JPT Uncovering the Middle East and North Africa 140296.5

Supplement to

MIDDLE EAST AND NORTH AFRICA

UNCOVERING THE

EXECUTIVE INTERVIEWSAHMED ALI AL SAYEGH, DOLPHIN ENERGY

ABDULLA NASSER AL SUWAIDI, ADNOCABDELHAMID ZERGUINE, SONATRACH

FAROUK HUSSAIN AL-ZANKI, KPCARNAUD BREUILLAC, TOTAL

MARK CARNE, SHELL

SAUDI ARABIA

KUWAIT

UAE

ALGERIA

IRAQ

QATAR

EGYPT

LIBYA

OMAN

COUNTRY ANALYSIS

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COVER PHOTO Saudi Aramco has created a 27-island complex connected by causeways to produce oil from the Manifa field, one of the largest oil fields in the world. The project is expected to produce 900,000 B/D of Arabian heavy crude plus natural gas and liquids when fully operational in late 2014. The enormous project also includes offshore platforms, water injection facilities, onshore drillsites, pipelines, and bridges. The project design ensures that it does not interfere with the migrations of several species and was nominated for a UNESCO environmental responsibility award.

JPT Supplement Staff Georgeann Bilich, Publisher

John Donnelly, JPT Editor

Abdelghani Henni, JPT Middle East Staff Writer

Stephen Rassenfoss, JPT Emerging Technology Editor

Robin Beckwith, Senior Staff Writer

Adam Wilson, Editorial Manager

Ngeng Choo Segalla, Copy Editor

Alex Asfar, Senior Manager Publishing Services

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Allan Jones, Graphic Designer

Craig W. Moritz, Senior Manager Exhibits and Sales

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3 INTRODUCTION: UNCOVERING THE MIDDLE EAST AND NORTH AFRICA The region controls 51% of the worlds proven crude reserves. Learn who controls what in the region.

4 SAUDI ARABIA: TRANSFORMATION GAMES Aramco is boosting its search for gas to achieve its new strategic goal, and is injecting innovation in the process.

16 KUWAIT: 2020 VISION Political meddling is costing the nations energy sector, but KPC is determined to achieve its target.

24 KPC Q&A: FAROUK AL-ZANKI, CEO Achieving its 2020 strategy goal is the ultimate objective of KPCs CEO.

26 UAE: LOOKING AHEAD Soaring local consumption is pushing ADNOC to tap the development of sour gas fields, as well as boost crude production.

32 ADNOC Q&A: ABDULLA AL SUWAIDI, DIRECTORGENERAL Ongoing projects are increasing output to meet soaring local demand.

34 SONATRACH Q&A: ABDELHAMID ZERGUINE, CEO The head of Sonatrach says multibillion-dollar projects are keeping Algerias upstream dreams alive.

40 IRAQ: A GIANT WOBBLES Colossal field development projects and a new era of exploration require a clear and stable investment climate.

46 QATAR: GAS FOR CASH After working on monetizing its gas reserves, the tiny Gulf state is focusing on redeveloping its oil fields.

52 DOLPHIN ENERGY Q&A: AHMED AL SAYEGH, CEO Dolphin Energy is supplying gas to the UAE with a firm commitment to the environment.

54 EGYPT: OPENING UP Egypt is sweetening its investment rules to attract IOCs to oil and gas bidrounds.

58 LIBYA: RISING FROM THE ASHES Restoring security is key to attracting investment to North Africas potential powerhouse.

62 OMAN: GOING WITH THE FLOW The Sultanate is investing billions of dollars to offset declines in oil production.

67 TOTAL Q&A: ARNAUD BREUILLAC, PRESIDENT E&P MIDDLE EAST The French supermajor is committed to the development of the energy sector in the region.

69 SHELL Q&A: MARK CARNE, EVP UPSTREAM MIDDLE EAST Shell sees opportunities for growth and long-term investment in theregion.

71 SPE IN THE MIDDLE EAST AND NORTH AFRICA Upcoming events in the Middle East and North Africa are listed.

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MIDDLE EAST AND NORTH AFRICAINTRODUCTION

3SUPPLEMENT TO JPT JANUARY 2013

Much of the worlds conventional oil and gas reserves are concentrated in the Middle East and North Africa region, with more than 51% of global proven crude reserves and 42.2% of world proven gas reserves located in this region. Saudi Arabia continues to

lead the world in crude oil reserves, and Iran and Qatar top the list for natural gas; but, many other countries are also importantplayers. These reserves, for the most part, are located in supergiant or giant oil fields. Of the 20 largest oil fields in the world, 13 are in this region, including the Ghawar Field in Saudi Arabia, Rumaila in Iraq, Zakum in the United Arab Emirates (UAE), and Burgan in Kuwait. Qatar and Iran contain the worlds largest gas deposits: the North Field in Qatar and the South Pars in Iran. The cost of oil exploration in the region is the lowest in the world, at an average cost of USD 3/bbl, compared with other regions where the cost is about USD 20/bbl.

The region is also the worlds leading oil producer. Five countries produce more than 2 million B/DSaudi Arabia, the UAE, Iraq, Iran, and Kuwait. While the Middle Eastern producers are increasingly focused on the Asian markets, North African producers such as Algeria and Libya target European clients.

The prospects for increased oil production vary significantly from country to country. In its medium-term forecast, the International Energy Agency foresees a significant output increase for Iraq, moderate growth in the

UAE, no change in Saudi Arabia and Kuwait, and a reduction in Iran over the next 5 years. Overall development of production capacity is expected to be generally slow. Future investment should be focused not only on the development of new capacity but also on compensating for the natural decline in currentdeposits.

Increases in gas production will contribute more to meeting fast-growing domestic demand rather than boosting exports. Some countries in the region have started looking for ways to develop unconventional resources including shale gas. Algeria is taking the lead in this domain, and Algerian Energy Minister Youcef Yousfi revealed that he believes his countrys reserves of shale gas are equal to that of the US. Algerias state energy company, Sonatrach, has signed a cooperation agreement with Italian company Eni for the development of unconventional oil and gas in Algeria, with a particular focus on shale.

According to a study by UAE-based Contax Partners, Oman is also making strides in unconventional gas development; and, through its Block 61 project with BP, it may host one of the most ambitious tight gas drilling projects in the world.

Furthermore, Saudi Aramco has signaled its intent regarding unconventionals by entering advanced talks to take a USD 2.2 billion, 30% stake in Frac Tec International, an American firm that has been a major player in the US shale revolution. Aramco aims to be extracting its first shale by 2020 and is currently conducting studies for potential shaleplays.

UNCOVERING THE

MIDDLE EAST AND NORTH AFRICAThe Middle East and North Africa region remains the worlds energy epicenter.

This special supplement sheds light on ongoing development in the region and includes one-on-one interviews with leading executives of national and international oil companies.

ABDELGHANI HENNI, JPT MIDDLE EAST STAFF WRITER

TRANSFORMATION GAMES

SAUDI ARABIA

SAUDIA ARABIATRANSFORMATION GAMES


Since the discovery of the first oil well in 1938, Saudi Arabia has emerged as a reliable global source of oil for the international market. It has recently completed a major oil capacity expansion, increasing its average production capacity to 9.1million B/D, with an estimated annual capacity of 3.3 billion bbl. This has made the the Kingdom of Saudi Arabia (KSA) a top oil producer in the world.

Over the past year, Saudi Arabia has maintained its world-leading conventional crude oil reserves at 259.7billion bbl by replacing 2011 production with oil from new field discoveries, expanding existing fields, and optimizing production. It also controls the worlds fourth largest gas reserves of 282 Tcf, with an average daily production of 9.9 Bcf/D.

Saudi Aramco, the state-owned company, continues its nationwide exploration efforts, focusing on frontier areas in the Red Sea and complex reservoirs onshore and offshore.

With the addition of Wedyan-1, a wildcat oil well located in the Rub al-Khali, 450 km southeast of Dammam, the company reached 113 total oil- and gasfield discoveries in 2011. The well flowed 2,300 bbl of oil from the Mishrif reservoirs. This well was the second new oilfield discovery in the Rub al-Khali since Saudi Aramco resumed exploration activities in the area in2005.

One of the major oil fields the company is developing is the offshore Manifa field, the fifth largest oil field in the world. The field is southeast of Safaniyah. Production from the field dates back to 1964, following the drilling of eight development wells. However, the facilities were mothballed soon after. The field is estimated to hold reserves of about 10 billion bbl.

Manifa is one of the biggest engineering projects in the world, involving 41 km of causeways, 3 km of bridges, 27 drilling islands, 13 offshore platforms, 15 onshore drillsites, water supply wells, injection facilities, multiple pipelines, a 420 MW heat and electricity plant, not to mention relocation of an entire coral reef.

