Oil Review Africa 1 2013

ORA 1 2013 Cover NEW_cover.qxd 04/02/2013 14:37 Page 1

■ Geology - p34 ■ Gas - p36 ■ E&P - p38 ■ Technology - p50

Volume 8 Issue One 2013

www.oilreviewafrica.com

Africa

Covering Oil, Gas and Hydrocarbon Processing

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

2013 outlook for Nigeria China hot for Africa’s oil Offshore companies vigilant to Africa oil spill threat Offshore survival course for O&G Subsea technology: an industry perspective Simplified pre-laid mooring solutions The deepwater drive that favours FPS Utilising lubricants to reduce downtime

Dr Bada, Managing Director of Shoreline Natural Resources.

See page 26.

Ghana’s ‘new path’ for handling oil revenue

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

S01 ORA 1 2013 Start_Layout 1 04/02/2013 11:16 Page 2

S01 ORA 1 2013 Start_Layout 1 04/02/2013 11:17 Page 3

■ Geology - p34 ■ Gas - p36 ■ E&P - p38 ■ Technology - p50

Contents

Volume 8 Issue One 2013

www.oilreviewafrica.com

Africa

Covering Oil, Gas and Hydrocarbon Processing

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

2013 outlook for Nigeria China hot for Africa’s oil Offshore companies vigilant to Africa oil spill threat

Columns

Offshore survival course for O&G

Industry news and executives’ calendar

Subsea technology: an industry perspective

4

Simplified pre-laid mooring solutions The deepwater drive that favours FPS

Analysis

Utilising lubricants to reduce downtime

BP’s confidence extends two decades more

10

The oil and gas major has launched the third in its new series of annual Energy Outlook 2030 reports. Developments in Africa are central to the continued completion and innovation it calls for.

Promoting policies that will stimulate growth

Dr Bada, Managing Director of Shoreline Natural Resources.

See page 26.

14

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

The FPSO Kwame Nkrumah MV21 in the Jubilee Field, is being tested to its full capacity.

Oil Review interviews Dr Duncan Carke, Chairman & CEO; Global Pacific & Partners.

Country Focus Nigeria

18

Chinese companies have blazed a trail in Africa in recent years.

Troubling 2013 outlook for Nigeria.

Interview with Dr Bada, Managing Director of Shoreline Natural Resources.

Ghana

30

Ghana’s ‘new path’ for handling oil revenue.

E&P News and developments

38

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

Safety & Security Offshore survival course gains popularity in O&G sector

48

ATA International looks at safety in the oil and gas environment, offshore safety training, why this is so important and what training is needed.

Technical Focus Oil spills

50

Only the reality of a spill can test a response strategy, though Africa, in conjunction with the multinational operators that work there, has taken steps to prepare for such an eventuality.

Subsea technology

Ghana’s ‘new path’ for handling oil revenue

Editor’s note IN THE OIL sector, China’s growing presence in Africa has led to greater competition in an area long dominated by US and European companies, Africa’s traditional business partners. In fact China has blazed a trail in recent years, snapping up natural resources projects to supply a growing economy back home.

Africa is becoming a major player in the world’s oil and gas play, with some recent world-class oil and gas discoveries in East Africa; however the more established West African countries are still substantial. Although Nigeria’s offshore oil production growth has virtually stood still, the implementation of the Nigerian Content Act has created 30,000 jobs in 30 months. The country has also set aside a sum of US$400mn in its 2013 budget for the construction of the Calabar-Ajaokota-Kano pipeline in order to speed up the completion of the Trans-Saharan Gas Pipeline Project (TSGP).

Despite output problems, the outlook for Ghana’s nascent status as an oil producer is bright, with further development at the Jubilee field and anticipated first oil from the TEN project, with a forecast for output to grow at an average rate of 60 per cent during the period to 2021. New president John Dremadi Mahama has pledged to use the revenues from the oil industry to drive Ghana’s development, all of which bodes well for its future.

52

Remotely-designed cathodic protection solution restores hull integrity.

An industry perspective (Technip) on subsea technology.

Simplified pre-laid mooring solutions.

The deepwater drive that favours FPS.

Well integrity

64

Gaining a green light on well integrity.

Lubricants

70

The importance of lubricants in the oil and gas sector should not be underestimated, particularly as they reduce valuable downtime.

Risk assessment

74

Ensuring the integrity of offshore facilities through risk-based inspection.

Innovations

76

Introducing some of the latest technology for the oil and gas sector.

56 going “deeper” and “longer”, subsea transport solutions are important.

Managing Editor: Zsa Tebbit - Zsa.Tebbit@alaincharles.com Editorial and Design team: Bob Adams, David Clancy, Andrew Croft, Prashanth AP, Ranganath GS, Kasturi Gupta, Meenakshi Nambiar, Genaro Santos, Nicky Valsamakis, Julian Walker and Ben Watts

Africa

Covering Oil, Gas and Hydrocarbon Processing

Publisher: Nick Fordham

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Serving the world of business

Oil Review Africa Issue One 2013 3

Industry News & Events

S01 ORA 1 2013 Start_Layout 1 04/02/2013 11:17 Page 4

Executives’ Calendar 2013 FEBRUARY 13-14 18-21

FLNG Nigeria Oil & Gas

LONDON ABUJA

www.smi-london.co.uk www.cwcnog.com

14th Southern Africa Oil, Gas & Energy Briefing Subsea Tieback Forum & Exhibition EAPCE '13 Angola Recruitment Summit Mozambique Gas Summit Global Oil & Gas HR Summit Oil & Gas North Africa Offshore West Africa ARA Week 2013 Oil and Gas Telecommunications 5th African Petroleum Conference and Exhibition

JOHANNESBURG SAN ANTONIO ARUSHA LISBON MAPUTO London ROME ACCRA MARRAKECH LONDON LIBREVILLE

www.petro21.com www.subseatiebackforum.com www.eac.int/eapce www.eliteic.net www.mozambique-gas-summit.com www.oilgashrsummit.com www.thecwcgroup.com www.offshorewestafrica.com www.ifrra.org www.smi-london.co.uk www.cape-africa.com

LIMEP - 2nd Liberian Mining, Energy & Petroleum Conference & Exhibition Ocean Business SPE NATC 2013 LNG 17 19th Western Africa Oil, Gas & Energy Week Ghana Summit Oil & Gas Libya Conference & Exhibition 2nd East Africa Oil & Gas Expo 2013

MONROVIA SOUTHAMPTON CAIRO HOUSTON WINDHOEK ACCRA TRIPOLI NAIROBI

www.infomine.com www.oceanbusiness.com www.spe.org/events/natc/2013 www.lng17.org www.petro21.com www.cwcghana.com www.oilandgaslibya.com www.expogr.com/kenyaoil

MARCH 5 5-7 6-8 8-10 12-14 13-14 18-20 19-21 19-23 20-21 26-28

APRIL 9-11 9-11 15-17 16-19 22-24 23-26 22-25 29-2 May

MAY 6-9 14-16 14-16 21-23 28-30

JUNE 4-6 11-12 13-14 18-20

OTC Petro.t.ex Africa 2013 SA Industry & Technology AIOGACE UMEC - Ist Uganda, Mining, Energy & Oil & Gas Conference & Exhibition

HOUSTON JOHANNESBURG JOHANNESBURG LUANDA

www.otcnet.org www.exhibitionsafrica.com www.exhibitionsafrica.com www.aiogace.com

KAMPALA

www.umec-uganda.com

Nigeria Oil & Gas Technology Lagos Power Mozambique Recruitment Summit Platts Crude Oil Summit 4th Eastern Africa Oil, Gas & Energy Conference 2013

LAGOS LAGOS MAPUTO LONDON NAIROBI

www.cwcnogtech.com www.lagos-power.com www.eliteic.net www.platts.com www.petro21.com

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

GNPC to host Offshore West Africa 2013 THE GHANA NATIONAL Petroleum Corporation (GNPC) has officially confirmed its support for the upcoming Offshore West Africa 2013 Conference & Exhibition. It has agreed to host the event, which is scheduled to take place at the International Conference Centre, Accra, Ghana from 1921 March.

Under the patronage of the Ministry of Energy, Republic of Ghana, and Endorsed by the Petroleum Commission Ghana, the 17th annual Offshore West Africa will once again address key technology and development issues for the West African offshore oil and gas market, through a comprehensive educational programme and three day

4 Oil Review Africa Issue One 2013

exhibition, under the theme – Deepwater Discoveries, Emerging Opportunities.

Sponsored by Tullow Oil, Schlumberger, ABS, Shell, Modec, NNPC, 2H Offshore, Hewlett Packard, Lloyd’s Register, Aker Solutions, Petroleum Technology Development Fund and Lufkin, as well as being supported by the Society for Underwater Technology, SPE Ghana, African University for Science & Technology, Ghana Oil Club, Lagos Oil Club and the Angola-US Chamber of Commerce, Offshore West Africa 2013 is on track to be one of the most successful in its 17-year history.

The Offshore West Africa 2013 conference provides a unique networking opportunity

for attendees to share technology and address issues with experts in their respective fields. The 2013 conference programme includes two parallel tracks packed with new technologies, case studies, original concepts and other exclusive local content.

Offshore West Africa 2013 will begin with the Opening Plenary. Technical topics at Offshore West Africa 2013 include Well Construction & Drilling Operations, Field Development, Flowlines & Pipelines, Riser Technology, Floating Production Systems, Production Optimisation, Geology & Geophysics, Subsea Technology, Safety & Environmental Concerns and Local Content.

S02 ORA 1 2013 News_Layout 1 04/02/2013 11:20 Page 5

Industry News & Events

S02 ORA 1 2013 News_Layout 1 04/02/2013 11:20 Page 6

Kenya, Mauritania, Gabon rated top for oil and gas potential

DNV and GL to merge

KENYA HAS BEEN ranked among the top three African countries where huge oil and gas deposits are likely to be discovered this year, giving hope to explorers who have heightened drilling in the country.

Paris-based lender BNP Paribas Bank rated Kenya, Mauritania and Gabon as the most promising exploration hotspots.

Bankers and mining analysts project that over US$300mn will be spent in Kenya on exploration activities this year by prospecting firms, especially after last year’s discoveries of crude oil onshore by Tullow Oil Plc and Apache Corporation natural gas offshore find.

“Recent exploration efforts have only scratched at the surface of these areas and we feel that their full potential remains underappreciated,” said the bank in a research note to investors.

The country expects drilling of eight more wells later in the year as BG Group, Afren Plc, Ophir Energy, Africa Oil Corporation and Vanoil Energy among other firms intensify their search for hydrocarbons in what oil and gas experts said could greatly transform global energy flows.

Analysts, led by Australian consulting firm Hartleys, project that drilling activity will increase in offshore Kenya with up to 10 wells expected this year.

Tullow Oil, a London Stock Exchange listed firm, plans to drill at least seven of the 10 wells in Kenya.

Aidan Heavey, Tullow Oil’s chief executive officer, said the firm expects to maintain its exploration-led growth strategy in countries where it operates especially after establishing Kenya as a new hydrocarbon province.

AN AGREEMENT HAS been signed to merge DNV and GL. The new entity will be called DNV GL Group. It will be one of the world's leading ship classification societies and risk experts in the oil and gas, renewable energy and power sectors, and among the global top three in management system certification.

"The merger rests on a strong strategic rationale, and responds to the challenges of increased globalisation, rapid technological change and the need for sustainable development. Our customers will benefit from an increased service offering and global competence base as well as one of the densest networks," said DNV's Group CEO, Henrik O. Madsen, who will be the CEO of the combined new company. "The merger with DNV supports our long-term goal of being recognised as one of the most respected technical assurance and advisory companies in the world", added GL Group's CEO, Erik van der Noordaa.

By combining the two international organisations, the new company will be one of the world's leading independent technical service providers with state-of-the-art technological expertise and strong capabilities for innovation.

With more than 17,000 employees and an extensive global network of offices, DNV GL Group is positioned to meet increased international competition and even better serve the needs of the customers.

The DNV Foundation will hold 63.5 per cent, while GL's owner Mayfair SE will hold 36.5 per cent of the shares. The new company, with a combined turnover of some US$3.4bn, will be headquartered and registered in Norway.

DNV GL Group will strengthen its foothold in several areas of expertise, including the maritime segment and across the entire oil & gas value chains.

The Group will also be one of the global leaders in pipeline verification and asset integrity services as well as in renewable energy certification and advisory services. Moreover, it will be a strong player within power transmission and distribution as well as testing and certification services.

GE Oil & Gas /JLS joint venture in Angola

Aggreko expands southern Africa network

GE OIL & GAS and the Angolan group GLS Holding have announced the formation of a new joint venture, GE-GLS Oil & Gas Angola Limited, to better support Angola’s rapidly growing oil and gas sector.

As part of the agreement, which received the approval of Angola’s National Agency for Private Investment (ANIP), the companies are planning a proposed initial investment of US$175mn to build a new manufacturing facility in Soyo, in the province of Zaire, that will supply subsea equipment to the oil and gas industry in Angola.

Dr. Eugenio Neto, president and CEO of GLS Holding, S.A. and vice president of the new JV, said: "GE-GLS Oil & Gas Angola Limited intends to support the development of Angola, bringing new manufacturing and industrial technologies to the country and creating hundreds of jobs directly and indirectly. The investment represents an important contribution to the country’s "Made in Angola" initiative and, consequently, for the continued growth of Angola’s oil and gas industry. It will be a great asset to Angola’s petroleum sector and the country and its first priority will be to meet domestic demand in Angola.”

The new manufacturing facility will start operating in two years.

Due largely to its offshore energy resources, Angola is undergoing rapid transformation and economic growth. The country has experienced increased exploration and development activity from the oil and gas industry over the last decade and is now one of the largest producers of crude oil in Africa.

GE has been active in Angola since the late 1950s, giving its support to the development of the national oil industry. Earlier in 2012, GE Oil & Gas also signed an agreement with Angola LNG, operator of one of the world’s most modern LNG and processing facilities, for processing liquefied natural gas (LNG). GE also is a major supplier of gas turbines and compressors for the Angolan offshore energy sector.

AGGREKO, THE WORLD leader in the provision of temporary power and temperature control services, has opened its new service centre in Walvis Bay. The new facility was formally inaugurated by Honorable Willem Isaak, Deputy Minister of Mines of Namibia and Martin Foster, Head of Local Business, Aggreko Southern and East Africa. Cleophas Mutjavikua, the governor of the Erongo region, was also in attendance.

The facility is the sixth service centre in Aggreko’s Southern and East African network and is the first operation to be based in Namibia.

The new depot will service the country’s rapidly growing mining industry and other industrial users throughout the country. Located next to the Port of Walvis Bay, the facility is strategically positioned to support Namibia’s shipping and fishing industries.

Aggreko provides turnkey temporary power and temperature control solutions to customers across a range of industries. Temporary power packages help companies deal with power outages and load shedding, guaranteeing their supplies and reducing the risk of business disruption when blackouts occur. Aggreko's temperature control expertise helps industrial, mining, food and beverage and major events companies to cope with peak seasonal demands and provides emergency capacity when vital cooling infrastructure breaks down.

Commenting on the new depot opening, James Shepherd, Aggreko’s Managing Director for Southern and East Africa, said: “Aggreko’s expansion into Namibia is a major step in our strategy to build local presence in the key industrial hubs of Southern and East Africa. As the region continues its strong growth, Aggreko is well placed to support this growth through the provision of the world leading temporary power and temperature control services.”

“Namibia is a key strategic market for Aggreko,” commented Martin Foster, Head of Local Business, Southern and East Africa. “Aggreko is highly committed to the development of the communities we operate in. We take very seriously the progression of our local Aggreko people and will hire and train a strong local workforce to support the new facility. The long-term success of our business is directly linked to a highly capable and well trained Namibian workforce.”

6 Oil Review Africa Issue One 2013

S02 ORA 1 2013 News_Layout 1 04/02/2013 11:20 Page 7

...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)

Industry News & Events

S02 ORA 1 2013 News_Layout 1 04/02/2013 11:20 Page 8

FMC Technologies receives equipment order from CNR International FMC TECHNOLOGIES HAS received an order from CNR International Ltd for subsea equipment for the Baobab field.

The Baobab field is located in Block CI40 West Africa approximately 25 km offshore from the Côte d’Ivoire.

FMC Technologies' scope of supply includes six subsea trees, eight wellheads, three manifolds, and a Subsea Control System including subsea distribution systems and associated topside control systems.

The equipment is scheduled for delivery in 2014.

"FMC Technologies is pleased to support CNR International in its ongoing development of the Baobab field," said Tore Halvorsen, FMC Technologies' Senior Vice President, Subsea Technologies. "This subsea production system provides CNR International with the subsea technologies needed to enable further development of the field."

CNR International is the operator in the CI-40 block and is partnered with Svenska Petroleum and Petroci, the Ivorian National Oil Company.

Welltec tools to speed up intervention TOTAL ANGOLA HAS contracted Welltec to supply downhole conveyance and intervention technologies and services.

These are designed to reduce mobilisation time for intervention operations compared to conventional methods applying coiled tubing or jointed pipe. Other benefits, according to Welltec, include a reduction in the number of offshore lifting operations, personnel, and footprint.

The contract is for three years, with two optional one-year extensions.

Plexus wins Cameroon contract with Glencore PLEXUS HOLDINGS PLC, the AIM-quoted oil and gas engineering services business and owner of the proprietary POS-GRIP friction-grip method of wellhead engineering, has agreed to supply its high pressure/high temperature ('HP/HT') POS-GRIP wellhead equipment, subject to finalisation of the contract, to Glencore Exploration Cameroon Ltd, the leading integrated commodities producer and marketer, for drilling a gas exploration well offshore Cameroon.

The contract will have an estimated initial value of circa US$1.1mn.

The order is initially for one well with an option to increase this to three.

This is the first contract Plexus will enter into with Glencore, and it is anticipated that revenues will commence in March 2013. The exploration drilling programme will utilise Plexus' POS-GRIP HP/HT 18-3/4" 15,000 psi wellhead equipment, and this contract further strengthens the company's growing presence in West Africa, and Cameroon in particular.

Chinese to build Nigerian refinery CHINESE FIRM SINO Arab Energy (SAE) and Nigerian company Osabo Refining and Petrochemical Industry Ltd have concluded plans to build a refinery at Akabuy.

Agreement for the construction of the US$7.5bn refinery, which is expected to produce 107,000bpd, has already been signed by the partnering firms.

Member of the management team of Osabo Refining, Etim Effiong Okon, said, “The process for the procurement of requisite licenses to establish and operate the refinery had fully commenced. The community where the refinery will be located has donated 500ha of land for the refinery.”

Okon added that the project partners will engage in the acquisition, exploration and development of oil blocks in the future, to complement refining operations.

He further revealed that the partners will also engage in the development of independent power plant and production of natural gas and oil.

According to Okon, the refinery will be expected to begin production within five years and would generate more than 10,000 jobs.

“The refinery would be built with specifications that meet international standards.

Its product base will include kerosene, jet fuel, diesel, gasoline, automotive gas oil, low pour fuel oil, high pour fuel oil, boat fuel, motor oil, lubricants, liquefied petroleum gas, LPG,” he noted.

Ghana Gas to start commercial production THE GHANA GAS Company is now looking to start commercial production from the gas processing plant in July which would be after completing the installation of the plant by the end of June.

The company last year announced that the plant would be ready for production by December 2012. But officials of the company attribute their inability to meet the target to government’s inability to meet some financial obligations on time. This also affected the supply of equipment being manufactured for the plant.

Dr. George Sipa Yankey, Chief Executive of the Ghana Gas Company, explained: “We were supposed to make down payment 20 days after the date that we signed the agreement, unfortunately for us, the Ministry of Finance delayed in the payment of our contribution of the down payment.

The US$700mn gas infrastructure project will process gas from the Jubilee Field for power generation. The facility is expected to process about 150mn standard cubic of gas a day.

Africa records $11.7bn in global oil deals AFRICA RECORDED US$11.7bn worth of oil transactions during the year 2012, up from US$7.7bn reported in 2011, according to Ernst & Young’s (E&Y) global oil and gas deal review published January 24, 2013.

Africa’s oil transaction volume increased from 93 in 2011 to 97 in 2012, the review indicated, describing the rise as “moderate”.

According to the E&Y, Sinopec’s US$2.5bn acquisition of Total’s 20 per cent interest in Nigerian deepwater block OML 138, gave a significant boost to the average deal value. The Sinopec deal was said to be the largest oil and gas transaction in Africa during 2012.

For the 2013 outlook on oil and gas in Africa, the financial firm says it expects a “greater deal flow and consistency with the 2012 regional trends”.

On the global front, oil and gas transactions recorded a staggering US$402bn in 2012, representing a 19 per cent increase compared to 2011’s

8 Oil Review Africa Issue One 2013

US$337bn, the review showed. Ninety-two transactions exceeded US$1bn in value compared to just 71 in 2011, it noted, despite a marginal decrease in oil and gas transaction volumes from 1,664 deals in 2011 to 1,616 in 2012.

E&Y’s review indicated that upstream remained the most active segment with $284 billion worth of transactions accounting for 71% of total deal values while the downstream segment were flat at $42 billion, with volumes also fairly stagnant at 162 transactions (6% lower than 2011).

Andy Brogan, E &Y’s Global Leader, Oil & Gas Transaction Advisory Services said “2012 saw a continuation of trends we have seen for the last few years supported by a relatively benign oil price environment.”

Brogan attributed the increase in the number of larger deals to the “function of more capital becoming available to the right class of buyer together with increased pressure from asset and company owners to crystallise returns”.

S03 ORA 1 2013 Analysis_Layout 1 04/02/2013 11:26 Page 9

S03 ORA 1 2013 Analysis_Layout 1 04/02/2013 11:27 Page 10

Analysis

On 16 January the oil and gas major launched the third in its new series of annual Energy Outlook 2030 reports. Developments in Africa are central to the continued competition and innovation it calls for.

BP’s confidence extends

two decades more F

OR THREE SUCCESSIVE years BP has been issuing an invaluable set of allforms long-term energy market forecasts each January. This complements the long-running (June each year) BP Statistical Review of World Energy.

The new Outlooks are designed to contribute to the wider global debate on global energy issues, addressing such questions as: What will the world’s fuel mix look like in 2030?; Where is the growth going to come from?; and What are the implications of the US shale revolution (and of course, Can it be replicated elsewhere?).

A combination of harnessing the power of competition, advancing technologies including engines and the fuel they burn through innovation, and opening up more resources should see us through said Group Chief Executive Bob Dudley in introducing this year’s study.

In their previous Outlook (issued January 2012) the BP forecasting team concluded that energy can be both available and affordable by a combination of competition, innovation and regulation. However security of supplies will remain an issue, they said, and CO2 emissions were not on track. Much the same conclusions have been reached this year.

Specifically they pointed out in 2012 that “energy efficiency” (how much fuel is used to produce a unit of GDP) has been increasing steadily since the 1970s, and the speed of this will accelerate through 2030. But global/individual consumption is increasing too.

It is the developing (“non-OECD”, a broad group) countries that are now driving energy demand as the fuel mix shifts away from heavily polluting oil and coal. By 2030 nearly two-thirds of global consumption will be taking place there, compared with little more than one-half in 2010.

Natural gas alone will fuel nearly one-third of the projected increase in world usage, and it is the electricity generators that will be responsible for the largest single share of this, even though renewables will continue to grow briskly.

The market share of oil will decline steadily, they said, particularly in the industrialised countries where consumption peaked back in 2005.

Nevertheless the Chinese, Indian and Middle Eastern markets for this easily traded liquid fuel will continue to grow strongly (the 2012 Outlook had a special focus on the impact of the first two of these). Increased demand from the transport sector will be a major factor behind this clear trend, they said last year, and the key place for OPEC supplies seemed secure.

10 Oil Review Africa Issue One 2013

However they warned that demand for middle distillates will grow strongest, which means older refineries could have difficulty adjusting their output, so that local bottlenecks will arise.

They also predicted that the market share of LNG – now a major African export, both Northern and sub-Saharan in origin – will continue to rise faster than most, with unconventional gas supplies playing an increasing role, too.

The results of all this for Africa looked pretty good back at the beginning of 2012. Asia would be where the demand for both crude oil and liquefied gas would be rising fastest, and both sub-regions of this continent remain major and rising suppliers of these highly-prized (and apparently index-linked) commodities. The price of oil in particular has continued to rise.

