa, the company has announced.

The well, located about 200 km south east of Johannesburg in the Witbank coal mining region, was the first of nine core holes to be drilled over Sunbird’s three lead projects.

Sunbird plans to drill three core holes on Ermelo by May, with gas desorption results due 60 to 90 days after completion of the final well.

Following that, the drill rig and crew will move to the Springbok Flats project, north east of Pretoria, to drill a further three wells there. The project is due to be completed, with the remaining three wells to be drilled in the Mopane project, south west of Messina, by early in the third quarter.

Sunbird managing director Will Barker said the company aimed to determine the resource potential of its the 144,300 ha Ermelo project.

“Each core hole will involve the sampling of coal seams for gas desorption analysis to determine the gas content of the coals,” he said. “Additionally, each core hole will undergo geophysical logging and permeability testing to determine the reservoir characteristics of coal intervals.”

The Ermelo permit and Ermelo West application provide a combined best estimate of 800 bcf of gas in place.

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Downstream

S11 ORA 2 2012 Health & Safety_Layout 1 12/04/2012 15:12 Page 52

Boosting electricity generation US INVESTORS ARE moving to boost electricity generation in Africa, where a lack of reliable power has long been one of the biggest impediments to broader economic growth.

On a two-week energy trade mission to Ghana, Nigeria, Tanzania, and Mozambique, officials from Chevron, General Electric, Symbion Power, Energy International, and Caterpillar met with government officials, chambers of commerce, and private sector leaders on the vast potential for American firms to invest in African energy.

In Nigeria, Deputy Assistant Secretary of State, William Fitzgerald, says US firms are among those preparing June bids for the privatisation of power plants and power distribution networks.

With regular supplies of less than 4,000 MW in a country where estimated demand tops 10,000 MW, Fitzgerald says President Goodluck Jonathan is moving to improve generation in partnership with private sector investors.

“The Nigerian government realises that to promote – certainly to diversify the economy – to bring the manufacturers back on line, they need to boost power,” Fitzgerald says. Many US firms are interested in oil and natural gas offshore Ghana, especially if Ghana and Côte d'Ivoire resolve differences over the location of their maritime border, he says.

“It's an exciting time to be in the energy sector in Ghana,” Fitzgerald says. “And I think what you are seeing is very much a commitment on the part of the Ghanaian government to embrace private sector companies to come in and do the work.

You are going to see employment levels increasing and reaching record heights.

You will also see education and health

sector clinics improving.”

In Tanzania, Symbion Power is operating an off-grid, renewable energy programme that has helped create 1,000 jobs for sugar cane and bamboo growers as part of the US$206mn energy component of Tanzania's nearly $700mn US Millennium Challenge Corporation compact.

Fitzgerald says officials in Nigeria and Ghana are looking at the possible transfer of that technology to solve their own offgrid power needs. But for all the interest US investors have about Africa, he says there must continue to be progress on lowering trade barriers to create a positive business climate.

“The American companies that are going to invest in Africa need to make a reasonable rate of return,” he says. “They are not doing it for development.”

US foreign direct investment in Africa has grown from about $14bn in 2006 to nearly $25bn in 2010. Total US trade with Africa last year was about $83bn. That is behind the European Union's $150bn and China's $90bn in total trade.

“Foreign leaders often say to me, Where are the American businesses? How come they’re not here competing for this construction contract or that mining deal? What are they waiting for?”

Secretary of State Hillary Clinton challenged business leaders gathered at the State Department.

“This administration is doing everything we can to help American companies, large and small, compete and succeed,” she says.

“But ultimately, we know it is up to you.

We can't help you if you are not hungry enough to get out there and compete for the business that is going to be available.”

Scott Stearns

Discussions underway to build an oil refinery in Gabon THE PRESIDENT OF the Gabonese Republic, Ali Bongo Ondimba, has recently visited the largest oil refinery in the world, situated in Ulsan, South Korea. The visit comes after the Government of Gabon signed a letter of intent with SK Energy (a conglomerate including Samsung) in January 2012 for the construction of a refinery in Port-Gentil in the Mandji Island Free Zone within two years.

The new refinery would replace SOGARA, the Gabonese Refining Company, which is now old and not capable of processing the quantities required by the President's policy on the development of raw materials.

Gabon is still currently exporting 95 per cent of its crude oil, with the remaining five per cent being processed locally by SOGARA. If negotiations are successful, the new refinery is expected to process 50,000 bpd (vs. the 21,000 bpd currently processed

by SOGARA). Half of this will be exported, while the remainder will be used locally.

The new plant will produce: 6 LPG, 6 Gas oil, 6 Diesel, 6 Jet fuel, 6 Fuel, 6 Refined petroleum.

The cost of building this refinery around US$1bn - will be shared between Gabon and SK Energy, supported by the Korean International Cooperation Agency (KOACI), which provides subsidies for Korean companies interested in doing business abroad.

The climate variable was taken into account in the feasibility studies. The new entity will limit its emissions of greenhouse gases, recycle natural gas and recover oil residue. The energy produced from the gas released during oil processing will be used to supply the refinery with green electricity.

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52 Oil Review Africa Issue Two 2012

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Health & Safety

Jack Winton* explains how recommendations for health and safety following specific incidents, such as the Macondo incident, have informed KCA Deutag’s policies.

Strengthening operational

integrity R

EAMS OF PAPERS have been expended in the wake of the 2010 Gulf of Mexico Macondo blow-out and the Montara oil spill off the coast of Australia the year before, with still more reports due to be published. Unlike many tomes that gather dust on shelves and are rarely looked at, the findings and recommendations from these specific incidents have been taken seriously by the oil and gas industry.

Following the Macondo and Montara incidents, reports by the International Association of Oil and Gas Producers and other industry and governmental bodies along with the BP investigation itself have come up with a number of excellent recommendations. What we have taken from them in particular are recommendations to improve competence management and to further strengthen our systems and processes around operational and technical integrity. In the area of health and safety, it is well known that safety levels improve as a result of having the right equipment and tools, thereafter by complete adherence to processes and systems. The final improvement step is all around behaviours, an area in which the industry has given significant attention. Operational in particular, and to a degree technical, integrity hasn’t received the same level of industry focus, however, we are all realising that process safety is just as important as behavioural safety.

At KCA Deutag, we define the spectrum of safe operations as technical integrity, operational integrity and HSSE - the behavioural side. Organisations have typically focused on technical integrity by maintaining and managing their assets, an area that KCA Deutag has always been strong on as a company.

Now the industry is also looking to strengthening operational integrity. For us operational integrity is about taking a holistic approach to safety which is everything from the design, maintenance and operation of the equipment to the competence of the people operating it and the human and behavioural factors associated with that activity. As a result we’re applying this holistic approach to those parts of our process that have the highest exposure: wellcontrol and lifting.

We’ve already rolled out a number of activities as part of our HSSE plan. For instance we have introduced an operational integrity review whereby we send a multi-disciplined team to each country where we have rigs to look at the full

The oil and gas industry needs to develop large-scale rescue, response, and containment capabilities

remit of operational activity. The concept has also been introduced to our HSSE forums where it is changing the language that we’re speaking. Operational integrity is now a much more common discussion point, running like a thread through all of our safety tools whether these are incident review panels or investigations, new start-ups or operational readiness plans.

Strong operations department We are also committed to developing group and local procedures through a strong and competent operations department. This includes a technical authority, similar to that which applies to equipment, where a particular person will be the final arbiter from a technical perspective as to what operation is, or is not, acceptable. The technical authority relates to wells that we’re drilling, particularly the higher risk wells, to ensure that the five core values of The KCA DEUTAG Way are enforced when it comes to operational integrity.

As a company we have over 100 rigs situated in 22 countries around the world, so we’re revisiting a safety case approach to critically review the controls we have in place to prevent a major accident. This means translating the safety case into practical procedures for clearly identified individuals.

Many of these are already in place through existing safety case work but we have chosen to review all our cases to ensure we have prescribed the best sets of controls possible. A thorough review of safety case “bow tie” studies has allowed us to confirm these control and mitigations aspects of our systems which are critical. We are addressing this by ensuring these aspects are incorporated into operational procedures, training, job descriptions and so on. These procedures run throughout the company as part of the way we do business wherever we operate in the world.

Wherever KCA Deutag works, we like to be in-country for the long-term and have a commitment to using local labour. This includes Africa where KCA Deutag has been working for around 50 years in countries such as Libya, Algeria, Angola, Mozambique, Tunisia, the Sudan, Nigeria and most recently Gabon. Before taking up my current position, I was senior vice-president for Africa responsible for on and offshore. In most areas of Africa locally sourced labour accounts for around 90 per cent or more of the workforce and our startup training programmes are run to meet not only our own high standards but local employment regulations.

Commitment to a universal standard Indeed, this commitment to a universal standard when it comes to delivering safe, effective, trouble-free operations for our clients wherever they are in the world, is what gives us our competitive advantage. Therefore it is vital that these standards are maintained whether we are working in the Artic or Angola.

Sometimes this can be challenging in tropical or desert regions where there are additional risks associated with weather and climate.

To successfully and safely operate in this variety of regions, we rely on the leadership of our supervisors and expect them to be safety and operational leaders.

Post-Macondo many of our major clients now expect compliance in a number of areas that perhaps weren’t so critical previously. We believe if we can demonstrate to industry we are taking operational integrity seriously then we believe that puts us in a more competitive position as well as ensuring we maintain our commitment to our staff. ■

* Jack Winton is Operations Senior Vice-President for KCA Deutag, one of the world’s leading drilling and engineering contractors,

54 Oil Review Africa Issue Two 2012

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Libya

Oil Review Africa travels to German oil and gas company’s headquarters in Kassel for their annual press conference to find out the latest about their operations in postGaddafi Libya.

Wintershall remains committed to

post-Gaddafi Libya G

ERMAN OIL AND GAS company Wintershall has restated its commitment to post-Gaddafi development in Libya as it looks to ramp its oil production in the country back up to prerevolution levels Having resumed operations within Libya in October of last year, Wintershall has rebuilt its production levels up to 60,000 barrels per day (bpd) from its sites across the country.