The 900,000-B/D heavy and sour oil field is set to be fully onstream by 2014. Overall offshore construction is 97% complete, including all offshore platform decks, subsea pipelines for crude oil gathering and water injection, and subsea power and communicationcables.

The company also completed all 27 man-made islands and the main and lateral causeways for Manifa. The islands were constructed to host shallow-water wells, which are more cost-effective than offshore rigs.

The field was originally planned for completion in 2011, but Saudi Aramco moved the startup date. Because we are producing much less than we planned a few years ago when we launched Manifa, we are no longer in need of Manifa at the earlier date, which was announced when the program was originally launched, according to Kahlid Al-Falih, president and chief

executive officer of Saudi Aramco.It will increase the Arab heavy component of our production and offset decline from otherareas.

By the time it is fully operational in December 2014, the Manifa field is expected to produce 900,000B/D of Arabian heavy crude oil, 90 Mcf/D of sour gas, and 65,000 B/D of hydrocarbon condensate. The Manifa will make up for the fields decline and keep Saudi Aramco production at 12 million B/D.

On the other hand, analysts say that the Manifa field is being fast tracked for several reasons. First, to provide feedstock for the new refineries that are being built with the help with oil majors. Second, to counter natural decline rates and maintain capacity at 12 million B/D. However, we should remember that, while Aramco is fast tracking the project now, it mothballed this project in the past, said Anas Alhajji, chief economist at NGP Energy Capital Management.

The Manifa field has been chosen as the main feedstock provider for SaudiAramcos two new 400,000-B/D heavy-oil refinery joint ventures with Total and Sinopec. The Yanbu refinery will process heavy crude from Saudi Arabias Manifa oil field, said Fahad Al-Helal, president and CEO of Yanbu Aramco Sinopec Refining Company(Yasref).

In addition to Manifa, Saudi Aramco also works on the Safaniya field, the worlds largest offshore field, which is about 200 km north of Dhahran, with a production capacity of about 1.3 million B/D. The Phase 1 upgrade of Safaniya aims to maintain the fields maximum production capacity of

LEFT Saudi Aramco produces Arabian Extra Light crude oil from the remote Shaybah field in the Rub al-Khali desert.

Following the completion of a massive oil development program, Saudi Aramco is focusing on developing gas reserves. This will allow the company to move further down the downstream chain and to become a fully integrated energy company by 2020.



6 UNCOVERING THE MIDDLE EAST AND NORTH AFRICA

Arabian Heavy crude oil. By the end of 2011, construction levels at the field reached 35% and flowline upgrades were successfully completed.

The infrastructure upgrade and electrification project will help sustain crude oil production to meet Saudi Aramcos maximum sustainable capacity targets for the field by the end of2013.

Stepping on the GasFrom 2009, Saudi Aramco refocused its attention to gas, launching a fast-track program for a host of projects in order to boost domestic supplies and meet spiralling domestic gas demand, which continues to come in at levels of about 6 to 7% per year. In fact, a gas shortage over the past 5 years has forced Saudi Arabia to burn increasing amounts of crude and refined products to generate

power, eating into its effective spare-capacity cushion as well.

We have undertaken aggressive programs of exploration to move gas resources into reserves utilizing and developing the most advanced technologies, said Prince Faisal Bin Turki Bin Abdulaziz, adviser, Ministry of Petroleum and Mineral Resources. This will enable the kingdom to grow its gas production capacity to about 15Bcf/D by 2016 from 7.7 Bcf/D in 2002, headded.

Saudi Arabias natural gas reserve increased sharply last year to 282 Tcf, compared with 181 Tcf in 1990. Average 2011 gas output was 9.88Bcf/D; by year-end, Saudi Aramco had managed to achieve peak daily output of 11.2Bcf/D. Recoverable gas reserves rose for at least the 12th year in a row, but

recoverable crude and condensate reserves fell in 2011, the first such fall since 1999, according to available data.

For instance, in 1990, about 75% of natural gas reserves in Saudi Arabia was associated gas, of which production can be constrained by the factors of oil production. Today, nonassociated gas accounts for more than 48% of total gas reserves, and we expect it to constitute a significantly higher proportion in the future, said Ali Al-Naimi, minister of petroleum and mineral resources of Saudi Arabia.

Alongside the development of the Manifa, which will supply an additional 65,000 B/D of condensate and 90 millionscf/D of sour gas once operational, Saudi Aramco has also committed to strong spending on its offshore gas developments to keep pace

SAUDI ARAMCO BY THE NUMBERS (million B/D)

2011 2010 2009 2008 2007 2006 2005

Crude and Condensate Reserves (bn barrels) 259.7 260.1 260.1 259.9 259.9 259.9 259.8

Crude Production 9.07 7.91 7.91 8.97 8.53 8.91 9.06

Crude Exports 6.63 5.53 5.66 6.88 6.60 6.96 7.19

Products Output 1.355 1.369 1.36 1.58 1.57 1.63 1.62

Products Exports 0.338 0.366 0.409 0.362 0.373 0.504 0.552

NGL Production from Hydrocarbon Gases 1.264 1.219 1.124 1.1 1.08 1.09 1.1

Of Which Propane 0.482 0.462 0.417 0.399 0.394 0.409 0.413

Of Which Butane 0.312 0.292 0.276 0.258 0.260 0.258 0.258

Of Which Condensate 0.255 0.257 0.227 0.255 0.258 0.257 0.245

Of Which Natural Gasoline 0.215 0.208 0.204 0.186 0.177 0.168 0.182

NGL Exports* 0.910 0.867 0.760 0.777 0.786 0.782 0.793

Gas Reserves (Tcf) 282.600 279.000 275.200 263.000 253.800 248.500 238.500

Raw Gas to Gas Plants (bn cfd) 9.88 9.39 8.67 8.336 7.998 8.224 7.871

Sales Gas Output (Trillion Btu/D) 7.87 6.99 7.421 7.61 7.023 6.86 6.63

Of Which Ethane (Trillion Btu/D) 1.4 1.33 1.114 1.022 1.033 1.0278 1.079

Reserves= recoverableSource: Saudia Aramco, *excludes sales by joint venture Samref and Sasref reneries

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with annual domestic demand growth of 7%.

Saudi Aramco is targeting a 30% increase in sales gas output by 2014 to 8 billion scf/D. In the longer term, the kingdom must try to meet a forecast of a threefold rise in consumption to 14.5billion scf/D by 2030.

With exploration in the onshore Rub al-Khali (Empty Quarter) continuing to disappoint, the company has switched its focus to the offshore Karan field, discovered in 2006.

Karan, 100 km north of the giant Ghawar oil field, is the kingdoms first nonassociated offshore gas field to be developed by Saudi Aramco. It has reserves of more than 9 Tcf of gas and the company expects to produce 1.8Bcf/D from the field by 2013.

Also, the startup of the offshore 1.3-Bcf/D Hasbah and 1.2-Bcf/D Arabiyah nonassociated fields in 2014 will be used to feed the Wasit gas plant, which is considered as one of the largest gas plants that Saudi Aramco has ever built and is expected to be completed in 2014. Ordinary supply of 2.5 Bcf/D will produce 1.75 Bcf/D of sales gas and can be augmented to 3.05 Bcf/D in peak summer demand months, the companysaid.

In addition, Saudi Aramco has begun pilot projects using high-end technology to extract unconventional gas, including tight gas and shale gas. The first unconventional gas wells are planned for this year. Saudi Arabias unconventional gas reserves resource base is large. The numbers are in the hundreds of Tcf, which are recoverable, Al-Falih said, cautioning, Until we do the exploration and pilots, we will not be able to bank on them, so to speak.

Ethane Shortage Maintaining the growth of gas and ethane output is vital to Saudi Arabia, given soaring domestic demand. In the past 7 years, there was massive allocation of ethane gas feedstock to many private and government-held petrochemical projects, which led to a shortage of ethane gas in Saudi

Arabia. Because of this, Saudi Aramco is undertaking several investments to keep ethane supply balanced, including the development of the Shaybah NGL project, to balance ethane gas.

The Shaybah NGL Program will construct a grassroots NGL recovery plant at the Shaybah field. It will process 2.4 Bcf/D of gas to produce 240,000 B/D of ethane when it starts production in 2014. In addition to increasing investment, the company is also setting new strategies to maximize the usage of its different available feedstock. Now, the mixed feedstock

strategy in the kingdom consists of the allocation of ethane and liquid cracking to petrochemicals producers. It is a strategy which governs the allocation of feedstock like ethane and naphtha to petrochemicals producers, said Abdulaziz Al-Judaimi, vice president of chemicals at Saudi Aramco.

Moving Downstream Saudi Aramcos ultimate goal is to be the worlds leading integrated energy and chemicals company by 2020. Over the decades, Saudi Aramco has transformed to a fully energy integrated company, said Abdallah al-Saadan, vice president of corporate planning at Saudi Aramco.