And on the emissions front all regions of Africa are winners too. First, because the cause of these is merely a negligible issue here, where so little fuel of any sort is sold commercially anyway (although the results are certainly not insignificant). And second, because Africa is the existing and coming source of some of the cleanest fuels on the planet, specifically LNG (now) and solar power one day, if the huge Desertec power-exporting scheme ever gets up and running in the North.

They also predicted that the market share of LNG – now a major African export, both Northern and sub-Saharan in origin – will continue to rise faster than most.

It is the developing countries that are now driving energy demand as the fuel mix shifts away from heavily polluting oil and coal.

A few new changes In this year’s Outlook a few changes are listed and gone into in detail, but the general theme of confidence in the security and sustainability of supplies - as long as energy efficiency continues to rise and the problem of carbon continues to be

S03 ORA 1 2013 Analysis_Layout 1 04/02/2013 14:44 Page 11

Analysis

S03 ORA 1 2013 Analysis_Layout 1 04/02/2013 11:27 Page 12

tackled - is maintained. Of course the big news internationally has been about the rising supply of gas, and the extension of this phenomenon to the huge discovered shale resources within the oil sector. Unfortunately on the very day the latest Outlook was launched the Algerian gas-hostage crisis was unfolding.

The good news is that both oil and gas supplies from North America are predicted to be well up on last year’s forecast (the first especially) due to developments in the technology of both shale resources and tight oil plays, with global transport consumption rising faster than anticipated 12 months ago, too. This will be compensated for by

reduced availability of Mid Eastern oil in particular, and knock-on effects with associated gas, BP believes.

Also expected as a new factor this year is a smaller contribution from biofuels in the fastgrowing transport sector due to “more modest expectations of the penetration of next-generation fuels.”

Meanwhile demand for resources for power generation has been raised even higher; this sector is unique in making use of all currently available energy sources, although the mix of fuels it uses is expected to change significantly.

The overall effect is that global energy

consumption is expected to rise faster and further through 2030 than was thought just 12 months ago, on the basis of a “most likely” assessment of future policy trends.

“Our policy assumptions are closest to those in the International Energy Agency’s ‘New Policies Scenario’, which assesses demand prospects on the assumption that announced national policy objectives are implemented,” the latest Outlook says.

“Yet our outcomes are closest to the IEA’s ‘Current Policies Scenario’ and the [US government’s] Energy Information Administration’s reference case, both of which assume no change in policy settings.”

Global energy consumption is expected to rise faster and further through 2030 than thought earlier.

Increased demand can be met Introducing this year’s report Group Chief Economist Christof Ruehl said: “The precise numbers are less important than the underlying story of the challenges we all face and the choices we make in producing and consuming energy.”

And Mr Dudley stressed the “positive aboveground factors” that have made North America in particular an “engine for energy innovation”. He ended on much the same note as his colleague.

“The overall conclusion is that increased demand can be met as long as competition is present to drive innovation, unlock resources and encourage efficiency.

“This is why we remain optimistic the world will produce the energy it needs to fuel continued economic growth.” ■

BP rethinking Libya operations after Algeria crisis BP IS RECONSIDERING its operations in Libya after the terrorist attack on its gas facilities in Algeria and as industry concerns over security in Libya grow.

"We had expected to restart drilling at the end of the second quarter this year, but we're currently reviewing our plans," a BP spokesperson said.

The British oil major was left stunned by the attack on In Amenas gasfield - operated by BP, Statoil and Algeria's Sonatrach which left 37 foreign workers dead after a four-day siege.

The incident immediately raised questions over Libya, where oil production has staged a strong comeback after the civil war, but where many of the fields lie exposed in

12 Oil Review Africa Issue One 2013

remote desert locations.

BP had been exploring acreage in Libya before the civil war that ended Muammar Qaddafi's 42year reign.

The security situation remains precarious. The militias raised to fight Gaddafi are struggling to control Libya's vast deserts, and it is widely believed that the Islamist terrorists who seized the In Amenas facility had crossed the country's hinterland on their way from Mali.

Libya's government has taken measures to protect the oil industry. Last September, Nuri Berruien, the chairman of the state-run National Oil Company told Bloomberg News that 10,000 militias were being trained as security guards and for border

The In Amenas facility in Algeria.

control, complementing an existing force of about 2,500.

Recently, Libya's deputy oil minister Omar Shakmak said that security forces at the border had been bolstered in response to the attack on In Amenas.

Yet experts agree that Libya is the North African country most vulnerable to attacks on its oil and gas installations, and oil companies are wary that the terrorist threat could spill across the border.

S03 ORA 1 2013 Analysis_Layout 1 04/02/2013 11:27 Page 13

Analysis

S04 ORA 1 2013 Interview_Layout 1 01/02/2013 17:00 Page 14

Former academic, economist, strategist, author and advisor, Dr Duncan Clarke is an authority on Africa’s oil and gas industry. His company, Global Pacific & Partners, organises oil and gas conferences around the world, including the annual Africa Oil Week in Cape Town, arguably the industry’s premiere gathering in the continent. Stephen Williams spoke to him for Oil Review Africa.

Promoting policies that will

stimulate growth L

AST YEAR'S AFRICA Oil Week in Cape Town provided a rare opportunity to sit down with Dr Duncan Clarke and ask for his views on the continent’s oil industry. It was also a chance to find out a little more of the background of this widely acknowledged oil industry expert who has authored a number of fascinating books including what must be a seminal reference work, Crude Continent – The Struggle for Africa’s Oil Prize (Profile 2008, and now a TV-Film documentary, by CNBC-Africa, 2010).

Born in what was then Salisbury, the capital of Southern Rhodesia (now Harare, Zimbabwe), he studied economics at Rhodes University (South Africa, 1966-69), and took a doctorate in economics at the University of St Andrews, Scotland (1975) while teaching at University College of Rhodesia, Salisbury (1970-74). But all that ended in 1975 when he was refused return to the university department of economics for what he elliptically described as “matters of politics”.

It was a traumatic time for this southern African country as the political isolation, sanctions and guerrilla war seeking the overthrow of Ian Smith’s white minority government – that had declared UDI (independence) from Britain in 1965 rather than accept majority rule – gained traction.

As Clarke made clear, he was in opposition to the Rhodesian Front government, notably its economic policies and political posture – but neither was he swayed by the ideas and socialist ideology that underpinned the liberation movements.

Excluded from the University, Clarke undertook private economic research and consultancy work for various companies and institutions. Then, in the nick of time (he had expected imminent “callup” for military service by the army) in early 1976 he was invited to head an institute for development studies at the University of Natal in South Africa. “I went the next day,” he recalled.

It was then the turn of the South African government to flex their muscles. “After seven months I was given what was effectively an exit notice on a one-way ticket,” he said. “It wasn’t exactly friendly; I got a letter that told me my application for residency had been turned down, this letter is still framed on my wall. It was curious as I had never made any such application, and indeed technically didn’t need to apply as a Rhodesian under practices in force at the time, given the concorde between the two governments.

14 Oil Review Africa Issue One 2013

“I left South Africa for London via Geneva, with R 100, where I met the International Labour Organisation, and they hired me on two contracts for nearly a year. Initially, for two months I authored an ILO book, ‘The Economics of Discrimination in Southern Rhodesia/Zimbabwe,’ based on research I had done for my PhD.” Thereafter Clarke joined the World Employment Programme working on African economies, and on leaving ILO continued doing his advisory practice as a one-man band out of Geneva. He conducted a large body of research “looking at a whole bunch of stuff” such as oil/energy and strategy for various companies and banks; institutions such as USAID; what was then the EEC (the forerunner to the EU); and UNECA in foundation economics for establishing the Preferential Trade Area for Eastern and Southern Africa (now COMESA), studies on matters as diverse as agrarian reform in Africa, trade financing, the economic impact of sanctions on South Africa, modern telecommunications impacts in Africa and the economics for a satellite system (called AFROSAT), and the formation of SADCC (the forerunner of SADC). “I did a lot of travel in and around Africa on economics and advisory work,” he pointed out.

Clarke remains as outspoken as ever about issues surrounding the hydrocarbon industry.

Extensive knowledge of Africa’s energy sector It was then that he ran into a Geneva company called Petroconsultants, who were interested in his extensive knowledge of Africa’s economies and energy industries. “We cut a joint venture deal together, and I produced a big fat analysis titled ‘Western African Oil: Corporate Strategy & Country Risks’. They made a nice bundle of money on that and then called me in to discuss another project as they wanted to do another one, and I agreed but told them that I wanted to look at oil in the ASEAN region. That thing also worked out.

“It was then in 1985 they asked me to sort out some problems in their Houston office. It was

Dr Duncan Clarke.

supposed to take two weeks, but took three months. Later they bought out my own operation, and I worked with them to set up their worldwide economics group based in Geneva with offices in Houston and London and later acquisitions in Singapore and Australia. I actually organised my first conference, for Petroconsultants, in Geneva in 1986.”

In 1988 he emigrated to Australia, running Petroconsultants Australasia from Sydney, and going “independent” again in 1989, and it was from there that he organised the first conference, under the Global Pacific & Partners’ label in 1990, in Singapore, as the Pacific Oil & Energy Finance Summit, in a joint venture with Asia’s well-known downstream guru Dr Fereidun Fesharaki. “We also conducted Pacific Petroleum Insiders’ strategy briefings at the Raffles Hotel from 1991 onwards; he focussed on the downstream, I did the upstream,” Clarke explained. “We had 30 or 40 clients. In those days, Asia was the place to be, just before Latin America opened-up and while Africa was still a bit of an unknown and more marginal quantity. I was based in Sydney, travelling all over Asia.”

The first Africa Upstream conference, focussed on exploration, was held in Camps Bay, near Cape Town in 1994. By this time, Clarke had teamed up from 1989 with a former colleague at Petroconsultants, Tim Zoba Jr, and had been joined by Babette van Gessel, currently Global Pacific & Partners’ vice-chair.

20 years of Africa Oil Week The rest, as they say, is history; but many conferences later (this year will mark the 20th edition of the Africa Oil Week) and with a number of books that each deal with particular aspects of the oil and gas industry under his belt (including his notable tome Battle for Barrels which deals with the Peak Oil argument – and dismisses it as deeply flawed) Clarke remains as outspoken as ever about issues surrounding the hydrocarbon industry, taking especial aim at the climate change argument and the trend towards resource nationalisation. Whatever other criticisms you might make of the man, you can hardly accuse him of pandering to political correctness.

Climate change When I asked Clarke about the climate change debate, he was characteristically not backwards in coming forward. “I am not a scientist but I find

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Analysis

The geoscientists in this world are the people who know most about it [climate change].

“The world is made up of hydrocarbons and economic growth depends on fossil fuels”.

less than credible the hysteria surrounding the mostly Western-driven agenda on climatology, purporting that all changes to climate are created solely by man-made activities and driven by or triggered uniquely by carbon dioxide emissions, which I believe are a very small part of the total historic and contemporary picture.

“I am not saying there is not a changing of the climate, but these changes have been going on forever. The geoscientists in this world are the people who know most about it because they have studied what changes have occurred over millions of years. But most climatology models are exactly that: computerised “models” without too much reference to long-term history or other scientific disciplines, mostly drawing presumptive conclusions. I feel there are real problems embedded in the assumptions, structure, editorial and mandates that come out of climate theory thinking that links it to solely anthropomorphic or man-made causes. There is a lot of contradictory evidence around, as Ian Plimer’s Heaven + Earth so well portrays.

Hydrocarbons to remain dominant “The world is made up of hydrocarbons and economic growth depends on fossil fuels: oil, gas and coal. From a realpolitik point of view, hydrocarbons are necessarily going to be the dominant portion of the energy mix, at about 7580 per cent, to the end of the century. Nonhydrocarbons will have reasonable growth but at a high price, usually subsidised. For African countries, I think what we should be doing is finding out how to maximise the economic growth rate and what to do most efficiently with energy systems in terms of resources, whether they are renewables or not.

Countries should examine least-cost options and make the best choice. Otherwise they are going to add cost and the long-run growth rate is going to fall. I just don't buy the Western political-driven strategy and drama about climate change at all.”

16 Oil Review Africa Issue One 2013

No one would doubt that Clarke’s opinions on climate change are deeply felt: as he put it, “whether I am a denialist or not, I don’t know”.

However, the argument that Africa simply cannot afford to turn away from a hydrocarbon future, or the assertion that renewables are unaffordable, may warrant further investigation. There is also a precautionary stance that might well be worth considering as, even if you do not fully buy into the man-made climate change thesis, there may be a case for moderating the emissions of greenhouse gases until the case is proven, one way or another.

Resource nationalisation The other “burning” issue that Clarke discussed with Oil Review Africa, and indeed was the subject of his lively presentation to the Africa Oil Week delegates, was the increasing world-wide trend towards resource nationalisation. He sees this as not a phenomenon unique to Africa, nor indeed the developing world.

“It is a global issue. It has been there for a hundred years and more. It tends to rise in times of significant deviation of crude prices from the mean average – which is where we are now with the onset of relatively higher prices compared to historical averages over 50 or 100 year cycles. And at the same time, the collapse of the Cold War pillars of “stability” encouraged a shift in global geopolitics architecture that has led to the unscrambling of the world. This has ushered in a high degree of balkanisation and the proliferation of weaker states.

“So from Latin America to Cuba, to Ecuador, from all over – Argentina most recently – and also getting to Africa, we see government seeking more control not only of oil and energy resources but the management of the industry to enhance the state’s relative income share that comes out of it, even to the point of trying to regulate to the nth degree in the product markets.”

Nevertheless, Clarke does not dispute that government has a role to play in setting the regulatory environment. “But when it oversteps the boundary of efficiency,” he argued, “it disturbs the fluid operations of the market as a whole. That results when you have excessive taxes, where you have crypto-taxes, and when you get micromanagement of investor decisions, retrospective capital gains taxes, and uncompetitive inhibitions imposed on the secondary transaction markets.

This helps to block up and constipate the unlocking of natural capital that is the key to future growth for all African countries.

“Anything that diminishes the rate of growth of GDP per capita - and resource nationalisation is one of those things - undermines the prospective future of the country concerned. So that is a problem. It is often built on advice and ideas that are antiquated and inappropriate and not applicable to Africa, that typically come from Western Europe and elsewhere, urging the imposition of higher tax takes and over-regulation to underline this thesis, often claiming also that in some way the oil industry is inherently manipulative, corrupt and somehow evil.

“And also in this context, politicians and predatory interests that compose many of the states in Africa are quite happy to follow this line of argument because they see this as a way forward to capture these rents or to allocate surplus funds in such a way that, while monies should go to investment and growth, they enter a private domain. So there is the core of the problem which undermines long-term growth.

None of the countries that have ever pursued resource nationalism, from Venezuela to Argentina and everywhere else, have ever experienced long-term, stable growth. I think that this is a lesson now for Australia’s Prime Minister Julia Gillard as the Labour government has enforced higher taxes on the energy industry with costly carbon obligations. It is discouraging to corporates and investors. I think she represents a symbol of resource nationalism but in an OECD country.”

It will be fascinating to hear what Clarke has to say at the next Africa Oil Week as it celebrates its 20th anniversary in November 2013. The meeting has become a fixture for all the leading oil and gas players in the continent, but something of a victim of its own success having now outgrown its traditional venue, The Pavilion Conference Centre in Cape Town. So from next year it will be moving to the huge Cape Town International Conference Centre – but no doubt will lose nothing of its unique character as Africa’s most important and stimulating oil and gas conference. ■

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Nigeria

Chinese companies have blazed a trail in Africa in recent years, snapping up natural resources projects to supply a growing economy back home.

China hot for

Africa’s oil I

N THE OIL sector, China’s growing presence in Africa has led to greater competition in an area long dominated by US and European companies, Africa’s traditional business partners.

And it’s a trend that still continues.

Most recently, Chinese state-owned company Sinopec paid US$2.5bn to Total of France for a 20 per cent stake in Nigeria’s OML 138 block, which includes the Usan oilfield.

This field - which began producing in February 2012 and has the capacity to produce 180,000 barrels per day (bpd) - accounts for nearly a tenth of Total’s equity Nigerian production.

OML 138 is jointly owned with Chevron, Exxon and Canada’s Nexen, while Nigerian National Petroleum Company (NNPC), holds the concession on the oilfield.

The sale, which will be paid for in cash, still needs to be approved by Nigerian authorities, but illustrates the appetite among Chinese firms for Africa’s natural resources sector.

Nigerian appetite The Total deal mirrors an earlier offshore Nigeria acquisition by another state-backed Chinese entity, CNOOC. It paid US$2.3bn in 2006 for a 45 per cent stake in OML 130 block, which includes the deepwater Akpo field, also operated by French oil giant Total, though CNOOC acquired its equity interest from privately-owned Nigerian firm, South Atlantic Petroleum.

The Akpo field, which came on stream in 2009, has a peak production of 225,000 bpd.

The same block also contains the Egina, Egina South and Preowei oilfields, where early development work is underway, offering plenty of future upside for the Chinese company and its partners.

There have been plenty of other energy-related transactions and investments by Chinese companies in Nigeria too through the years.

Last February, for instance, China National Material Group Corporation Limited completed the construction of a US$1bn cement plant in Nigeria, reflecting the increasing depth of the country’s involvement in Africa’s biggest oil producing economy.

Enter Uganda While Nigeria has provided a focus for activity, a natural bias given the country’s oil wealth, Chinese firms have plugged into opportunities right across the continent.

CNOOC, alongside Total, has dived into Uganda’s emerging oil sector, joining lead operator Tullow Oil of the UK, in a US$2.9bn deal to exploit deposits in and around the Lake Albert area.

This may yet take some while with the three partners still awaiting final government approval on their proposed development plans for the Albertine rift basin.

This would pave the way for the multi-billion dollar investment required to build the key infrastructure required to enable oil production to start.

Kampala is also waiting for new legislation to be passed to strengthen the management of its nascent oil industry.

Uganda first discovered commercial hydrocarbons along its border with the Democratic Republic of Congo (DRC) in 2006.

After a succession of further discovery wells, crude oil reserve estimates are now put at around 3.5bn barrels.

First oil out of landlocked Uganda is not expected until at least 2017, though, while peak production could pass more than 200,000 bpd by the end of the decade.

Deal making

South Africa’s state oil company PetroSA has partnered with China’s Sinopec Group to work together in pushing the building of the proposed Mthombo crude oil refinery project. Construction on project Mthombo project, which will be the biggest refinery in Africa, is expected to start this year, with the refinery to come on stream by 2015.

18 Oil Review Africa Issue One 2013

As well as Africa’s big oil economies, and upcoming producers like Uganda, Chinese companies have also invested in smaller energy states and other territories with proven natural resources appeal.

A little over a year ago, Sinopec acquired an 80 per cent stake in Pecten Cameroon, for example, while China Nonferrous Metal Mining announced plans to invest US$2bn in Zambia’s established minerals sector.

In fact, Chinese companies have gained a foothold in virtually every single African market during the past decade, and across all industry

CNOOC bought a 45 per cent stake in Nigeria’s OML 130 block, which includes the Akpo field.

Sinopec's purchase [for stake of OML 138 block] is just the latest example of China buying up commodities and developing mineral resources in Africa. sectors, from farming to finance.

This fast growing bilateral relationship is reflected in the buoyant trade that is developing between the two sides.

Two-way trade was estimated to be worth US$200bn in 2012.

There are now estimated to be more than 2,000 Chinese companies now pursuing projects right across Africa.

Downstream business And it is not only upstream business that has seduced the Chinese in Africa.

Again, Sinopec is actively pursuing a number of big refinery projects across the continent, most notably in South Africa, where it is working with PetroSA on a potential 400,000 bpd facility.

Two years ago, it also showed interest in building three new 250,000 bpd oil refineries in Nigeria, with funding from the China Export & Credit Insurance Corporation and a group of other Chinese banks.

The refineries, still in the early planning stages, would be sited in Lekki in Lagos State, Brass in Bayelsa State, and Lokoja in Kogi State, although it is far from clear if all, or any, will go ahead.

Elsewhere, CNOOC announced plans last year to invest in a US$1.5bn refinery in the Lake Albert rift

S05 ORA 1 2013 Nigeria 1_Layout 1 04/02/2013 11:36 Page 19

Nigeria

S05 ORA 1 2013 Nigeria 1_Layout 1 04/02/2013 11:36 Page 20

Production began from the Usan oil field in February.

basin, as part of its wide-ranging commitments to Uganda.

The government in Kampala is understandably keen to see its reserves used to boost local development where possible.

Most existing China-backed refineries in Africa, in Algeria, Chad and Nigeria, are small in scale, although its Sudanese facility, which opened way back in 2000, has a processing capacity of 100,000 bpd.

Beyond Africa But it is not only Africa where Chinese companies have found fruitful ground.

Last year, CNOOC gained approval from Canadian government officials in its quest to acquire Calgary oil company Nexen.

The deal, worth US$15bn, marks China’s biggest single overseas energy acquisition.

In 2005, the US blocked a proposed US$18.5bn takeover by CNOOC of American independent Unocal, due to concerns centering on a Chinese state-owned company gaining control over an ‘American’ oil producer.

Separately, CNOOC and Sinopec have both spent billions of dollars acquiring other Canadian energy assets in the past year or so.

Outside of North America, Chinese companies are active across Latin America and Asia as well as the world’s most important oil-producing region, the Middle East.

China National Petroleum Corporation (CNPC) is currently reported to be in pole position to land the lead stake in the West Qurna-1 field from Exxon, further boosting China’s presence in this rising oil powerhouse.

The US super-major is quitting southern Iraq to focus on the country’s semi-autonomous northern Kurdistan region, where investors are offered a more lucrative share of output.

Its departure would all but wipe out the American presence in Iraq’s southern oilfields, though independent, Occidental Petroleum retains a small stake in the Zubair field.

CNPC is also active on other Iraqi fields, most notably Rumaila - dubbed Iraq’s workhorse field, as it makes up over half of current national output where it partners British giant BP. Sinopec, like Exxon currently, is also active in Iraq’s Kurdistan region.

Unique challenges But Chinese companies will not do business in Africa without escaping some of the unique challenges posed by working in this vast and diverse continent.

In Nigeria, this includes the prickly issue of community relations, and befriending locals close to oil production activities.

As countless western oil companies have discovered to date this is not an easy task.

Elsewhere, China has found itself in a tricky position in Sudan, where it has invested heavily in the energy sector of both Sudan, and the new South Sudan.

It has found itself caught between its long-time ally in Khartoum in the north and its new partner in the South, which inherited three quarters of Sudan's oil output after the split, the eventual outcome of a two decades-long civil war.

Beijing has been forced into taking a far more proactive role in soothing relations between the two sides than it would normally do given its usual ‘non-interference’ stance in foreign relations.

China is the largest buyer of Sudanese crude, importing 260,000 bpd in 2011, according to the International Energy Agency.

More to come There are other challenges to be faced too.

The recent Sinopec deal with Total in Nigeria comes at a time when the Chinese economy itself has slowed its rapid growth.

Late last year, Sinopec itself reported a drop in profits in the three months to September, due to weak local demand for petrochemicals.

For Nigeria, the hope is that the Chinese are there to stay.

Whether China’s state oil companies will continue their quest for more business in 2013, against the backdrop of a weakening domestic economy, and a far from robust world economic climate, remains to be seen.

For Nigeria, which has seen foreign investment by traditional partners drop off because of new oil laws that hand greater control to local companies not to mention the perennial problems in the restive Niger Delta - the hope is that the Chinese are there to stay.

Some commentators have tipped Nigeria’s output to fall in the next decade unless more is done to encourage foreign investment.

Certainly, Total’s willingness to sell a prized asset like the Usan field could foretell the shape of things to come.

For now, Nigeria remains Africa’s biggest producer, exporting around 2.5mn bpd, with aims to raise output to 4mn bpd longer-term, but the outlook is cloudy.

Luckily for Nigeria, like the rest of Africa, the big Chinese corporations are bucking the trend right now. ■

Oando moves to raise funds for ConocoPhillips acquisition LEADING NIGERIAN ENERGY company Oando has offered its third rights issue in an attempt to raise capital to fund the US$1.79bn acquisition of the Nigerian operations of US multinational energy corporation ConocoPhillips, and the partial settlement of its existing debt.

Oando plans to raise US$340mn through the exercise which would see its issued shares increase to 6.7bn from 2.27bn.

Wale Tinubu, the company CEO, said in an official statement: “We count on the consistent support of our shareholders to seize the opportunity to take up their rights and benefit from the higher-margin value creation the [acquisition] offers.”

Since its share value climaxed at 243 naira (US$1.5) per share in 2008, the company has seen its share price plummet. Currently, Oando trades for about 7 cent/share on the floor of the Nigerian Stock Exchange (NSE).