The company has stated that its immediate aim was to increase production within the country to pre-revolution levels of 100,000bpd.

Strong support from new government Wintershall Libya general manager Dr Uwe Salge told Oil Review Africa that the company had received strong support from the new government and regional leaders.

“The focus is to re-establish pre-war production and there is a clear agreement among all players, including other oil producers and the state, to achieve this as fast and as efficiently as possible,” Salge remarked.

“The signals we are receiving from Tripoli and Benghazi is that everybody supports the oil industry and that it should be centrally organised.

“I see no signals that the country’s new leaders want to change this; even the leaders in the east of the country who want more federalism argue that certain sovereign structures should remain.

“They do not want to separate or divide the oil industry,” he added.

Salge said that the firm’s Libyan employees were taking a “more pragmatic” approach than before the revolution, with many people on the ground and in management roles now more willing to make quicker decisions.

At the company’s annual press conference in Kassel, Germany, Wintershall chairman of the board of executive directors Rainer Seele described Libya as a “test case” for the firm’s corporate activities in the Arab world, and said that Wintershall’s commitment to the North African country would make it more attractive to potential partnerships across the region.

“Libya is going to become more important as an investment market for us,” Seele remarked. “We did not abandon our staff [in the country] and they did not abandon us.”

Despite announcing increasing profits for 2011, the company’s overall production levels fell by 15 per cent, which Seele said was mainly due to the crisis in Libya.

The company’s expectant growth from its Nord Stream operations with Russian gas giant OAO Gazprom, as well as its growing interests off the

Wintershall says it has boosted output in Libya to three times what it was in the autumn.

56 Oil Review Africa Issue Two 2012

Wintershall operates eight onshore fields around 1,000 km southeast of Tripoli.

Wintershall’s capacity within the country could enable it to produce the desired 100,000 bpd within a couple of days. coast of Norway, has allowed it to take a measured approach towards the stabilisation of its Libyan operations.

Long-term Libyan activities “Our activities in Libya have always been long-term and our contacts [within the country] date to before the Gaddafi era,” said Wintershall executive director for exploration and production Martin Bachmann.

“We deploy Libyan staff to sites around the world. Most of our staff in the country are Libyans and we will continue to train and invest in these staff.”

Assuming conditions remain stable, Bachmann said that Libya’s “enormous potential” would lead to Wintershall’s continued investment in the country.

The company has invested more than US$2mn in the country in the past five years, Bachmann noted.

Salge, who is based in Tripoli, added that Wintershall’s capacity within the country could enable it to produce the desired 100,000 bpd within a couple of days, but that infrastructural issues needed to be rectified before it was possible to export the oil.

“At the moment we are dependent on rectifying certain infrastructural elements, such as pipeline repairs, but we cannot export such volumes at the moment as the pipeline is not able to sustain the necessary higher pressure we would need for that,” Salge said.

“Certain sections of the pipeline need to be repaired and replaced and we are in contact with the National Oil Corporation and the pipeline operators.”

Salge predicted that it would be at least another 12 months before the company was exporting 100,000bpm from the country. ■

S12 ORA 2 2012 Topaz _Layout 1 12/04/2012 16:38 Page 57

Topaz Marine provides supply and support services to the offshore oil and gas industry, supporting major projects. Roy Donaldson, COO, recently met with Oil Review.

to the energy industry WHAT IS THE background to your marine operation? What were its main functions at the outset and how has it developed?

The company started in 1973 as a marine engineering company (Nico) servicing vessels. Nico International, now a subsidiary of Topaz, was established in Dubai to service the increasing marine traffic generated by the oil boom. It bought one vessel then a second, but only needed one-and-ahalf, so chartered one out. This worked so well that the company kept buying, and by 2002 it had eight vessels.

Nico became Topaz in 2002 and started new manufacturing lines within the oil and gas fabrication works and installation, such as pressure vessels, process skids and structural works. The vessel TEAM Oman was added to Topaz's fleet.

Its specialised cable laying capabilities significantly increased the Topaz fleet's diversity (we just signed a contract with ABB for a further five years).

In 2009 Topaz launched a revitalised corporate brand and the new divisional brands Topaz Marine and Topaz Engineering, and in 2010 entered the Brazilian market through the acquisition of two vessels deployed in Brazil followed by West Africa in 2011. Today the company has 100 ships with an average age of six to seven years.

Your fleet includes anchor-handling tug supply vessels, platform Topaz Energy and Marine has sent two anchor handling tug supply vessels to the Atlas, supply vessels, multi-purpose supply vessels, specialised barges and Mira and Britannia fields offshore Nigeria. ice-breakers. Could you give some examples of the services such offshore support vessels offer?

The PSVs supply all equipment to support the drill Technology has enabled oil and gas recovery rigs such as mud, tubulars, casing and cement and from deeper, more difficult to reach and more also personnel, food, fuel and water. The anchor dangerous offshore areas. Do you constantly Demand now is deep, handling tug supply vessels (AHTSV) are vessels upgrade and adapt your services to meet these difficult, distant and which supply oil rigs, tow them to location, anchor challenges? them up and, in a few cases, serve as Emergency Oil companies are looking for vessels that are dangerous.

Rescue and Recovery vessels (ERRV).

DP2. Currently we are upgrading nine vessels to AHTSV differ from Platform Supply Vessels (PSV) DP2 (at a cost of US$9.5-19mn) in dry dock, in being fitted with winches for towing and anchor adding additional risers. Six new vessels have handling, having an open stern to allow the decking of anchors, and having come online this year with the possibility of being joined by four more. more power to increase the bollard pull. The machinery is specifically There is also a demand for DP3 vessels. designed for anchor handling operations. They also have arrangements for quick anchor release, which is operable from the bridge or other normally Rising oil prices make offshore operations ever more viable. Does the manned location in direct communication with the bridge. same apply to your support services?

The multi-purpose support vessels are designed to operate in a more Yes. We only invest in vessels that are needed and they are nearly all working. specific role whether it be pipe-laying, diving, well intervention, ROV, stand-by and accommodation vessels to name a few. Designed as a multiIt’s very early days for Nigeria. However, Ghana, Angola and a number role vessel for the oil and gas industry, these vessels provide supply and of other present and planned African operations are offshore. And, of general support; construction support; maintenance support; and course now, East Africa is showing a lot of potential. Do you see underwater pipeline inspection. Secondary roles might include platform potential in the sub-Saharan African market as a whole? fire fighting and cooling, anti-pollution oil dispersant spray operations as Currently the company sees so much opportunity in Nigeria that they are not well as standby and rescue operations. planning to go further afield – such as to Angola and Ghana, let alone East Africa – yet. Revenues are higher there than in the Middle East but costs are Has demand for vessels like these grown as more exploration and very similar. production has gone offshore?

Demand now is deep, difficult, distant and dangerous: it is deeper and further And what do you see as the main challenges for your business in the offshore and riskier as it is so deep. Also compact mud might be required to coming year – or years? keep gas pressure down. Shallow water drilling is continuing in Nigeria; it is The major challenge is crew! There is an extreme shortage of seafarers mainly repair and installation contracts that have been postponed. However, worldwide. We need to look at the future and not employ expatriates. It only now the market is increasing and tenders are starting to come out again, we costs GBP2,000 per month (US$3,150) to train a cadet but it’s a question of haven't seen much cut-back. attracting them in the first place.

Oil Review Africa Issue Two 2012 57

Interview

Marine and engineering solutions

Technology

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Building real-time, remote pressure management service capability to enhance safety and reduce drilling NPT, by Andreas Sadlier, Chris Wolfe and Mike Reese, Baker Hughes; and Bill Kenda, Deepweater Drilling & Completion Consultant (Apache Deepwater LLC formerly Mariner Energy Inc)

Changing the face of real-time remote

pressure management A

S DRILLING ENVIRONMENTS become more challenging and complex, the need to increase safety margins and reduce drilling non-productive time (NPT) costs continues to intensify.

It is also likely that our industry’s future will face greater pressure from regulators and the public to ensure safer drilling practices.

More and more operators are turning to remote surveillance services as a way to provide real-time interactions with wellsite personnel to mitigate drilling hazards.

Through remote monitoring services, dedicated personnel can actively monitor multiple operations and spot potential problems that busy rig hands might otherwise overlook or lack the specialized training to recognize.

In addition to the health, safety, and environmental (HSE) benefits of fewer personnel on location, remote service engineers/specialists can easily collaborate with a team of experts located in an offsite center of excellence, providing greater wisdom for real-time decisions compared to any one person at the wellsite.

Developing a value-added remote service from scratch requires many elements for success. For example, providing a remote, realtime integrated pressure management service requires careful planning and development of service components.

These include facilities and communications infrastructure, software and data-management tools, clearly defined service integration processes and communications protocol, trained and available personnel for job

execution, and customer partners willing to field test service solutions.

This paper offers a case study on how a successful remote, real-time integrated pressure management and wellbore stability service has been developed in the US Gulf of Mexico.

It discusses the various aspects of the service’s development from defining the service objectives, components, and deliverables to the communications protocols and the personnel competencies and training requirements for staffing.

The paper also describes aspects of the physical facilities, communications infrastructure, and real-time software tools that provide automated alarms, which aid personnel in keeping the drilling operation out of trouble.

Finally, a customer field trial that helped to improve the service further is examined and a brief summary of future developments is provided in the paper.

Many of today’s wells are being drilled in challenging environments in order to access previously inaccessible petroleum reserves.

Due to the complexity, geologic uncertainty, and sophisticated technology required for construction, a significant number of wells experience elevated drilling costs. The result is excessive drilling NPT and vast HSE risks.

Two separate studies of drilling-related NPT have been published and their results are shown in Fig. 1.

On the left-hand side of the figure (Dodson 2004), the pie chart shows that at least 42 per cent of all drilling NPT can be attributed to geomechanic issues. The more recent, independent study (Welling & Company 2009) shown on the right side of Fig. 1 confirms this quantity.

The authors of this paper contend that if more proactive effort were placed on identifying, predicting and mitigating trouble zones during the planning phase and while drilling, a significant reduction in NPT and a greater degree of safety could be accomplished. A real-time pressure management service was established to address these needs.