We have launched 14 initiatives which aimed at creating a sustainable and diversified expansion of the kingdoms economy and to enable a globally competitive and vibrant Saudi energy sector, he said.

As part of its diversification program, Saudi Arabias new policy forhydrocarbon resource utilization isbased on adding value at every stepinthe production chain. This meansthe procedure of allocating feedstock for future projects will not be as easy as it has been in the past because of stiff competition for gasfeedstock.

The plan to increase gas production will offer companies from different industrial sectors the opportunity to implement their long-term investment without worrying about the availability of feedstock.

Downstream producers are asking at what cost the feedstock will be allocated. The current price for ethane gas in Saudi Arabia is USD 0.75 per million Btu, while propane is calculated according to a specific formula of naphtha price in Japan multiplied by a conversion factor, currently estimated at about 0.700.

This officially expired last year, but the government has yet to disclose a new pricing. The price of the ethane feedstock supplied for petrochemical companies hasnt been increased, and it will remain stable at the same level, al-Naimi said in early January.

In spite of a shortage of gas feedstock, the Saudi petrochemical industry is entering a golden era. We are witnessing the largest growth in the industrys history with the total production of petrochemicals, chemicals, and polymers expected to be over 100 million tons by 2016, a 250% growth from 2006 levels, said Turki.

Our annual production of ethylene and propylene is expected to grow by over 230% and 300%, respectively, from 2006, he said. The associated cumulative investments for all of these petrochemical projects are expected to be more than $150 billion by 2016.

Manifa is one of the biggest engineering projects in

the world, involving 41km of causeways, 3km of

bridges, 27 drilling islands, 13 offshore platforms, 15 onshore drill sites, water

supply wells, injection facilities, multiple pipelines,

and a 420 MW heat and electricity plant.

Integration GameSaudi Aramco has traditionally worked on developing its hydrocarbon reserves alone. This has always worked well for the upstream projects. For the downstream projects, the story isdifferent.

The company seeks partners with the expertise to plan, execute, finance, and subsequently operate a world-scale integrated refining and petrochemical complex or an oil refinery. This is not an easy task and leaves only the worlds largest IOCs or chemical companies as likely partners.

Saudi Aramco has launched a number of integrated petrochemical and refining projects, namely Rabigh Refining and Petrochemicals Company (Petro Rabigh) in joint venture (JV) with Japans Sumitomo, which was launched in 2009. The two partners also launched a second

phase of the project. Saudi Aramco Total Refining and Petrochemicals (SATORP) is slashed for completion in earlier 2013, and the Yasref, despite the exit of ConocoPhillips, which was replaced bythe Chinese Sinopec. Sinopec is one of the biggest companies in the world, and they provide their expertise to make the JV successful as it runs 33 refineries over the world, al-Helal said, commenting on the reasons behind the selection of Sinopec as a partner.

In addition, Saudi Aramco and Dow Chemical have launched what is considered the largest integrated petrochemical and refining project intheworld, Sadara Chemical. The USD-20-billion project will consist of 26 units building on Saudi Aramcos project management and execution expertise and utilizing many of Dows industry leading technologies. Once completed,

the Sadara complex will represent the worlds largest petrochemical facility ever built in a single phase.

Several companies involved in downstream projects with Saudi Aramco consider this move as an opportunity to gain a footprint in the upstream sector. For Total, our involvement in a downstream project in KSA may help us in gaining a footprint in the countrys upstream sector, said Patrick Pouyann, president of refining and chemicals atTotal.

Although some integrated projects are very engineering challenging and require cutting-edge technologies, the increasing demand on jobs for locals is putting more pressure on Saudi Aramco to create more jobs. Thats why it aims to be the worlds leading integrated energy and chemicals company by 2020.

|

|

SAUDI ARAMCO


In the oil industry, smart water has been synonymous withlow-salinity waterflooding to increase oil recoveries. But work by Saudi Aramco points to chemical changes that can make injection more effective other than lowsalinity.

The goal of the SmartWater Flood research program at Saudi Aramcos EXPEC Advanced Research Center (ARC) is to modify the chemistry of the seawater it injects, altering the properties of the rock surfaces, loosening the reservoirs hold on the crude oil left after years of waterflooding.

Saudi Aramco has pushed ahead with an ambitious research and development program to look for ways to increase oil recovery from carbonate reservoirs by changing the salinity and ionic composition of the seawater injected to maintain pressure and push oil toward producing wells.

It has shown significantly more oil can ultimately be produced by diluting seawater, while it studies why that occurs in search of a better formula for its SmartWaterflooding.

We still need to do more fundamental research to understand how water ions interact with carbonate rock surfacesthis is the long-term objective, said Samer AlAshgar, EXPEC ARC manager. We are coupling laboratory research and field testing to expedite the development of this emerging technology.

The goal is to understand how to control wettabilitythe tendency of a rock surface to attract oil or to attract waterby changing the ionic composition of the water. Researchers have found that chemicals other than sodium chloride are the critical factors in that change, though salt can affect the process.

EXPEC ARC is now trying to create injection water formulated to remove residual oil from rock surfaces without having to reduce the seawaters salinity by diluting it with de-ionized water.

That would represent a major advance. Breaking the connection with low salinity would eliminate the cost and logistical challenges connected with producing fresh water for dilution, which can be a tall barrier for operators considering low-salinity injection. Our ultimate target is to

reveal the full potential of SmartWater Flood without the need to dilute, said Ali Yousef, a petroleum engineering specialist and Focus Area Champion of SmartWater Flood in Reservoir Engineering Technology Division at EXPEC ARC. Dilution is only the starting point, and we are confident thataddressing the role of ions is the key to achieving thisgoal.

The Carbonate ChallengeWhen Saudi Aramco began its smart water research program in 2007, there were doubts in the industry it could be effective in a carbonate formation. Saudi Aramco embraced the challenge because it offered it a chance to maximize the value of the enormous seawater injection system used to maintain production, while other options presented significant challenges.

Chemically enhanced oil recovery (EOR) would require developing chemicals able to perform in Saudi Arabias high-temperature/high-salinity carbonate reservoirs. Carbon

SAUDI ARAMCO

INJECTION INNOVATIONSEEKING A SMARTER VERSION OF LOW-SALINITY FLOODING

Workers prepare for an early test of Saudi Aramcos SmartWater Flood technology. The leader of the 25-person project team, Ali Yousef, is on the right.

STEPHEN RASSENFOSS, JPT EMERGING TECHNOLOGY EDITOR


dioxide flooding requires reserves of the gas not readily available in Saudi Arabia.

In comparison the added infrastructure needed to prepare and deliver smart water appeared limited, and theresearch suggested it could improve results throughout the life of a field, not just older reservoirs where years ofwater flooding has left only the hard-to-produce residualoil.

But back then, there was little known about how techniques that had worked elsewhere would perform in Saudi Arabias fields. Most of the published papers covered injection in sandstone reservoirs, where the benefits were thought to be due to the clay minerals in those reservoirs, which are not found in carbonate ones.

That meant Saudi Aramcos research team was basically starting from square one. They did lab tests confirming that flooding a carbonate reservoir with a mixture of sea water and de-ionized water yielded more oil, and fundamental research into why that occurred. This required finding ways to observe the behavior of oil droplets on the surface of reservoir rock. We needed new tools and procedures, Yousef said.

EXPEC soon found that diluted sea water could yield more oil from core samples flooded in lab tests. The Smart Water Flood program was recently honored as the Best Oil and Gas Innovation or Technology in the Middle East North Africa region at the ADIPEC Conference. But recognition was slow in coming.

Our early research in 2007-2009 confirmed that diluting seawater does work for carbonate reservoirs, Yousef said. Even after publishing our research work, many were skeptical about it.

The Big DifferenceFor those involved in smart water research and development a prime target is changing the wettability of the rock, switching it from a tendency to adsorb oil (oil wet) to a preference for water (water wet). There were doubts that could be done because of the differences in how fluids and rocks interact in carbonate and sandstone reservoirs.

Saudi Aramcos laboratory testing showed that reducing the salinity of a water flood yields more oil production from core samples, after extended seawater flooding.

The core-flood tests showed that using dilution to halve the salinity of the injection water used in Saudi fields, to about 30,000 ppm, increased the incremental recovery from the core composite by 8%. Further increasing the dilution, reducing the salinity to about 6,000 ppm, added 10% to the incremental recovery.

Encouraging lab results led to single-well field tests that confirmed the potential of increasing oil recovery in a typical Saudi carbonate reservoir. Flooding a small area around a well and then producing from it reduced the residual oil present by about 7-9 saturation units, in line with pre-test modeling and simulation studies.