The company urged its shareholders to subscribe for more shares to help boost the fundraising.

In December, Oando PLC, announced that its affiliate Oando Energy Resources (OER) had entered into agreements with ConocoPhillips to acquire its entire business interests in Nigeria for an estimated cash of US$1.79bn including customary adjustments.

The agreement included the purchase of two onshore businesses and

20 Oil Review Africa Issue One 2013

two offshore operations which includes Conoco Exploration and Production, which holds a 95 per cent operating interest in OML 131.

S06 ORA 1 2013 Nigeria 2_Layout 1 01/02/2013 17:02 Page 21

S06 ORA 1 2013 Nigeria 2_Layout 1 01/02/2013 17:02 Page 22

Nigeria

Troubling 2013 outlook for Nigeria. Samuel Cuciszuk reports

Between a rock and a

hard place N

IGERIA'S OIL SECTOR faced another troubled year in 2012, despite hopes otherwise – at least from a security and political perspective. Despite the long political deadlock, this was counter to expectations. Overall Nigerian crude production suffered a dip in Q4 2011 and in the first two months of 2012; however this was down to a number of pipeline attacks and resulting force majeure, together with particularly the glitch and oil spill at the offshore Bonga platform. All in all, these things felt like a temporary chink in the continuing recovery shown by Nigeria since 2010.

Levels of militancy in the Niger Delta seemed to be falling in the wake of President Jonathan’s policies, while efforts by some of the supermajors and Nigeria’s NNPC to reinvigorate some of its mature onshore assets by farming them out to more focused juniors and midsize players, were starting to bear fruit.

Instead, the security situation in Nigeria took a turn for the worse, as crude theft gangs in its oil producing regions seemed to proliferate, causing multiple pipeline bombings throughout the year, as well as further damaging investor confidence. The threat to expatriate oil and shipping workers from piracy and gangs specialising in kidnapping for ransom, did not seem to visibly diminish either.

All of this seemingly chronic malaise took place along the backdrop of continued stalemate surrounding the Petroleum Industry Bill (PIB), which in its last iteration still is viewed by the international oil companies as negative to their interests. Hence, 2012 saw little to no movement forward on investment in future projects and exploration levels throughout the country continued to be depressed in a historic comparison. Particularly worrying is of course the failure to attract renewed offshore deepwater exploration and development commitment, given the increasing maturity of Nigeria’s onshore and shallow water assets.

Worsening security conditions Also oil companies are increasingly openly talking about the worsening security conditions in Nigeria, with Peter Voser, Shell’s CEO in early January in a speech published by the company, saying that “the overall security situation in 2012 has worsened. The stealing and sabotage of crude oil intensified. It’s a multi-billion-dollar business”, before calling for a multi-stakeholder approach and saying that the scope of the problems were beyond Shell alone to be fixed. Given the deep-

22 Oil Review Africa Issue One 2013

The 180,000 bpd Usan field is the only new large oilfield ramping up offshore Nigeria.

More reserves could be proved up should more exploration be carried out. rooted problems in Nigeria’s oil producing regions with issues like separatism, few would challenge the notion that the problems are within the remit of an oil company to fix. However, the call for a multi-stakeholder approach – fuzzy and politically non-dangerous as it may sound – just after the mention of the deep problems with violence and corruption, signals an increased dissatisfaction by the company with the Nigerian government.

Similar less-than-veiled criticisms have been emanating from other large oil companies active in the country over the past years.

As the outright separatist rebellion by groups like MEND has abated in Nigeria, following a successful military push and a round of negotiations including wide amnesties for fighters, the organised oil theft – bunkering – industry has spread, or dispersed, on what seem to be a larger number of purely criminal groups. While previously there was some level of centralisation, for the lack of a better word, in control of these criminal networks, as they in different ways sustained the guerrillas, these groups now act completely on their own. Given the size of the oil theft and smuggling market in Nigeria it was perhaps to be expected that just weakening the political organisations would not kill the criminal business, unless the state was in the meantime able to better insert itself into the oil producing regions and start addressing all the social, economic and environmental needs in these areas.

Nigeria’s political deadlock has however made anything similar to a successful push by the state

into these regions impossible. While the military still has an important role to play in the physical hunting down of the criminal networks and in the closing down and dismantling of illegal refinery sites, the main battle against the bunkering gangs will have to be done through a more concerted fight against corruption. The political deadlock, and to some extent the lack of political will to undertake important reforms of Nigeria’s financial legislation, has, instead of continuing to build on the military gains in recent years, left a wide space open for criminal groups to operate in.

Rampant corruption, criminality and a political deadlock is obviously not a good backdrop to attract investment into an industry and Nigeria’s oil industry is no exception. For years, exploration investment has been on the wane, which is particularly problematic given the very vast sums needed to sustain growth in Nigeria’s deepwater acreage – its growth region. Development investment has, quite naturally, moved in the same direction. Last year saw only one new large oilfield ramping up offshore Nigeria, the Total-operated 180,000 bpd Usan field (divested to Sinopec later in the year). Such a project speed is not consistent with the potential of Nigeria’s offshore deepwater and not only are there estimates that more reserves could be proved up should more exploration be carried out, there are discoveries which are awaiting to be appraised and developed.

PIB delays Delays in the process surrounding the PIB’s passing has created a deep uncertainty about the legal and fiscal framework for upstream investments in Nigeria. That different drafts are floating around and receiving endorsements from groups within the parliament have only further added to the confusion, particularly for oil companies contemplating cost- and technology-intensive deepwater projects. Efforts by the government, through the NNPC, to counter this and force oil companies to move forward have only backfired so far. Late last year the souring of relations between NNPC and some of Nigeria’s largest upstream actors, Total and ExxonMobil likely included, became critically visible, as the tiff over delayed final investment decisions (FID) went public.

The NNPC “cautioned” unnamed oil companies “over false allegations of deliberately stalling projects”, adding that it would not be “stampeded or browbeaten” to compromise its contract award processes. Phrases like “calculated media blackmail” were also flying

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Nigeria

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about. The caution was seen as a rebuff to oil companies claiming that NNPC was holding up the decision-making process for new developments. Particularly the Total-led development of the 200,000 bpd Egina deepwater field, initially hoped to come onsteam in 2010 and ExxonMobil’s development of the 40,000 bpd Erha North phase-II satellite project, were mentioned in the subsequent industry comments.

NNPC has issues with the cost calculations submitted by the oil companies, which in their turn claim that deepwater oilfields will be uneconomic under the PIB. NNPC’s move further raised concerns that the Nigerian government might begin putting pressure on oil companies as licenses start to approach their expiry dates, even when there are development plans submitted but not passed. Such a move could help the NNPC and the Nigerian government put the blame squarely on oil companies for some time in Nigeria’s internal political discourse, but even if relinquishments would not be forced, it could only serve to burn bridges with the still rather small community of investors having enough technical know-how to undertake deepwater developments.

It is for instance interesting to note that the largest single shareholder (but not the operator) in the Egina project is China’s CNOOC (45 per cent) which hopes to gain knowledge and experience from the project. The stalemate is therefore not only damaging relations with international oil companies, but with some of the most important internationally active NOCs too.

The virtual halt in Nigeria’s offshore oil production growth will by now take several years to reverse, while mature decline will start to become a real problem in within the same medium timeframe. The increased production which has come from onshore and shallow water redevelopments by eager midsized and junior players are all well, but will not continue to provide enough to counter falling output rates, as the North Sea example has shown in the past decade.

A problematic time More worrying, the Nigerian lack of growth comes at a particularly problematic time with regards of the marketing of its crudes, which also will not help it build investor confidence. West African crudes have been the main losers so far to the US shale oil boom, with their exports being backed out of US, while European demand has been unable to offer options for the market and much of the Asian fuel demand growth is being fed by refineries configured for heavier crudes. Consequentially, West African crude differentials have taken a beating. The permanent loss of US market shares places NNPC and oil companies producing Nigerian crude in a more complicated situation and instead of meeting the challenge with some form of concerted proactive strategy and government support for all actors, there is instead a feeling in the markets that the opposite is the case.

This places Nigeria in a very worrying position for 2013 and onwards, with not only its upstream investment having stalled, relations between oil

Afren's Okoro East exploration well made a discovery earlier last year.

There are discoveries which are awaiting to be appraised and developed. companies and the NNPC having soured, but also its international crude market shares being in flux and its crudes being heavily discounted in a historic comparison. While the latter is because of events outside its control, the sense that West African crudes have switched a geographical advantage to a disadvantage adds a further reason for investors to choose other oil plays, with more promising growth prospects and better regulations, at a time when Nigeria, strategically, cannot afford them doing so. ■

Nigerian Content creates 30,000 jobs in 30 months THE IMPLEMENTATION OF the Nigerian Content Act in the past 30 months has deepened the Nigerian Oil and Gas local supply chain and increased industry manhours performed

by Nigerians by over 350 per cent resulting in over 30,000 direct productive jobs, the Minister of Petroleum Resources, Mrs. Diezani AlisonMadueke has said.

Speaking at a meeting of the Governing Council of the Nigerian Content Development & Monitoring Board held in Abuja recently, the Minister who doubles as the Chairman of the Council explained “that just by insisting on using Nigerians in the industry, we have deepened the local supply chain.”

The jobs were generated in engineering, fabrication, exploration and production, marine transportation and logistics sectors, which had been

24 Oil Review Africa Issue One 2013

developed to become more robust. She expressed optimism that the job growth trajectory will not only be sustained but also drive multipliers across industries following the integration of youths training into the implementation process.

“I have no doubt that more jobs will be created in 2013 and we shall achieve greater localisation of industry services, manufacturing and fabrication in 2013,” she added.

According to Alison-Madueke, Nigerian Content implementation has increased the level of participation of Nigerians in oil and gas contracts to 87 per cent of total industry contracts, describing this is a first step towards domiciliation of spend and local value addition.

Commenting further on the success recorded so far, the Minister noted that “The Board

has to a large extent achieved consensus in most aspects of Nigerian Content implementation to the extent that there has been no major dispute amongst stakeholders on interpretation of provisions of the Nigerian Content Law. “Stakeholders are also responding positively to the need to do things differently in the industry, for the benefit of all. This clearly demonstrates that we have been carrying the industry along in the implementation of the Act.” In his remarks, the Executive Secretary of Nigerian Content Development and Monitoring Board, Engr. Ernest Nwapa explained that the Nigerian Content implementation model is focussed on growing and utilising in-country capacity, while operators are made to consider long term value addition. Under this model,

Ernest Nwapa, Executive Secretary of NCDMB.

government might get slightly lower revenue but this will be compensated with a higher incountry value and greater attention to life cycle of industry operations.

While acknowledging progress on the quantum of contracts awarded to Nigerians, the Executive Secretary stressed that real Nigerian Content can only grow if Nigerian companies that win contracts procure items from Nigeria and execute the jobs in-country.

S06 ORA 1 2013 Nigeria 2_Layout 1 01/02/2013 17:02 Page 25

SGS as the world’s leading inspection, verification, testing and Certification Company, we provide competitive advantage, drive sustainability and deliver trust. Recognised as the global benchmark for quality and integrity, we employ over 70,000 people and operate a network of more than 1,350 offices and laboratories around the world. We are continually pushing ourselves to deliver innovative services and solutions that help our customers move their businesses forward.

SGS have their operations established in Nigeria since 1957, we have a local content workforce of over 90% indigenous Nigerians and we are fully committed to “The Nigerian Content Policy� as promulgated by The Federal Government of Nigeria.

SGS Inspection Services Nigeria Limited board of directors consists of 50% Nigerian nationals and the Company has 50% Nigerian shareholding.

S06 ORA 1 2013 Nigeria 2_Layout 1 01/02/2013 17:02 Page 26

Nigeria

Oil Review Africa talks to Dr Bada, Managing Director, Shoreline Natural Resources.

Shoreline Natural Resources plans

for expansion WHO IS SHORELINE Power’s joint venture partner in Shoreline Natural Resources and how was the deal consummated?

Shoreline Power’s joint venture partner in Shoreline Natural Resources is a company called Heritage Oil plc which has been listed on the London and Canadian Stock Exchange for many years and also on the Canadian one. Both parties looked at each other and agreed to join forces to form a joint venture company to bid for Block OML 30. We put in a first class commercial and technical bid, which Shell recognised. After due negotiations we came up with the winning price.

You talk of Heritage Oil plc. What kind of relationship do you have?

Shoreline Power’s relationship with Heritage starts off with mutual respect, simply because both parties bring different things to the table. I will give you a little background on the Shoreline Group itself and what it brings to the table; this will give you an idea why they were very excited to come and work with Shoreline Power on this project. The Shoreline Group has been involved with oil and gas and industrial engineering for several years. Shoreline Power bought ABB's electrical manufacturing assets here in Nigeria through a competitive bid process over eight years ago. These assets were manufacturing assets. We were able to do commercial transactions with well known international companies and, in the international world, due diligence about the company you want to do business with is very important, especially when dealing with developing countries.

Also some years back, within the oil and gas sphere, we bought a 17 per cent of Schlumberger Testing and Production; on the basis of this we also have a seat on the board of Schlumberger Testing and Production. We also bought out and set up a company in Port Harcourt called Trans-Amadi Facilities Limited (TAFL). We turned this facility into an oil and gas logistics base. With this facility we host and work with oil companies such as Seawolf Drilling, Siemens Oil & Gas and Haliburton, amongst others.

Obviously, your success in the business world was what contributed to a lot of banks being confident to get involved and finance this project?

That is correct. International lending and funding is primarily about confidence and trust in the people you are lending to. If there is no confidence you will not be able to see this kind of

26 Oil Review Africa Issue One 2013

other assets successfully and we believe this shouldn't be any different. We do see challenges with NPDC, which their dynamic management also see. They understand that the divestment has put onto them new producing assets that they need to bring to capacity very quickly. The challenge they have is that they have to try and see how they can staff up and improve their capacity which will allow them to manage all the investments that they have taken up within a short period of time and manage them effectively.

Dr Bada, Managing Director, Shoreline Natural Resources.

transaction take place. I must make something quite clear so it is on record; this is actually the largest oil and gas E&P asset acquisition by any Nigerian company, at the time of its completion.

This is the largest of any such transaction in Nigeria in which an indigenous company gathers the consortium together, financially and technically to fund this.

Nigerian companies in the E&P are in fact marginal players; will this acquisition take you from a marginal player to a big player in the oil and gas business?

In the scheme of things, the acquisition of OML 30 is a significant landmark event both for us as a company and as a country. It is the largest assetbased acquisition by a Nigerian oil company and on completion of the transaction we have either the largest or second largest reserves of any indigenous oil company. Our reserve base is certified by an independent reserve auditor out of the United Kingdom, called RPS Energy Consultants.

You will be working with the Nigerian Petroleum Development Company (NPDC). ..can you elaborate on this please?

NPDC for the record is the operator of OML 30, as chosen by the government, and a 45 per cent share holder. Our confidence level in NPDC is strong and that is largely because NPDC has been known as an operator in the past. It has operated

Is this a plus for Local Content?

This is a fantastic big tick for Local Content. It is also a magnifying glass because people are going to look at companies like the joint venture between NPDC and Shoreline Natural Resources and see what they do with their assets: So it is a challenge as much as it is a plus. We have to prove to ourselves first and foremost then to our financiers and shareholders that we can actively develop this asset not just as well as the IOCs but much better.

We also have to prove to everybody that is looking from outside that indeed Nigerian companies in joint ventures with NPDC can develop world class asset as well as any other oil company.

What role is Atlantic supposed to play in this asset? Does it have any role?

Atlantic does not have any direct role with Shoreline Natural Resources, but Atlantic is a strategic partner of NPDC, not just on OML 30 but a few other strategic divestments. Now the role of Atlantic from what we know is to fund NPDC's cash call, but as a result of funding the cash call they might also be involved in some sort of technical overview to see how the cash call work is going on.

Atlantic will work solely with NPDC, who will work with us as JV partners.

I just want to put this on record. Is it 45 per cent to you and 55 per cent to NPDC? That’s the equity, isn’t it?

That is correct. Finally I would like to also say something in terms of our growth plan. Shoreline’s plan is not to remain just an OML 30 company, but we are actively seeking new assets in exploration and even production. Obviously we can’t disclose anything where we are still in discussion. These would be primarily in Nigeria but also elsewhere in West Africa. Our plan is to develop Shoreline Natural Resources to become one of the largest if not the largest oil and gas company out of Nigeria working into Africa. ■

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Nigeria

FG to spend $400mn on Trans-Africa gas pipeline project THE ACTING DIRECTOR General, Infrastructure Concession and Regulatory Commission (ICRC), Mr Ghaji Bello, has stated that the Federal Government would commit US$400mn into the Trans-Africa Gas Pipeline project.

He said that the project, which would run from Nigeria to Algeria, is expected to be completed in 2018.

Bello made the disclosure in Abuja at a two-day Technical Workshop on Presidential Infrastructure Champion Initiative (PICI) organised by the New Partnership for Africa's Development, (NEPAD) with the theme: ‘PICI: A Panacea for Sustainable Growth and Development in Africa.'

The Acting DG said: "As a sign of commitment, the Nigerian government has made a commitment of US$400mn in the 2013 budget in order to finance the project up to the next stage. And I think that is why all of us as Nigerians should be proud of that.

"Really, there would be transformation of the economy and once this is done, you will find that the issue of infrastructure will to a high extent be solved."

He said President Goodluck Jonathan had given his pledge to support the initiative as part of the country's contribution to Africa's infrastructure growth.

He said: "Let us also bear in mind that with our population which is put at above 150mn, the Infrastructure Concession and Regulatory Commission (ICRC) of which I'm the Acting Director General has been directed to try and set up funding to move the project forward.

The project, according to Bello, runs through several African countries

and is expected to boost the economic activities of the areas and increase intra-Africa regional trade.

In his remark, the Special Adviser to the President on NEPAD, Tunji Olagunju, said his agency is Africa's strategy for continental economic integration and sustainable development.

"As a framework, it is anchored on a tripod of principles: African ownership of its development trajectories, partnership between people and governments and between government and private or corporate sector of the economy and the need to use the resources and expertise of Africa's natural capital for its sustainable development," he said.

Olagunju added that PICI sought promote a network of regional infrastructure projects in support of economic and market integration which is led by heads of state of African countries.

"Today there is no doubt that infrastructure is critical to economic transformation especially in eliminating poverty in our continent.

"This position has been confirmed in an independent study conducted by the Infrastructure Consortium for Africa (ICA)," he disclosed.

However, Olagunju, noted that there are some challenges affecting the pace of infrastructure implementation in Africa, adding: "Firstly, there is the issue of effective co-ordination, whether within a country or among states, as a result of which stakeholders are effectively prevented from knowing the true status of projects implementation.

"The inability to perform a monitoring role apart; there is also the need for greater transparency and accountability in the implementation of such projects, more so, because funding is typically sourced from the traditional budgetary allocations and donors financed loans or grants."

PIB discussions with IOCs THE MINISTER OF Petroleum resources, Mrs. Diezani Alison-Madueke has said that discussions are on-going with the International Oil Companies (lOCs) operating in Nigeria to tighten the fiscal terms under the proposed Petroleum Industry Bill (PIB), currently before the National Assembly.

The Minister made the remark at a panel discussion on “PIB and the Future of Nigeria’s Oil Industry’’, in Abuja at the 18th Nigeria Economic Summit.

She noted that contrary to the view of the IOCs that the fiscal terms as contained in the PIB were harsh, they are fair.

According to her, Nigeria still remained one of the most attractive countries in terms of fiscal regime or ‘government take’, adding that the total ‘government take’ in the PIB, was 73 per cent, up from 61 per cent in current deals with the IOCs. She said the current deepwater terms were negotiated in 1993, when oil prices were just US$20 a barrel and that section 16 of the Deep Offshore Act prescribes that changes be made to this particular fiscal regime to restore benefits to the government commensurate with increased oil prices, once oil prices have exceeded US$20 per barrel in real terms.

According to her the Act also prescribes that changes be made 15 years after the

28 Oil Review Africa Issue One 2013

Mrs Diezani Alison-Madueke.

commencement of the deep offshore act, and that Nigeria was not alone in the tightening of the fiscal terms.

She said the goal was to achieve a `fair balance between government and contractor share to ensure that risks do not outweigh rewards’.

She said the PIB introduced a price-based royalty for crude prices beyond 70 dollars per barrel, and all cost-based incentives have now been replaced with productionbased incentives, because government revenues accrue from production and not from cost.

The Minister explained that the reforms in the PIB had been divided into two areas namely the fiscal and non-fiscal reforms,

where the non-fiscal reforms relate to institutional and policy reorientation, while the fiscal reforms represent the `largest overhaul of government petroleum revenue system in the last four decades’.

She identified the central objectives of the fiscal reforms to include simplification of revenue collection by Government, capturing of windfall profits in the event of high oil prices as well as the collection of more revenue from large profitable fields in deep offshore waters.

According to the Minister, gas fiscal terms are now fully integrated into the oil fiscal terms which is the first time this has happened in Nigeria. The country has 187 trillion cubic feet of proven gas reserves.

In his remarks, Abiye Membere, the NNPC Group Executive Director, Exploration and Production said dialogue remain the panacea to addressing all grey areas in the PIB. Also speaking, the Managing Director of Seplat Petroleum Development Company Mr. Austin Avuru cautioned against reducing the PIB discussions to fiscal issues such as `tax and royalty’.

“The cardinal point of the reforms is to make institutions more effective in the oil and gas sector in the interest of all,” he said.

He implored government to address key issues killing investment in the country.

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Ghana

When the oil rigs starting pumping crude off the coast of Ghana, many people wondered whether Ghana would be able to break the "curse" that has often marked Africa's oil industry. It seems that a new dawn has broken. Jon Offei-Ansah reports

Ghana's 'new path' for handling

oil revenue G

HANA'S REVENUE MANAGEMENT Act - passed more than a year after the first oil was pumped from the country's Jubilee Field - has been described as an "innovation." The law outlines clear mechanisms for collecting and distributing petroleum revenue. It specifies what percentage should help fund the annual budget, what should be set aside for future generations and what should be invested for a rainy day.

Petroleum revenue contributed four per cent of the government's total capital spending in 2011.

The funds went mainly to investments in road infrastructure, but also to building the capacity of the oil and gas sector, repaying loans and strengthening agriculture, most notably for fertiliser subsidies.

The Ghanaian authories received a total of US$340mn in revenue from the country’s oil production in the first three quarters of 2012.

US$146.5mn of the receipts was transferred to the oil parastatal, the Ghana National Petroleum Corporation (GNPC), according to figures released by the finance ministry in January. The ministry is yet to report on the third quarter transfers to the Ghana Petroleum Fund (GPF), which according to the Petroleum Revenue Management Act, should receive any excess revenues above the quarterly Annual Budget Funding Amount (ABFA) - the share of revenues spent directly on the annual budget.

According to the Act, the ABFA should be at most 70 per cent of the oil revenues, excluding transfers to the GNPC, also known as the benchmark revenue. In quarters where transfers are made to the GPF, it means the benchmark revenue fell short of the quarterly ABFA. In the first half of 2012, about US$12.5mn and US$3.7mn were transferred into the Stabilisation Fund and Heritage Fund respectively. Data from the central bank, Bank of Ghana, shows that the Ghana Petroleum Fund, as at January 2012, had an opening book value of US$54.8mn, while the closing book value as at June 30, 2012 stood at US$54.9mn for the Stabilisation Fund and Heritage Fund respectively.

The Stabilisation Fund was established to mitigate the impact on the annual budget and sustain public expenditure capacity during periods of unforeseen petroleum revenue shortfalls, while the Heritage Fund is meant to ensure Ghana’s oil wealth benefits future generations.

FPSO capacity under threat Meanwhile, the floating production, storage and offloading (FPSO) vessel at the Jubilee fields is, for

30 Oil Review Africa Issue One 2013

The FPSO Kwame Nkrumah MV21 is being tested to its full capacity.

the first time, being tested to its full capacity following the field’s increase in daily oil production due to the start-up of two Jubilee Phase 1A wells and the successful acid simulations. Jubilee operator, UK’s Tullow oil, says the field is currently producing about 110,00 barrels per day (bpd). ‘The total well production capacity is now over 120,000 bpd, therefore allowing the current FPSO capacity to be tested over the coming weeks,’ Tullow said in its trading statement in January. It added that drilling of the Sapele-1 well in Deepwater Tano licence had commenced and was expected to be completed by end-February adding, ‘this will conclude exploration activity in this licence.’