Remote pressure management service

Developing a value-added remote service from scratch requires many elements for success.

The primary objective of the real-time, remote pressure service is to supplement conventional predrill geomechanical modeling by identifying trouble zones in real time and taking corrective actions.

This results in an increase in safety margins (e.g., diminish the potential for a kick) and a reduction in drilling NPT (due to hazard mitigation). Additionally, by providing this service from a remote location, HSE risks are also reduced.

During wellsite pressure management endeavors, the pressure engineers are in continuous face-to-face communication with the operator’s rig supervisor. However, delivering this service remotely is more challenging because the remote pressure engineers must build trust and confidence with the operator by ensuring constant communication and careful data management from a remote location.

Service components and integration

Figure 1 - Greatest sources of NPT

58 Oil Review Africa Issue Two 2012

The first service component, the predrill geomechanical model, uses offset well data and/or seismic data to derive a safe operating window profile versus depth that is used for initial well planning purposes.

The primary objectives of conducting a predrill model are to identify trouble zones and

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Technology

S13 ORA 2 2012 Technology_Layout 1 12/04/2012 15:18 Page 60

appropriate geomechanical modeling methods. The drilling and casing programs are then designed based on the predrill geomechanical model.

Fig. 2 shows a typical depth-based mud weight window that can be viewed in real time using an Internet browser. The shaded area is the “safe operating window.” The operator’s representative is responsible for maintaining the downhole mud weight and equivalent circulating density (ECD) within the safe operating window and the remote pressure analyst updates the safe operating zone while drilling.

Delivering real-time pressure monitoring/modeling remotely requires collaboration between consultants, geoscience, operations and the remote pressure engineering team. Typically, the remote pressure engineering team is responsible for providing continuous mud weight window updates to the operator’s drilling team, while the other groups provide support and additional advice as needed.

Communications protocol With modern computer systems and high speed data communications now commonplace in the petroleum industry, high-quality data are now available in real time.

In-depth analysis of relevant pressure management data is typically carried out by an expert at the wellsite or in a remote center with information then dispersed accordingly to facilitate decision making.

In a remotely monitored operation, it is vital that all interested parties stay informed on a continual basis as decisions normally made at the wellsite must now be shared with offsite personnel.

Establishing a communication protocol can be quite complex, depending on the type of service provided, the communication capacities of the operation, or the number of companies involved. An example communication protocol flow chart for remote pressure management is presented in Fig. 3.

Remote operations platform Executing a successful remote drilling service requires a reliable and scalable remote operations platform.

This includes a secure, robust communications infrastructure, physical facilities and expert personnel available 24/7 to interpret current conditions and provide recommendations. It also includes software to automate, process, and display information.

To accommodate the remote pressure management service requirements, a separate remote services center was commissioned. The center is used to operate a variety of complex interpretive services including: pressure management, drilling optimization, reservoir navigation and other services that optimize the wellbore construction process.

Furthermore, a collaboration room (Fig. 4) was established that can be used in conjunction with other subject matter experts (SME) and/or client representatives for accelerated decision making.

With modern computer systems and high speed data communications now commonplace in the petroleum industry, highquality data are now available in real time.

Personnel The most challenging aspect of delivering a remote pressure management service is finding personnel with the appropriate skill sets.

A typical engineer is required to have vast knowledge in the areas of geology, geophysics, petrophysics, and petroleum engineering because the analyst uses a wide range of information (such as seismic, acoustics, images, formation tests and drilling) from all of these disciplines.

Engineers with these skill sets are usually very scarce and difficult to acquire, especially for 24/7 operations.

As pressure management services are designed for hazard mitigation

60 Oil Review Africa Issue Two 2012

Figure 2 - Example of mud weight window

throughout the drilling process, remote pressure management engineers are required to be available 24/7.

The minimum plan requires a total of four personnel: two remote pressure engineers working separate 12-hour shifts (while the third is on days off) and a sales and engineering support specialist who ensures the smooth operation of the remote services center. In reality, more remote pressure engineers are required because of workload, training, vacations, etc.

Training A comprehensive training program is generally structured as follows: candidate selection, initial training, structured, targeted training and continuous advanced training with mentoring.

Candidate selection is especially critical for pressure management engineers as they must be technically competent and must possess excellent communication skills.

The initial training phase should provide the engineers with a broad knowledge of the drilling process, geology, geophysics and formation evaluation.

Targeted pressure management training should include hands-on training in pore pressure and wellbore instability mechanisms, principles, methodologies, processes, predrill modeling (1D or 3D), and real-time operations.

Pressure management engineers gain further experience through an excellent mentoring program where the engineers are exposed numerous, diverse pressure management jobs.

Software capability and data integration Information management is also a key component required for delivering high-quality service execution.

Commercial software for pore pressure analysis and prediction provides a platform for integrating the predrill model and real-time information.

Many of these systems provide sufficient functionality, but for remote services, software tools must acquire real-time wellsite data through the remote services platform and infrastructure.

Therefore, a solution to address data integration needs while taking advantage of the collaborative benefits of remote services was needed.

It was determined through customer trials that software which assisted personnel in filtering out relevant information and alerted them of potential hazards before they are encountered would be extremely beneficial. The solution concept is presented in Fig. 5.

First, a predrill geomechanical model is developed for the prospect (label 1 in Fig. 5). The model is then delivered to the remote center where it is

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S13 ORA 2 2012 Technology_Layout 1 12/04/2012 15:24 Page 62

Figure 3 - example of remote pressure management communications protocol

imported into the real-time pressure management software (label 3 in Fig. 5).

Next, real-time measurements while drilling (MWD/LWD), mudlogging, and wireline are continuously sent from the rigsite to the remote center in real time.

These measurements are delivered using the service company’s remote operations platform communications infrastructure, indicated by label 2 in Fig. 5. The Wellsite Information Transfer Standard Markup Language (WITSML) is typically used to transmit the while-drilling data from the wellsite into the real-time pressure management software platform.

There, the pressure analysts compute the safe operating window and send the relevant data to the remote operations visualization system (label 4

A solution to address data integration needs, while taking advantage of the collaborative benefits of remote services, was needed. in Fig. 5). This enables multiple experts to view the same information at the same time from any global location with an internet connection.

Finally, automated alarms (label 5 in Fig. 5) built into the real-time collaboration system help minimize unplanned events from occurring.

Alarms included are: kick risk, lost circulation risk, hole cleaning efficiency, wellbore collapse risk, and several “look-ahead� alarms.

Remote pressure management service implementation Due to HSE concerns, there has been an increasing industry trend to provide services remotely.

In deploying a remote or wellsite pressure management service, there must be a fail-proof communication protocol, an accurate predrill analysis, adequate real-time measurements available, and a dedicated cross-discipline team of professionals.

There must be an interactive communication link between the wellsite (driller, LWD, mud logging, mud engineer, and the drilling foreman), customer (drilling engineer, geologist, and geophysicist) and the remote services center (geoscientists, drilling applications engineers, pore pressure and wellbore stability experts).

Customer trials

Figure 5 - Remote pressure management service information workflow

62 Oil Review Africa Issue Two 2012

While most companies have dedicated personnel specifically looking at the issues surrounding pore pressure and wellbore stability, they are often understaffed and undertrained.

S13 ORA 2 2012 Technology_Layout 1 12/04/2012 15:19 Page 63

References Dodson, James K. "Gulf of Mexico 'trouble time' creates major drilling expenses." Offshore, January 2004.

Welling & Company. Worldwide Survey of the Market for Drilling Services. Market Report provided to Baker Hughes, Houston. Welling & Company, 2009.

One particular operator expressed the desire for real-time pressure management services for a deepwater Gulf of Mexico project.

The project contained many unknowns because of limited offset well data, poor seismic velocities and a high potential for centroid (dipping bed) effects near salt.

In this particular well, a split wellsite/remote pressure management service was deployed utilizing LWD resistivity and acoustic measurements.

While drilling, the pressure engineers were able to compute an updated, accurate mud weight window. The analysis revealed that the sands were highly overpressured (sand pressures > shale pressures).

Accurately monitoring and modelling the safe operating window in real-time enabled drilling down through the primary target objectives.

Additionally, interactive communication and proactive decision making between the operator’s office (drilling and geology) and the wellsite/remote pressure engineers aided in the successful drilling of the well.

Conclusion and recommendations Many elements are required for a successful remote service. Due to the enormous NPT associated with geomechanic issues, a real-time remote pressure management service was developed meet operational needs.

There are numerous challenges involved in developing a remote interpretive service. These include: scarcity of qualified personnel, data communications infrastructure, appropriate software, establishing communication protocols and exhaustive training.

The lessons learned from customer trials indicate that effective planning, communications protocol, and experienced personnel make the execution of a remote realtime pressure management service an effective value-added solution that can solve major operator challenges.

In the future, it is envisioned that this real-time pressure management service will expand to include comprehensive remote wellbore stability services to minimize other geomechanical issues (e.g., running casing to bottom).

It is anticipated that additional automation from software tools including enhanced alarms,

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Technology

advice, and/or recommendations from knowledge databases will provide higher service quality by reducing the variability in the service and decision-making process. â–

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Technology

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Driven by the need to develop fields in deeper waters, more challenging locations and in reservoirs of increasing geological complexity, the subsea installation market is expected to grow at a significant pace over the next few years, with deepwater developments likely to be a major element of many of the world’s IOC and NOC portfolios.*

The African subsea market continues

to hot up T

HE LATEST WORLD Deepwater Market Report from analysts Douglas Westwood forecasts a 90 per cent growth in deepwater expenditure between 2012 and 2016 as compared to the previous five-year period, with a total of US$232bn predicted to be spent subsea. In addition, Emerson expects the number of new Christmas Trees coming on stream each year to increase from about 280 in 2011 to around 720 by 2016.

As part of the so-called deepwater ‘golden triangle’ alongside North and South America, Africa is likely to secure a significant portion of this spend with the same Douglas Westwood report estimating that 72 per cent of forecast deepwater spend will be in Africa and the Americas.

