Total Technology Report.pdf

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EDITORIAL

No company can survivein todays competitiveworld without an ongoingeffort to create newproducts, develop newprocesses and meet newexpectations.


3/1243February 2012 / TechnoHUB 2

Senior Vice President Strategy,Business Development, R&D

We have brought together in this edition a selectionof the best articles written by Total expertsand published over the last two years by the maininternational industry associations, such as SPEand EAGE, and in reputed journals such as FirstBreak, Offshore Magazine, Oil & Gas Journalor the Journal of Petroleum Technology.

Technical papers are organized in six categories:HSE, geology, geophysics, reservoir, drilling &wells and field operations, reflecting the pathfollowed by development of an oil or gas fieldfrom exploration to production. To provide amore comprehensive picture of Totals activities,these technical aspects are supplemented withdetails of the human resources strategy thatunderpins our extensive technical expertise.

The focus in TechnoHUB is, naturally, on innovation.No company can survive in todays competitive andchanging world without an ongoing effort to create

new products, develop new processes and meet newexpectations. Totals growth strategy relies to a greatextent on innovation and has three main thrusts:

TechnoHUB magazine is an opportunity to showcasethe wealth of exploration and production expertise

technical know-how, project management experienceand sustainable development initiatives that Totalcan offer its partners and co-venturers.

Olivier CLERET de LANGAVANT

Maximizing our existing production limiting the natural decline of ourfields by improving recovery andmaintaining the integrity of facilities

Bringing our projects on stream onschedule and at the best cost.

Continually renewing our reserves acquiring

new acreage; targeting new geologicalfrontiers for a bold exploration; sharing ourexpertise in alliances with new partners, and

Total has ambitious growth targets: to add 1.4 billionbarrels of reserves per year, increase production byan average of 2.5% each year, and maintain at least12 years of 1P reserves and 20 years of 2P reserves.The key to achieving this growth, which must beboth profitable and sustainable, is cost-effectivetechnology. That is what TechnoHUB is all about.We hope you find our magazine stimulating.


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GEOPHYSICS

58 Velocity modelbuilding with waveequation migration:the importance ofwide azimuth input,versatile tomography,and migration velocityanalysis

68 Impact ofmodelling shallowchannels on 3Dprestack depth

migration, Elgin-Franklin fields, UKCS

78 3D modelling-assisted interpretation:a deep offshore subsaltcase study

4 TechnoHUB 2 / February 2012

HSE

26 New ways tomonitor offshoreenvironments - A lookat four novel methodsand their advantages

58/85STRATEGIC

6Total SpreadsIts Wings

14Arctic may revealmore hydrocarbonsas shrinking iceprovides access

21Total upsAngola content,maximizes gas forlatest cluster project

Multiphase pumpsto drive out heavyMiocene crude

6/25GEOLOGY

32 The whys andwherefores ofthe SPIPSY methodfor calculating theworld hydrocarbonyet-to-find figures

46 Borehole image logsfor turbidite faciesidentification:core calibration andoutcrop analogues

26/31 32/57

CONTENTS


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FIELD OPERATIONS

110 Subseaintervention system for

arctic and harsh weather

DRILLING & WELLS

102 Advanced Drillingin HP/HT: The TOTAL

Experience on Elgin/

Franklin (North Sea

UK)