Kosmos said their allocated expenditure will go into developments of commercially viable discoveries and to complete explorations and appraisals offshore Ghana.

In a related development two American oil companies have committed funds to finance activities in Ghana’s oil fields. Kosmos Energy, Tullow’s partner on the Jubilee field has indicated that it has made available an amount of US$400mn

to fund its activities in the country’s oil fields. Using its estimated net proceeds of nearly US$550.2mn from its public offering sale of 30,000,000 common shares, Kosmos said the allocated expenditure will go into developments of discoveries which are commercially viable and to complete explorations and appraisals at offshore Ghana.

In a filing to Securities and Exchange Commission of the US, the company said ‘we estimate we will incur approximately US$500mn of capital expenditures for the year ending December 31, 2011. This capital expenditure budget consists of US$175mn for development and US$225mn for exploration and appraisal in Ghana.’

In budgeting for future activities, Kosmos says it relies on a number of assumptions such as the discovery success rate of oil, the number of wells planned to be drilled and the costs involved in developing or participating in the development of a prospect. According to the company, these assumptions are subject to political, economic, regulatory and environmental uncertainties and if one or more of the assumptions prove to be incorrect then it may decide to raise additional funds if the conditions for raising such capital are favourable.

Oil giant Hess Corporation has also announced plans to spend a chunk of a budgeted US$550mn on further exploration activities on the Deepwater Tano/Cape Three Point Block.

Hess is the operator of the Block with a 90 per

S07 ORA 1 2013 Ghana_Layout 1 04/02/2013 11:43 Page 31

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Ghana

cent stake. The GNPC partners Hess in the DT/CTP Block with a 10 per cent stake.

immediately commenced plans for the commercial exploitation of the oil reserves. There are also ongoing engineering studies for the development and commercialisation of the gas reserves of the block.’

Eni is operator of the block with a 47.22 per cent slice while Vitol holds 37.78 per cent and GNPC the remaining 15 per cent with an option to grab five per cent more.

Eni confirms commerciaility of Sankofa In a separate development, Italian oil major Eni has proven the commercial viability of an oil discovery off Ghana after an appraisal well hit a large amount of pay. The Paolo Scaroni-led company has now ‘immediately commenced plans for the commercial exploitation of the oil reserves’ at the Sankofa East discovery on the Offshore Cape Three Points (OCTP) Block. Eni made the discovery at the block in the Tano basin 50 km offshore in September with the Sankofa East X1 well.

Eni has immediately commenced plans for the commercial exploitation of the oil reserves.

The company has now completed the first appraisal well - Sankofa East 2A - which was drilled eight kms from the discovery well to a total depth of 4050 m water depths of 990 m. Eni said it struck a 76 m gross column of oil with 32 m of net pay in good quality Cretaceous sands. It also hit 23 m gross of gas and condensate, 17 me net pay.

The Italian now estimates that the discovery

New minister for energy and petroleum Eni’s recent discovery is important because it confirms the commercial standing of the oil discovery in the OTCP block and the strategic importance of the block for further industrial and economic development in the country.

holds 450mn barrels of oil in place of which 150mn barrels is recoverable. ‘The result is important because it confirms the commercial standing of the oil discovery in the OTCP block and the strategic importance of the block for further industrial and economic development in the country,’ a statement released early January read. The appraisal well confirmed the extension of the oil accumulation in the Cenomanian sequence.

‘The data acquisition confirmed the hydraulic communication in the oil prone reservoir between the discovery and the appraisal well. Eni has

Meanwhile, Ghana's president John Mahama has named Emmanuel Armah Kofi Buah as minister for energy and petroleum, promoting him from the deputy position he held for four years. Buah, a 46year-old management consultant by training, held management positions at the US Postal Service before returning to join Ghana's parliament in 2009.

He hails from the western region hosting Ghana's offshore Jubilee oil field. Many see his appointment as a move to appease local chiefs from the region. They had requested that a native of the area be the minister responsible for the sector after the government rejected their bid to be granted 10 per cent of oil revenues. ‘We see this appointment as a fair move by the president to ensure regional balance and continuity,’ said Franklin Cudjoe, director of policy watchdog IMANI Ghana. ■

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S08 ORA 1 2013 Geology & Gas News_Layout 1 01/02/2013 17:04 Page 33

Geology

S08 ORA 1 2013 Geology & Gas News_Layout 1 01/02/2013 17:04 Page 34

TGS starts 3D seismic offshore Liberia TGS HAS STARTED acquisition of a 3D multi-client survey, Sunfish, which covers up to 7,800 sq km of acreage in the Harper basin offshore Liberia.

TGS is chartering the 12-streamer Polarcus Asima for this survey for approximately six months. Data processing will be performed by TGS and will be available to clients in 4Q 2013, prior to the Liberia 2013 Bid Round.

The survey is supported by industry funding.

The bid round likely will include 13 ultra-deepwater tracts. The National Oil Co of Liberia (NOCAL) has reported that offshore there are currently 17 blocks, 12 of which are either under contract or in contract review.

“This survey provides excellent data coverage for the source prone, syn-rift and early post-rift sequences, in this highly prospective area offshore Liberia,” said Stein Ove Isaksen, SVP Eastern Hemisphere for TGS. “TGS has been active in acquiring data over the West Africa Transform margin for the past decade and this survey demonstrates TGS' ongoing commitment to grow the seismic data library in Africa.”

Chariot completes 3D offshore Mauritania CHARIOT OIL & GAS Ltd has completed a 3,500-sq km 3D seismic acquisition program offshore Mauritania.

The survey, in block C19, done by Fugro-Geoteam, targeted the southwest section of the block. Once the data has been processed, it will be interpreted with the aim of identifying drilling prospects.

Thombo starts 3D seismic acquisition, Block 2B, South Africa THOMBO PETROLEUM LTD has started its 3D seismic acquisition over the A-J1 graben in Block 2B, off the west coast of South Africa, using the WesternGeco ‘IsoMetrix’ marine isometric seismic technology. The survey is WesternGeco ‘IsoMetrix’ marine isometric seismic technology. intended to reveal the extent of the A-J1 oil discovery and to enhance the company’s understanding of the many other prospects and leads in the graben which have been identified from existing 2D seismic data.

Commenting on the start of the survey, Trevor Ridley, Managing Director and founder of Thombo, said: “Thombo has been very impressed by WesternGeco’s preparations for this cutting-edge survey and we look forward to its successful conclusion in February, subject of course to suitable weather and sea conditions. Our aim is to complete the work without leaving any trace of our presence on the marine environment. We have worked closely with WesternGeco and the Petroleum Agency of South Africa with this objective in mind and, on board, we are using specialist observors to ensure we pay due respect to other users of the environment, including marine mammals. ”.

Thombo is a privately-owned company with South African shareholders, including a previously disadvantaged shareholder and Director. The company has a 75 per cent interest in the Block 2B Exploration Right issued by the Petroleum Agency of South Africa in 2011. The balance of 25 per cent is held by Afren plc.

34 Oil Review Africa Issue One 2013

ARKeX FTG survey for Taipan in Kenya ARKeX, THE PROVIDER of non-seismic geophysical imaging services, has recently been awarded a contract by Taipan Resources Inc to acquire an airborne Full Tensor Gravity Gradiometry (FTG) survey over Block 2B onshore Kenya. The survey will be used to further assess the petroleum system and derisk any future exploration activities.

Block 2B contains both tertiary and cretaceous plays. The tertiary plays are analogous to the Tullow Oil and Africa Oil Ngamia-1 discovery located in the main Tertiary rift to the west.

“ARKeX and FTG have a long history in the region with numerous surveys conducted in Kenya, Ethiopia, Tanzania and Uganda,” said Paul Versnel, VP Sales at ARKeX. “The technology has been ideally suited to the geology and frontier nature of East African exploration. We are very pleased to be awarded the Taipan survey and look forward to sharing the interpreted results in due course.”

Mr. Maxwell Birley, CEO commented, "The Anza Basin is one of the largest tertiary-age rift basins of the East African Rift system which contains multi-billion barrel oil discoveries. We continue to believe based on existing gravity, magnetic and seismic data that the 'sweet spot' of the Anza Basin is located on Block 2B. Recent proprietary geochemistry work completed by Taipan also demonstrates that there is excellent quality tertiary oil-prone source rock present in the Anza Basin in the region of Block 2B."

Tanzania operators line up seismic surveys AMINEX IS PLANNING a 1,200-km 2D seismic programme over the deepwater area of the Nyuni block offshore Tanzania.

It is in discussions with seismic vessel contractors to perform the survey during 1Q 2013.

Earlier last year Aminex compiled 141 km of seismic data as part of a transition zone programme over the shallow waters, reefs, and islands of the Nyuni Area PSA, awarded in October 2011.

Operations had to be suspended in late June due to rough seas. The company is evaluating options for completing the survey in conjunction with the deepwater programme to cut costs.

Canadian company Antrim Energy has provided an update on another potential exploration campaign over the Pemba-Zanzibar exploration license offshore and onshore Tanzania, operated by RAK Gas. Antrim has negotiated a 20 per cent stake in the concession following the pre-drilling (seismic) phase and an additional 10 per cent interest to be exercised up to 180 days after receipt of initial drilling results.

RAK Gas has submitted a proposal for a revised work programme to the federal government of Tanzania.

Environmental impact assessment work has started, with seismic operations expected to proceed shortly.

S08 ORA 1 2013 Geology & Gas News_Layout 1 01/02/2013 17:04 Page 35

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Gas

S08 ORA 1 2013 Geology & Gas News_Layout 1 01/02/2013 17:04 Page 36

Bechtel awarded Mozambique LNG feed CONSTRUCTION GIANT BECHTEL has landed a front-end engineering and design contract for Mozambique’s first LNG terminal, the company said.

The initial phase of the plant in the Cabo Delgado province will have a capacity for five million metric tonnes per year, with future plans to produce 50mn metric tonnes per year.

The plant is planned for a 2018 startup.

"We are excited by the prospect of working with Anadarko and its partners to develop a world-class facility that will bring jobs and economic development to Mozambique," said Jack Futcher, president of the company's oil, gas and chemicals unit.

Bechtel is currently at work on four LNG complexes in Australia and one in the US. It has supplied 28 LNG trains in nine countries.

Two steps to first gas off Mozambique AMERICAN INDEPENDENT ANADARKO has taken the second major step towards a four train, 20mmtpa LNG plant from offshore Mozambique.

The company’s award of a front-end engineering and design (FEED) contract to a joint venture vehicle comprising Fluor and JGC came two weeks after it reached Heads of Agreement (HOA) with Eni, establishing foundational principles for the co-ordinated development of the common natural gas reservoirs spanning both Mozambique’s Offshore Area 1 (operated by Anadarko) and Offshore Area 4 (operated by Eni). Anadarko targets the first LNG cargo for 2018.

The facility will be located in the Cabo Delgado province, 2,000 km north-east of Mozambique’s capital, Maputo. Anadarko discovered massive reservoirs of gas in the Indian Ocean offshore Mozambique in early 2010. Eni arrived later, continuing the luck in a different block. Both companies are on record as saying that the reservoirs

Conceptual design of natural gas liquefaction facility in Mozambique.

are some of the largest discoveries in their portfolios in over 10 years.

New York-listed Fluor and Japanese firm JGC have a 50-50 partnership in the JV that won the FEED contract. They say they have “brought together a talented and experienced team that leverages the combined strengths of JGC’s industry-leading LNG experience with Fluor’s fifty-plus year reputation for executing large

Uquo reaches first gas

Bidders get more time for Ruvuma UK-LISTED AMINEX has extended the bidding period for the planned farm-out of its Ruvuma production sharing agreement onshore Tanzania.

The East Africa-focused company said it made the extension at the request of several interested parties which had already visited the data room.

Aminex said at the start of this month it had received “substantial interest” from both multinationals and national oil companies for a stake in the 6000-sq km licence, which contains the Ntorya-1 gas and condensate discovery made last year.

Bids were initially set to be made by 8 February but the bidding process is now likely to be completed in March.

“We are very pleased with the strong interest shown in our Ruvuma PSA and have decided to

complex projects in sub-Saharan Africa.”

The FEED will deliver designs for the initial phase of the project, which will consist of four trains, each capable of producing fivemillion tons a year of liquefied natural gas (LNG), culminating in 20-mn metric tons a year. The project has the potential to expand to a capacity of about 50mn metric tons a year of LNG.

keep the farm-out process open for longer than originally anticipated to accommodate a number of interested parties,” Aminex chairman Brian Hall said.

Aminex holds a 75 per cent stake in the Ruvuma PSA while partner Solo Oil holds 25 per cent.

The pair are looking to farm out half of their respective interests in the block, which sits on the Tanzanian border with Mozambique.

FRONTIER OIL-OPERATED Uquo field onshore south east Niger Delta basin flamed to life on the 29th of December 2012.

The company is now commissioning the 200mmscfd Uquo field Ekid gas plant.

Frontier Oil hopes to start commercial gas production to Ibom Power, through the 66km Accugas pipeline (operated by Seven Energy) by end January 2013. The Uquo Field is a gas field with an oil rim. Frontier anticipates that production from the oil rim will commence around end of March 2013.

Victoria finds more customers for Cameroon gas WEST AFRICA-FOCUSED Victoria Oil & Gas (VOG) has announced that 15 customers are now taking gas from its Logbaba field in Cameroon. The firm said that since its last update in midDecember a further four customers have been

36 Oil Review Africa Issue One 2013

commissioned and begun gas consumption, while another 10 contracted customers are awaiting conversion of their facilities to take gas.

VOG said that weighted average production is currently 2.8mn scsfd for a standard operating

week. The company, through its wholly-owned subsidiary Rodeo Development, holds a 95-per cent interest in Logbaba and is the operator.

VOG added that it has identified more than 60 prospects for gas as well as on-site gas-fired power

demand along the existing and planned route of its pipeline.

The firm also announced that Société Générale has committed to a lending facility of US$15mn, which VOG believes will satisfy a substantial part of its future funding requirements.

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For AMOSCO, quality is first priority VALUE, DEFINED HERE as offering a high quality service at a fair price, is an important consideration for both providers and end users within a number of service industries. Yet within competitive markets, the temptation for service providers to manipulate the value proposition in favour of offering low prices at the expense of quality is clear. In this respect, the oil and gas inspection industry within Africa is no exception.

For AMOSCO however, an oil and gas inspection company with over 30 straight years of experience working within Africa, the importance of avoiding this temptation in favour of providing a true value offering cannot be overstated.

“The oil and gas inspection business in particular is one where an emphasis on providing a high quality service to clients at all times, and at a correspondingly fair price, is paramount”, said Joe Graham, AMOSCO’s Regional Manager for Africa. “When you consider, for instance, that daily rental rates for some rigs range from several thousand to in some cases several

hundred thousand dollars, the proper inspection of items such as drill pipes, tubing and casing is not an area where you can afford to cut corners under any circumstances. Naturally, the provision of true quality comes at a cost, but our clients appreciate our sustained commitment to striking a genuinely fair balance”.

AMOSCO has, in recent times, further strengthened its commitment to service quality via the creation of a specific quality oversight

manager for Africa role, a position now occupied

by Shibin Surindran. Charged in particular with ensuring that existing quality best practices, knowhow and synergies within and between AMOSCO’s various operations in Africa are maintained and wherever possible enhanced, Surindran is acutely aware of the profound significance of high quality inspection work. “The importance of quality to inspection work is well understood and embodied by all our staff, the majority of whom have been with us for many years. We all understand that the smooth and efficient discovery and production of oil and gas is key to society’s functioning, and that the oil and gas inspection business has an integral role to play in this respect. From the most basic to the most complex of tasks, we place great emphasis on accuracy and efficiency in all our work in order to safeguard our clients’ assets, and ensure the safety of their personnel. This has been a key facet of our sustained success over the years, and I have every confidence that this will continue to be the case moving forward”.

Oil Review Africa Issue One 2013 37

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Africa Oil begins drilling Sabisa well AFRICA OIL CORPORATION has launched drilling operations on the Sabisa-1 well in the South Omo Block in Ethiopia The company has said that the drilling will take approximately 60 days to reach the planned total depth of 2,600 m.

Africa Oil has a 30 per cent working interest in the block, with Tullow having a 50 per cent interest and Agriterra Limited holding the remaining 20 per cent interest. Marathon Oil Ethiopia BV has, however, announced a transaction to purchase Agriterra’s interest in the South Omo Block.

The South Omo Block is located in the northern portion of the Tertiary East African Rift, where Africa Oil and its partner organisation, Tullow, have made two significant discoveries in the Lokichar Basin of Kenya.

The Sabisa well has similar structural features as the two discoveries in Kenya.

Africa Oil president Keith Hill said, “This is an exciting well which has the potential to de-risk a large portion of our current portfolio of prospects. With the exploration campaign planned with our partners, Tullow and Marathon, in 2013, we will have the opportunity to change the profile of the company in the coming year. With our recent financing completed, we are well situated to execute exploration campaigns in East Africa.”

Uganda to auction 13 oil blocks in 2013 THE UGANDAN GOVERNMENT is planning to auction at least 13 oil blocks in the Albertine Rift Basin this year as soon as the government lifts a ban on the licensing of new acreage, according to Uganda's junior energy and minerals minister.

Peter Lokeris said the planned auction will allow international oil companies to bid for exploration acreage in the basin, where existing companies have discovered deposits of as much as 3.5bn barrels of crude oil.

The government has demarcated a total of 17 oil blocks in the region, Mr. Lokeris said. Four of the blocks were licensed before Uganda imposed a licensing ban on new acreage in 2007. The remaining blocks will be auctioned as soon as President Yoweri Museveni enacts a

new law lifting the licensing ban.

"Competitive rounds for new acreage will be guided by the new petroleum...some of the acreage previously licensed to oil companies has been returned to government through relinquishment requirements and the expiry of licenses," Mr. Lokeris said on the sidelines of an oil conference in Kampala.

The licensing round will be Uganda's first since it imposed the ban in 2007, which was put in place following the confirmation of commercial oil reserves. Oil exploration companies have since made a flurry of discoveries in the country, increasing the size of Uganda's oil reserves from around 300mn barrels in 2006 to 3.5bn barrels to date.

Mr. Lokeris said oil exploration

companies operating in the Lake Albertine Rift Graben have had a success rate of around 87 per cent, finding oil in 76 oil wells out of the 87 wells drilled so far.

"Preparations for development of some of these discoveries is ongoing before production can commence...This is an exciting time for the country," he said.

Companies with licenses in the country so far include Tullow Oil, Total and Cnooc. The three companies are planning to invest around US$10-12bn to develop oil fields in four blocks as Uganda continues plans to join the ranks of African oil producers.

Companies such as Eni, Lukoil Holdings, and Essar Oil have expressed interest in acquiring oil licenses in the country.

Tullow to step up Kenyan exploration UK-BASED OIL company Tullow Oil has said it has plans to step up exploration activity in Kenya in 2013 Tullow chief executive Aidan Heavey said, “We have had significant exploration success [with two frontier discoveries at Ngamia-1 and Twiga South1] in establishing Kenya as a new hydrocarbon province and continued to add to and mature our exploration portfolio in the country.”

The oil firm revealed that it now has plans to carry out 11 further explorations in Kenya and Ethiopia in 2013.

Tullow informed that the planned exploration and appraisal wells include the “high risk Paipai-1 wildcat in Block 10A, which is currently in the top seal of the main objective at a depth of 3,850 metres”.

The oil giant has also started a testing programme

at Twiga South-1 in Kenya to build up knowledge of the natural variance in reservoir performance.

Tullow added, “Test flow rates are not expected to exceed 500bpd per interval due to limits of the test equipment, reservoir energy and reservoir quality.”

To date, five tests have been planned by the company in 2013, with three in the Upper Lokhone reservoir. Operations will also include drilling Etuko-1 well on what was formerly known as the Kamba prospect, and flow testing Ngamia-1.

Tullow said the discoveries, its successful exploration in Uganda, and recent major offshore gas discoveries by its industry peers have established East Africa “as an exciting new energy region”.

Total to retain major oil license in Uganda TOTAL IS SET to retain a major oil license in the northern section of Uganda's oil-rich Lake Albertine Rift basin, after striking a new oil discovery following months of extensive drilling activities, company and government officials have said.

The development is a major boost for the prospects of the company's operations in Uganda, where the exploration license for the block, known as 1A, where the discovery was made was due to expire next month.

Honey Malinga, the assistant commissioner at Uganda's state-run Petroleum Exploration and Production Department, said that the discovery would also boost the size of the country's crude reserves, currently estimated at 3.5bn barrels.

"Total will automatically retain the license, we have asked them to apply for an appraisal and production license for the block," Mr. Malinga said.

38 Oil Review Africa Issue One 2013

Company spokesman Florent Segura said that the discovery requires further appraisal to determine its potential. Details about the size of the discovery are expected in the next few weeks.

Uganda is set to join Nigeria, Angola and Sudan among sub-Saharan Africa's major crude producers after a series of huge oil discoveries along its western border with Congo.

Total co-owns the license with China's Cnooc Ltd and Tullow Oil. According to Mr. Malinga, Total had drilled three dry wells in the block before striking oil in the fourth late December.

Total said early last year that it would spend US$300mn on exploration and appraisal programmes in Uganda.

In October, Uganda took back control of another oil block, Kanywataba, from the three

joint-venture partners after their exploration license expired before a discovery.

Tullow had controlled the entire oil acreage comprising three oil blocks in the Lake Albert area until February last year, when the government finally approved a long-delayed US$2.9bn deal to split the oil licenses with Cnooc and Total.

Total operates blocks 1 and 1A located in the northern section of the rift basin and block 2, which straddles Uganda's Hoima and Bulisa districts, and Cnooc operates the Kingfisher oil fields located at the southern tip of Lake Albert.

The three companies are expected to invest around US$10-12bn to develop the oil fields, but they remain embroiled in a spat with the government over the fields' development plans and refining options, which continue to push back the planned start of production.

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Pura Vida buys stake in Gabon PURA VIDA ENERGY has confirmed its entry into the oil and gas exploration hotspot of Gabon, as the Perth-based junior is set to count a list of major international energy giants among its new neighbours.

Pura Vida, which was Australia's most successful initial public offering of last year, will pay US$9.4mn for an 80 per cent stake in the Nkembe block off Gabon's coast. The company said Nkembe was "surrounded by oilfields" and offers strong potential for future oil discoveries.

The deal represents Pura Vida's first attempt to repeat its recent success in Morocco.

Earlier this year, the company struck a US$230mn deal for US-based Plains Exploration & Production to drill two wells on Pura Vida's Mazagan project off the Moroccan coast.

French oil and gas major Total already has producing oilfields in the waters off Gabon, while Japan's Mitsubishi recently made a discovery in the block immediately north of Nkembe.

International giants Royal Dutch Shell and Petrobras are also actively exploring off Gabon.

African Petroleum resumes oil hunt offshore Liberia THE SEMI-SUBMERSIBLE EIRIK Raude has spudded the Bee Eater-1 exploration well on block LB-09 offshore Liberia for operator African Petroleum Corp.

The location is 9.5 km northwest of African Petroleum’s 2012 Narina-1 well, which discovered oil in Turonian reservoirs. Bee Eater-1 will test a potentially westerly extension of Narina-1 in an axial position of the fan for improved reservoir quality, updip of the presumed Narina-1 oil/water contact.

Prospective resources for the Bee Eater/Narina fan system, which extends over an area of 300 sq km, are estimated at 840mn barrels, with a further 2.396 barrels potentially in additional prospects on blocks LB-08 and LB-09.

After completing Bee Eater-1, Eirik Raude will drill another well – various locations are under consideration in both blocks.

African Petroleum is negotiating to bring in PetroChina as a 20 per cent partner in LB-09. It is also in discussions with other major international oil companies on various exploration blocks off Côte d’Ivoire, Liberia, Gambia, and Senegal.

Farm-out negotiations are expected to be completed during the current quarter, providing funds for further wells in 2013 and 2014.

Oil Review Africa Issue One 2013 39

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Namibia regulators approve stake sale to GALP BRAZILIAN OIL STARTUP HRT Participacoes em Petroleo has said that Namibia's Mines and Energy Ministry approved the sale of a stake in three offshore blocks to Portugal's Galp Energia.

In the deal, first announced in November, the two companies said that Galp had acquired a 14 per cent stake in the three exploration blocks in return for covering a portion of drilling costs.

The deal helps clear the way for HRT to start drilling in the highly prospective region off Namibia's coast, which geologists believe could hold an area similar to Brazil's subsalt because the two areas were connected millions of years ago. Billions of barrels of crude oil were discovered under a thick layer of salt

in the Atlantic Ocean off Brazil.