Another report from Quest Offshore Resources (Subsea Acceleration: Fathoming New Technologies) forecasts 3,200 new subsea tree orders between 2011 and 2015 with 60 per cent of these being in offshore Brazil and Africa. Along with Brazil and Australia, West Africa remains a key market for Emerson and we are currently pursuing 80 subsea projects over the next two years.

So in what specific areas is this growth in subsea installations being seen?

The increasing demand for subsea trees and associated hardware, such as control modules, manifolds and umbilicals, is helping drive the need for many broader solutions – solutions that can provide operators with more information and greater control over their subsea operations.

This covers everything from reliable reservoir and well monitoring in order that production keeps flowing, through to the avoidance of costly shutdowns resulting from sand, hydrates or an increased amount of water in the flow lines.

Continued growth of multiphase meters Take the issue of measuring flow rates in the well streams and the role of multiphase and wet gas meters subsea.

Today, there is a definite need for multiphase flow meters to be installed from field start-up to efficiently manage the reservoir throughout its production life, ensure optimal recovery and maximise output. As of 2010, according to Gioia Falcone of Texas A&M University and Bob Harrison from Soluzioni Idrocarburi Srl, there were 3,314 multiphase and wet gas meters installed worldwide – a number that is likely to double over the next ten years.

Current Emerson multiphase installations in Africa include the West Delta Deep Marine (WDDM)

66 Oil Review Africa Issue Two 2012

Emerson's subsea network answers many of operators’ questions relating to subsea operations.

The last few years have seen a raft of new subsea challenges concession offshore Egypt, where 49 Roxar Wetgas meters have been installed to help the operator Burullus monitor water production profiles in realtime; the deepwater Akpo field, offshore Nigeria where Roxar subsea Multiphase meters have been deployed; and the Kizomba B development, offshore Angola, where Roxar subsea Multiphase meters and subsea sensors have been installed for the operator, Exxon. Through the continuous measurement of the amount of oil, condensate, gas and water at the wellheads on the sea bed, Exxon will be able to determine the optimal production capacity of each well (thereby avoiding the risk of overproducing the well), increase flow assurance from the fields and optimise the production process.

In the WDDM example in Egypt, over just a four month period, the Wetgas meters were utilised to avoid several water breakthroughs, identify zones for water production, and optimise gas production within acceptable and controlled water rates. By providing early warnings of the water produced, the meters have helped Burullus and its partners save several wells from water breakthrough leading to a sustainable production strategy moving forward.

For all the benefits of multiphase meters, however, the last few years have seen a raft of new subsea challenges that they have to face. This

includes a wider range of process conditions with more liquid and water present in the flow as well as deeper wells with higher process pressures and temperatures; and the growing remoteness of many subsea fields where costs for subsea interventions and periodic fluid sampling (PVT) are high.

In addition, there has also been an increase in the number of subsea tie-backs with EICDataStream, the global projects database of the UK trade association, the Energy Industries Council noting that there are 27 current and future subsea tie-back projects in Africa. Examples of fields where subsea tie-backs are in place include the Diega & Carmen oil fields in Equatorial Guinea; the Foxtrot, Mahi & Manta gas fields off the Côte D’Ivoire; the Erha North and Erha South fields, offshore Nigeria; and the Kizomba development offshore Angola where Emerson’s Roxar meters are in place.

The risks of longer horizontal production pipelines and tie-backs is that it takes more time to detect a water breakthrough in the well, increasing the need for real-time monitoring to prevent obstacles to flow assurance, such as hydrates and water encroachment.

It is therefore vital that today’s subsea multiphase and wet gas meters come with an extended operating range, added resilience, and generate ever more accurate and sensitive measurements of flow rates and water production profiles.

Emerson’s latest subsea wet gas meter, for example, is being designed to include new microwave electronics to provide even more stable and accurate measurements. The meter will be

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Technology

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The new Roxar downhole flow sensor system generates multiphase flow measurements from downhole in the well and deep in the reservoir.

Downhole reservoir monitoring and hydrate management are also crucial to African subsea operations today. particularly applicable for new gas finds, such as off the East African coast where Anadarko and ENI, for example, are engaging in significant exploration activities offshore Mozambique.

With the new meter, transmission and resonance measurement significantly extend the operating range. The meter also includes a salinity measurement system which can inform the reservoir engineer where formation water is entering the flow as well as also helping the process engineer when adjusting injection rates of scale and corrosion inhibitors.

Other developments in Emerson’s multiphase metering capabilities include a new downhole flow sensor system which will, for the first time, generate multiphase flow measurements from downhole in the well and deep in the reservoir, leading to increased operator understanding of reservoir flow and zonal contributions from wells; and to be launched in early 2013, a subsea version of Emerson’s third generation multiphase meter.

The new meter version will be two thirds of the size and half the weight of the current subsea version without any technology compromises. Such compactness is crucial, with many subsea manifolds offshore Africa already crowded with instrumentation.

pressure and water cut, but also gas fraction, sand rate and flow velocity.

Deployed in production, injection, or observation wells, the Roxar Permanent Downhole Monitoring System (PDMS), for example, continuously transmits accurate pressure, temperature and flow rate data from the reservoir in real time to local or remote well control facilities.

Some of its gauges have been in operation for decades, requiring minimal maintenance.

In addition, Emerson has recently launched a new solution that can generate information from the B annulus within the casing of an oil well – previously a ‘no go’ area. The new tool is expected to have a significant impact on both production and offshore safety, provide early warnings of high pressures, protecting casing integrity, and preventing pressure build-up and, in the worst case scenarios, shallow gas blow outs.

68 Oil Review Africa Issue Two 2012

Transparency & integration It is this integration of instrumentation which is central to the increased need for transparency and better handling of information in Africa’s subsea field operations.

This is being enhanced through a specialised Windows-based field monitoring system which enables E&P operators to observe their fields from remote facilities.

Known as Roxar Fieldwatch, the system incorporates a wide range of Emerson’s reservoir monitoring instrumentation within one single control system framework, covering everything from sand monitors and erosion probes through to downhole pressure and temperature gauges; and the tracking of well test jobs.

The latest version also comes with new erosion-combatting capabilities which enable operators to install virtual erosion sensors within their production system – particularly to monitor bends, T-bends and reducers in areas where it’s difficult to deploy physical sensors. While not as accurate as real sensors, the virtual erosion models can calculate important production information by inputting flow information, pressure and temperature data.

Maximising asset returns Success in maximising asset returns in subsea operations today depends largely on operators’ ability to characterise and understand reservoirs and generate accurate production information to guide decision-making.

How are my wells performing? Are there any conditions that affect my assets and the production flow? How do I keep my assets working for the full life of the field with the same efficiency?

Many of these questions are now being answered. ■

Downhole reservoir monitoring & hydrate management Downhole reservoir monitoring and hydrate management are also crucial to African subsea operations today.

To this end, Emerson’s Roxar intelligent measurement devices and sensors are highly robust and are utilised not only to monitor temperature,

Hydrate build-up, where crystals formed in high pressure and low temperature gas flows can block pipelines and interfere with production, are also a particular risk in deepwater fields today.

The situation can be made even worse, however, if the wrong amount of hydrate inhibitors, such as MEG (Monoethylene Glycol), is injected. We have seen cases, for example, where up to 20 per cent of the pipeline capacity is occupied with MEG, due to overdosing.

In response to this need to establish greater control over the measuring and injection of hydrate inhibitors, Emerson has developed a compact and robust subsea retrievable injection valve solution, which provides operators with precise control over chemical dosage rates.

The injection valve can also be integrated with other measurement solutions, such as the subsea wet gas meter, to increase subsea production performance. In this case, the wet gas meter measures the early onset of formationwater production and then the subsea chemical injection valve ensures that the necessary preventative is action.

The Roxar subsea Multiphase meters have been deployed on fields, such as the Akpo field offshore Nigeria and Kizomba B development offshore Angola.

* By Steve Jennings & Ingar Tyssen, Emerson Process Management..

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Technology

The AX-S subsea well intervention system is one of the most significant and innovative pieces of technology the subsea industry has seen and is specifically designed to directly address some of the unique operation demands of the deepwater subsea environment.*

Meeting the

deepwater challenge I

T IS WIDELY recognised that while subsea well intervention is necessary, traditional methods can make it a time consuming and very costly activity, with drilling and semi submersible rig costs running at up to US$1mn to $1.4mn a day spread rate. There are more than 4,000 oil and gas producing subsea wells worldwide and this number is increasing at a rate of approximately 500 a year. With many such wells over a decade old, intervention is crucial to allow for maximum oil and gas extraction.

The sustained rise of deepwater oil and gas explorations has made the challenge of costeffective well intervention even more pertinent. The challenging conditions experienced at depth, in regions such as West Africa, Brasil, Asia and the Gulf of Mexico, mean many wells have been producing for several years without necessary intervention. This often results in sub-optimum production and ultimate recovery reduction.

It was clear that the oil and gas industry required a step-change in technology and it was at 3,000m (10,000ft) that the AX-S (“access�) challenge started.

A-S meets your intervention needs at any depth.

This solution is designed to close the value recovery gap between subsea and dry-tree fields.

Developed at 3,000m Following a seven-year development programme, involving the technical expertise of a range of partners, international oilfield services company Expro has developed a technology which provides a cost-effective well intervention solution designed to close the value recovery gap between subsea and dry-tree fields by providing a safe, riserless and remotely operated subsea solution which is at least one third the cost of using a rig.

The AX-S subsea well intervention system is one of the most significant and innovative pieces of technology witnessed by the subsea industry. It is a life of field solution to well intervention and is specifically designed to directly address some of the unique operating demands of the deepwater subsea environment.

The system, which is deployed from a monohull vessel, is the world’s first intervention technology that can operate in depths up to 3,000m, which covers every subsea well across the globe. It allows operators to significantly increase production rates and ultimate recovery from subsea wells.

The AX-S system has been designed and built with the input of more than 200 vendors and significantly reduces subsea intervention time. As a comparison, a typical deepwater intervention can take approximately 10 to 12 days using a rig, compared to only six to eight days using AX-S.