Saudi Aramco still plans to conduct more single well tests to fully optimize the current process leading to a multi-well demonstration pilot to determine the impact on ultimate recovery and reserves, said Abdulaziz Al-Kaabi, chief technologist EXPEC ARC Reservoir Engineering Technology.

Its studies of changes on the rock surface showed the main reason for the gains was a change in the wettability from slightly oil-wet to strongly water-wet.

Now the goal is to discover what causes this change, and use that understanding to create more effective injection

SeawaterTotal Salinity57,600 ppm

Twice DilutedSeawater

Total Salinity:30,000 ppm

8.5%IncrementalOil Recovery

100

Cum

ulat

ive

Oil R

ecov

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(% O

OIC)

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10 Times Diluted

SeawaterTotal Salinity:

6,000 ppm

10%IncrementalOil Recovery

20 Times Diluted


3,000 ppm


100 Times Diluted


600 ppm


The chart shows greater oil recovery from a composite core as increasing amounts of water with progressively lower salinity levels is injected, starting at the left with seawater (about 60,000 ppm salinity). But there is limit to the benefits of dilution.

Reduced salinity water was observed to change the wettability of a rock toward water-wet. Contact angle measurements, an indication of the rocks attraction to oil molecules, changed as the salinity levels were reduced, up to a point.

FieldFormation

Water

100

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Seawater

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tabi

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Test 1

Test 2Intermediate-wet Zone

Water-wet Zone

Test 3

Seawater

SAUDI ARAMCO


water. The real challenge is to fully describe how tuning ionic composition changes rock wettability, said Yousef. This has been our focus over the past years, and we have successfully achieved significant progress toward this end.

Published studies suggest that introducing the right ions change the charge on the carbonate rock surface, loosening its grip on oil not removed by water flooding.

Saudi Aramcos SmartWater research also showed that it enhances the pore coupling among different pore systems found in Saudi Arabian carbonate reservoirs. All of these are still possible explanations for changing the chemistry of injection water may matter.

Past smart water research have pointed to ions other than salt (Na Cl) having the greatest impact on the relationship between fluids and rock in a carbonate reservoir. Ion reactivity with the carbonate rock surface is very complex and depends on different factors including rock mineralogy, reservoir conditions, oil composition, what has been injected in the reservoir, and others. Yousef said.

Low-Salinitys LimitsSmart water flooding began with the observation that reducing the salinity of injection water could mean greater production. But there is a limit.

Saudi Aramco research showed the gains from dilution decline quickly after passing 10 times diluted (6,000 ppm). Going to 100 times diluted with fresh water offered no added benefit. Our research on this front showed that we need to have the right ion composition, not just dilution, Yousefsaid.

There are many theories of what happens at the pore level that releases more oil. Past studies come back to the ability of three ions found in seawatersulfate (SO

4) calcium

(Ca+) and magnesium (Mg+)to change the chemistry of the rock-fluid interface reducing the hold of oil.

For example in chalk reservoirs, the negatively charged sulfate combines with positively charged ions on the rock surface, reducing its attraction to the acidic, negatively charged carboxylic groups in the oil, according to an SPE paper whose authors include Tors Austed, a professor at the University of Stavanger who has investigated seawater injection in Norwegian fields.

The calcium, and in hot reservoirs the magnesium, further reduce the attraction by bonding on the oil side of the interface, further shifting reservoirs described as oil wet or mixed-wet, toward water wet.

A paper by Saudi Aramco also suggested that SmartWater can add more useful ions by dissolving anhydrite (CaSo

4) found in the formation, generating sulfate

ions. At the same time, diluting seawater will significantly reduce associated with salt ions (Na+, Cl-) in the reservoir, and this will increase accessibility of sulfate ions to carbonate rocksurface.

Dissolving anhydrite could also enhance the connectivity among pore systems allowing SmartWater to reach pores that were not accessible by injected seawater, according to the paper.

Sodium chloride (Na Cl) does not appear to have a direct role in that process. But Yousef and Austed said that in reservoirs with high levels of salinity, salt can increase the presence of sodium (Na 1-) and chlorine (Cl 1+) in the microscopic layers separating oil and rock, limiting access for the three ions considered capable of causing wettabilitychanges.

Austed concluded that high levels of dilution reduce both the level of salt, and of the ions in seawater capable of altering the rock properties. He concluded that adding more sulfate could improve oil recovery.

Saudi Aramco has come up with a theory for how to change the reservoir chemistry to free more oil in itsreservoirs.

We have recovery mechanisms that are essentially different from what has been proposed in the literature, said Yousef. Rather than changes based on sulfate, calcium and magnesium, we need to understand that it is not possible to explain the impact of water chemistry on residual oil independent from complexity of carbonate porous media (heterogeneity at the pore scale).

A well site in the Saudi Arabian desert set up for an early test in Saudi Aramcos SmartWater technology development effort. The line of tanks hold desalinated water to dilute seawater, which improved oil recoveries. A goal of the program is to use a fundamental understanding of the process to increase yields without having todilute.

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Considering All the AnglesThere are many reasons offered for why results elsewhere would not apply in Saudi Arabian oilfields. On the list in a paper from Saudi Aramco are: differences in the rock types, the composition of the reservoir water and fluids, injection practices, and the laboratory methods used to simulate what goes on in the formation.

That could also be the starting point for a check list of criteria for applying its Smart-Water Flood technology in the field. As with other EOR methods the success of the project will depend on carefully choosing a reservoir based on detailed testing of it properties, designing a program that suits the conditions there, and executing the planoperationally.

The Saudi Aramco Smart-Water Flood team reflects the complexity of the task. It now numbers 25 people from a wide range of disciplines. There are chemists to analyze the chemicals present and how they change fluid-rock interactions, research engineers, reservoir engineers, production engineers and field operations experts.

Saudi Aramco is studying how ions change the oil-water-rock interaction at the microscopic level in the reservoir while testing the process in the field to identify potential problems and optimize the process.

For further reading:

SPE 154076 Improved/Enhanced Oil Recovery from Carbonate Reservoirs by Tuning Injection Water Salinity andIonic Content by Ali Yousef, Saudi Aramco et al.

SPE 154077 The Impact of the Injection Water Chemistry onOil Recovery From Carbonate Reservoirs by Ali Yousef, Saudi Aramco, et al.

SPE 159526 SmartWater Flooding: Industrys First Field Testin Carbonate Reservoirs by Ali Yousef, Saudi Aramco, et al.

SPE 137634 Laboratory Investigation of the Impact of Injection Water Salinity and Ionic Content on Oil RecoveryFrom Carbonate Reservoirs by Ali Yousef, Saudi Aramco, etal.

SPE 154570 Water-Based Enhanced Oil recovery (EOR) bySmart Water in Carbonate Reservoirs by S. Jafar Fathi, Core Energy AS, and Department of Petroleum Technology, University of Stavanger, et al.

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2020 VISION

KUWAIT

KUWAIT2020 VISION


Kuwaits first commercial production of oil began in 1946, some 65 years ago. Up until 1990, its production had been dominated by a few reservoirs. The Burgan Al Kabeer field (Greater Burgan) had the biggest share of the total production reaching 70 to 80%.

At the time, all its production was natural flow and water-free and the average oil rate per well was significantly high. Reserve-to-production ratio was exceptionally high. In addition, capital investment and operating cost were relatively low, considering the high incremental production that, at one time, reached almost 4 million B/D.

However, such luxury and blessing could not continue forever. Over the past 20 years, and following the Iraqi invasion, Kuwait Petroleum Corporation (KPC) has exerted much effort to reshape the oil sector to prepare for thefuture.

As the national oil company in Kuwait, KPC controls the energy sector through several subsidiaries. Its major subsidiaries are Kuwait Oil Company (KOC), the upstream arm; Kuwait National Petroleum Corporation (KNPC), the downstream arm; Petrochemical Industries Corporation (PIC), in charge of the petrochemical sector in the country; and Kuwait Foreign Petroleum Exploration Company (KUFPEC), in charge of exploration and production (E&P) activities outside the country.

Kuwait is the fourth largest oil exporter in the world, with its

population of 5 million consuming only 10% of its oil domestically, and is now pushing at the limit of its production capacity. By 2020, Kuwait hopes to have production capacity of 4 millionB/D of oil and has already announced a series of ambitious projects to make thishappen.

The oil fields spread over the state and split off into four main parts: north, west, south, and east. Kuwaits production capacity includes 700,000B/D of oil from the north fields, 500,000 B/D from the west fields, and 1.7 million B/D from the Greater Burgan.

It also produces oil from joint fields, called the divided zone or neutral zone, with Saudi Arabia. This includes the divided land zone in Wafra and the offshore divided zone, known as the joint operations, in Al Khafji. Kuwait Gulf Oil Company (KGOC) is responsible for the management of Kuwaits share of the natural resources in the dividedzone.