"We can confirm we will commence operations in [first-quarter 2013] for our exploratory campaign

in Namibia," HRT Chief Executive Marcio Rocha Mello said in a statement. Earlier this month, HRT received the drilling rig, the Transocean Marianas semi-submersible, that will be used to drill exploration wells in the offshore blocks.

The rig, transferred in Ghana waters, will take three weeks to reach Namibian waters, and then undergo an additional 21 days of testing.

The goal is to get the rig on location and prepared to drill the Wingat prospect in the Walvis basin by the end of the first quarter, HRT said.

Wingat lies in about 1000 m of water in the PEL-23 block. The wildcat is expected to take about 60 days to drill.

Jasper secures contract off Congo JASPER INVESTMENTS LTD has announced that its subsidiary, Jasper Drilling Pte Ltd, has signed a contract with CNOOC Congo SA for the deployment of the drillship, Jasper Explorer. Under the contract, the Jasper Explorer will drill two firm wells plus one option well in offshore

Republic of Congo, West Africa. The programme duration for the two firm wells is anticipated to be about 100 days excluding any well testing.

Contract commencement is in the first half of March 2013 when the rig is expected to depart from its current location in Spain. Drilling is expected

to start late March 2013.

The estimated contract value, based on the programme duration for the two firm wells plus mobilisation and demobilisation fees, is approximately US$33mn.

Tullow extends West Leo contract

BP starts Angola production

TULLOW PLC HAS exercised its contractual option to extend the contract for the rig West Leo (UDW semisub) by two years from May 2016 to May 2018. The West Leo is expected to carry out operations in West Africa until the end of its contract in May 2018.

The potential contract revenue for the extension is estimated to approximately US$450mn based on 97 per cent utilisation and includes a performance bonus arrangement. This brings the total estimated contract value to US$1.13bn.

Seadrill took delivery of West Leo in early 2012 from Jurong Shipyard. The semi, based on the Moss Maritime CS50 Mk II design, has been under contract with Tullow and working offshore Ghana since April 2012.

BP HAS STARTED production from one of the largest subsea developments in the world as flows from the PSVM development off Angola got under way.

Production from the development in Block 31, operated by the UK supermajor, is set to hit 70,000 bpd of oil before more than doubling over the coming year as two other fields come on line.

PSVM is being exploited with a Modec-owned floating production, storage & offloading (FPSO) vessel, with four different fields involved. The unit has 1.6 million barrels of storage capacity and is the first FPSO to work Angola's ultra-deepwater plays.

Initial production is coming from the Plutao field before the Saturno, Venus and Marte fields come onstream.

BP chief executive said: “PSVM is one of the largest subsea developments in the world and was one of BP’s key project start-ups for 2012 as we grow higher-margin production.

"Over the coming decade, we expect Angola, where we have extensive interests from exploration through to production, to be one of the main hubs delivering growth for BP.” The development consists of the four fields which were discovered between 2002 and 2004 in water depths of up to 2000 metres. A total of 40 production, gas and water injection wells will be connected to the FPSO through 15 subsea manifolds and associated subsea equipment.

BP operates the block with a 26.67 per cent stake with Sonangol's stake of 45 per cent split between two divisions, Statoil on 13.33 per cent, Marathon on 10 per cent and SSI 31 on five per cent.

Sonangol Exploration & Production is the concessionaire.

The West Leo rig.

40 Oil Review Africa Issue One 2013

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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.

Our Services include: Basic Offshore Safety Induction Emergency Training (BOSIET), viz: Offshore/Onshore Induction Training Helicopter Underwater Escape Techniques (HUET) Survival at Sea (SAS) Basic Fire Fighting Basic First Aid Others are: International Minimum Industry Safety Training (IMIST) Advanced Fire Fighting AED & Advanced First Aid Breathing Apparatus Wearers' Course Confined Space Entry Helicopter Landing Officer (HLO) Helicopter landing Assistant (HLA) Helideck Fire Fighting Helideck Team Member Training Offshore Lifeboat Coxswain Personal Survival Swimming Search and Rescue Standby Fire Watch Swing rope Transfer STCW 95 Further Offshore Emergency Training (FOET) Dangerous Goods Awareness Training Proficiency in Survival Craft and Rescue Boats (PSCRB)

E&P

S09 ORA 1 2013 E&P_Layout 1 04/02/2013 11:59 Page 42

Dana to move forward with Nefertiti

Chevron signs petroleum deals off Morocco

DANA PETROLEUM HAS been given the go-ahead by the Egyptian government to further develop the Nefertiti oil field in the Gulf of Suez following the successful completion of an appraisal well.

The Aberdeen-based oil and gas company, in partnership with INPEX, successfully drilled the exploration well Nefertiti-2X at the end of 2012. The well tested at a maximum stabilised flow rate of 1,850 barrels per day (bpd) with an electrical submersible pump (ESP), and the field is expected to produce around 2,500 bpd (1,625 bpd net to Dana) when it comes on stream in around six months.

Following the successful appraisal, the two companies agreed with the Egyptian General Petroleum Company in November 2012 that the Nefertiti field was a commercial field. Eng. Osama Kamal, Minister of Petroleum and Mineral Resources, approved the lease on 20 January, 2013.

Dana’s Managing Director in Egypt Nick Dancer said, "The Nefertiti field is a first for Dana in that it is an offshore field that we have explored by drilling extended reach wells from an onshore location. Whilst increasing the complexity of the wells, it reduces the drilling and subsequent development costs and reduces development time as well as protecting the offshore environment including a number of coral reefs. I’m delighted we’ve been given the green light to progress the development, and also undertake further drilling in the area to test a different play concept in the Nefertiti Field."

CHEVRON CORP HAS signed petroleum agreements related to three offshore areas in Morocco, a push to expand its footprint in frontier basins.

The oil and gas company has signed the agreements with Morocco's Office National des Hydrocarbures et des Mines which, once awarded, will allow Chevron to acquire seismic data and conduct studies in deepwater areas known as Cap Rhir Deep, Cap Cantin Deep and Cap Walidia Deep located between 97 km and 193 km west and northwest of Agadir, Morocco. The areas encompass about 29,267 sq km with average water depths ranging from between 100 and 4,480 metres.

"This is an opportunity for Chevron to expand its already strong presence in the region and allows us to acquire further knowledge about promising geology in an emerging area," said Ali Moshiri, president of Chevron Africa and Latin America Exploration and Production Co. Chevron has a 75 per cent working interest in the three areas, with the Office National des Hydrocarbures et des Mines holding the remaining 25 per cent.

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42 Oil Review Africa Issue One 2013

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Tel: (+234) –(0) 1 – 4627763 (+234) –(0) 1 – 4627764 Email: info@ieslglobal.com WARRI FIELD OFFICE Suites I & II, Jeffia Estate, PTI Road Effunrun, Warri, Delta State Tel: (+234) 803 548 2518 Email: warri@ieslglobal.com PHC OFFICE 34, Old Aba Road, Rumu Omasi Area P.O. Box 12837, Port – Harcourt, Rivers State Tel: (+234) –(0) 84 – 772158 Email: portharcourt@ieslglobal.com

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S09 ORA 1 2013 E&P_Layout 1 04/02/2013 11:59 Page 44

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.

December 2012 - Oil & Gas THIS MONTH Country ALGERIA ANGOLA CONGO GABON KENYA LIBYA NIGERIA SOUTH AFRICA TUNISIA OTHER Total

Oil 26 7 2 6 0 15 10 0 1 12 79

Gas 10 0 0 0 0 0 3 0 0 1 14

Misc 2 0 0 0 3 0 0 0 1 3 9

LAST MONTH Oil 23 7 2 5 0 14 10 0 1 12 74

Gas 13 0 0 0 0 0 2 0 1 1 17

Misc 1 0 0 0 3 0 1 0 2 4 11

LAST YEAR Oil 23 8 2 6 0 0 14 0 1 9 63

Gas 9 0 0 0 0 0 2 0 0 0 11

Misc 1 0 0 0 1 0 1 0 0 2 5

Source: Baker Hughes

Vanoil receives extension on Kenya PSC

Vanoil extends agreement with Rwanda

VANOIL ENERGY HAS reported that the Kenyan Ministry of Energy has extended the deadlines within which Vanoil must satisfy the work programme obligations defined in its Production Sharing Contract (PSC).

Previously, Vanoil was obligated to finish drilling its first well by 30 April 2013. Now, under the terms of the latest extension, Vanoil must only commence drilling its first well before 31 July 2013 and, with sufficient technical justification, Vanoil may place its first two wells anywhere within the boundaries of Block 3A and 3B to satisfy the work programme obligations within the Initial Exploration Period of its PSC. Aaron D'Este, the company's president and CEO, stated: "We were very pleased to secure this key extension. Vanoil is the first company to complete 3D seismic onshore in Kenya and our exploration programme is among the most robust ever completed in country. The time extension granted to Vanoil allows us to fully realise value from our 3D data and to drill our first two wells in rapid succession. The ability to place both wells anywhere within the boundaries of 3A and 3B also gives Vanoil the flexibility to target its most exciting prospects. We view 2013 as a transformational year for the company and we now have the time and operational flexibility to extract maximum value from our assets.�

VANOIL ENERGY HAS executed a two-month extension to its Technical Evaluation Agreement with the Rwandan Ministry of Natural Resources.

The agreement provides Vanoil with the exclusive right to negotiate a Production Sharing Contract (PSC) covering approximately 1,631 sq km of the East Kivu Graben, located beneath Lake Kivu, Rwanda

44 Oil Review Africa Issue One 2013

Eco inks joint operating agreements for offshore Namibia ECO (ATLANTIC) OIL & Gas, through its wholly- owned subsidiary, has signed three joint operating agreements with NAMCOR, the National Petroleum Corporation of Namibia, and Azimuth Ltd, an exploration and production company backed by majority-owner Seacrest Capital Ltd. and Petroleum Geo-Services ASA (PGS).

The agreements were signed with respect to the Guy, Sharon and Cooper license blocks located in the prospective Walvis Basin offshore Namibia.

Colin Kinley, chief operating officer of Eco Atlantic, from the company's Windhoek office in Namibia, commented: "The Agreements signed by NAMCOR and Azimuth will enhance the exploration efforts of our three offshore blocks. We support the maturity of the partnerships, and embrace the opportunity to work with experts at NAMCOR and Azimuth. Collectively, we bring extensive oil and gas experience to the Walvis Basin. We understand this oil play and the significant potential it has and look forward to working collaboratively with both companies to continue our exploration work in the Walvis basin, where significant drilling activities are scheduled for 2013 commencing this quarter."

Obeth Kandjoze, managing director of NAMCOR, commented: "We are very pleased to sign the Joint Operating Agreement with Eco Atlantic and Azimuth on the Sharon, Cooper and Guy licenses offshore Namibia. The partnership brings significant offshore oil and gas experience which will no doubt assist in the exploration and development of the licenses in the prospective Walvis Basin. This agreement also signifies the international support and interest in the development of Namibia's oil and gas resources.""

S10 ORA 1 2013 Offshore Survival_Layout 1 04/02/2013 12:42 Page 45

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The Group

S10 ORA 1 2013 Offshore Survival_Layout 1 04/02/2013 12:54 Page 46

Project Databank & Project Focus Compiled by Data Media Systems

OIL, GAS AND PETROCHEMICAL PROJECTS Project ADDAX - Oron Redevelopment & Extension Bauchi International Airport BRASS LNG - Brass River LNG Plant CHEVRON NIGERIA - Escravos Gas-to-Liquids (GTL) Project CHEVRON TEXACO - Agbami Oil Field Development Ebok Development FLEX LNG - LNGP1 (Floating LNG Production)

Sector Offshore Infrastructure Gas Gas

Facility Budget Oil & Gas Field 400000000 Airport 70000000 Liquefied Natural Gas (LNG) 3500000000 Gas to Liquids (GTL) 1700000000

Status EPC EPC EPC ITB EPC

Start Date Q3-2005 Q4-2010 Q4-2004 Q3-2001

Completion Date Q4-2012 Q3-2013 Q4-2017 Q4-2013

Offshore Oil Offshore

EPC EPC EPC

Q1-1998 Q2-2007 Q1-2006

Q4-2014 Q4-2013 Q4-2015

FPR - Araromi Refinery Project Kita Marine Oil Field - OML 123 MART RESOURCES Umusadege Field Development Njaba Oil Field - OML 124 NNPC - Olokola LNG (OKLNG) Plant Ofon Field Development Phase 2 Okoro and Setu Fields Development Okwok oil field - OML 67 Owowo Oil Field - OPL 223 OYO Field Development Southern Swamp Associated Gas Solution Project (SSAGS ) Stubb Creek Field TEPN - Nkarika Field TOTAL - CONOIL - OML 136 Development TOTAL - Egina Field Development TOTAL - OML 58 Upgrade Phase 1 TOTAL - OML 99 Ikike Field YFP - Aje Blk OML 113

Refining Oil Oil

Oil Field 5000000000 Oil Field Development 450000000 Floating Production 500000000 Storage and Offloading (FPSO) Refinery 3000000000 Oil Field Development 350000000 Oil & Gas Field 500000000

FEED EPC EPC

Q2-2010 Q4-2007 Q4-2008

Q4-2017 Q4-2015 Q4-2014

Oil Gas Offshore Offshore Oil Oil Offshore Gas

Oil Field Development 150000000 Liquefied Natural Gas (LNG) 20000000000 Offshore Platform 500000000 Oil Field Development 450000000 Oil Field Development 400000000 Oil Field Development 250000000 Oil Field Development 1000000000 Gas Production 1000000000

EPC EPC ITB EPC EPC EPC EPC EPC EPC

Q1-2008 Q1-2005 Q2-2007 Q3-2006 Q1-1968 Q3-2005 Q1-2006 Q1-2011

Q4-2015 Q1-2016 Q1-2015 Q4-2013 Q4-2015 Q3-2015 Q4-2014 Q1-2015

Oil Offshore Oil Oil Oil, Offshore Offshore Offshore

Oil Field Development Offshore Platform Oil Field Development Oil Field Development Oil & Gas Field Offshore Platform Offshore Platform

EPC EPC EPC EPC EPC EPC EPC

Q4-2003 Q1-2001 Q3-2007 Q4-2003 Q1-2006 Q2-2009 Q4-2004

Q3-2012 Q4-2014 Q1-2017 Q4-2015 Q2-2013 Q4-2015 Q4-2014

200000000 11000000 300000000 2000000000 1000000000 12000000 10000000

Project Summary Project Name

Ofon Field Development Phase 2

Status

EPC

Name of Client

EPNL- Elf Petroleum Nigeria Ltd

Start Date

Q2-2007

Budget ($US)

500,000,000

End Date

Q1-2015

Award Date

Q4-2011

Location

Ofon, Nigeria

Facility Type

Offshore Platform

Project Status In May 2007, Technip was awarded a turnkey contract by Total Exploration & Production Nigeria Ltd for the loadout, transport and installation of the topsides of the OFP2 fixed platform on the Ofon field. 19 July 2007, Nigerian National Petroleum Corporation (NNPC) and Total, through its subsidiary Elf Petroleum Nigeria Limited, announced the launch of the Phase 2 of Ofon Field Development Project. The new phase of the field development project will eliminate gas flaring in Ofon, in line with the policy of the Federal Government of Nigeria, and give support to the NNPC/EPNL Joint Venture meeting its gas commitments.

Gas will be monetised through the NLNG plant. In addition, all produced water will be reinjected into the reservoir. Akmos Global Services has been responsible for the supply of maintenance spare parts for the Ofon platform, which is offshore. Aibel is working on the design of five new platforms, major modification of three existing platforms and required pipelines and cables. In addition Aibel is conducting preparatory work for long lead equipment and EPC contracts. In October 2011, Saipem was awarded the contract to provide EPC, fabrication and installation of the OFP2 jacket and a living quarter platform for phase 2.

Fabrication of the 900m, 1,970t jacket and 4,500t piles will take place in Rumuolumeni Yard in Port Harcourt. The vessel Saipem 3000 will provide offshore activities when the project comes on line. In Q4 2011, Eiffage Construction Mallique was awarded a US$424mn Engineering Procurement Construction and Commissioning (EPCC) contract for the OFON

Phase II. The AVEON Offshore has been awarded a contract by Eiffage Construction Metallique for the fabrication of some major components of the LQ Platform for Ofon Field Development Phase 2. In February 2012, construction and installation works were started.

Eiffage Construction Metallique is constructing the platform from standard building blocks to be deployed in Oil Mining Lease 102, some 65km off the Nigerian coast, in water depths of 40 m. The platform will accommodate up to 140 personnel, generating around 45 cmpd tonnes of waste water. Engineering work will be done by Sofresid in Lorient and OOP in Lagos. A consortium of Actemium Oil & Gas Engineering (AOGE) and Yokogawa was selected for providing the detailed engineering, functional analysis, HIPS detail studies, instrument data base management, supply of machines vibration monitoring system and electrical network power shading 5,000 I/O. Nexans will provide Halogen-free, thermoset compound SHF2 or XLPE low smoke PVC outer sheath to reduce gas flaring. The project is scheduled to come on stream in 2014. In August 2012, Hamworthy was awarded a contract to supply sewage treatment facilities to the Eiffage to use on Ofon Field Development Phase 2. The ST50C treatment plant has been designed to operate within harsh offshore conditions in both a hot and humid salty environment, where it will also be subject to sand-laden winds.

Incorporating pumps, blowers and instrumentation, the stainless steel unit will be designed, constructed and tested at Hamworthys factory in Poole.

Nigerian National Petroleum Corporation and Total have launched Phase 2 of the Ofon Field Development Project.

S10 ORA 1 2013 Offshore Survival_Layout 1 04/02/2013 12:42 Page 47

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Safety and Security

S10 ORA 1 2013 Offshore Survival_Layout 1 04/02/2013 12:42 Page 48

ATA International looks at safety in the oil and gas environment, offshore safety training, why this is so important and what training is needed.

Offshore survival course gains popularity

in O&G sector This course is specifically designed for oil and gas companies that have staff members manned on an oil-rig platform.

I

NDUSTRIAL OPERATIONS CAN ensure that the dangers and perils faced on offshore sites can be significantly reduced, by ensuring that employees undergo comprehensive Offshore Survival Course (OSSC) training provided by occupational health and safety expert Action Training Academy (ATA), in collaboration with the Cape Peninsula University of Technology (CPUT).

Offshore survival training comprises a basic introduction to safety, working procedures and legislation in the offshore industry. The five day training course, which takes place in Cape Town, covers all aspects of offshore survival, including; practical water survival, helicopter underwater escape training (HUET), basic fire fighting and first aid awareness.

ATA International business development manager Nicole de Montille said: "This course is specifically designed for oil and gas companies that have staff members manned on an oil-rig platform for more than 24 hours at a time. Due to the highly specialised nature of the training, we run the course in collaboration with the Cape University of Technology, at its Survival Centre."

De Montille noted that the first two days of the training are theoretical, where trainees learn the basic principles of survival in a classroom-based environment. "Offshore workers are usually anywhere between 30 minutes and two hours away from the nearest land-based facilities, and it is therefore vital to understand the basic principles of survival in an emergency situation. This includes evacuation, first aid and basic fire fighting."

Theoretical and practical training Following the theoretical training, de Montille highlighted the fact that trainees undergo an intensive three day practical training session. This includes HUET* training, whereby the trainees are strapped into a simulated helicopter cabin, before being dropped into a swimming pool.

48 Oil Review Africa Issue One 2013

The standards of offshore survival training are exceptionally high, and no compromises are made whatsoever.

"This type of escape training teaches trainees how to stay alive in a tropical oceanic environment by learning to identify the nearest point of exit and how to swim away. They are placed upside down in the dark in order to learn how to survive, even in the most disorientating scenarios," she continued.

What's more, trainees also receive hands-on fire fighting training, which is a fundamentally important aspect of offshore survival training, as quick and effective control of a fire can avoid a potentially catastrophic disaster.

De Montille highlighted the fact that physical fitness is a prerequisite for all trainees. "The standards of offshore survival training are exceptionally high, and no compromises are made whatsoever. If a person fails the practical, they simply will not be certified to go offshore.

With this in mind, a trainee must be fully selfsufficient and healthy to qualify for this course, as offshore platforms are one of the most dangerous working environments in the world."

First-class training facilities in Cape Town According to de Montille, ATA's OSSC training has proven to be highly popular among large corporations based in the USA, Europe and Asia.

"The training facilities at the Cape Peninsula University of Technology are world class, and this has resulted in exceptionally high demand for the course. We do, however, only have the capacity

International students attending to an emergency.

for 12 trainees per class, so placements are limited, and courses are booked out far in advance."

In addition to providing comprehensive health and safety training, ATA also arranges all transport and accommodation on behalf of its students, in order to streamline the entire process. de Montille added: "Assisting students who are in a foreign country is a major valueadded service offered by ATA, as it eliminates the stress associated with extensive travel before undergoing a major training exercise."

As the OSSC training course continues to gain popularity, de Montille remains confident of the future outlook for ATA. "As investment in oil and gas continues to rise, so too does the number of people working on offshore rigs. Corporations are also becoming more conscious of worker safety, and I believe that ATA has placed itself in a strong position as the preferred supplier of training to this constantly expanding industry moving forward," she concluded.

*HUET is the acronym for Helicopter Underwater Escape (or Egress) Training which offshore workers have to undergo as part of the requirements for working on offshore platforms and oil rigs. â&#x2013;

S11 ORA 1 2013 Technology_Layout 1 01/02/2013 14:47 Page 49

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S11 ORA 1 2013 Technology_Layout 1 01/02/2013 14:47 Page 50

Oil Spills

Only the reality of a spill can test a response strategy, though Africa, in conjunction with the multinational operators that work there, has taken steps to prepare for such an eventuality.

Offshore companies vigilant to Africa

oil spill threat E

VER SINCE THE 2010 Deepwater Horizon disaster in the Gulf of Mexico, oil spills and, more importantly, how to prevent them - have been top of the agenda among the world’s major energy companies.

They always were, of course, but the high profile nature of the US tragedy, which left 11 people dead, reminded everyone just how bad things can get.

An estimated five million barrels of crude oil spewed into the Gulf from the broken Macondo well in the ensuing weeks and months, taking its toll on the wildlife of the area and the natural environment.

Africa, fortunately, has not yet experienced anything on that sort of scale, nor the intense level of public scrutiny that followed from media crews and angry politicians.

Whether Africa’s oil producers could respond with the same vigour of BP, hounded vociferously by US officials and citizens alike, has yet to be tested.

International standards Of course, many of the big operators working in Africa’s offshore industry are those with a footprint in other key producing regions of the world, such as the Gulf of Mexico.

One of them is again BP, which has a strong presence in Angola, a country that has blazed a trail for West Africa’s booming deepwater sector.

BP, which has undertaken a great deal of soul searching in the wake of the Deepwater Horizon spill, along with the contractors it works with, insists its safety and integrity procedures are the same anywhere in the world.

Other big deepwater operators - Chevron, Total, Exxon, Shell, and the vast army of international contractors they all employ - likewise follow the same guidelines across all markets, and have access to the very latest and advanced industry technology.

To date, in Angola, nor elsewhere on the continent, there has been nothing like a spill of the severity of the Macondo slick for any of them to contend with.

Bonga leak But that is not to say there have not been any leaks: there have, and lots of them.

The worst upstream spill Africa has faced is probably Nigeria’s deepwater Bonga oil leak, a field operated by Shell Nigeria Exploration and Production Company (SNEPCo).

The leak, which took place at the end of 2011 during a transfer of oil to a tanker from Bonga’s floating production, storage and off-loading (FPSO)

50 Oil Review Africa Issue One 2013

Shell's oil spill off Nigeria's coast

The worst upstream spill Africa has faced is probably Nigeria’s deepwater Bonga oil leak in 2011. vessel, led to 40,000 barrels of crude being dumped into the Atlantic Ocean.

In this case, SNEPCo’s Oil Spill Response Procedure, and its Emergency Response Team, were immediately activated to manage the situation.

A remotely operated vehicle (ROV) was used to identify the source of the leak, which originated from one of three loading lines linking the FPSO to an intermediate buoy, which in turn is linked to the loading tanker. The spill was contained before it reached the shore and production was re-started from the Bonga field less than two weeks later.

Shell also deployed a giant Hercules C-130 aircraft to deliver airborne dispersants to the area of a suspected third party oil spill, which was identified in a separate location nearby in the wake of the Bonga clean up.

Nonetheless, Nigeria's oil regulator has still asked Shell to pay as much as US$5bn in damages, a fine that the company contests.