70 Oil Review Africa Issue Two 2012

To enable deployment of the system, Expro has entered into a multi-year charter party contract with TS Marine Asia Pacific to use its DP 2 multiservices vessel Havila Phoenix for worldwide operations. The Havila Phoenix is 110m long and 23m wide with a moonpool of 7.2m x 7.2m, a 250 tonne actively-heave compensated subsea crane and 2 x 4000m rated Schilling UHD Workclass Remotely Operated Vehicle (ROV) systems.

Designed for deepwater The AX-S structure is 34m tall and weighs 220t, is deployed onto a subsea tree with an activeheave compensated fibre-rope winch from the vessel, and is remotely controlled from the surface like an ROV. It consists of an integrated set of pressure-contained subsea packages compromising well control package (WCP), tool storage package (TSP), wireline winch package (WWP) and fluid management package (FMP). A hydraulic plug-pulling tool overcomes the risks associated with pulling and setting tree crown plugs, while a novel control umbilical overcomes the challenges of weight and subsequent deployment/handling system size.

The AX-S system has a fully-enclosed pressure housing, with no dynamic seals between the wellbore and surrounding environments.

The WCP is a dual safety barrier containing industry-proven 7 3/8inch shear seal and gate valves.

If any safety issues arise, the operator has time to identify the problem and isolate the wellbore.

Positioned directly above the WCP is the TSP, which contains eight tool pockets, located around the inner circumference of the package. The tools are swapped on the seabed (in minutes rather than hours) and as they are held in a pressure retained housing, no pressure testing is required after each tool change, saving significant operational time.

The tools are run in the well by the WWP. Contained in a pressure housing means issues such as hydrocarbon leaking into the surrounding water and water seeping into the well are all but eliminated. The winch has 7,620m of monoconductor that conveys the various intervention tools into the well.

The final subsea section, the FMP, can deploy glycol fluid into the system to flush out seawater and also hydrocarbons that are then circulated back into the well or more likely back to the host subsea production system. Depending on the specific needs of the customer, seawater can be mixed with the fluid in variable ratios as required, for pressuretesting and flushing.

A control cabin on the vessel has a computer generated interface to control and instruct the various packages on a fully automated basis. The control system comprises of all hydraulic controls subsea meaning that there is no requirement for any hydraulic lines going back to the surface. To ensure operations are safe and effective, video cameras and an ROV are an integral part of the system.

Expro, Deep Tek Ltd and Parkburn have

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Technology

developed a fibre rope umbilical bundle and handling system for deployment of the AX-S system that comprises three individual umbilicals helically wrapped around a main fibre rope, which provides greater strength and operational efficiency than wire rope alternatives. It is buoyant in water and therefore adds no additional weight to the overall deployment system. This also reduces the winch power consumption, surface equipment size and there is no torque in the lifting line that may prove hazardous in the management of vessel-based operations.

The technology also brings benefits in the safety aspect of its design. As the tool swaps are carried out on the seabed, back deck operations are far safer. Also it is only necessary to disconnect the running tool and umbilical from the support vessel to leave location, leaving the system as a fully pressure containing safety barrier on top of the subsea tree.

The system is more cost effective than riser based alternatives because it is supported from a mono-hull vessel, and is faster to operate than wire-throughwater solutions especially on horizontal trees. Studies carried out by Expro indicate that AX-S is the only viable solution that is economically attractive for wireline intervention in deepwater wells and this step-change in philosophy brings significant commercial and operational advantages in shallower water regions as well.

Scott Pattillo, senior AX-S engineer, oversees testing of the AX-S system in Aberdeen.

Subsea and deepwater well intervention is increasingly important as operators look to extend reservoir life and maximise production.

Conclusion

Tried and tested Expro is currently undergoing a comprehensive testing programme, which started in June 2011, to ensure that every element of the AX-S system is working effectively before it is finally commissioned and commercialised in 2012.

The company successfully completed the roll out of a three-phase wet testing process in September. Starting at a depth of 115m in the Buchan Deep, East of Peterhead, Scotland, the active heave compensation tool, winder and umbilicals, deployment and recovery of dummy packages onto the seabed and AX-S running tool thrusters and orientation were tested.

These elements were then successfully tested at 1,206m water depth in Sognefjorden, North east of Bergen, Norway and finally tested in deeper waters of 2,444m North of Shetland in the Norwegian North Sea. The final phase will be to install the AX-S subsea packages and run the final commissioning tests on a subsea wellhead, which is due to be completed by early 2012 prior to heading for its first commercial job.

Expro has now signed a long-term frame agreement with Total E&P UK Ltd, a subsidiary of the Total Group enhancing the company’s strategy and long-term commitment to its life of field vision for subsea developments in any water depth.

This first agreement will allow Expro to work together with its clients to foster Expro’s subsea well intervention capabilities and ensure these meet industry requirements. Discussions are also advancing with various other global and independent operators who all see the vision and value of the AX-S technology.

Subsea and deepwater well intervention is increasingly important as operators look to extend reservoir life and maximise production, however with budgets being constantly scrutinised across the industry, increasing rig costs and declining availability mean intervention is an activity which could come under threat (or typically does not happen on subsea wells).

Expro’s AX-S system delivers a cost-effective answer to this dilemma and helps to promote good practice and maximising AX-S to reserves and value within the industry through the concept of increased intervention.

The emergence of deeper water plays provides a ready and willing market for this technology.

With the number of subsea wells increasing across the world, it has opened up opportunities for emerging and maturing subsea regions, such as Brazil, the Gulf of Mexico, India and West Africa. These are potentially huge areas for not only AX-S, but also Expro’s range of services and it will be working closely with those regions to deliver and meet the needs of customers.

AX-S aims to provide enhanced hydrocarbon recovery by providing wet trees with the same opportunity for intervention and management as is available on dry trees. The system has the potential to transform the economics of subsea well production by providing a safe, cost-effective solution compared to traditional intervention methods. ■

*Matthew Law is technical manager for Expro’s AX-S business.

Damen Shipyards awarded contract to build modular dock for Port of Djibouti A DAMEN MODULAR Dock (DMD) 4020 is being constructed for - and will be delivered to Djibouti. Djibouti’s busy port is one of the most important gateways to the African continent and is strategically located at the confluence of the Red Sea and the Indian Ocean. Besides maintenance of the Port Authorities’ own fleet, the dock will be used for repair and maintenance of port-calling vessels.

The dock, that measures 50 x 20 m, is to be used for repair and maintenance of the Authorities’ fleet, which consists of various supporting vessels such as tugs, shoal busters and pilot vessels. The delivery of the DMD 4020, currently under construction in Dubai, is scheduled for the second half of 2012. After testing in Dubai and delivery of the dock in Djibouti, a Damen Services team will stay on location for two years to give operational and technical support. Damen Services the

Netherlands will support the dock operations by supplying parts, equipment and expertise.

The practical and competitive dock can be built worldwide and can be used in various types of marine circumstances. It can also be outfitted with

cranes, accommodation units, roller blocks, workshop units, sandblast curtains and dock mooring systems. In fact, with an ISO 14001 certification, it lives up to the latest standards in environmental care. The design incorporates such features as low emission motors, LED lighting and dedicated systems for waste management and spills avoidance.

The secret lies in the simplicity of the construction, consisting of two wing walls that are coupled to a number of individual pontoons.

Marcel Karsijns, Manager Special Projects, says: “Every unit measures 10 m. You can enlarge the dock to a length of 100 m whenever you choose. Modules and wing walls are coupled afloat. It’s equally simple to unlock the components. You can upkeep and repair these modules in the dock itself, making the dock selfmaintaining. In addition, the dock contributes to the uptime and success of our customer’s fleet.”

Oil Review Africa Issue Two 2012 71

Technology

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Does pipeline supply of gas at extreme depths have to be limited to high priced, specially made and very thick pipes? Not necessarily. Phil Desmond discusses a new approach to deepwater pipeline supply that adapts some existing technologies and, potentially, cuts costs — without undermining safety standards.

Is the gas pipeline industry

out of its depth?

M

ANY FLOORS ABOVE ground level is possibly not where you would expect to be when discussing technology that is to run along the sea bed. However, if you’ve got a good story, it really doesn’t matter where it’s told. And X-Stream is a very good story, as DNV, a global provider of knowledge for managing risk, made clear in a press conference earlier this year in a high-rise building in central London.

X-Stream is a new pipeline concept researched and developed by DNV. Its aim is to lower the costs of deep-and ultra-deepwater gas pipelines but still meet safety standards.

If it can be done it will probably find the market receptive. Gas fields are going deeper and further offshore and the likeliest alternative gas transport option — FLNG — is not particularly cheap. X-Stream of course would need some upfront investment and testing but DNV presents it as a reasonably priced option, if it can be commercialised.

DNV would not be the company that commercialised X-Stream; that’s for the oil and gas industry itself to do — with DNV’s help if required. However, based on past experience, DNV is not being overly optimistic in promoting this concept. The company has been instrumental in developing and upgrading the safety and integrity regime and standards for offshore pipelines over a number of decades.

Today, more than 65 per cent of the world’s offshore pipelines are designed and installed to DNV’s offshore pipeline standard.

The selling point of the concept is that by controlling the pressure differential between a pipeline’s external and internal pressures at all times, the amount of steel and thickness of the pipe wall can be reduced by as much as 25-30 per cent — and possibly more. That’s an important claim because today’s very thick pipelines can only be produced by a limited number of pipe mills and laid by a limited number of vessels. Reduced thickness means more pipe mills and vessels, which means more competition, more economies of scale and cheaper pipelines. That, at least, is the idea.

Downloads and videos explaining the technical details of the concept can be found at http://www.dnv.com/resources/video/x_stream _gas_transport_concept.asp and http://www.dnv.com/binaries/X_Stream_gas_tr ansport_concept_tcm4-506349.pdf. However, a brief summary goes as follows: during

72 Oil Review Africa Issue Two 2012

DNV has developed a new deepwater pipeline concept.