The Swing FieldKuwaits swing producer is the Greater Burgan, located in southeastern Kuwait. It contributes the biggest share of the crude oil production of about 1.7million B/D, but Burgans days as the mainstream of the local oil industry are numbered. Local experts say about 62% of its total reserves have been depleted. While the current high rates of production from the field can be maintained over the medium term, there are fears that this could cause irreparable damage to the reservoir.

The Greater Burgan is the worlds largest sandstone oil field, with a total surface area of about 1000 km2. Oil production from this area is considered easy compared with other locations. It includes three producing subfieldsBurgan itself, Magwa, and Ahmadi.

In October 2011, KOC awarded a water injection project contract at Burgan to Koreas GS Engineering and Construction to maintain pressure. The water injection is into Wara, one of the fastest depleting reservoirs, and the vital project will allow the company to maintain the current output level from Wara reservoirs. Reservoirs recently discovered at the field are also helping to offset depletion.

It will also pave the way for future projects related to the increase of oil production and the preservation of the environment through dealing with overflow and associated water by recycling and injecting it into the reservoirs. The project includes the injection of about 6,000 bbl of treated water in several wells in the Burgan oil field by a pipeline network to be fed by anew central installation.

KOC also plans a water injection pilot plant in the Dharif field.

Northern Kuwait FieldsUpstream activity in north Kuwait is a massive operation, and it is entering an exciting phase, with greater production and new field development projects under way. Currently, northern Kuwait is averaging crude oil production capacity of approximately 700,000 BOPD, of which KOC produces the full capacity. The development plans in north Kuwait fields are aiming to enhance the production from the major producing reservoirs as well as developing the minor and new reservoirs.

North Kuwaits production today represents approximately 24% of its national crude output. That proportion may change as significant upstream spending is under way to further develop those resources.

The development of north Kuwaits fields was announced in March

Political meddling in Kuwaits energy sector is costing the country, but Kuwait Petroleum Corporation (KPC) is determined to achieve its 2020 vision to increase

production output to 4 million B/D.ABDELGHANI HENNI, JPT MIDDLE EAST STAFF WRITER

LEFT Kuwait National Petroleum Company, the downstream arm of KPC, has launched ambitious plans toincrease the refining capacity of thecountry.

KUWAIT2020 VISION


2010 with a proposed drilling program for 200 wells to tap heavy crude as production from the massive Burgan field peak production declines.

The plan for drilling at northern Kuwaiti fields was indeed initially encompassing the drilling of 200 wells. We surpassed this number by far, reaching a total of 537 wells drilled in this area, 258 of them drilled in 2011,Hosnia Hashim, deputy managing director for north Kuwait at KOC, said.

One of these wells was the second longest shallow well drilled in the world, with a horizontal section of 1,602 ft. Hashim said careful preplanning and geomechanics studies were required for an efficient design to prevent problems with artificial lift.

Kuwait has also launched the North Kuwait Heavy Oil Project, where KOC faces challenges related to a shortage of thermal-process expertise within the company.

KOC has been steadily dropping its heavy-oil production targets from 900,000 B/D by 2020 to 450,000 B/D and now 270,000 B/D.

The 12 to 15API, 5% sulfur crude comes from the Lower Fars reservoirs of the Ratga field and is one of the heavy crude oil fields located in the north. Ratga is shared with Iraq, where it is known as Rumaila. Under the original plan, Lower Fars was to produce 50,000B/D by 2012. However, Sami

Al-Rushaid, chairman and managing director of KOC, reiterated at the Kuwait Oil and Gas Conference and Exhibition in February last year that the firms latest production target is 60,000 B/D by 2016.

The Ratga field was one of the reasons behind the Iraqi invasion of Kuwait in 1990. Iraq accused Kuwait of stealing billions of US dollars from its Rumaila field through vertical drilling, while Kuwait denied all the Iraqi claims. Following the Gulf War, the United Nations redrew the border, putting all the oil wells of Ratga on Kuwaiti soil.

Iraq and Kuwait are currently in talks about their oil fields on their shared border. Diplomats were quoted early this year by Reuters saying that Iraqs Umm Qasr Port is practically located on the Kuwaiti side.

Other northern oil fields include Roudhatain, Sabriya, Bahra, Abdali (shared with Iraq, where it is known as Umm Qasr), and another shared field called Zubair in Iraq. KOC has a USD150million ongoing project to build crude flowlines to take extra crude to the central pipeline by August 2013. KOC also plans to inject 500,000 B/D of water into the Sabriya and Roudhatain fields in the north by 2014.

Other initiatives to develop Kuwaits north oil fields included theUSD-7-billion plan called Project Kuwait. Approved by the Supreme Petroleum Council (SPC) in 1997,

the plan aimed to pay international oil companies (IOCs) a fee per barrel produced. KPC formed the Oil Development Company (ODC) to manage the project and signed operational service contracts with the supermajors. The government, however, for political reasons, never approved the project andODC has quietly closed, local sources said.

Neutral Zone FieldsKuwait also produces oil from the Wafra joint operations located in the neutral divided zone and the Khafji joint operations located near the Khafji area in Saudi Arabia. The two countries share the reserves equally, working together to extract, refine, and market them for mutual benefit. Proven oil reserve in the divided zone is about 5billionbbl, equally divided between thetwocountries.

KGOC is in charge of the divided zone operations, and Kuwaits share from the divided zone is currently 258,000 B/D of oil, including onshore and offshore fields. This includes 109,000 B/D from onshore Wafra field and 149,000 B/D from offshore Khafji joint operations.

The Khafji joint operations (KJO), a joint venture between KGOC and Aramco Gulf Operations, is in charge of the development and operation of the fields, including Al-Khafji, Lulu, Hout, and Dorra.

WHOS WHO IN KUWAITS ENERGY SECTOR

Hani HusseinOil Minister

Farouk Hussain Al-ZankiChairman of Kuwait Petroleum

Corporation (KPC)

Sami Al-RushaidChairman of Kuwait

Oil Company

Fahed Al-AjmiChairman and Managing

Director of Kuwait National Petroleum Corporation

(KNPC)

Maha Mulla HusainChairman and Managing

Director of Petrochemical Industries Company (PIC)

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KUWAIT2020 VISION


Kuwaits total offshore output is 300,000 B/D, all from the Khafji field. It produces 38,000 B/D of Hout-grade crude and 262,000 B/D of Khafji-grade crude. Khafji is a small part of a field that lies mainly on the Saudi side of the maritime border, where it is known asSafaniyah.

Offshore capacity will increase to 400,000 B/D by 2019 under a development plan that will bring on stream the Lulu oil field (shared with Iran, where it is called Esfandiar) and bring back into production Hout field, which has been shut in since 2005 because of pressure problems. Maximizing the Khafji is an ongoing development plan.

The offshore development plan includes a gas pipeline that will take gas that is being flared at Khafji, which produces 50 million ft3/D to 60 millionft3/D, and allows KGOC to implement its 1% flaring policy by 2015. French contractor Technip announced in February 2012 that it had won the 110-km gas and condensate pipeline contract, to be completed by the second half of 2014. The pipeline was also supposed to take nonassociated gas from the Dorra field, which is shared with Iran and known there asArash.

The Dorra field, located close to the shore of Kuwait and Saudi Arabia, has long been a bone of contention between Kuwait and Iran, which also lays claim to part of the field. While Tehran and Kuwait are yet to agree on their maritime claims, Riyadh and Kuwait stuck a deal in 2000 and have since worked to develop the undisputed part of the field under the KJO.

The plan had been to share the gas pumped from Dorra at an offshore facility in the Arab Gulf. About 6 months ago, the media reported that Saudi Arabia came up with a new proposal, pressing Kuwait to share the gas out on land at Khafji in a plan that would require another overland pipeline to be laid to Kuwait.

Dorra was supposed to start up in 2017, ramping up to 1 billion ft3/D, of

which 50% will go to Kuwait. The total investment cost of project development is USD 7 billion, to be equally shared by Kuwait and Saudi Arabia.

The Neutral Zones other potential big booster is the onshore Wafra field. Chevron operates the onshore fields on behalf of Saudi Arabia. Onshore total production of the Wafra field is 220,000B/D, of which 50% will go to Kuwait. The goal now is to stabilize it and then increase with Wafra EOR (enhanced oil recovery) projects to 300,000 B/D, 50% (150,000 B/D) of which will go to Kuwait. The increase in production will start by 2015, said Hashim Al-Rifaai, chairman and managing director ofKGOC.

Meanwhile, Chevron Saudi Arabia said that preliminary results of the steam inundation project at the field are promising. The agreement between Saudi Arabia and Chevron was extended and amended in 2009; it will expire in2039.