Onshore spills Most previous oil spills in Nigeria and elsewhere have been smaller and onshore.

Many of these have been caused by sabotage or militant attacks, particularly in Nigeria’s troubled Niger Delta region.

SPDC has made huge efforts to be transparent

with regard to these and any other spills, publicly reporting oil spill statistics annually since 1995.

For most of the last five years, there have been between 150 and 200 separate spills recorded by Shell Petroleum Development Company (SPDC), the country’s biggest single oil producing joint venture, the majority the result of sabotage.

The cumulative loss from all recorded oil spills each year is generally small, between 10,000 barrels and 30,000 barrels.

In 2008 and 2009, however, the losses spiked to 100,000 barrels each year, as tensions in the Delta intensified and sabotage attacks became routine.

As part of its spill response, Shell continuously monitors for leaks in the delta and responds to anomalies where necessary, following a defined action plan that begins with shutting down the oil flow to the leak for containment, before clean up.

This includes recovery of as much of the spilled oil as possible, and then remediation work, a longer term process aimed at returning the site to its previous state.

Nigeria’s National Oil Spill Detection and Response Agency also has set procedures for dealing with spill incidents.

Serious business Shell found itself in court in the Hague only last year facing claims by four Nigerian farmers that it should pay compensation for damage to their land.

They claim oil spills ruined their livelihoods, though Shell insists it could not be liable in the claim because most spills were caused, once again, by criminal damage.

The company also faces difficulties in carrying

S11 ORA 1 2013 Technology_Layout 1 01/02/2013 14:47 Page 51

Angola on alert To date, there have been no major spills in Angolan waters although the government has fined operators where it has felt the need to.

A decade ago, Luanda issued its first ever fine to Chevron which was ordered to pay US$2mn for causing environmental damage, following a 2002 offshore spill that polluted beaches and forced fishermen to stop work.

with Shell reinforcing its asset integrity and safety programme in the wake of the incident.

But only the reality of a spill can test a response strategy, though Africa, in conjunction with the multinational operators that work there, has taken steps to prepare for such an eventuality.

The Global Initiative for West, Central and Southern Africa (GI WACAF), for instance, is another partnership between the IMO and IPIECA to enhance the capacity of countries to prepare for and respond to marine oil spills.

Its aim is to strengthen the response capability in 22 countries, through the establishment of partnerships between industry and national authorities, and to foster greater regional co-operation.

The hope is that this readiness will never truly be called upon like it was in the Gulf of Mexico nearly three years ago.

As always, when it comes to oil spills, prevention is better than cure. â&#x2013;

If anything, despite the catalogue of minor spills onshore Nigeria, Africaâ&#x20AC;&#x2122;s oil industry has yet to face any major crisis, certainly on a par with the Deepwater Horizon accident.

And, as serious as the Bonga spill was two years ago, this may have been an important wake up call,

Wake up call

As part of its spill response, Shell continuously monitors for leaks in the delta and responds to anomalies where necessary.

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Oil Review Africa Issue One 2013 51

Oil Spills

An investigation found the spills were the result of leaks from poorly maintained pipes used to transport crude from the platforms.

Like Nigeria, Africaâ&#x20AC;&#x2122;s other big offshore producer has also established contingency plans for dealing with any incidents.

The Ministry of Petroleum and oil industry operators teamed up to develop a joint response blueprint with the assistance from the International Maritime Organisation (IMO) and the IPIECA, the global oil and gas industry association for environmental and social issues.

The plans include a great deal of cooperation among all the big operating oil companies, including the likes of Chevron and BP, Exxon and Total.

A mutual assistance pact allows for the maximum use of all available resources at a time of crisis, including vessel mounted dispersant spraying equipment, helicopter spray buckets, shoreline cleaning, and temporary storage equipment.

out repairs to infrastructure because of the regionâ&#x20AC;&#x2122;s infamous volatility.

The case, which is linked to spills in Goi, Ogoniland; Oruma in Bayelsa State; and a third in Ikot Ada Udo, Akwa Ibom State, is being brought against Shell by the farmers and the Dutch arm of the environmental group, Friends of the Earth.

If successful, it could pave the way for thousands of other compensation claims, with locals long arguing that oil industry operations are polluting the delta land.

Last year, a report by the United Nations Environment Programme said over half a century of oil operation, by firms including Shell, had caused deeper damage to the Ogoniland area of the Niger Delta than earlier estimated.

In the past, Shell has accepted responsibility for two specific spills in the region, in 2008, saying it would settle these cases under Nigerian law.

Subsea Technology

S11 ORA 1 2013 Technology_Layout 1 01/02/2013 14:47 Page 52

Vessels that operate across the globe in waters of varying levels of salinity and temperature are highly susceptible to critical corrosion damage. Stephen Hall, Cathodic Protection Engineering & Design Manager, Stork Technical Services discusses a solution.

Remotely-designed cathodic protection solution

restores hull integrity O

NE EXAMPLE WHERE critical corrosion can occur is on steel or aluminium hull plates and this results in the complete penetration of the hull below the waterline. This can render a vessel unseaworthy meaning it is dry docked for unscheduled and costly maintenance.

Cathodic protection (CP) is a proven, costeffective and efficient corrosion mitigation solution and is central to almost every hull design. With accurate datasets it is possible to predict the most likely future state of a hull’s integrity, which assists with effectively planning preventative action if required. However, a number of factors impact on the effectiveness of a CP system, such as structural components, surface area and existing coatings, and as these variables can change over time it is possible for premature corrosion to occur.

A recent example of this is when Stork Technical Services (Stork) was approached by a major subsea services provider to investigate the premature depletion of sacrificial anodes located on the hull of one of its survey vessels. A remedial design and installation plan was required within the week the vessel was dry docked for ongoing maintenance.

Developing a CP system A CP system comprises an anti-corrosion coating and either sacrificial anodes, most commonly used subsea, or impressed current anodes with a power unit to drive them. The aim of a CP system is to polarise a structure as quickly as possible and maintain the optimum protection for the design life.

To develop an effective CP system for a hull, information and data on factors such as the sea chests and operating environment has to be analysed and related to certified industry design standards and previous project experience.

The condition of the surface area and type of existing coatings must also be determined to calculate the required mass of the anodes, the electrical current output by the total anodes present and from each individual anode. Using this information and recommended current density values it is then possible to develop an effective CP system based on the mass and electrical current demands.

Monitoring a vessel’s CP System Once designed and installed, planned inspections to gather datasets are required to determine if the system has achieved its initial goal of continuously protecting the hull. For sacrificial CP systems used below the waterline, an ROV is equipped with a

52 Oil Review Africa Issue One 2013

An example of a corroded prop and stern prior to a CP system installation.

For vessels without ROV capabilities, an electrochemical potential survey around the hull can be carried out using a ‘dip-cell’ method. multi-electrode system to measure potentials and current densities around the hull. Both the potential and current density readings taken are used in detailed analysis of the data. Anode output currents can be calculated from the readings obtained by using an appropriate mathematical model such as a modified Dwight’s equation or McCoy’s formulae. As the ROV survey system uses a traceable calibration source a historic trend analysis can also be evaluated accurately and used to make meaningful predictions. All of the gathered data, along with the original design details, allow for an accurate assessment of a hull’s corrosion risk and aids in planning preventative maintenance.

For vessels without ROV capabilities, an electrochemical potential survey around the hull can be carried out using a ‘dip-cell’ method. This utilises a standard silver/silver-chloride reference

electrode which is placed close to the hull in various locations at varying depths and measured with a high input impedance voltmeter. While this method is effective it can only be used to identify CP potentials.

Monitoring the effectiveness of an ICCP system is more complex. As well as monitoring the anodes, it is also essential to test the power units, stationary reference cells and other components that comprise the ICCP system to ensure it is working effectively.

Case study – remedial design for premature hull corrosion Stork was contracted to review sacrificial anodes on a vessel that had suffered corrosion damage.

Analysis of the data sourced regarding the previous CP system, identified the premature anode depletion was caused by an insufficient anode mass which increased the current demand required per anode.

Stork was required to design a new CP system and, given the short operating window, the company took the decision to design a system remotely from Aberdeen, UK, that could be assembled and installed locally using only the anodes that were readily available at the yard in West Africa.

The vessel’s original CP design consisted of a sacrificial anode system in conjunction with a coating system instead of an ICCP system. To design

S11 ORA 1 2013 Technology_Layout 1 01/02/2013 14:47 Page 53

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Subsea technology

S11 ORA 1 2013 Technology_Layout 1 01/02/2013 14:47 Page 54

A CP technician performing a dip cell hull potential survey.

the new system the vessel was analysed in various categories, including the hull, rudder, nozzle, sea chests and thrusters, as each component presented a different design challenge. The possible electrical discontinuity between components meant that the

CP systems on areas that were not electrically connected had to operate independently.

After considering a range of options, a conservative current density was used to allow for a more rapid breakdown in coating than normal. This decision was also influenced by the fact the vessel normally operates in warmer tropical water which can result in a higher corrosion rate. The conservative current density employed in the design ensured that the previous high depletion rate would not occur within the system’s intended design life.

CP systems based on a predominantly zinc alloy, which was designed to last for three years, and a predominantly aluminium alloy, designed to last for five years, were developed to allow the subsea services provider to draw a comparison on the most effective design based on what was available on site. The aluminium-based system provides a greater current over a longer period of time per unit mass than zinc.

As well as selecting the most effective materials for a CP system, the placement of the anodes is equally important to ensure that the entirety of the vessel’s hull and associated components are sufficiently protected. Detailed docking plans were also developed to enable the on-site engineers to correctly position the anodes onto the ship’s hull for optimum efficiency.

The vessel has now been re-fitted and has returned to operational capacity. Regular dip cell potentials will be taken around the hull to monitor the effectiveness of the system and ensure it is operating as planned.

The aluminium-based system provides a greater current over a longer period of time per unit mass than zinc.

Conclusion With significant global demand for services such as survey, IRM and diving, vessels that are dry docked for corrosion related issues can result in significant loss of revenue for subsea service providers. CP systems are a cost-effective corrosion mitigation solution; however, they must be designed and installed correctly to operate for the expected design life. Failure to do this can result in premature corrosion and a remedial design being required.

Stork developed a CP solution remotely and within a tight operating window for a survey vessel that helped prevent any further unnecessary downtime due to a corrosion related issue. ■

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www.exprogroup.com 54 Oil Review Africa Issue One 2013

S11 ORA 1 2013 Technology_Layout 1 01/02/2013 14:47 Page 55

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S12 ORA 1 2013 Subsea Technology_Layout 1 01/02/2013 17:07 Page 56

Technology

Chikezie Nwaoha recently interviewed Robby O’Sullivan, Vice President, Engineering & Technology, Subsea, Technip.

An industry perspective on

subsea technology HOW HAS SUBSEA technology evolved over the past decade? How is the subsea technology of today more effective/efficient than the technology of previous generations?

There are many elements which drive the development of new and innovative technologies, but of course, the primary driver is always market demand. In this regard, we can consider that the market demand for subsea technology over the past decade is a product of the continuing growth in world energy demand and the simultaneous depletion of accessible oil and gas reserves in onshore and shallow water offshore reservoirs.

These factors have pushed the industry into deep and ultra deepwater acreage which required innovation and new technology to enable exploration and development. Initially, the technology challenges associated with deepwater developments were identified as the physical constraints of designing and installing subsea products (hydrostatic pressure and product weight). However, a number of peripheral challenges not initially evident include fluid characteristics of deepwater reservoirs and associated flow assurance challenges, corrosive fluids, subsea product reliability and remote intervention, to name but a few. It’s fair to say that Brazil was exploiting resources in very deep water in previous decades, but the associated flow assurance challenges and the requirement for large diameter pipelines were not present in Brazil at that time and neither were the sour service reservoirs. So Brazil had pioneered deepwater exploration and developments in excess of 1,000 m using small diameter, sweet service pipelines and risers which were the technology developments of previous decades.

When West Africa and the Gulf of Mexico stepped into deeper waters a decade or more ago, it became apparent that the earlier advances made

by Brazil were excellent platforms from which to launch the technology developments to address the deeper waters of 1,500 to 2,000 m with the added complications of flow assurance challenges, larger diameters and sour service. So the last decade has concentrated on conquering these challenges and of course achieving water depth capability up to 3,000 m at the same time.

Ironically, Brazil is set to benefit in the short term from these developments of the last decade as their pre-salt discoveries experience even more severe flow assurance and sour service challenges in ever growing water depth which continue to push the boundaries.

56 Oil Review Africa Issue One 2013

Subsea transport solutions is an important area today.

What are the major products available on the market today in terms of subsea technology?

To a certain extent, part of the extension of subsea products (particularly pipeline products) to deeper water has been facilitated through design optimisation where products were over-designed in previous years and we learned to optimise our designs through use of more refined analysis tools such as finite element analysis (FEA), computational fluid dynamics (CFD) and increased material testing and behavior understanding. However, these tools were not enough and new or advanced product developments were also required. One classic example of a product which combines technology development of the product and the associated analysis tools is the Anti H2S Flexible Pipe developed by Technip. The presence of H2S sour gas in the annulus of a flexible pipe calls for the use of lower strength steel wires in the annulus to accommodate the sour environment, particularly for a fatigue sensitive riser. This in turn limits the water depth capacity and pressure rating of the pipe as hydrostatic collapse capacity and tensile weight carrying capacity of the pipe is dictated by the strength to weight ratio of these steel components.

The last decade has seen extensive research throughout the industry to develop better analytical tools to simulate the environment of the annulus

and the static and dynamic behaviour of the steels in that environment. These advances in simulation capability and material science behaviour have been complemented by the development of the Anti H2S pipe which incorporates a polymer barrier layer of specific chemical formulation which consumes the H2S before it can permeate to the annulus of the pipe. This allows the design to revert to the higher strength/weight ratio steel wires which can achieve greater water depth capability. Subsea Processing equipment is another area of considerable development in the last decade and subsea boosting pumps in particular have now established a track record, while subsea separation and compression are still in their relative “infancy”. Technip has pioneered the flexible pipe Integrated Production Bundle (IPB), reeled rigid Electrically Trace Heated Pipe in Pipe (ETH-PiP) which are fast becoming recognised as potentially key tools in the overall subsea processing toolkit.

The ability to control the temperature of the fluids can improve the flow characteristics in the pipeline and contribute to hydrate management and enhanced oil recovery, thereby optimising or potentially eliminating the requirements for separation and boosting. In combination, these elements of subsea processing can contribute to the economic viability of a subsea development

S12 ORA 1 2013 Subsea Technology_Layout 1 01/02/2013 17:07 Page 57

Technology

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Technip was awarded by Total E&P Angola an EPIC contract for the second phase of the Girassol Resources Initiatives (GirRI) development project off Angola.

with difficult fluid characteristics. Of course, other “products” which have played a significant role in the enabling of deepwater development fields are the installation equipment and methodologies such as enhanced remote intervention tools, connector systems and vessel laying equipment.

When selecting a particular subsea technology, what are some key considerations an end-user should make to ensure success?

In one word, reliability is the key to selection of a subsea technology. The relative difficulty to access subsea components for maintenance means that they have to be designed for uninterrupted operation for the life of the field. Track record is obviously a primary criterion for the selection of a product, but of course for the introduction of novel technologies, it becomes a risk management exercise to identify the lowest risk solution. The end user will generally focus on suppliers and contractors with a general track record in deploying new technologies, but the industry is now also beginning to standardise on technology development processes which maximise the chances of success and minimise the risk of new technology deployment. These processes are broadly based on the Technology Readiness Level (TRL) approach combined with robust gate review processes which assess the qualification level of a technology and all of its components and related interfaces throughout the development process. If used correctly, these systems can be used to effectively to “derisk” or maximise the reliability of the final product. Where feasible, it should also be considered to deploy the technology initially in a Pilot mode where the consequence of teething problems may not be severe.

What are some best practices you can offer end-users in the areas of specification, installation and maintenance of subsea technology to ensure long-term performance?

As above, a robust technology qualification process is essential and this should consider all of these areas. The success of the process depends on the identification and timely involvement of all stakeholders including component suppliers, installation and maintenance contractors to ensure that the specifications are practical and feasible throughout the entire supply chain throughout the life of the field. In addition to this, the emerging technologies which enable monitoring of subsea

58 Oil Review Africa Issue One 2013

products will play a key role in the future. There are two main areas where monitoring brings added value to a subsea development, namely product “Health Monitoring” (otherwise referred to as Asset Integrity Monitoring) and “Flow Monitoring”.

Health Monitoring is a powerful tool to enable an end-used to identify early signs of impending performance issues and intervene in a timely manner to avert full failure or shutdown. Flow Monitoring on the other hand can enable the end user to optimize throughput based on an understanding of the real time flow conditions in a system, but in the near future should also enable improved proactive management of hydrate formation, wax formation and slugging to avert their detrimental impact on operations.

What are some pitfalls you see end-users commonly encounter in subsea technology applications? How can end-users best avoid and/or respond to such application pitfalls?

Interface management between different elements of the supply chain is a key success factor and failure to address this can result in costly and time consuming rework and delays. As an example of this, a decade ago, the industry suffered considerable delays during installation because the interface design between some of the subsea production equipment and the connecting pipelines had not been addressed. This was a product of the contracting strategy and natural phase lag between contract awards for these two components (longer procurement lead times for subsea production equipment dictated earlier contract awards for those components and subsequently the interface connector systems were designed by the equipment supplier with relatively little attention to the loading imposed by a connecting pipeline during installation and operation). In more recent years, this situation has improved as subsea equipment companies have identified pipeline designers and installation contractors as key interface stakeholders in the development of their connector technologies and have involved them in the qualification process at an earlier stage. However, this is just one example of a key supply chain interface which has been largely resolved. There are many other similar interfaces across the industry and very often across different company boundaries where exchange of proprietary information and confidentiality complicate the challenge. It is incumbent on the end users, product suppliers and contractors alike to address this issues through early interface and stakeholder management.

Are there collaborations between academia and industry in the implementation of subsea technology? One that will develop new theory or methodology, and also address a relevant industrial problem?

Academia is a natural source of expertise for industry to solve technically challenging problems and collaboration happens continuously with Technip and all of the other industry players.

However, in many cases, this tends to be on an ad hoc basis where an industrial company looks

Reliability is the key to selection of a subsea technology. outside for help on specific topics. Some companies have developed a more strategic approach to formally identifying the strengths of different universities and research institutions and building a more structured, long-term collaboration around this structure. This is a far more value-adding approach as it allows the research institute or university to develop a longer term programme based on a better understanding of industry requirements. Otherwise it is difficult for a university to understand the context of many of the projects on which they work. It is likely that the specific collaboration models established by some oil companies in particular will be replicated around the industry in the coming years.

What is on the prospect in terms of subsea technology? How will the subsea technology of tomorrow be more effective/ efficient than the subsea technology of today?

Many of the technologies developed in the last decade for deep water provide a robust platform for the next phase of development. The terms “longer” and “deeper” are used a lot recently to define the technology demands on the industry. Development of more remote fields in areas such as the Arctic will require longer subsea tiebacks, subsea processing, reliability and improved remote monitoring and inspection. Already, some remote fields are being developed using gas compression and long tiebacks. At the same time, the industry is beginning to define the next step in water depth and some prospects have already been identified in 4,000 m depth. It is unlikely that extrapolation of the existing products and installation equipment and methodologies will apply in such deep water and some step change innovation will be required to address this challenge.

What are the plans for the future, from the industry stand point?

As above, the trend is for the subsea industry to go “deeper” and “longer”. One of the primary areas driving demand for longer tiebacks is the Arctic where the vision of a number of operators is the “Subsea Factory” or “Subsea to Shore” concept where there will be no surface facility on the field.

There are already some examples of all-subsea developments in India and Egypt for example, but the more recent and forthcoming developments in the North Sea using gas compression, longer tiebacks and in more northerly locations are approaching the Arctic vision. In such situations, where the infield infrastructure and much of the tieback infrastructure will be under ice for much of the year, the requirements for reliability, monitoring and remote intervention take on even greater significance and the end users will be carefully monitoring the success of the near future intermediate steps. ■

S12 ORA 1 2013 Subsea Technology_Layout 1 01/02/2013 17:07 Page 59

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Technology

S12 ORA 1 2013 Subsea Technology_Layout 1 01/02/2013 17:07 Page 60

Challenges have increased in mobilisation, moving and mooring of offshore mobile drilling units. Viking SeaTech has applied advanced engineering designs and operational experiences to ensure the successful deployment of safe and fit-for-purpose mooring systems. Mike Main, Managing Director for the UK and Africa discusses their evolving technology.

Simplified pre-laid

mooring solutions F

OR CENTURIES AFRICA'S oil and gas reserves remained untapped and undisturbed. Now operators and drilling contractors face the increasing challenges of mobilising, moving, mooring and operating their mobile offshore drilling units (MODU) off African coasts, where they are targeting deep water oil hydrocarbon reservoirs.

The waters skimming the region’s shores require a higher degree of technological innovation in order for them to tap into the hydrocarbon stores locked beneath the seabed.

But companies looking to expand into the region’s rich waters need more than just the technological will to succeed. They must also navigate complex ribbons of red tape, face a swinging political pendulum and operate in some of the most remote and challenging areas in the world.

With more than 25 years’ experience in some of the world’s harshest and most demanding

environments, including the North Sea, Viking SeaTech has applied advanced engineering designs and operational experiences to ensure the successful deployment of safe and fit for purpose mooring systems. We have also successfully designed and deployed our mooring systems in other environments such as off the coasts of Egypt, Ghana and the Côte d’Ivoire.

As offshore operators look to take their exploration efforts into ever more remote and demanding areas, the challenges have increased in mobilisation, moving and mooring of the offshore mobile drilling units that they are so dependent on. A number of challenges need to be met to ensure that moored rigs can be operated safely and efficiently in the offshore oil and gas fields, which may be located in deep water or, increasingly, where complex seabed infrastructures have been installed.

Semisubmersible MODUs are moved to new

The waters skimming the region’s shores require a higher degree of technological innovation in order for them to tap into the hydrocarbon stores locked beneath the seabed. locations on a regular basis – workovers and completion operations on existing wells have tight deadlines to meet. It is therefore in the interests of the operator to minimise the loss of operational days through reducing rig move times from location to location in a safe, efficient and costeffective manner. Maximising the operational use of the MODUs requires highly efficient logistical

Viking SeaTech has vast experience in Ghana and the Côte d’Ivoire.

60 Oil Review Africa Issue One 2013

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Technology

operations and there are significant dangers of delays and spiralling costs – especially with the huge amount of resources required to move and safely moor such rigs.

Viking SeaTech has worked with the Burullus Gas Company through Rashpetco in Egypt for the past three years. We recognised that their rig moves were taking more and more time with the knock on effect being spiralling costs. A proposal was submitted for using a Taut Leg Prelay System in order to complete their rig moves in a more efficient cost-effective and safe manner. Rashpetco in recognising the safety, time and cost benefits accepted the proposal and the first deployment of the taut leg pre-lay system was carried out in February 2012. Between February 2012 and July 2012 four rig moves using our taut leg pre-lay system equipment and engineering design were successfully completed without incident. The total rig operational days saved in comparison with the conventional mooring system they had been using was 24.5 days giving them an operational cost saving of several million US$. This also gave the operator the opportunity to bring their existing wells back online sooner that predicted.

A producing oil or gas field sea bed can become extremely congested due to the ever increasing subsea technology where complex subsea infrastructures have been deployed. By using our experience and advanced engineering designs Viking SeaTech can deliver a safe and non-intrusive mooring solution through deployment and use of the taut leg pre-lay system.

The taut leg pre-lay system using vertically loaded anchors, steel wire and fibre ropes is installed and buoyed off prior to the rig moving off its current operational location. Provided that the rig has a prelay system deployed on its current location enables efficient and time saving rig mooring disconnect and hook-up times. In reducing the total number of days required for rig moves provides the client with reduced operational times and total overhead costs.

Our ever evolving mooring technology allows us to offer simplified prelaid mooring solutions that are safe, fit for purpose, cost effective and provides environmental protection of the sea bed infrastructures.

One of our previous and highly successful pre-lay projects we undertook in the Côte d'Ivoire helped save one major operator several millions of US dollars. This was an extremely difficult deep water location, where our engineers had to design a prelay system to be safely deployed taking into account soil stability, complex subsea infrastructures and deep sea bed undulations with steep severe slopes. This was further complicated by the client requirement for the rig to have the ability to skid the rig between two drill centres which were 1,000 metres apart. The rig was safely and securely moored on location for over one year and successfully completed several skidding operations between both well centres without incident.