Its aim is to lower the costs of deep-and ultra-deepwater gas pipelines but still meet safety standards. installation, it is necessary to fully or partially flood the pipeline to control its differential pressure. An inverted High Pressure Protection System — i-HIPPS — and inverted Double Block and Bleed valves — i-DBB — are used to ensure that the system immediately and effectively isolates the deepwater pipe if the pressure starts to fall. In this way, the internal pipeline pressure is maintained above a critical level for any length of time.

A concept study As we have noted, this is a concept study; a basic and detailed design will need to be carried out before the X-Stream concept is realised on a real project. DNV intends to work further with the industry to refine and test the concept.

Experienced players in the pipeline industry will notice that much of this is not new — and that is something DNV freely admits. The company based its concept on improving existing technological systems rather than inventing new ones, as DNV’s global pipeline manager, Asle Venås, explains. “We looked at

several technologies, some new and some based on existing technologies. This one was what we saw as the most promising,” he says.

That, however, begs an important question: if the systems existed already, why was DNV the first to come up with this concept? In fact, says Venås, several authorities have already suggested using continuous internal pressure in pipelines as a concept, “but without giving details on how this can be done. We put several technologies together in a way that makes this safe and reliable.”

The fact that this is not a system requiring a totally new approach is important. After all, technological change is often slow in the oil and gas world. While he does not estimate a specific timeframe from acceptance of the concept to development, testing and launch, Venås does say: “X-Stream is based on already proven technology so I guess it should be relatively easy to qualify and implement.” However, he adds: “Time is dependent on the resources put into development.” In any case, “it is a concept that needs to be studied further”.

But it could clearly meet a need. “We know that the cost of long-distance gas transport in ultra-deep water is a serious challenge,” says Venås. “X-Stream was started after our CEO Henrik Madsen had been told this by the CEO of Petrobras, which faces this challenge on its presalt development. “

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z International showcase for oil exploration, production, refining and petrochemicals z Where service and supply companies meet the oil and gas producers and refiners z On display: drilling and downhole technology, reservoir management and engineering solutions, LNG, pipelines and refinery development z Exhibiting countries include: Canada, Egypt, France, Germany, Italy, Netherlands, Turkey, UAE, UK, USA and Libya z High-level conference programme 23-24 April – to be inaugurated by Libyan Minister of Oil, Abdul-Rahman Ben Yezza z Exhibition running alongside Infrastructure Libya 2012 – the International Exhibition & Conference for Libya’s Rebuilding Programme Sponsored by:

Exhibition opening times: $SULO DQG $SULO

Entry to Oil & Gas Libya 2012 exhibition is free of charge to business and specialist visitors only. All visitors will be registered on arrival.

For further information please go to:

or contact the organisers: DAR ALARAB, 18 Algeria Square, Tripoli Phone: 021 333 9141 Email: exhibitions @alarab.co.uk

Technology

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It will be important to maintain the minimum pressure in the pipeline during pre-commissioning.

Africa will have a lot more gas to deal with soon.

Bear in mind also that even though areas like the Middle East tend to carry out E&P at modest depths, pipeline transport of gas overseas (from Oman to India, say, which has been mooted) will inevitably involve greater depths. Venås explains: “The Middle East has a lot of gas and in principle only one country to export to that is within reach for pipelines — and that is India. However, the Arabian Sea is ultra deep.”

Of course African gas involves depth of production as well as supply. “A large part of the oil and gas field offshore West Africa is in very deep water and the new licences issued are in even deeper water,” says Venås. And there is a clear opportunity to monetise that gas if transport costs can be driven down. “In West Africa most of the associated [offshore] gas is flared because it is too costly to send to shore. The only country in West Africa where it is forbidden to flare the associated gas is Ghana.”

And Africa will have a lot more gas to deal with soon, he suggests “There are also several new oil and gas fields in other areas offshore Africa, such as Mozambique, which has discovered large reserves.”

FLNG, which has been, and will be, regularly covered in these pages, remains costly and will take a long time to develop. If pipeline production costs were to fall as a consequence of adopting X-Stream (or a version of X-Stream designed for commercial use), it might quickly pay back the money spent on development. That, however, depends on a number of factors: the type of projects that use it, the timing of its adoption, and customer demand for example. Pipelines may become cheaper as thickness becomes less of an issue but really big economies of scale may be a bonus that arrives a lot further down the line, And DNV may be among those to benefit, even though from DNV’s point of view this is a research concept rather than a project. The company would, however, hope to gain from the application to the new deepwater pipeline environment of its established profiling, consultative, verification, standardisation and certification business.

Of course without X-Stream the deep sea gas pipeline business is not necessarily doomed. However, as Venås notes, “If the cost goes down more projects will become financially feasible.” And those projects will start at levels unimagined in the past. How deep would Venås suggest? “No limit. By looking at the trend it appears the industry will go deeper and deeper.” ■

TDW Offshore develops largest ever Smartplug isolation tool change-outs. It is currently Type Approved by TDW OFFSHORE SERVICES AS (TDW) announced Det Norske Veritas for a maximum operating that it has successfully designed and built a pressure of 199 Bar. customised 48-inch SmartPlug® pipeline “The tool design is based on our proven 42-inch pressure isolation tool for Nord Stream AG. SmartPlug design,” said Larry Ryan, Director, Weighing approximately 12 tons, it is the largest SmartPlug tool ever produced.

Operations for TDW Offshore Services. “However, Nord Stream retained TDW to assist in the exceptionally large diameter of the pipeline developing contingency solutions for pipelay, meant that Nord Stream required a SmartPlug pressure testing and planned future tool that was 30 per cent larger. The new maintenance of the Nord Stream gas pipelines.

SmartPlug tool is not only exceptionally large, Upon completion, the two 48-inch pipelines but is also capable of isolation at extremely high will extend approximately 1,220 km from pressures,” he added.

Russia through the Baltic Sea to Germany.

The SmartPlug pipeline pressure isolation The new 12-ton 48-inch SmartPlug pipeline pressure isolation tool that TDW Offshore Services customTDW carried out a series of pre-engineering method is designed to provide great value to designed for Nord Stream will facilitate pipeline studies before finalising the design. The owners and operators of pipeline systems. It maintenance activities.

SmartPlug tool was designed, built and makes it possible to safely isolate the area rigorously tested by TDW at its global headquarters in Stavanger. The targeted for work from hydrocarbons without bleeding down the new 48-inch SmartPlug tool will be used to safely isolate pipeline entire work zone, which is costly and time-consuming. It is also very pressure during scheduled pipeline maintenance and potential valve effective in minimising impact on the environment.

New additives remove hydrogen sulphide BAKER HUGHES HAS developed a chemical additives line designed to remove hydrogen sulphide from asphalt or bitumen products. Baker Petrolite SULFIX 9610 and SULFIX 9614 asphalt additives help reduce hazardous levels of hydrogen sulphide that can lead to health, safety and

74 Oil Review Africa Issue Two 2012

environmental issues. Hydrogen sulphide, a toxic, colourless highly flammable gas, is a common component of many petroleum products, including those used in asphalt for construction of roadways.

Baker Petrolite's technology for the treatment of asphalt reduces exposure to hydrogen sulphide

throughout the asphalt supply chain - from the refinery to the paving process.

"Working together with asphalt producers, Baker Hughes can help them stay on track with their health, safety and envronmental programmes, " notes Jerry Basconi, vice president of Baker.

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A NEW BAKER Hughes service identifies potential drilling issues before they occur by pinpointing similar case histories in real-time using a global library of drilling practices and expert advice to provide operators with suggestions on how to respond or take corrective actions while drilling.

Baker Hughes’ WellLink Radar Remote Drilling Advisory Service is an integrated solution that uses case-based reasoning and event detection. It leverages Verdande Technology’s DrillEdge software to reduce uncertainty, minimise nonproductive time (NPT) and increase safety. The service allows for the remote monitoring of multiple wells simultaneously and enhances drilling efficiency. This can reduce HSE risk by limiting personnel on the rig.

Baker Hughes’ remote service engineers monitor real-time drilling operations around the clock while the DrillEdge software looks for patterns based on similar situations where issues have occurred in previously drilled wells. When a similar situation occurs, the software automatically recalls relevant cases from the Baker Hughes’ knowledge base of experience and best drilling practices. The engineers investigate, validate and determine the best course of action. They then make recommendations to avoid potential drilling challenges. New cases can be included in the knowledge base, allowing for the continuous enrichment of the service.

An independent operator successfully deployed the WellLink Radar Remote Drilling Advisory Service in an ultradeepwater well, within a previously

undrilled block of the Gulf of Mexico. The offset wells on a nearby block had experienced pack-offs, stuck pipe, lost circulation and influx of water. While drilling, the WellLink Radar Remote Drilling Advisory Service identified multiple events including packoffs, overpull, maxed-out torque, hard stringers, string stalls and changes in pore-pressure. These events are known symptoms that could lead to drilling problems such as stuck pipe, twist-offs, lost circulation and influx. Based on matches with previous cases, the identification and validation of these potential events enhanced the risk assessment. By preventing these possible drilling problems, the WellLink Radar Remote Drilling Advisory Service potentially saved the operator an estimated US$2mn for each incident avoided.

Modular Dock for Djibouti from Damen A DAMEN MODULAR Dock (DMD) 4020 is being constructed for - and will be delivered to Djibouti. Djibouti’s busy port is one of the most important gateways to the African continent and is strategically located at the confluence of the Red Sea and the Indian Ocean. Besides maintenance of the Port Authorities’ own fleet, the dock will be used for repair and maintenance of port-calling vessels.

The dock, that measures 50 x 20 m, is to be used for repair and maintenance of the Authorities’ fleet, which consists of various supporting vessels such as tugs, shoal busters and pilot vessels. The delivery of the DMD 4020, currently under construction in Dubai, is scheduled for the second half of 2012. After testing in Dubai and delivery of the dock in Djibouti, a Damen Services team will stay on location for two years to give operational and technical support. Damen Services in the Netherlands will support the dock operations by supplying parts, equipment and expertise.

The practical and competitive dock can be built worldwide and can be used in various types of marine circumstances. It can also be outfitted with cranes, accommodation units, roller blocks, workshop units, sandblast curtains and dock mooring systems. In fact, with an ISO 14001 certification, it lives up to the latest standards in environmental care. The design incorporates such features as low emission motors, LED lighting and dedicated systems for waste management and spills avoidance.