Chairman of the company, Ahmed Al-Omer, said that, from the initial results at the joint operations as well as the simulation model and other studies that are subject to assessment,

the company expects to produce more than 500,000 BOPD, while the amount of explorable oil is more than 6 billion bbl.

He added that the injection of steam inundation in the first Eocene reservoir in Wafra has increased production by more than 600% of the primary production (without steam injection), showing that the cost of this phase rose to more than USD340million.

The project requires the drilling of 10,000 wells for production, steam injection and monitoring of temperatures, in addition to the installation of large separate facilities to generate energy and steam, anticipating the issuance of the decision to invest in the development of the entire field in late 2013. The first phase of steam injection in the Eocene would begin by 2017.

Al-Omer said that the quantity contained in the first Eocene reservoir is estimated at 9 billion bbl of oil, whileseparate tests are under way forsteam inundation at the second Eocene reservoir that is a little deeper in Wafra.

Kuwait is working to boost oil production to 4 million B/D by 2020.

KUWAIT2020 VISION


Despite the high quantities of crude contained in the Eocene reservoir, Chevron faces difficulties in selling the crude without a discount because of its exceptionally high sulfur (4.5%) and metals content. Only a sophisticated refinery can process it, sources familiar with the project said.

Other producing onshore Neutral Zone fields include North Fuwaris, South Fuwaris, Humma, and Arq.

Gas Dilemma Kuwait faces a huge gas shortage because of high local consumption andcompetition between power generation and petrochemical companies. Current associated gas production is about 1.1Bcf, while free gas is about 140 MMcf, which does not meet local consumption.

In addition to associated gas, Kuwaits power stations burn liquefied natural gas (LNG) and high-sulfur foil oil (HSFO) at a ratio of about 30:70 from March to October and only HSFO during the winter. In the past, power stations burnt about 9 million-10million tons of HSFO in one year. Under a term contract, Kuwait exports one cargo (70,000 tons) per month of HSFO

(180centistoke) to Pakistan, local media sources revealed.

Gas supply in Kuwait is very limited, as the majority of it is associated with oil production, said Hamad Al-Terkait, ex-president and CEO of Equate Petrochemical Company. There are some new discoveries of nonassociated gas, but these discoveries are mainly directed at power generation.

In the short term, Kuwait has looked at various options to meet the gas shortage. It tried unsuccessfully to import gas from Qatar and Iran. Two gas pipelines from Iraq to Kuwait were built before Iraqs 1990 invasion of Kuwait but were never commissioned. Although two independent companies have been in talks with Baghdad to import gas for petrochemical projects, Iraq is unlikely to agree to this.

To address the shortage, Kuwaitimports 500 MMcf/D of LNG in the summer under a deal with Shell andVitol. KNPC is studying the building of a permanent LNG import terminal, which will lower operating costs. To helpplan this, it needs to know if the planned refinery expansion to producemore fuel oil will go ahead

andwhen the Jurassic project will hit itstargets.

In addition to LNG import, Kuwait has launched capital investment projects to reach self-sufficiency in gas. These investments aim to increase free gas production capacity to 1 Bcf by 2016.

Currently, the norths Jurassic gas fields, Umm Niga and Sabriya, produce a total of 50,000 B/D of light oil and condensate mixed with 140millionft3/D of sour gas.

KOC is relying on exploration to find fields that will produce a total of 1 Bcf/D of gas, in order to achieve its target of 4 Bcf/D by 2020, including 2.5Bcf/D of nonassociated gas.

The Jurassic fields final target is 1 Bcf/D by 2016. Dorra is expected to produce 500 MMcf/D by 2017. The associated gas target is 1.5 Bcf/D, up from the current 1.3 Bcf/D.

However, Kuwaiti Parliament is investigating Shells USD 800 million enhanced technical services agreement (ETSA), looking into whether state-owned KOC overstepped its authority in issuing the consultancy contract to help develop the 1-Bcf/D Jurassic gas project in the northern fields of Umm Niga and Sabriya and if Shell has operational control.

Under the contract signed between Shell and KOC, Shell was to deploy technical experts to Kuwait to support KOC in its management of the ongoing development of the Jurassic gas fields. This project is bothcomplicated and challenging because of unconventional geological formations, difficult reservoir conditions, and complex gascompositions.

Political MeddlingOne of the critical issues facing the energy sector in Kuwait is the intervention of its Parliament in different projects. In December 2008, the SPC decided to reverse its approval of the agreement between Dow Chemical and Petrochemical Industries Company (PIC) to enter into the

Kuwait Gulf Oil Company is in charge of Kuwaits share at the offshore divided zone with Saudi Arabia at Khafji Joint Operations.


USD-17-billion K-Dow Petrochemicals 50/50 jointventure.

In May 2012, the International Court of Arbitration of the International Chamber of Commerce (ICC) held that PIC was liable for the merger and awarded damages to Dow of USD2.16billion.

In February 2009, Kuwait decidedto scrap the fourth refinery project worth USD 15 billion, stating that KNPC did not adhere to the tenders committee regulations. The 615,000-B/D refinery project had facedopposition from several deputies,who alleged that there were violations, particularly in handing out a package to Fluor, a US company, without a tender. Some deputies threatened, at that time, to question former oil minister Mohammadal Olaim if he went ahead with signing thecontracts.

The government bowed to pressure and asked the audit bureau to investigate whether the tender process showed irregularities. The bureaus report was not made public; but, according to local media, it concluded that the project was unfeasible.

After the cancellation of the 615,000-B/D refinery at al-Zour, KNPC relaunched the project, which may be tendered in early 2013 but at a lower capacity; the SPC had previously recommended a 530,000-B/D refinery to cut costs. Al-Zour is designed to refine heavy sour crude that may be difficult to sell to the overseas market. The establishment of Al-Zour refinery will allow Kuwait to process heavy oil coming from fields such as the Wafra field, where the crude has exceptionally high sulfur (4.5%) and metals content because only a sophisticated refinery can process it.

Kuwaits total refining capacity is 936,000 B/D, through three main refineries, including the Shuaiba refinery at 200,000 B/D, Mina Abdulla at 270,000 B/D, and Mina al-Ahmadi at 460,000 B/D.

The political meddling in Kuwaitsenergy sector was a disaster for the countrys reputation as a hostfor investment; political intervention undermined the trust in the process. But this situation does notscare oil executives in the country who are confident that foreigninvestorswill eventually understand the reasons behind the cancellations. It is our system, andwe have to live with it, said BakhitAl-Rashidi, deputy managing director at KNPC.Ithink that, after some time, people will understand this as it is about multibillion-dollarprojects.

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What are the major oil and gas development projects that Kuwait Petroleum Corporation (KPC) is undertaking? What is their status in term of delivery? Are they on target? How much capacity will they add to the countrys total output?In 2010, Kuwaits total oil production was approximately 2.5 million BOPD. In 2011, Kuwaits total oil production was approximately 2.7 million BOPD. Since November 2011, Kuwaits total oil production averaged 3 million BOPD. KPC plans to reach 4 million BOPD by 2020.

When will you make a final decision about the Neutral Zone Wafra field? What is the production of the field and the expected cost?Oil production capacity in the Neutral Zone is currently about600,000 BOPD, all of which is divided equally between Saudi Arabia and Kuwait. The Wafra oil field has a capacity of240,000 BOPD. The production capacity is in line with overall strategies. KPC has a plan that was developed jointlywith its partner to expand production in the Neutral Zone. The plan is being implemented to reach the targetedproduction.

The company has started an aggressive exploration program in the country to increase its production capacity by 2020. What is the status of these projects?As I said earlier, KPC plans to reach 4 million BOPD by 2020. The major upstream activities designed to meet our 2030 Strategic Direction are as follows:

Focus on exploration Conduct many reservoirs studies Build and modernize production facilities Apply enhanced oil recovery (EOR) technologies

What are the gas fields projects that KPC is currently developing to meet Kuwaits soaring consumption? What capacity does your company target?

The increasing consumption of gas is mainly due to population growth and expanding local industries. KPCs strategy for meeting the expected energy demand growth is to focus on increasing domestic gas production. The countrys associated gas production, which has been rising alongside the sustained increase in oil output over the past year, currently stands at around 1.35 Bcf/D.

What is the situation with the Jurassic gas project in the northern fields? Do you expect to solve the problems related to this project soon?Our plan to meet such high demand is to develop newly discovered, deep, and high-temperature/high-pressure naturally fractured reservoirs. Currently, our nonassociated gas production is only 130 Mscf/D, where KPC plans to reach 1,000 Mscf/D by 2030. So the challenge is great in term of both volume and complexity of the reservoirs.