Our work with the Burullus Gas Company and our other operation in the Côte d'Ivoire demonstrates and reflects on the benefits of deploying a prelaid system. In order to ensure operations move quickly and efficiently you must also look beyond the seabed. Political turmoil, including government changes, plays an important role in operations. Only five of the continent’s 55 countries are not producing or at least exploring their oil capabilities or potential and many of the countries cashing in on their stores are plagued by political upheaval. Angola, South Africa and the two Sudans have all recently hit the headlines for resource-fuelled turmoil.

Some countries are easier than others to operate in. For instance, we have worked with all the major operators in Ghana both for rig moves and using our internal engineered designs for pre-lay systems. We are on track to significantly expand our global operations and achieve our goal through utilising our experience, professionalism and expertise in becoming the clients preferred company of choice for all the marine services we provide. Expansion demands innovation. The oil and gas industry can be very conservative when it comes to mooring. Many companies prefer to stick to tried and tested methods. But the global terrain requires those same companies to shed their conservative methods and adopt a more progressive technology, which ultimately is safer and cuts costs. Pre-lay mooring systems have been already successfully and effectively used in the North Sea, Barents Sea, Mediterranean, Africa and Australia with continual growth evolving through the requirement for subsea infrastructures being installed on the sea beds. There are a few locations and operations where using a pre-lay mooring system is neither cost effective or required such as South-East Asia and the ultra-deep water locations such as Brazil; they are applicable for the rest of the world. ■

62 Oil Review Africa Issue One 2013

S12A ORA 1 2013 Well Integrity_Layout 1 01/02/2013 17:08 Page 63

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S12A ORA 1 2013 Well Integrity_Layout 1 01/02/2013 17:08 Page 64

Technology

Dr Liane Smith (FREng), Director and founder of Intetech, explains how enterprise-wide visibility of operating well data enables oil and gas firms to ensure the right people have access to the right information at the right time for rapid and informed decision making.

Gaining a green light on

well integrity O

IL AND GAS operators are sitting on vast reserves of data that has the potential to transform the way they manage the integrity of their wells. Today, many lack visibility at field or enterprise level because information relating to well production, barrier equipment and design is held in different departments in various formats and under different timelines.

Not only do these ‘silos’ make it difficult for senior executives and management teams to collate, compare and report on well integrity data, but the length of time this can take impacts on their ability to identify problem wells, make informed decisions and take remedial action. With around half of all well workovers and shut-ins in mature fields caused by well integrity problems, this lack of visibility presents a significant risk and cost to the business.

The challenge is compounded by the fact many oil and gas operators have grown by acquisition, which means certain asset information is stored or reported in different systems and is not always readily available to the right decision makers.

Using web-based software with smart functionality, it is possible to acquire information from multiple sources – including third-party databases and legacy systems – and display it in a single management dashboard. This provides an instant view of current well integrity status as well as historical key performance indicators (KPIs) at a well, field or enterprise level.

The data integrity challenge Scaling, corrosion and failed well barrier equipment are all common issues that call for great vigilance to minimise the risk of leakage. Importantly, managing well integrity is much more than simply ensuring safety during a current activity or specific scenarios; rather, it concerns the sustainability of the equipment to operate safely for the full design life of the well.

As such, information on the status of safety-critical well barrier components must be completely dependable, and the performance of these components must be totally predictable should a problem arise at any given point in time. An operator must be confident that they know how their well barrier safety equipment is going to respond. For example, if they shut a subsurface safety valve, they know with certainty it’s going to shut in the several seconds it’s supposed to, which could be a matter of life and death in certain situations.

Sustained annulus pressure, whereby casing pressure rebuilds after being released, is the number one killer of wells. It can lead to an external leak or, at worst, result in a blowout. Even if no leakage occurs, the risk is that when pressure within the well rises above the design limit at which it is safe to operate (i.e. the safe operating envelope), a failure of well barrier equipment can be too risky to repair and therefore the well has to be abandoned. Again, poor quality information about annulus pressure creates a real possibility that incorrect and perhaps dangerous decisions might be made.

Silos of well integrity information make it difficult to collate information for analysis and review, which in turn makes it hard to identify inaccuracies that would otherwise allow operators to pinpoint barrier components at risk of failure. Similarly, the large volumes of information collected automatically from instruments on a well using Supervisory Control And Data Acquisition (SCADA) systems is in essence ‘dumb’ or ‘grey’ data, because it is simply a set of readings that in many cases, is rarely interrogated or validated. When compared against readings acquired manually (which tend to be more reliable, though less frequent), anomalies are often found.

64 Oil Review Africa Issue One 2013

Many oil and gas operators have grown by acquisition, which means certain asset information is stored or reported in different systems and is not always readily available to the right decision makers.

Managing well integrity is much more than simply ensuring safety during a current activity or specific scenarios.

Instant insight with traffic lights and email alerts A cost efficient and flexible approach is to interface to third-party systems such as production data management and other types of database (e.g. WellView, SAP, Maximo) and extract the required information for presentation in a management dashboard – this is effectively a graphical user interface providing a simple overview of key operating well and production data, but allowing users to drill through to more detailed engineering data as required.

This type of system allows operators to build on their existing investments and legacy data, by starting out with their basic information and then scaling the system accordingly. For example, initial set-up might see the translation of well design data from various electronic and paper formats into an audited well design database that is accessible per well for managing and generating well handover documentation. It might also collate the results of routine and specialised leak testing of safety critical elements (SCEs) for monitoring and review.

Once basic functionality has been established, more sophisticated applications can be introduced, such as using production data to estimate corrosion damage to the tubing in a well, automatically identifying the presence of sustained annuli pressures and notifying users with warning traffic lights and email alerts, or risk-ranking wells failing to meet safe operational limits.

A traffic light warning system provides a simple yet powerful visual device for highlighting wells at risk. A green, amber or red light provides an instant view of well status – i.e. whether it is being operated within its safe operating envelope and whether all well barrier components are intact. In addition, reports can provide a standardised format for the well integrity data being monitored to ensure better efficiency and clearer communication of well integrity issues across the enterprise.

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Technology

Corrosion is a common issue that calls for great vigilance to minimise the risk of leakage.

Informed decision making Most operators accept that certain well barrier component failures are inevitable and operational constraints may mean that they cannot be repaired immediately. It can be necessary for wells with individual pieces of equipment not in full working order to continue to operate, provided risk assessment indicates the risk level is acceptable. Of course, some types of failure call for the well to be shut-in and repaired immediately, but for the majority of noncritical failures, repairs are scheduled to take place within a designated timeframe, or when the opportunity arises.

Testing and preventative repairs have an associated cost and an impact on the operatorâ&#x20AC;&#x2122;s short-term productivity, whilst equipment failures have different costs and perhaps an impact on long-term productivity, or potential safety and environmental consequences. A well integrity management solution provides decision makers with the intelligence they need to strike the right balance. Having all well integrity data at their fingertips helps them to make the right decision in terms of carrying out maintenance and repairs in a timely fashion, based upon a risk ranking strategy that not only ensures safety, but prioritises resources in an optimum way to lower the overall risk level that an operator is carrying.

This intelligence can help to reduce operating costs substantially by adopting risk-based inspection frequencies, and feed-back of the performance experience to well designers can result in more reliable equipment selection for new wells.

A well intervention engineer needs to know the complete history of a well and the integrity status of its near neighbours in order to make an informed decision when it comes to correcting an issue with a well. With an incomplete picture not only is there a risk that they might not solve a

problem, they could make it worse. Moreover, while sustained annulus pressure or individual well issues can be controlled and addressed in isolation, the danger is that a combination of issues occurring in offset wells simultaneously can lead to unexpected escalation of consequences if the full picture is not visible.

Well integrity management is about controlling all of the different factors that could be affecting the safety of the well in real time continuously, over the 30+ year design, life with a robust overarching system that ensures high integrity of the wells is established and maintained.

Seamless risk management There can be tens, if not hundreds of potential users requiring access to well integrity data and all will have slightly different aims and requirements.

Providing decision makers with enterprise-wide visibility of well integrity status creates a seamless risk management process that is no longer dependent on a patchwork of disparate systems and spreadsheets. Instead, all departments and risk areas are integrated into a single, highly functional system that creates a single version of the truth that translates into usable information for proactive decision-making.

Crucially, a well integrity management system provides the ability to analyse, compare and validate all operating well data, alert and report on exceptions and make information available throughout the enterprise to the right people at the right time. This is proven to significantly reduce the number of integrity-related shut-ins and workovers while providing a level of production assurance that delivers a new level of operational efficiency. â&#x2013;

Africa

Covering Oil, Gas and Hydrocarbon Processing

Make sure you visit our new website with updated news coverage in Africa.

You can also view our digital edition of this issue on www.oilreviewafrica.com Oil Review Africa Issue One 2013 65

Technology

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Oil and gas E&P is not only moving towards deeper and more remote waters, but both technology and economics are making it more viable for companies to do so. Those trends are enabling and encouraging another: floating production systems (FPS). In the first of two articles on deepwater exploration, Infield System’s Catarina Podevyn, author of a major new report*, gives Vaughan O’Grady the economic and technical background to the apparently unstoppable rise of FPS.

The deepwater drive that

favours FPS I

T’S NOT SURPRISING that as a new report puts it “The FPS market is one of the key markets of the offshore industry today”. That report, from independent energy research and analysis company Infield Systems Limited, tracks the rise in use of floating production systems (FPS) across the world and predicts a robust future market.

FPS is booming because today we are exploring in areas regarded as impossible to reach only decades ago. How did we get to this point? High tech or hard work? Both, says Catarina Podevyn, Analyst — Business Strategy and Analysis - with independent energy research and analysis company Infield Systems and author of the new report. “Over the decades the accumulation of knowledge within offshore exploration and production has been interspersed with great leaps in technological innovation,” she explained, These leaps, she says, include subsalt drilling, intervention-less trees in West Africa, and subsea compression and separation. She singles out Petrobras in the deep and ultra-deepwater market, and Norway’s Statoil, which is focusing on the development of new technologies for harsh-environment operations, as operators at the forefront of innovation within the industry.

However, they may not be representative of the industry as a whole. Both Petrobras and Statoil are NOCs with substantial R&D budgets. In most cases advances in exploration occur through an accumulation of knowledge and experience.

“Ultimately,” she said, “the majority of operators, without the balance sheets to mitigate the risks associated with new technology, will always favour proven technologies.”

FPS favoured in deep water Increasingly, when it comes to deep and ultradeep exploration, they are favouring FPS rather than fixed systems. Examples of FPS include floating production semi-submersibles, (FPSSs), tension leg platforms (TLPs) and spars. However, on a global basis FPSOs (floating production, storage and offloading units) dominate the FPS market.

Taking production offshore is a big investment: the basic job of separating out oil, gas, water and muck offshore is a complex business. Presumably, therefore, a prospect needs to be pretty big to justify the investment in FPS. How big?

“This is very difficult to quantify and depends

66 Oil Review Africa Issue One 2013

The Kizomba B FPSO - ExxonMobil’s ‘design one, build multiple’ approach reduces costs and also helps in supporting the high local content demands of West African countries

on a variety of factors,” said Podevyn. “Water depth is a key determinant; Infield Systems believes reserves located between 0-20 metres require 10-20mn barrels to justify investment, whilst reserves located in water depths of > 500 m would need to contain closer to 50mn barrels.

Secondly, the proportion of oil, gas and condensate is key in calculating the potential profitability of a field — rarely are fields just oil and gas.” Not only that, but the level of sulphur and the heaviness of the product, measured by the API number, will also be important factors in justifying the economics of a field.

bespoke designs to continue. She added, “In many circumstances the specific environmental conditions along with field complexity often dictate whether a bespoke design is necessary.”

As an example of this she cited BP’s Schiehallion replacement FPSO, Quad 204, which is expected to be installed in 2015 offshore West Shetland in the UK. It’s a bespoke new-build unit — bespoke because of the strong wave environment associated with the field’s location.

Offshore Australia FPSs, meanwhile, have to be designed to withstand extreme weather conditions. Shell’s Prelude development, for example, is designed to withstand a one-in10,000- year cyclone. Sevan’s cylindrical FPSO in the North Sea (and soon in the Barents Sea) is designed with similar motion characteristics from all directions, a feature that can help to reduce hull fatigue.

Demand for bespoke units to continue

Less need for bespoke in Africa

To be truly effective, FPSs may also need to suit the fields they deal with. Is that a problem in the present economic climate? Podevyn agrees that in almost all circumstances a bespoke or new build floating platform design will always demand greater capital expenditure than a converted unit or more standardised design. However, with a movement towards increasing deep, remote and complex developments within challenging environments, she expects the demand for

The demanding conditions of the North Sea are not replicated in Africa, however. “Offshore West Africa, there is less need for bespoke designs,” said Podevyn. “Here, we have also seen a movement towards greater ‘standardisation’ of FPSOs, seen through, for example, ExxonMobil’s ‘design one, build multiple’ approach on the Kizomba [Angola] developments. Not only does this reduce costs, but it also helps in supporting the high local content demands of West African

Taking production offshore is a big investment.

S12A ORA 1 2013 Well Integrity_Layout 1 01/02/2013 17:08 Page 67

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Technology

S12A ORA 1 2013 Well Integrity_Layout 1 01/02/2013 17:08 Page 68

countries,” she added.

The FPS trend offers up a number of opportunities to the right suppliers and manufacturers of course. Which equipment supply areas does Podevyn feel can expect to benefit?

“With the increasing movement into deep waters, those service and engineering companies offering particular support, experience and technologies within this sector will undoubtedly benefit,” she said, adding that “larger leased floating platform contractors would be expected to benefit going forwards from the growth of the FPS market; the likes of SBM, Modec, BW Offshore and Sevan Marine. With an increasing number of independent operators entering the market, the choice of a leased FSPO is seen as a favourable option.”

Growing offshore gas market Floating production doesn’t just mean oil of course. There’s a growing offshore gas market.

But could the current low price of gas undermine investment in offshore production?

“Shale gas and cheap LNG from East Africa have the potential to divert investment from gas around the world,” Podevyn agreed. “At the same time however,” she pointed out, “operators such as BP and ExxonMobil are more judged on reserve replacement; this results in a confidence that many projects will still go ahead and remain viable at lower spot prices. It would take a huge collapse to affect the majority of projects. In addition, and ultimately, the global increase in energy demand will support the economic viability of gas projects over the longer term.”

Floating liquefied natural gas (FLNG) is still some way off however. Australia has the most projects proposed, along with Asia. However, Podevyn points out, the only project that is actually under construction is Shell’s Prelude,

Shell’s Prelude currently under construction by Samsung.

68 Oil Review Africa Issue One 2013

which is being built by Samsung. Shell has announced a planned installation date in 2016.

“This project is potentially game changing for the industry,” says Podevyn, “and Shell have stated intentions to build a further two-to-three generic units based on the Prelude design. It is planned to produce 3.6 mtpa of LNG and be one of the largest vessels in the world.” Not surprisingly the price tag is somewhere around US$3bn.

This may not actually be the first unit installed. Petronas has two units (Petronas Malaysian FLNG FPSO-1 and Petronas Malaysian FLNG FPSO-2), the first of which could potentially be installed in 2015. These are much smaller in scale and likely to be closer to 1.5mtpa capacity so could be fabricated to a shorter timescale This may not translate to the fast-growing East African gas market, however. “East Africa has the gas reserves and is geographically located to export to the key energy hungry markets of China, Japan,” Podevyn agreed.

“However, work timescales are slow and an onshore option is preferred.”

Possibilities for Mozambique?

As regular readers will know there has been some speculation that the (approximately) 100tcf of gas reserves offshore Mozambique in the Rovuma basin discovered by Anadarko and Eni could be developed via an FLNG installation. However, an

One could argue that deepwater production and facilitating equipment like FPS are a question less of economic viability than of need.

onshore liquefaction facility is the most likely development solution. As Podevyn pointed out, “The discovered gas resources far exceed the commercial threshold to support a large-scale LNG development. Anadarko and partners are currently designing an onshore liquefaction facility (pre-FEED by KBR, Technip) which will consist of two five mtpa trains with the potential to expand to six and an FID is expected in 2013.”

At a conference early last year one speaker suggested that global demand will require the oil production equivalent of four Saudi Arabias by 2050. That being the case, one could argue that deepwater production and facilitating equipment like FPS are a question less of economic viability than of need.

However, this argument only goes so far. As Podevyn said: “While this may be the case, operating companies are nevertheless profitdriven and an asset will always have to be deemed economically viable before a final investment decision is made. However,” she added, “economic viability can be met by simply altering investment strategies. A clear example would be through the installation of a converted floating platform over a new-build, which may reduce cost significantly, or if offshore infrastructure already exists in the area, taking the decision to develop a smaller field through a subsea tie-in to the existing development.”

Of course, the more exploration goes offshore, the cheaper it becomes. That’s the idea anyway: that economies of scale will kick in. Did Podevyn see that as a reasonable argument?

“In theory, yes,” she said, “particularly in the case of regions where a more standardised floating platform design can be implemented across several fields.” And of course from an operator perspective leading IOCs and NOCs have the benefit of economies of scale compared to independent operators.

It may come as little surprise that offshore Brazil is a clear example of where economies of scale are currently developing; with high local content requirements, local yards and contractors are given the opportunity to gain significant experience. “With increasing economies of scale,” said Podevyn, “over the longer term Brazilian fabricators hope to offer a viable cost alternative to established yards in Singapore, South Korea and China — although this may not be for some years.”

Clearly the distance, depth and sheer size of Brazilian prospects mean that it is going to be cited in any discussion of offshore exploration and FPSOs. But African prospects are far from negligible, as we shall see in part two of this feature. ■

The Floating production Systems Market Report to 2016 is published by Infield Systems, an independent energy research and analysis company that is dedicated to the provision of accurate and up-to-date data, market reports, mapping, analysis and forecasts for the offshore oil and gas and associated marine industries. For more information, and to order the report, go to www.infield.com

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Technology

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In an unforgiving environment where every day of unscheduled downtime can result in major financial losses, it is vital that oil and gas companies maintain their equipment by taking advantage of the various advanced lubricants at their disposal, writes Akram Reda, Industrial Marketing, Europe, Africa & Middle East, ExxonMobil Lubricants and Specialties.

Utilising lubricants to

reduce downtime At the processing stage, lubrication remains critical to the overall productivity and performance of a plant.

M

AJOR OIL AND gas producers face a daily challenge to meet current production targets, placing a great responsibility on oil and gas companies operating in the region to maximise productivity and reduce unscheduled downtime.

Across the entire production process, from drilling to delivery, advanced industrial lubrication can play a key role in keeping operations running efficiently, 24 hours a day, as well as reducing operating costs.

Drilling and exploration is a significant investment for oil and gas companies, with rig hire alone costing as much as tens or even hundreds of thousands of dollars per day. Taking this into account, companies must avoid any unplanned downtime.

70 Oil Review Africa Issue One 2013

Examining changes in the oil analysis data over time (trending) is necessary to assess the condition of the lubricant.

A typical offshore oil and gas rig is reliant on a number of lubricants to ensure its efficient operation. Turbines and reciprocating engines provide primary and auxiliary power, gears and bearings are crucial in draw works, cranes, mud circulating, top drive and rotary tables and

compressorsâ&#x20AC;&#x2122; power refrigeration and air systems.

Whether it is an engine oil, turbine oil, gear lubricant, hydraulic fluid or grease, one equipment failure can bring the entire operation to a halt.

At the processing stage, lubrication remains critical to the overall productivity and performance of a plant. Take for example the key role of a turbine oil in keeping operations online. A turbine failure in an oil refinery and resulting shutdown can cost millions of dollars.

When it comes to transportation, marine vessels depend on a range of lubricants to ensure they remain fully operational. From the main engine, propulsion systems, auxiliary engines and thrusters to the deck crane, deck machinery and winches, a

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Technology

Maximising productivity

By trending oil analysis data it is possible to proactively address undesirable conditions before they become problems

wide range of lubricants are required to ensure oil and gas is efficiently transported around the world.

Advanced lubrication Advancements in lubricant technology, especially fully-synthetic based products, have resulted in significant breakthroughs regarding the extension of equipment life and oil drain intervals. These breakthroughs can help oil and gas companies maximise productivity and reduce unscheduled downtime throughout the drilling, processing and transportation chain.

For example, Mobil SHC fully synthetic lubricants can last up to six times longer, with upper operating temperature limits that can typically reach 50°C (90°F) higher than mineral oils.

The high temperature performance of lubricants is particularly important for oil and gas companies operating in the Middle East, where the high ambient temperature coupled with the high speeds and heavy-loads placed on applications, requires a lubricant which can maintain protection in highoperating temperatures.

Other research and development areas that leading lubricant providers have focused on in recent times include improving the energy efficiency of equipment while maintaining these extended operating periods. Recent breakthroughs from Mobil Industrial Lubricants include lubricants to improve the energy efficiency of natural gas engines that are used to power drilling and production rigs. These are in addition to hydraulic, gear and bearing oils which are used in a variety of applications.

The natural gas engine oil, Mobil SHC Pegasus, uses breakthrough technologies to optimise equipment productivity and protection and is the first gas engine oil formulation on the market to deliver real energy saving potential. Extensive independent university laboratory and field tests have demonstrated that the product helps reduce

72 Oil Review Africa Issue One 2013

Beyond oil analysis, visual system inspections should be conducted regularly to check and document the condition of systems. fuel consumption by up to 1.5 per cent*. The new Mobil SHC Pegasus formulation also delivers the potential for increased oil drain intervals of more than 16,000 hours - three to four times that of premium natural gas engine oils. This can help reduce unplanned downtime as well as reduce the amount of waste oil generated.

ExxonMobil’s state-of-the-art hydraulic oil, Mobil DTE 10 Excel, has been proven to help industrial organisations increase productivity, reduce unscheduled downtime and improve the energy efficiency of their machinery. Compared to standard hydraulic oils, Mobil DTE 10 Excel can provide up to a six per cent improvement in hydraulic system efficiency** and 300 per cent increase in oil drain intervals.

The latest addition to the Mobil SHC brand of high-performance synthetic lubricants, Mobil SHC 600 Series oils, are expertly formulated to deliver a number of performance advantages over conventional oils. Featuring the latest Mobil SHC technology with advanced synthetic base fluids and a proprietary additive system, the oils can deliver a service life up to six times longer than competitive mineral oil based gear and bearing lubricants.

In addition, developed through extensive laboratory and in-service testing with some of the world’s leading equipment manufacturers, the nextgeneration Mobil SHC 600 Series oils exhibit energy savings of up to 3.6 per cent*** compared with conventional oils.

In order to help maximise the productivity of machinery and reduce costs, ExxonMobil recommends incorporating an oil and equipment condition monitoring programme alongside the use of high quality lubricants. As part of routine maintenance, the "health" of the lubricant and the equipment itself should be regularly checked.

Typically, it is advised that maintenance professionals perform quarterly oil analysis and annual system inspections.

Examining changes in the oil analysis data over time (trending) is necessary to assess the condition of the lubricant. By trending oil analysis data it is possible to proactively address undesirable conditions before they become problems, which is crucial given the huge potential downtime costs associated with an offshore rig being offline for any period of time.

For equipment maintenance professionals who want an effective oil analysis monitoring programme, there is ExxonMobil’s proprietary online Signum oil analysis programme. Signum oil analysis offers engineers immediate access and direct control of their lubricant sampling programme.

Technical support Beyond oil analysis, visual system inspections should be conducted regularly to check and document the condition of systems. Inspection data can be used to establish the optimum time to perform maintenance on critical components such as filters, valves, hoses and pumps. Comprehensive leak detection should also be performed, especially if excessive oil usage is noted during a routine system inspection.

Due to the 24/7 nature of the oil and gas sector, it is important that companies have access to experts that can work alongside in-house engineers to develop optimised lubrication solutions for applications. Variables such as operating temperature, load, cycle and age of equipment have an impact on the most appropriate lubrication, monitoring and maintenance package.

To service oil and gas companies in the Middle East, ExxonMobil has a Field Engineering Services (FES) team on the ground to offer technical support to companies operating in the region. On a day-today basis they work with companies to address lubrication issues as well as proactively identifying ways in which productivity can be further increased by switching to more advanced lubricants. The technical specialists in the Middle East are part of a global FES team, which shares application expertise and best practice through its work in supporting oil and gas companies in other areas of the world such as the Gulf of Mexico, the North Sea, Russia, the Asia Pacific region and Africa.