The secret lies in the simplicity of the construction, consisting of two wing walls that are coupled to a number of individual pontoons. Marcel Karsijns, Manager Special Projects, says: “Every unit measures 10 m.

You can enlarge the dock to a length of 100 m whenever you choose.

Modules and wing walls are coupled afloat. It’s equally simple to unlock the components. You can upkeep and repair these modules in the dock itself, making the dock self-maintaining. In addition, the dock contributes to the uptime and success of our customer’s fleet.”

Industry’s first hot bolt clamp technology STORK TECHNICAL SERVICES, the leading global provider of knowledge-based asset integrity management services for the chemical, oil & gas and power sectors, has launched an industry-first hot bolt clamp system that enables the safe removal and replacement of corroded bolts on live flanged connections that have eight bolts or less.

The system has been extensively field-tested and was successfully utilised by Stork operatives for a recent project on a Chevron North Sea Limited operated asset in the North Sea. Fraser Coull, operations support director for Stork Technical Services, said: “Corroded and substandard bolts can seriously impact on an asset’s integrity and lead to hydrocarbon releases.

Our innovative hot bolt clamp system provides a safe, efficient and cost-effective method of rectifying this issue which can be delivered outwith a traditional shutdown period.”

The system hydraulically clamps pressurised bolted

pipeline flanges together so that corroded stud bolts can be safely removed without exerting additional force to the gaskets. Once all of the bolts have been replaced, the hot bolt clamps are depressurised and removed. Change out of the bolts is achieved without taking the flanges out of operation, disruption to the standard line pressure or danger of hydrocarbon release.

The hot bolt clamp system removes the potentially time consuming activity from planned or unplanned shutdown programmes; thereby reducing downtime and minimising personnel required on-board when bed space is at a premium.

Most importantly, the clamp system improves the safety for offshore operatives and the asset as a whole by reducing the likelihood of hydrocarbon releases which can have a devastating impact offshore.

Coull continued: “We constantly strive to improve the safety and quality of our service delivery

Stork’s hot bolt clamp system enables the safe removal and replacement of corroded bolts on live flanged connections that have eight bolts or less

through innovation and the hot bolt clamp system is an excellent example of this. The system will deliver significant benefits to our customers and our recent project success with Chevron has led to wider interest from across the industry.”

Oil Review Africa Issue Two 2012 75

Technology

New service to detect and diagnose drilling challenges before they occur

Innovations

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Quickflange launches fixed cost ‘taster kits’ QUICKFLANGE, ONE OF the industry’s leading providers of high performance pipe connection systems, is to launch a series of fixed cost ‘taster kits’ designed to stimulate initial use of its own ‘cold’ pipe connection solution.

The new taster kits, which are being launched in the UK and the Netherlands and which will be priced based on each installed flange, will allow operators to see the benefits of the Quickflange for themselves before making any longer-term commitments. Furthermore, operators will also be safe in the knowledge that there will be no additional costs from open-ended mobilisation or if a particular job is delayed or moved. Such delays can be particularly expensive with additional costs relating to rental equipment and increased personnel requirements.

The Quickflange pipe connection solution provides a fast, convenient, safe and highly cost effective piping solution equivalent in strength to a welded or mechanical connection. As it takes place within a ‘cold-solutions’ environment, the Quickflange solution doesn’t require heat sources in the same way that welding does.

“These taster kits are all about bringing our Quickflange solution to a wider operator audience so they can see for themselves its undoubted benefits of cost effectiveness, flexibility and safety, while being secure in the knowledge that there will be no additional costs or surprises.” said Quickflange CEO, Rune Haddeland. He continued: “For smaller markets and potential customers, this new service will provide a reduction and simplification of commercial risk, highly visible and transparent pricing, and what we believe to be the most cost effective and flexible mechanical pipe connection solution on the market today.”

The taster kit is designed to provide coverage for pipe sizes of up to 8” in diameter and is limited to certain materials, such as carbon and stainless steel,

and CuNi/duplex. The kit consists of a number of common size Quickflanges, which are charged for on a ’use or return’ basis and shipped to the customer, with training on the configuration and use of the tool provided to a small number of personnel.

For many piping managers and engineers, the prominent technology for installing flanges is that of welding. However concerns remain as to the speed, cost and resources required, as well as the safety implications due to the need to access heat sources and, on occasion, the need to shut down production.

The Quickflange solution is a safe, ’cold’ connection solution with the flange machined in such a way that it can slide onto the pipe itself without the use of heat or other potential ignition sources. A hydraulic tool is then used to activate the flange, allowing for a mechanically robust flange-to-pipe connection within minutes.

The fact that the Quickflange is modified from a standard flange and is selfcontained also means that it can be easily shipped and delivered within hours.

With such a simple ‘cold-solution’ connection, existing personnel can also be trained up with no need for increased staffing.

Typical Quickflange applications include pipe work and new spool tie-ins; the replacement of existing flanges; fitting flanges in space restricted areas; replacing damaged or corroded piping; the insertion of valves; and the avoidance of welding in inaccessible areas.

Antech extends wellhead outlet range ANTECH LTD, A leading UK design engineering and manufacturing company serving the upstream oil and gas industries, has significantly expanded its wellhead outlet range. In addition, the entire range is now fully IECEx-certified.

Since 2001, AnTech has been supplying ATEX-certified, single and dual conductor wellhead outlets. The wireline, completions and coiled tubing drilling specialist has recently announced two new options: the triple conductor and the fibre optic line.

The wellhead outlet is used in permanent completions where pressure and temperature must be continuously monitored. It connects the downhole cable to the surface telemetry system, and is attached to the wellhead to provide a safe connection between the cables and seal against downhole pressure. The configuration ensures that the integrity of the wellhead is maintained, even if the downhole cable is flooded.

Having developed a bespoke fibre optic wellhead outlet for a major service company, AnTech is now making a system available to the global market. It is working on numerous enquiries to provide a fibre optic alternative to operators and service companies around the world.

“We always aim to develop products that

76 Oil Review Africa Issue Two 2012

The wellhead outlet has been re-engineered to operate safely in the higher temperatures typically generated by the majority of HPHT (High Pressure, High Temperature) wells.

arise from specific demands from the marketplace, and the fibre optic Wellhead

Outlet is no exception,” said Tim Mitchell, Sales Manager at AnTech. “Well before we created a custom-built system for our customer, we had been receiving enquiries for a fibre optic option. We’re confident that the new system will be embraced by the global market, just as our Wellhead Outlet range has been during the past 10 years,” he added.

With the growth in multi-drop intelligent completions, there has been an increase in the number of conductors required and power requirements downhole. In response AnTech has developed a new triple conductor option to further enhance its range which features both single and dual conductor Wellhead Outlets. With its innovative connector and cablehead, the triple conductor design offers simple and safe connection, while retaining the same configuration as AnTech’s existing outlets.

With the introduction of the fibre optic and triple conductor options, AnTech now offers solutions for nearly every type of wellhead seal and downhole line. With single, dual, triple and fibre optic solutions available, AnTech aims to meet all customer requirements and become the leading provider of ATEX- and IECEx-certified Wellhead Outlets worldwide.

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ICT

VSATs play an important role in many parts of oil and gas E&P, but on rigs they are essential. However, asks Vaughan O’Grady, how much can — and should — you expect to pay to keep in touch offshore?

Are you paying too much for your

satellite service?

E

NSURING EFFECTIVE SATELLITE communications for your oil rig does not come cheap. But how much you actually pay for your VSAT and use of satellite networks depends on a number of factors — for example, which of the available bands you use. In one of Africa’s oil-producing regions, attenuation caused by monsoon-like conditions could be a problem for the Ku band and entirely rule out the higher frequency Ka band — at least for now. You may therefore require a deployment in the C band, further down the spectrum, which has less susceptibility to rain fade.

If that is the case antenna kits may run up to US$100,000 for a fully stabilised maritime antenna (a figure that doesn’t necessarily include installation). Some oil and gas customers may then have to pay monthly usage bills of $40,000 per site.

There is another downside. Antenna diameter is inversely proportional to frequency. So as frequency increases the antenna diameter decreases. Given its portion of the electromagnetic spectrum, this means that C band requires a wide — very wide — antenna. “You’ve got a 2.4 m antenna that has to be pointed continually at a certain part of the sky,” explains Simon Bull, senior consultant with specialised telecommunications consultancy company COMSYS*. This means spending money on stabilising a very big antenna and on protecting it from the elements with an even bigger — up to 3.6 m — radome. Hence the price tag. A similarly performing Ku band system antenna kit costs up to $60,000, and monthly bills are less than a similarly provisioned C band system.

However, C band’s reliability in difficult conditions, as is often the case offshore Angola and Nigeria, can still give it the edge.

No significant price drop soon And that is one reason that services won’t get significantly cheaper too soon. As Martin Jarrold, Chief of International Programme Development, GVF**, points out, VSATs in both the offshore and onshore O&G sector tend to be more expensive due to their ruggedness, which is in turn due to the harsh conditions in which they must operate; offshore platforms, tankers and pipelines, not to mention remote land drilling locations, can be unforgiving places. The good news is that Ku band units are getting sturdier, have longer histories of reliability, and offer more capabilities for single channel per carrier (SCPC) services (dedicated satellite bandwidth services popular in the oil and gas environment). “On the equipment side,” says

78 Oil Review Africa Issue Two 2012

With the push into deepwater, satellite communications will remain a critical piece of oil and gas communications offshore.

VSATs in both the offshore and onshore O&G sector tend to be more expensive due to their ruggedness, which is due to the harsh conditions in which they must operate.

Jarrold, “the movement from 2.4m stabilised maritime VSATs [for C band services] to 1.2m or even 0.6m stabilised maritime VSATs [for Ku band services], rather than specific equipment efficiencies, is driving down costs.”