What are the challenges facing the operations of thecompany? There are a number of challenges that KPC is facing in order to achieve its strategic direction across its diverse business activities, including the upstream. They are as follows:

Developing technical capability in gas and heavy-oil fields Promoting and increasing the number of qualified

personnel and training them in the light of the complexity of our activities

The cost escalation of capital projects in the oil sector caused by the increasing complexity of the oil reservoirs, complex operations like nonconventional, and water management and water injection

Is it easy for KPC to acquire the necessary technologies fordrilling?KPCs 2030 strategy is technology driven; we seek to have the necessary technology from major oil companies as well as

Q&A WITH

FAROUK HUSSAIN AL-ZANKICHIEF EXECUTIVE OFFICER, KUWAIT PETROLEUM CORPORATION

KUWAIT PETROLEUM CORPORATION Q&A

The CEO of Kuwait Petroleum Corporation outlines the companys plans to reach 4 million BOPD.



service companies. This is among the reasons why we have been successful in bringing our production to be in line with our plans and targets.

What incentives does Kuwait/KPC provide to foreign investors who want to help the country invest in upstream technologies and transfer technologies? Development of crude oil production would require an effective collaboration with international oil companies through enhanced technical service agreements, which is the best formula that meets the interests of both KPC and international oil companies (IOCs) fairly. Hence, higher production targets will be reached through collaboration andtechnological cooperation with IOCs to use their technicalexpertise and technologies in the field of EOR andtodevelop heavy crude oil as well as light crude oil potentials in Kuwait.

How would you describe relations between KPC and the IOC operating in the country? KPC has established over the years excellent relations withIOCs on many fronts. With regard to its vision for

the future, KPC is seeking to be a global leader in the oil and gassector. We are interested in choosing the best partners towork with through collaboration with prestigiouscompanies.

KPC is involved in several upstream projects outside the country through its subsidiaries. What is the situation with these projects? Kuwait has upstream projects in about 13 countries around the world, including Egypt, Yemen, Sudan, Pakistan, Indonesia, Vietnam, Australia, China, the UK, Tunisia, and Malaysia. The Kuwait Foreign Petroleum Exploration Company (KUFPEC) plans to expand. In September 2012, KUFPEC became an operator in Pakistan and became an operator in Australia at the end of last year.

Major national oil companies in the region are launching plans to invest in shale gas and unconventional resources. Does KPC plan to tap such type of investments? To date, it does not look like KPC has unconventional resources such as shale gas; but, it is too early to confirm that. Our focus now is on conventional resources.

SPE North Africa Technical Conference and Exhibition (NATC)

A Paradigm Shift in the Oil and Gas Industry of an Evolving Region

1517 April 2013InterContinental Citystars, Cairo, Egypt

Plan to Participate

www.spe.org/events/natc

To register for the event, email [email protected]

LOOKING AHEAD

UAE

UAELOOKING AHEAD


Oil and gas production has beenthe mainstay of the economy in the United Arab Emirates (UAE) and will remain a major revenue earner long into the future. Proven recoverable oil reserves are estimated in the 97-billion- to 98-billion-bbl range. This equates to a phenomenal 9.5% of globalcrude oil proven reserves.

As for natural gas, proven recoverable reserves are estimated at about 214 Tcf. The small nation holds the fourth largest proven natural gas reserves in the Middle East after Iran, Qatar, and Saudi Arabia. As with oil, the largest reserves of 198.5 Tcf are located in Abu Dhabi. UAE government sources estimate that such reserves at current production and, excluding any new discoveries, will last for more than 150years.

Almost one-third of the top 20 largest oil and gas projects in the Middle East under execution today are taking place in the UAEs booming upstreamsphere.

With the exception of a large, pan-national strategic pipeline project,all of the work for the projects is being undertaken in Abu Dhabi, the national epicenter for energydevelopments.

However, Ras al-Khaimah, Sharjah, and Dubai all have operations and development projects, which are significant and worthy of some attention, not forgetting the vital and increasing role Fujairah plays in the national energy equation.

Gas Shortage It is hard to believe that a country with a huge gas reserve relies on imports to meet its soaring domestic demand. However, this is a reality in the UAE, which holds the fifth largest gas reserve in the world.

The majority of its reserves are difficult and expensive to produce safely because of the high sulphur content. Even with this gas reserve, the UAE is importing 2 to 2.3 Bcf/D from Qatar, which is projected to reach 5 Bcf/D by 2015, said Khaled Al Awadi, gas operation manager at Emarat.

To meet the increasing demand, the UAE is taking steps to increase gas supplies. ADNOC (Abu Dhabi National Oil Company) is increasing its investments with international oil companies to explore and develop the gas reserves, said Al Awadi. He added that Dolphin Energy and Sharjah Petroleum could also supply more to the UAEs hungry gas market.

While Sharjah may contribute 2% of supply, imports from Iran (should an agreement be reached) through the Crescent Petroleum-owned natural gas pipeline would supply 3% of the total demand by 2025, mainly for power and domestic use. Dubai will add 5% to the total supply.

However, with any given scenarioof gas supply, the UAE will still face shortages. Hence, the UAE is investing heavily to increase its gas reserves and to import liquefied natural gas (LNG).

Facing a growing gas shortage, Abu Dhabi burns an increasing amount of diesel and crude in its power stations each summer, pushed by double-digit growth in subsidized electricity demand and an economic policy that encourages industrial development. The emirate

plans to import LNG equivalent to 600 Mcf/D of gas by summer 2014 while it develops its gas fields.

Dubai also imports 1 MTPA of LNG by means of a floating storage and regasification unit, which provides a peak summer supply of 400 Mcf/D.

Abu Dhabi Taps Sour GasIn Abu Dhabi, much of the gas reservesare inextricably linked to oil production. At the same time, most have a high sour content, thus making extraction and processing an expensive business. For example, the Khuff gas reservoir has hydrogen sulfide content ranging between 20,000 and 200,000ppm, a level that has to be reduced to 50ppm.

Like other higher-cost hydrocarbon options, the attractiveness of sour gas has been enhanced by the surge in world energy prices and local consumption. But the decision whether to press ahead with development depends on much more than a simple assessment of costs against the likely sale price.

For Abu Dhabi, the development of its substantial sour gas reserves is also a key tenet of the emirates policy to ensure that there is enough gas supply to meet its growing power generation requirements. Development of the sourgas field is important to theeconomic prosperity of Abu Dhabi, said Nora Ismagilova, a business analystat Contax Partners. With demand for gas from utilities and other industries rising, the emirate of Abu Dhabi faces major gas supplychallenges.

Major sour gas fields in Abu Dhabi are the Shah, Bab, and Hail fields. Abu Dhabi is jointly developing the USD-10-billion Shah field with Oxy, which will

LEFT ADMA OPCO is in charge of the development of the offshore fields in Abu Dhabi.

The United Arab Emirates has undertaken a massive upstream investment project to meet soaring domestic consumption.


UAELOOKING AHEAD


ramp up to 500 Mcf/D of gas by the end of 2015. Shah and Bab were originally planned to start up in 2012.

The development of sour gas fields is very challenging and difficult. Drilling equipment and pipelines have to be carefully insulated. Infrastructure must be able to withstand high levels of pressure. Waste processing and disposal requires special attention because elemental sulphur is abyproduct.

In addition, the production of sourgas and its conversion to the usable sweet product poses technical and financial challenges because hydrogen sulfide is toxic and highly corrosive to certain metals. Raw sourgas is generally treated at the wellhead stage to remove the sulphurimpurities.

Such problems have traditionally discouraged oil companies from exploiting this reserve, but, in recent years, a growing number have successfully gained experience in handling sour gas.

UAEs Oil SectorBy far the biggest deposits of oil in the UAE have been found in Abu Dhabi. The emirate controls more than 85% of the UAEs oil output capacity and more than 90% of its reserves. Dubai and the northern emirates have a minor share.

However, Ras al-Khaimah, Sharjah, and Dubai all have operations and development projects, which

are significant and worthy of someattention.

Dubai currently produces between 50,000 and 70,000 B/D, according to some commercial estimations; Dubai does not publish data on its production, which reached its peak in 1991 at 400,000 B/D, and had dropped to 80,000 B/D by 2007. In that year, the United States government estimated Dubais reserves at 4 billion bbl of oil and 117 Bcm of natural gas.

Dubai operates five oil fields. The four offshore fields are Rashid, Fatah, Southwest Fateh, and Fallah, and the onshore field is Margham.

Dubai has recently announced the discovery of a new field, which lies east of the small field of Rashid, located 70km off Dubais coast. No further details about the field werereleased.

Dubais northern neighbor, Sharjah, is the third largest hydrocarbon producer in the UAE, with oil production centered on the offshore Mubarak field. It lies close to an area occupied by Iran, and the northern part of the field lies in an Iranian concession area. As a result, while Sharjah has drilling and production rights, it shares production and revenue with Iran. At the same time, 20% of Sharjahs remaining revenue is shared with the emirate of Umm al-Qaiwain and 10% with Ajman. Sharjahs hydrocarbon resources are confined largely to natural gas andcondensates.