To augment this technical expertise, ExxonMobil has specialist strategic distributors located in all of the key Middle East oil and gas markets to offer fast and reliable delivery of Mobil Industrial Lubricants.

Oil and gas companies looking to optimise the productivity of their equipment need to ensure they have access to the latest lubricants and services, as well as application expertise. ■

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Risk Assessment

S13 ORA 1 2013 Technology_Layout 1 04/02/2013 12:52 Page 74

Managing and operating oil & gas facilities has become increasingly sophisticated.

Alfredo Jones, Managing Director, Alduco Energy discusses how to ensure the integritiy of offshore oil & gas production facilities through Risk Based Inspection (RBI).

Ensuring the integrity of offshore facilities

through RBI A

LL COMPANIES AND operators in the oil & gas industry are under increasing pressure to meet stringent technical and commercial criteria, such as achieving and maintaining production targets, mitigating challenges, improving reliability, minimising production costs, improving asset protection, whilst maintaining the highest safety and environmental standards. In addition advances in technology has led to the life extension of oil & gas fields, which in turn has resulted in the continued use of oil & gas production facilities (FPSOs, platforms and pipelines) beyond their intended design life in many cases of 20 years. Sixty per cent of the world’s offshore oil & gas production facilities still in operation are past their theoretical design age of 20 years.

Stringent regulatory requirements have also made it more essential than ever to correctly manage and maintain all assets, as failure to do so could lead to catastrophic consequences including unplanned costly shutdowns, loss of product, pollution to the environment, accidents which in some cases have been fatal. Increasingly asset integrity management strategies such as RBI are being implemented to assist oil & gas companies to mitigate these risks.

Following an explosion in April 2001, the ConocoPhillips-owned Humber Refinery in the United Kingdom was found guilty of failing to appropriately monitor the deterioration of its pipe work. A Risk Based Inspection (RBI) programme has since been employed by the company.

Periodic inspections of oil & gas facilities are a requirement in the oil & gas industry.

Risk Based Inspection (RBI) Periodic inspections of oil & gas facilities are a requirement in the oil & gas industry, as this leads to maintenance planning to ensure the safe operation of such facilities. RBI is a methodology used in the industry for the systematic decision making to identify process equipment, storage tanks, piping and structures which are more likely to fail, causing damage to equipment, endangering the lives of personnel and polluting the environment in addition to expensive production shutdowns. It combines the principles of risk (likelihood of failure multiplied by its consequences) with operational experience to obtain a cost effective inspection programme targeting inspection where and when it’s needed.

Advances in technology has led to the life extension of oil & gas fields.

Benefits * To safeguard integrity. * To reduce the risk of failure. * Avoiding unnecessary inspection – Inspection intervals are based on the risks associated with the equipment and therefore inspection personnel can spend most of their time on the high risk areas and less time in the low risk areas. * Cost saving – due to fewer inspections, fewer or shorter shutdowns and longer run length. * Information from inspections on one piece of equipment can be utilised in determining the inspection intervals and scopes for similar equipment. * To apply a strategy of doing what is needed for safeguarding integrity and improving reliability and availability of the asset by planning and executing maintenance that is needed due to findings from the inspections. * Reliability and compliance with applicable regulations, codes and standards * Increasing oil & gas facility availability and optimum repair and replacement scheduling * Extended oil & gas facility life.

There are many international engineering standards and recommended practices that outline requirements, methodologies and the implementation of RBI. Included in these are API RP 580 & 581.

In conclusion, RBI provides a logical, documented, repeatable methodology for determining the optimum combination of inspection frequencies and inspection scopes. RBI objective is to ensure focus of inspection to areas with high risk, while inspection in areas with low risk will be reduced or excluded from the normal inspection programme and therefore result in significant inspection and maintenance cost reduction.

Fluorescent oil spill detection technology MANY OIL COMPANIES still rely on unsophisticated visual reports of oil spills, meaning many leaks are not detected until a slick comes to the surface and is visible to the human eye. Cambridge Consultants have developed a new oil spill detection technology platform, which is capable of detecting the natural fluorescence of even tiny amounts of oil in or on water.

If you shine ultraviolet light onto the various different types of crude oil, you will get a

74 Oil Review Africa Issue One 2013

fluorescent signal back - it will light up.

However, there are other things that also fluoresce and give off visible light if you illuminate them in that sort of environment - the trick is to know how you can tell the difference between what is oil and what is something you are not concerned with. In order to appreciate the parameters of designing a sensor like this, Cambridge Consultants developed a sensing setup that allows one to understand the illuminating

ultraviolet source, how much power is being put in and how it's distributed.

The company also looked at the detection optics, the optical arrangement and the sensor itself - which collects the fluorescent light and puts it onto a detector - and how you filter that. It also considered what other fluorescent signals get in the way, what sort of signal they might give off and the different ways you might separate them out from the signal you are trying to measure.

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Extending Field Life

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A novel power generation technology from Maersk Oil is set to provide new commercial solutions for enhanced oil recovery and unlocking stranded gas fields, writes Bob Alford, TriGen Project Manager at Maersk Oil

Maersk Oil’s TriGen technology unlocks

clean energy M

AERSK OIL’S TRIGEN technology is derived from the space industry and involves burning gas together with pure oxygen to produce power, water and carbon dioxide. The resulting high purity CO2 is captured – making the power generation emission-free – and can be transported to fields for enhanced oil or gas recovery (EOR/EGR).

This technology can provide synergy across the energy industry to create value for both resource owners and energy producers. The global energy business has traditionally been separated into upstream, downstream and power generation activities.

This provided the right business focus for resource owners and power producers and made perfect sense with current oil extraction and power generation technology. With TriGen, however, linking power generation back to upstream oil and gas activities, a zero emission solution across the energy value chain becomes possible as all of its outputs are useful commodities.

It was the EOR application that first caught the eye of Maersk Oil, as we had already started to study whether we could use CO2 to enhance recovery from our own mature oil fields, and were seeking low-cost sources of the gas.

76 Oil Review Africa Issue One 2013

However, we soon realised that the technology’s multi-stream output, including its ability to burn CO2-contaminated gas as fuel without any pre-treatment, actually gave it access a number of business opportunities around the world.

We are currently exploring opportunities in the Middle East and South-East Asia that have different value chains and benefits, yet both can now be made commercial from the implementation of the TriGen technology.

In the Middle East, we are investigating whether TriGen’s low-cost CO2 can enable EOR projects In the Middle East, we are investigating whether TriGen’s low-cost CO2 can enable EOR projects. Gulf countries in particular have increasingly focused on clean energy, while many of its oil and gas reservoirs are well-suited to CO2EOR and nitrogen or CO2 based EGR. Here, gas would be burned to produce clean power and water for households. Nitrogen, a by-

product from the production of pure oxygen, and CO2 would be supplied to oil fields – nitrogen to maintain the pressure in depleting reservoirs and CO2 as the EOR agent coaxing out oil that would otherwise not be recovered.

In TriGen’s oxyfuel combustion process, fuel is mixed with pure oxygen and burned at pressure in excess of 100 bar and temperatures over 2,200 degrees Celsius. TriGen gets its pure oxygen from a standard Air Separation Unit that compresses and cools atmospheric air until oxygen and nitrogen are separated by distillation.

The hot combustion gasses that are produced (only steam and CO2) are expanded in a turbine that drives a generator while the pure water and resulting high quality CO2 are separated. The generated power becomes emission-free as the ‘reservoir ready’ CO2 is transported to oil and gas fields where it is injected deep underground for EOR/EGR. Traditionally, CO2-based EOR has only been feasible in areas with large sources of natural CO2 – chiefly in the United States. But the ability to produce pure CO2 as a by-product of a commercial power generating venture now makes CO2-based EOR attractive in regions such as the Middle East, which has limited sources of natural CO2.

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Extending Field Life

The pure oxygen combustion of TriGen

The technology provides Maersk Oil with a competitive advantage in the Gulf region, as it offers both the benefit of clean power and low-cost CO2 to increase recovery potential Additionally, as TriGen produces water, it can be placed in remote locations where water is not readily available. This water can be used for domestic purposes or irrigation. In the oil field, the low salinity water is beneficial for improving recovery in water floods.

The technology provides Maersk Oil with a competitive advantage in the Gulf region, as it offers both the benefit of clean power and low-cost CO2 to increase recovery potential. The technology also complements our current work and studies on CO2-based EOR in Denmark and Qatar, enabling us to offer integrated field development solutions in this area.

In South East Asia, the value chain starts at a different point – at world class gas fields that lie undeveloped because they are contaminated by CO2. Such stranded gas fields could now potentially be produced economically because the TriGen technology can burn gas contaminated with up to 90 per cent of CO2 without requiring any costly pre-treatment for CO2 removal.

We would be unlocking enormous value to the states that have been sitting on these fields, unable to produce them commercially. Although it is early days yet, with technical and commercial challenges to overcome, these are just the kind of projects that affirm Maersk Oil’s pioneering approach to business.

We launched the project two years ago and in January 2011 announced the acquisition of rights to the combustion technology from US-based Clean Energy Systems (CES).

CES, in collaboration with Maersk Oil, Siemens and the US Department of Energy, is maturing the technology. Derived from rocket science, where pure oxygen is used to burn fuel, CES has proven the technology on a smaller scale

78 Oil Review Africa Issue One 2013

over the last 15 years. Siemens is currently converting a conventional gas/air turbine to a gas/oxygen turbine for a commercial power plant project in California using the TriGen technology.

The converted turbine – approximately the size of a Maersk shipping container – will be hooked up to a power grid in North Los Angeles later this year and has the capacity to deliver 150 megawatts of electricity – enough to provide energy to over 100,000 homes. ■

Bob Alford is senior manager of business development & strategy and TriGen project manager at Maersk Oil

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Technology

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AutoTrak system triples ROP THE BAKER HUGHES AutoTrak rotary closed-loop drilling system, integrated with Baker Hughes advanced logging-whiledrilling (LWD) technology, reduced the drilling cost per meter from US$2,000 to US$1,000 and tripled the rate of penetration (ROP) from 4 m/hr to 12 m/hr for an operator offshore Tunisia.

The operator had encountered difficulties with directional drilling control due to highly interbedded formations. “This is a challenging environment for steerable motors due to potential hang-up of the bottomhole assembly [BHA] on ledges when performing directional work, resulting in low gross ROP, limited wellbore positioning control, and poor hole quality,” says Ezekiel Falini, AutoTrak Product Manager. “The AutoTrak system

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80 Oil Review Africa Issue One 2013

enabled drilling longer and more complex well trajectories at higher ROP through very thin payzones, delivering high-quality boreholes precisely positioned in the reservoir for superior performance.”

In addition, the Baker Hughes aXcelerate higher-speed measurement-while-drilling (MWD) telemetry system allowed the acquisition of required LWD data in real time without limiting instantaneous ROP. Baker Hughes Reservoir Navigation Services enabled development of a prewell model that could make intelligent and accurate real-time wellbore trajectory decisions based on acquired LWD data. “Reservoir navigation in the horizontal drain sections allowed a significant increase in reservoir contact and positioned these wells in the highest-quality reservoir zones,” Falini explains. “This increased optimum reservoir exposure improved the production performance of the wells and ultimately total field recovery.”

In one well, the horizontal drain section length exceeded the planned reservoir contact by approximately 60 per cent. In another, the horizontal drain in the top of the reservoir was optimised by drilling 200 m in the highest-porosity upper zone. Reservoir navigation, coupled with precise automated steering control, helped avoid water contact.

“Baker Hughes BHAs and custom drill bit designs were optimised to minimise stickslip, lateral vibration, and whirl events to improve drilling performance, borehole quality, and overall operational performance,” Falini added. “Drill bit durability and gauge improvement were important factors in extending the use of PDC bits into challenging interbedded formation environments without compromising the bit’s efficient cutting mechanism.”

Reservoir Navigation Services Software

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ORCA FOR OBM is proving highly effective for the initial clean up of a series of new wells in West Africa. The new wells had been drilled with an OBM and completed with standalone sand screens. The most recently treated well, where the operator was expecting initial production of just under 1000 bpd, is producing at just under 2000 bpd.

ORCA for OBM has already proved highly effective in remedial applications where wells had not been treated during well completion. In some cases, oil production has increased by up to 1,400 bpd or 500 per cent.

The recent results from West Africa demonstrate that ORCA for OBM is suitable for both initial clean up and remedial treatment of wells drilled with OBM.

Previously ORCA for OBM significantly improved production rates in a series of new wells in Asia. The wells had not previously been treated during completion. Lab tests showed that ORCA for OBM would effectively remove the damage – and it delivered successful remedial treatments. The operator is now using ORCA for OBM to clean new wells drilled with OBM in other fields.

Magnetrol’s new GWR solution offers improved control level performance MAGNETROL INTERNATIONAL INC has launched the ECLIPSE Model 706 guided wave radar (GWR) transmitter, a best-in-class level control solution that advances guided wave radar technology with improved performance for a wide range of level and interface control applications.

The Eclipse Model 706 is designed to provide outstanding accuracy, reliability and safety for virtually all process industries. Latest-generation features include: Enhanced Signal Performance – The Eclipse Model 706 innovative GWR circuitry achieves both a higher transmit pulse amplitude and improved receiver sensitivity, resulting in a signal-to-noise ratio (SNR) that is nearly 300 per cent higher than competitive GWR devices. This assures precise, dependable control for every level application, including extremely low dielectric media, extended measuring ranges, and punishing conditions where foaming, boiling or flashing can occur.

Overfill Capable Probes – Magnetrol offers the only guided wave radar transmitter on the market with a complete line of overfill capable probes.

Unlike other GWR transmitters that use algorithms to infer level readings in

top-of-the-probe dead zones, the Eclipse Model 706 measures true level to within specification all the way up to the process flange. Coaxial and single rod overfill capable probes can be installed in various configurations on the vessel, even when the risk of flooding exists.

Advanced Diagnostics – The Eclipse Model 706 takes the user interface experience to new levels of convenience and functionality. The LCD diagnostics convey critical real-time waveform and trend data with outstanding ease of use. Additionally, the Eclipse Model 706 can be preconfigured online prior to shipment, to ensure plug-and-play transmitter commissioning and automatic capture of echo curve during upsets.

The Eclipse Model 706 transmitter provides safe, efficient and cost-effective liquid level and interface control, and is virtually unaffected by fluctuating process conditions including density, dielectric, viscosity and specific gravity. The Eclipse Model 706 introduction represents the latest GWR innovation from Magnetrol, the company that introduced the original Eclipse Model 705 – the very first two-wire, loop-powered GWR transmitter for industrial liquid level applications.

Extensive range of protective clothing The Portwest brand and its extensive range of head-to-toe protective products continue to develop and today the company's safety clothing and PPE is used extensively throughout Africa, the Middle East, the Caspian region and Europe.

COVERING A MULTITUDE of industries that include the oil and gas sector, power generation, ports and shipping industries, construction, petrochemical and welding processes, the Portwest brand is guaranteed to provide the correct protective clothing solution, with a quality garment, at a competitive price.

The company has been designing and manufacturing workwear and protective clothing since 1904. All of the clothing, gloves, safety footwear, helmets and ear protectors are extensively tested and carry full CE markings,

along with EN certification, ANSI certification and GO/ST Russian standards from independent, world-renowned testing institutions. High value is placed on worker safety, product durability and user comfort.

The Flame Resistant brochures contain a collection of clothing and PPE products, of which 34 are new, that are perfect for industries where exposure to heat is a risk to the worker. The range of Ignis heat reflective aluminised range is previewed for the first time, alongside the Solar structural fire suits. The Ignis fabric is an extremely lightweight aluminised 330g certified to EN 1486 and EN ISO 11612.

The company's Solar structural fire suits are used by fire rescue units throughout the world and are all certified to EN469: 2006.

To compliment the fire suits Portwest also manufacture an outstanding range of

flame resistant coveralls, jackets, trousers and undergarments. Key to the African market are lightweight BizFlame anti-static FR21 and FR28 coveralls. These versatile fabrics are designed for use in hot climates with weight options of 210g or 280g.

Portwest has an excellent collection of products for the African markets and are wholly committed to becoming the safety brand of choice. 2013 will see further developments in the product range, African logistics and permanent infrastructure within the region, culminating in local stock and production. The territory manager, Mr. Friday Anwansedo (Friday@portwest.com) can be contacted to discuss sales opportunities at any time, and will be available to meet during NOG 2013, Stand B24.

For more info visit www.portwest.biz

Oil Review Africa Issue One 2013 83

Innovations

New well production surpasses expectations

Technology

S16 ORA 1 2013 ICT News_Layout 1 04/02/2013 14:13 Page 84

EFC Group develops rigless intervention system for Baker Hughes EFC GROUP, A leading designer and manufacturer of instrumentation, monitoring, handling and control systems for the global oil and gas industry, has delivered a highly innovative mechanical handling contract to provide a Rigless Intervention System for Baker Hughes.

Following a brief from the oilfield services company, Aberdeen-based EFC Group delivered on the ambitious concept by designing and building the Mastiff™ RIS. The system was initially conceived for well bore tubular extraction during well abandonment and conductor preinstallation activities, however carries the potential for useful work in many other offshore well servicing and construction type activities.

Ted Littlechild, sales director at EFC Group,

said: “The Mastiff™ RIS provides operators with an alternative method for carrying out pipe installation and retrieval operations, which typically require a costly offshore rig. Using the RIS reduces the cost of abandonment, workover and drive pipe pre-installation operations.”

The Mastiff™ RIS supports pulling and cutting of 15m sections of 36-inch (and larger) conductor pipe, inner casing and cement, a significant improvement over casing jack systems which usually work with 1.5m sections.

The substructure has also been designed to accommodate a wide range of platform layouts to achieve a ‘turn-up and assemble’ capability, without the need for platform modification.

Overall, the design offers a high level of

GWR solution offers improved level control MAGNETROL INTERNATIONAL INC has launched the Eclipse Model 706 guided wave radar (GWR) transmitter, a best in class level control solution that advances guided wave radar technology with improved performance for a wide range of level and interface control applications.

The Eclipse Model 706 is designed to provide outstanding accuracy, reliability and safety for virtually all process industries. Latest generation features include: * Enhanced Signal Performance – The Eclipse Model 706 innovative GWR circuitry achieves both a higher transmit pulse amplitude and improved receiver sensitivity, resulting in a signal to noise ratio (SNR) that is nearly 300 per cent higher than competitive GWR devices. This assures precise, dependable control for every level application, including extremely low dielectric media, extended measuring ranges, and punishing conditions where foaming, boiling or flashing can occur. * Overfill Capable Probes – Magnetrol offers the only guided wave radar transmitter on the market with a complete line of overfill capable probes.

Unlike other GWR transmitters that use algorithms to infer level readings in top of the probe dead zones, the Eclipse Model 706 measures true level to within specification all the way up to the process flange. Coaxial and single rod overfill capable probes can be installed in various configurations on the vessel, even when the risk of flooding exists. * Advanced Diagnostics – The Eclipse Model 706 takes the user interface experience to new levels of convenience and functionality. The LCD diagnostics convey critical real time waveform and trend data with outstanding ease of use. Additionally, it can be preconfigured online prior to shipment, to ensure plug and play transmitter commissioning and automatic capture of echo curve during upsets.

The Eclipse Model 706 transmitter provides safe, efficient and cost effective liquid level and interface control, and is virtually unaffected by fluctuating process conditions including density, dielectric, viscosity and specific gravity.

For more information, visit: eclipse.magnetrol.com.

84 Oil Review Africa Issue One 2013

safety, removing the need for working at height. Employing simple, well-engineered principles and mechanisms has resulted in an affordable, portable solution in comparison to traditional approaches.

Mr Littlechild continued: “The RIS is highly innovative, with unique qualities such as the ability to be quickly dismantled into standard shipping containers, making Mastiff™ easily and affordably transportable to any international location.

“This is a significant contract for us, resulted from a segment opportunity which Baker Hughes identified in the global oil and gas service market. We pride ourselves on how closely we listen to our clients’ requirements, and offer a truly bespoke solution which encompasses these needs.”

Torque action debris breaker removes scale in one day SPECIALIST DOWNHOLE TOOL provider, Peak Well Systems, has been instrumental in reducing the intervention time required for wellbore clean-up operations by a leading international oil company in West Africa. The torque action debris breaker was used to remove hard scale from a wellbore in order to allow the plugging of a water producing zone.

The 2 7/8” tubing had multiple obstruction points from 1,459m to 1,935m at 52° deviation. The sectional lengths cleared of scale deposits by the torque action debris breaker ranged from 1m to 5m. The operator believes that the powerful performance of this Peak tool was key to clearing the well much faster than a prolonged campaign using standard broach systems.

I n response to the outstanding performance of Peak’s downhole tools, a representative from the operating company commented: “The Torque Action Debris Breaker has exceeded our expectations, particularly when you consider that our wireline crew used 0.92” slickline and a 1 ½” toolstring to clear all the restrictions in less than a day.”

Scale removal using wireline is highly cost-effective and also affords the operator better flexibility for clearing further wells.

Other wellbore clean-up campaigns using the Torque Action Debris Breaker have demonstrated that it can reduce intervention times by as much as 75 per cent compared to standard broach systems.

As a direct result of the success of this campaign, the operator has confirmed that it will use Peak’s Torque Action Debris Breaker as the company’s primary system to remove scale and debris restrictions in all future well clean-up operations.

S16 ORA 1 2013 ICT News_Layout 1 04/02/2013 14:13 Page 85

Integrating the mining, petroleum and energy sectors into the development strategy for a Liberia that is moving forward

9 â&#x20AC;&#x201C; 11 April 2013 Monrovia, Republic of Liberia

Organised by:

www.limep.com

PLEASE FAX THIS PAGE WITH YOUR DETAILS TO +44 20 7681 3120 or email to: Liberia@ametrade.org

S16 ORA 1 2013 ICT News_Layout 1 04/02/2013 14:13 Page 86

ICT

CNL expands operations into North Africa CNL SOFTWARE, A world leader in Physical Security Information Management (PSIM) software, has expanded its operations in the Middle East and North Africa in the wake of increased demand for its IPSecurityCenter PSIM software, and the successful deployments of some of the largest PSIM projects in the region.

During 2012, CNL Software increased its number of reference customers in the Middle East; helping to bring PSIM solutions to critical national infrastructure, law enforcement and safe city projects. To support this growth in the region CNL Software has expanded the region’s team based in Dubai, with the addition of Daniel

Bloodworth as Technical Sales Manager ME and Lee Wagstaffe as Technical Account Manager.

“CNL Software is investing in deploying experienced resources in the Middle East, to not only support our existing customers, but to respond to a significant increase in requests for new PSIM projects in the region,” explained Matthew Kushner, VP Global Sales & Marketing – CNL Software. “We are taking this market very seriously, as we see that the majority of new security projects are specifying PSIM.” Daniel Bloodworth continued, “This year we launched Arabic support in IPSecurityCenter to meet our customers’ requirements. In addition,

we have secured a number of strategic alliances and partnerships with organisations including ArrowLabs, Ateco, GBM, Orion Systems JLT, Schneider Electric and Smart Cube to better support the region. We look forward to building upon this year’s accomplishments by delivering even more, successful PSIM projects throughout 2013.”

CNL Software’s IPSecurityCenter PSIM Solution provides a single Common Operating Platform (COP) for all of an organisation’s mission-critical security systems, delivering intelligence to the point of need and providing process guidance to enhance security posture.

Schlumberger launches new spectroscopy service SCHLUMBERGER HAS ADDED the Litho Scanner* high-definition spectroscopy service to the Scanner Family* rock and fluid characterisation services.

The Litho Scanner service measures an enhanced suite of elements, including carbon, magnesium and aluminum, in real time to help provide a detailed description of complex reservoirs, including unconventional, shaly sand and carbonate. In addition, this latest wireline service provides a stand-alone quantitative determination of total organic carbon (TOC), critical for the evaluation of shale reservoirs.

“Customers need to understand formation composition and mineralogy, particularly in unconventional reservoirs to be able to make timely completion

decisions,” said Catherine MacGregor, president, Schlumberger Wireline. “Litho Scanner provides critical formation and reservoir data at the well site previously available only after extensive, time consuming and costly laboratory analyses.”

The Litho Scanner service has been run successfully on more than 80 wells in all the major shale plays in North America, in South America and in conventional reservoirs. In Canada, the Litho Scanner service was successfully used to interpret the mineralogy in a lithologically complex shale gas reservoir comprising multiple clay types in addition to quartz, feldspar, calcite, dolomite, ankerite and pyrite. The determination of TOC enabled both an accurate quantification of total porosity and a quantitative assessment of reservoir quality.

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