So C band won’t always have things its own way. Nor, however, will VSATs. Market research and consulting company Northern Sky Research (NSR) suggests a present-day oil and gas market roughly split 70 per cent/30 per cent between VSATs and MSS units (such as Inmarsat’s BGAN and FleetBroadband or Iridium’s OpenPort). As new discoveries occur near or above the Arctic Circle, NSR adds, MSS providers, specifically Iridium, which has the only true global coverage area, will experience an uptake in usage until VSAT providers are able to overcome look-angle limitations in the northern latitudes.

Predicted revenues high Nevertheless NSR projects that oil and gas VSAT

revenues will reach $742mn by the end of 2020.

Most of these VSAT units will be used to enable low data rate applications that are important in pipeline distribution networks. However, with the push into deepwater, satellite communications will remain a critical piece of oil and gas communications offshore. Ku band VSATs will provide the bulk of operator revenues during the forecast period. That admittedly, is in part because of Ku’s large installed base in the onshore segment (servicing pipelines) but Ku is also slowly reaching the global coverage of C band and, as we have seen in this series of articles, it has a growing reliability record on offshore E&P platforms.

As Jarrold has noted, the movement to Ku band and the trend in pricing for that band when compared to C band should eventually benefit VSAT services for oil and gas users. And there’s more good news: NSR projects that newer technologies such as HTS (High Throughput Satellites) that promise a lower cost per bit and at least twice the

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THE 4 TH SAUDI ARABIA INTERNATIONAL OIL & GAS EXHIBITION

24-26 SEPTEMBER 2012 DAMMAM, KINGDOM OF SAUDI ARABIA WWW.SAOGE.ORG

ICT

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throughput of current satellites, will command seven per cent of total revenues by the end of 2020. However, while HTS services promise lower cost per bit they operate in frequencies (often the Ka band) that might cause reliability issues in the offshore oil and gas environment. TDMA technology, popular in less critical satcoms applications, is also slowly grabbing market share and may push costs down, but SCPC links will still be present through to 2020 for customers who demand more secure, dedicated, critical communications.

But whatever efficiencies may be introduced, satcom costs will never come down to the level of conventional communications so it’s no surprise that some oilfield service companies and others visiting offshore might choose to lease such services. In fact NSR research indicates that this is becoming more and more common. Jarrold explains: “As the life cycle of products is becoming shorter and technological advances expected with HTS Ka band satellite grow near, more satellite service providers are offering leasing services to oil and gas clients as an upgrade path to more advanced equipment and services.” This isn’t the whole story, however. Jarrold points out: “Due to much more rugged and solid equipment, for the maritime segments (offshore, service vessels and tankers) replacement cycles of antennas are extending the lifecycle of VSATs from five to seven and sometimes ten years. This requires a careful ROI analysis from O&G end-users,” he adds.

Whatever the costs, oil companies can expect their satellite communications usage to grow — and not just for the obvious reason that so much now happens offshore. As Bull points out, the experts who can assess well logs, drilling conditions, seismic surveys and other technical geological questions that are now part of the growing mountain of important data available to oil companies, are hardly likely to do their assessment from a rig. “Those guys are getting fewer and older,” he points out, “and they don't want to go to a rig offshore Angola. They want to sit at their desk in Houston or Aberdeen and study the data. So this stuff has to be brought back”. That, and the sheer volume of data that can now be retrieved and assessed also means many more gigabytes of data consumed on a monthly basis. On the positive side, the money spent on bandwidth could be partly offset by savings on transport, support and staffing costs.

Obviously the satellite market is never going to challenge cellular and fibre. “The entire satellite business is big: billions and billons of dollars,” says Bull. “But put it in the context of the whole telecoms market, the whole IP market, and it’s nothing.” And, as we learned in part one, the satellite trunking market in Africa was all but obliterated by undersea cable. But the satellite business will survive — and not just because the oil and gas industry will always need it. As Bull says, there are two truths that always need to be remembered. “One: as much satellite capacity as you can ever build you will always be able to sell.

Roxar launches reservoir modelling solution EMERSON PROCESS MANAGEMENT has released Roxar RMS 2012, the latest version of its reservoir modelling software. The launch sees the continued expansion of Roxar RMS into the geophysics domain through a completely integrated reservoir modelling workflow which includes seismic interpretation, reservoir simulation, reservoir behaviour predictions, and uncertainty management.

“With average global oil & gas recovery rates at just 22 per cent, the smallest percentage improvements can have a huge impact on both future oil & gas production and the bottom line”, said Kjetil Fagervik, managing director of Emerson’s Roxar Software Solutions.

“Accurate predictive reservoir models that can realistically represent the underlying seismic data and that can offer a seamless route from seismic to simulation are absolutely central to efforts to improve oil & gas recovery today. These are the underlying goals behind Roxar RMS 2012.”

The key new features of RMS 2012 include seismic inversion, seismic attributes, and field planning.

6 RMS Seismic Inversion allows geoscientists to use seismic data to create a rock property model quickly and accurately through increased automation.

6 RMS Seismic Attributes is a powerful new visualisation toolkit which enables modellers to extract maximum value from their seismic data.

6 The RMS Field Planning functionality enables modellers to quickly and accurately create multiple, optimal well plans for their fields.

80 Oil Review Africa Issue Two 2012

Two: you never know where you're going to sell it.

There’s never going to be a situation where we've got tons of capacity and we can’t sell it. Whether it goes on aircraft, trains, boats, rigs, land-based drilling rigs or RVs, it will get sold.”

So how much are West Africa’s oil rig owners likely to have to pay to guarantee communications?

Well they’ll certainly want to negotiate on bandwidth and availability but, as Bull points out: “When you come down to it, rental of a rig is a million dollars a day. So when you're spending $10,000 or $50,000 or $100,000 a month on mission-critical application it's inconsequential in the scheme of things, frankly.” ■

Notes *COMSYS is a specialised telecommunications consultancy company with a core expertise in satellite and VSAT systems. www.COMSYS.co.uk **The Global VSAT Forum (GVF) is an association of key companies involved in the business of delivering advanced digital fixed satellite systems and services to consumers, and commercial and government enterprises worldwide. GVF acknowledges the contribution of Northern Sky Research, the GVF Oil & Gas Communications Conference Series Content Partner, in the responses supplied for this article. The 16th conference in the series is planned for Luanda, Angola, in Q4 2012.

See www.gvf.org for more information.

PVI Lite - newest member of PipeView integrity software PII PIPELINE SOLUTIONS has introduced its PVI Lite software, the company’s newest addition to its family of PipeView™ Integrity software, a fully integrated software environment that enables pipeline operators to easily control and use data, perform advanced risk assessment and establish integrity management plans for their networks.

When dealing with inline inspection (ILI) data, operators face several key issues to keep track of the volume of data generated, accurately compare one run to another and leverage ILI data to determine a pipeline’s fitness for service. Currently, operators typically use spreadsheet-based solutions, which are time consuming and prone to error, to perform these tasks.

The PVI Lite software provides the opportunity for real productivity gains for integrity teams by allowing operators to conduct consistent and accurate ILI integrity evaluations—including fitness for purpose assessments—using formulas based on proven industry best practices. This product is a “plugand-play” solution that works directly from ILI files, with no data conversion, commissioning or implementation required.

Additionally, operators can use the PVI Lite software as a tool to catalogue and organise ILI and other data associated with a pipeline network.

Operators also can use the software to assess the significance of ILI-reported features on the immediate and future integrity of the pipeline. The PVI Lite software can be used with data from a variety of vendors, including PII. Most importantly, the tools found in the software are the same as those used by PII’s internal integrity engineers.

The new software has already been adopted by operators in North America, Europe and Australia, particularly by those customers that need to conduct in-house integrity evaluations but do not want to invest in a GISbased solution. The new product was developed to fill a gap in the market between software provided with ILI reports and comprehensive data management systems.

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We are delighted to announce to our numerous Clients and the industry at large that Tolmann Allied Services Company Limited has achieved ATLAS approval as an invigilation centre for OPITO International Minimum Industry Safety Training (IMIST). IMIST is an OPITO standard which supports the global oil & gas industry to meet safety initiative targets. Tolmann has always been in the fore front of delivery of internationally accredited safety training.

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Information Technology

S14 ORA 2 2012 IT_Layout 1 12/04/2012 17:36 Page 82

Rockwell Automation extends PlantPAx process automation system ROCKWELL AUTOMATION HAS extended the reach of its PlantPAx process automation system to integrate critical rotating assets, such as compressors, pumps, turbines and fans, giving users the ability to manage plant-wide operations with a single platform. The PlantPAx system combines the company’s core process automation capabilities and technologies with those of partners and acquisitions to deliver an integrated control and information solution to customers.

Users can now tie intelligent motor devices into this unified-control architecture, making an immediate and measurable impact on asset availability, operational efficiency and energy management. The tight integration between process automation and motor control is especially beneficial in heavy industrial applications with considerable mechanical investments, such as mining, power, oil and gas, water/wastewater, and pulp and paper applications.

PlantPAx system users will have access to diagnostic information on any device in the system from any location – including motor control centres, drives, compressors, pumps, fans and instrumentation. Leveraging the

EtherNet/IP network, engineers can monitor process conditions such as electric motor current, vibration signatures of key rotating assets and torque signatures of variable speed drives. This allows plant engineers to predict potential problems and help avoid equipment downtime – resulting in improved productivity and reduced maintenance costs.

Leveraging a single-network architecture to bring operational information from motor control devices into the control system also helps engineers extend the life of their mechanical assets and improve their overall configuration, operation and maintenance experience.

Unlike other distributed control systems that require users to manually map data from motor control devices to the control system, the PlantPAx system mirrors the device memory, making data automatically available within the control system. Users can also setup applications in the PlantPAx system to collect and archive performance data from motor control devices into databases for analysis.

This convenient data acquisition provides cost savings throughout the lifecycle of the

Subscription Form 2012

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equipment. Furthermore, since EtherNet/IP is the delivery mechanism for the PlantPAx system, users can avoid electrical hazards by accessing information remotely, helping personnel safely monitor, troubleshoot and diagnose motor control centres and other equipment. In addition to integrating motor control devices into the control system, other key features with the PlantPAx system include: 6 EtherNet/IP network support for redundant systems and Device Level Ring (DLR) network topology that provides a highly available EtherNet/IP network without any additional infrastructure costs.

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