The search for oil in Ras al-Khaimah has been continuing since

1967, with the emirate estimated to have reserves of 400 million bbl of oil and condensate. Offshore production from the Saleh field has fallen from an initial rate of 11,000 B/D to 2,000 B/D and is now suspended.

Fujairah, Ajman, and Umm al-Qaiwain remain the only three emirates where no oil deposits have been located, although exploration has been carried out. All are optimistic that commercial quantities may one day bediscovered.

Abu Dhabi: The Epicenter Thanks to the resource wealth endowed on Abu Dhabi, the federation of seven emirates has become a crucial energy producer, typically exporting about 2.32 million bbl of crude oil each day to predominantly Asian markets.

ADNOC operates 14 subsidiaries that participate at every level of the oil and natural gas sectors. The contract structure is based on a long-term, production-sharing basis, often through joint venture companies.

Most of Abu Dhabis producing oil fields are operated by three consortia: Zakum Development Company (Zadco); Abu Dhabi Marine Operating Company (Adma-Opco), owned by ADNOC, BP, Total, and the Japanese Oil Development Company (Jodco); and Abu Dhabi Company for Onshore Oil Operations (Adco), which includes Shell, BP, Total, ExxonMobil, and PortugalsPartex.

WHOS WHO IN UAES ENERGY SECTOR

Mohammed Dhaen Al Hamili

UAE Minister of Energy

Abdulla Nasser Al SuwaidiDirector General of ADNOC

Abdul Munim Al-KindyCEO of ADCO

Ali Rashid Al-JarwanCEO of ADMA-OPCO

Jasem Ali Al-SayeghGeneral Manager, Takreer


Much oil production in the UAE comes from the Zakum oil system, a collection of oil fields that makes up the third largest oil zone in the world. The Upper Zakum field is run by Zadco, with 60% interest owned by ADNOC and Jodco and ExxonMobil holding the remaining stakes.

Abu Dhabi now has a plan to boost its crude production capacity to 3.5 million B/D by 2018. As part of this strategy, Zadco is reviewing the possibility to use extended reach drilling from four artificial islands to expand production from 550,000 to 750,000 B/D by 2015, increasing the recovery rate to 70%.

The largest onshore oil fields are operated by Adco. It runs the Bu Hasa oil field, which produces as much as 600,000 B/D, as well as the Murban Bab, Sahil, Asab, and Shah oil fields, contributing another 705,000 B/D of light, sweet crude.

These projects are components of a plan to boost Adcos aggregate production from its current 1.4millionB/D to 1.8 million B/D by 2017. This means the comprehensive development of a group of fields and reservoirs, including the Asab field to increase sustainable production from 290,000 to 340,000 B/D.

ADNOC said in a statement that its investments include the development of the Sahil and Shah fields to increase production capacity so that Sahil can produce 100,000 B/D instead of its current 55,000 B/D, and Shahs production becomes 70,000 B/D instead of 50,000 B/D.

Likewise, the Jasyoura field is to be developed to accommodate two gas separation lines in a new central plant due to be operational by the end of March 2013, ADNOC said.

ADNOC said it is also developing Adcos Thammama and Habshan 2 reservoirs to boost production to 80,000 B/D.

Habshan 1 is also under development, the first package of which is estimated to increase the production by 30,000 B/D by the end of 2014.

Likewise, the development of North East Bab fields are expected to increase sustainable production to 230,000 B/D by 2016 (for Rumaitha field) and by 2017 for Al Dhabiya field. Development projects will also cover Bida Qamzan field and Bab gas compression project, the statement added.

Adma-Opco operates the main offshore assets in Abu Dhabi, which have been in redevelopment to maximize output. The Umm Shaif and Lower Zakum offshore oil fields have a combined capacity of 520,000B/D, and, after an expansion at each, they will have a production capacity of 425,000 and 300,000 B/D, respectively. The company drilled 22new wells in 2011 as part of its capacity boost.

Currently Adma-Opco is involved in the development of Lower Zakum field to increase its production by 100,000 B/D by 2016. The company is operating seven drilling rigs and two barges, which will almost double in the next 2 to 3 years as part of the capacityboost.

The company is also planning to develop new fields like Razbot and Umm Lulu fields to process, store, and ship 105,000 B/D by the common facilities. Additionally, work is under way in Nasr field, which is expected to process 65,000 B/D and the shipment of the

crude for final processing, storage, and shipping to Das facilities. These projects are expected to increase Adma-Opcos oil production to 970,000B/D by 2020, the statementsaid.

Two new oil fields have also come into development: Nasr and Umm al-Lulu. These will add 170,000 B/D by2018.

Zadcos development of the Upper Zakum field is one of the biggest ongoing projects. The projects facilities are to be installed on four artificial islands that are being constructed and connected to the present facilities to increase oil production to 750,000 B/D by 2017, the company said.

Confusion Spreads in Concession International oil companies (IOCs) are confused about the selection process in bidding for fields operated by the Adco consortium. The concession includes most of the UAEs major onshore fields and expires in January 2014.

The confusion is continuing into its fourth year. Twice in 2011, ADNOC told its Adco partners (ADNOC 60%; Shell, Total, BP, and ExxonMobil 9.5% each; and Portugals Partex 2%) that it expected the Supreme Petroleum

ADNOC is developing a sour gas field, Shah Field, in partnership with OXY.

UAELOOKING AHEAD


Council (SPC) to make a decision about extending the concession. First, SPC said it would decide by the summer, and then it said it would make the decision by the winter. It had also told the consortium about a pending decision in 2010 and 2009.

The oil companies receive USD 1/bbl produced in revenue from Adco, a rate last reviewed in the 1980s, when oil prices and the operating costs of running oil fields were significantly lower than today.

Abdulla Nasser Al Suwaidi, ADNOCS director general, said at the recent Abu Dhabi International Petroleum Exhibition and Conference that his company is willing to keep the structure of its oil and gas concessions in the UAE unchanged and will present its recommendation to the SPC early this year.

Bob Dudley, chief executive of BP, said that he is optimistic that cooperation will continue, despite the news that BP will not be allowed to participate in the prequalification process because of the UAEs irritation over the United Kingdoms political policies. Following the visit of British Prime Minister David Cameron to the UAE in early November, the matter appeared to be solved.

Some big oil companies, notably ExxonMobil, have expressed their discomfort about the concession

structure. They are concerned about operating side by side with rivals in an ADNOC-controlled concession, with all partners expected to share their owntechnology.

IOCs operating in Abu Dhabi know that the concession confusion is part of doing business in Abu Dhabi. In 2008, another concession expired. It was run by Abu Dhabi Gas Industries (ADNOC 68%; Shell 15%; Total 15%; and Partex 2%) that operates the major onshore gas fields. The SPC also had to decide then whether to break up a consortiums concession into individual fields or renew it. The council did not reach a decision until 6 months after the expiration date; the concession was later renewed by default in March 2009 for another 20 years. Abu Dhabi had to post-date the deal from its October 2008 expiration date.

Bypassing the Hormuz Strait As Iran keeps up on its threat to close the Strait of Hormuz, Abu Dhabi has constructed a pipeline to avoid using the strategic waterway. In July, the Abu Dhabi Crude Oil Pipeline (ADCOP) began operation, thereby providing an alternate route for UAE crude exports.

The Habshan Fujairah pipeline links the onshore field of Habshan in Abu Dhabi to the UAEs new export terminal in Fujairah, located on the Gulf of Oman.

The USD-4.2-billion project was set to be fully operational by the end of2012.

The pipelines first shipment was 500,000 bbl of crude oil destined for the Pak Arab Refinery in Pakistan, a joint venture between Abu Dhabis International Petroleum Investment Company and Pakistan.

The new infrastructure saves international oil tankers a week in transit time over shipping oil from Abu Dhabis export terminal at Jebel Dhanna, approximately 255 km west of Abu Dhabi. Potential disruptions to marine traffic through the Strait of Hormuz as a result of US economic sanctions against Iran also contribute to the importance of the 400-km pipeline, which was originally slated for commissioning in2010.

UAE Oil Minister Mohammed al-Hamli said that the pipeline will initially pump oil for export at Fujairah at a rate of 1.4 million B/D, with a future plan for 1.8 million B/D, which means that 70% of the UAEs crude can be exported through the Fujairah terminal.

The project consists of the pipeline, pumping stations, a 12-million-bbl oil terminal, offshore loading single-point mooring systems, and other facilities. China Petroleum Engineering & Construction was ADCOPs main engineering, procurement, and constructioncontractor.

Umm Shaif is one of ADMA-OPOCs two major fields. (Photo courtesy of ADMA-OPOC.)

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