HUMAN RESSOURCES

116 Geoscience careersat Total

120 Yves-LouisDarricarrre President,

Exploration & Production,

Total

RESERVOIR

86 Polymer Injectionin a Deep Offshore

Field Angola, Dalia/

Camelia Field Case

92 4D pre-stackinversion workflow

integrating reservoir

model control and

lithology supervised

classification

5February 2012 / TechnoHUB 2

Edition: February 2012 //

TECHNOHUB

Totals Exploration-Production techniques magazine

[email protected] //

Publication Manager A. Hogg / Editor-in-chefV. Lvque

assisted by V. Rogier (Rythmic communication) /

Editing committee G. Bouriot, P. Breton, Ph. Julien,

D. Le Vigouroux, M. Magurez, F. Mombrun, P. Montaud,

D. Pattou, L. Stphane / Special thanks to the authors of the

Contexts J. Arnaud, F. Audebert, J.L. Bergerot, J.J. Biteau,

J.B. Joubert, P. Julien, B. Kampala, F. Larrouquet, V. Martin,

P. Mauriaud, D. Morel, J.C. Navarre, E. Rambaldi, N. Tito,

S. Toinet / Authorizations for republication obtained from

First Break, JPT, Oil & Gas Journal, Offshore Magazine,

The Way Ahead, Recruitment / Translation A. Frank /

Design and production Bliss agence crative //

ISSN 2257-669X

86/101 102/109 110/115 116/122


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Site of the Total-led Yemen LNG plant.

Production of liquids and natural gas was 2.36 millionBOEPD in the second quarter of this year, up 8% fromthe second quarter 2009, while total 2009 outputwas 2.28 million BOEPD. The Company estimatesthat the share of gas in production will increasefrom 44% in the first half of 2010 to 46% in 2014.

Yves-Louis Darricarrre, president of TotalsExploration & Production Division, said: Total E&P

wants to grow profitably and be one of the best ofthe majors. To achieve this objective, Total mustmaximize production from existing fields. Thisis being done by improving recovery rates frommature fields and by extending production plateaus.Technology and investment are the keywords here.

He said the Company plans to bring on streama large portfolio of projects and that startupsbetween 2010 and 2015 will account for 880,000BOEPD of production (i.e., approximately33% of Totals production in 2015).

The main startups between 2011 and 2014 includeTrinidad Block 2C, Islay in the North Sea, Usan andOfon 2 offshore Nigeria, Halfaya in Iraq, AngolaLNG, Bongkot South in the Gulf of Thailand, andKashagan Phase 1 in the Caspian Sea off Kazakhstan.

We must also focus on reserves replacement,he added. This means renewing Totals portfolioby focusing on organic growth (ongoingexploration, access to discovered resourcesopportunities awaiting development), andcompleting it with selective acquisitions.

ORGANIC GROWTH

Totals chairman and chiefexecutive officer, Christophe deMargerie, echoed this focus onorganic growth: If we can domore on exploration, we willdo it, and for the time being wehave decided to increase ourexploration budget from USD1.9 billion in 2010 to USD 2.2billion in the years to come.We definitely need to be abit more aggressive and totake a little bit more risk,

which means being in frontierexploration areas as well asin the traditional ones.

As well as expanding its hydrocarbon explorationand production activities around the world, Total isalso strengthening its position as one of the globalleaders in the natural-gas and LNG markets.The Company is also expanding its energy offeringsand developing complementary next-generationenergy activities including solar, biomass, and nuclear.

Downstream, Total is seeking to adapt its refining

system to market changes while consolidatingits position in Europe and expanding its positionsin the Mediterranean basin, Africa, and Asia.

Totals chemicals activities will also continue to bedeveloped, particularly in Asia and the Middle East.

In its core upstream sector, Total is launching a raftof projects over the next few months and years.

Some of those are already under construction,including Pazflor, Usan, Angola LNG, and Kashagan,while others such as the West of Shetlands Laggan-

Tormore project, the Surmont Phase 2 heavy-oilproject in Canada, and the CLOV (Cravo, Lirio,Orquidea, Violeta) deep project offshore Angolaare all coming off the drawing board this year.

And it is on Angolas Pazflor that Total will beshowcasing some of the new technology that it hasbeen working on. Pazflor will be the worlds firstdevelopment to implement large-scale seafloor gas/liquid separation and pumping. Pazflor paves the wayfor technologically feasible, economically viable accessto increasingly hard-to-produce oils, said Darricarrre.

He said another deep offshore challenge isto develop small satellite fields located far fromproduction facilities, and other resources lyingin deep, inhospitable waters.


8/1248 TechnoHUB 2 / February 2012

AFRICA THE KEY

A look at Totals major upcoming projects gives some

idea of the importance of Africa to the Companysoverall plans. In 2009, Total E&P equity productionin Africa averaged close to 750,000 BOEPD,accounting for 33% of the Groups total production.

Africa is one of the main focuses for growth inTotals production, Darricarrre explains. Most of theprojects there in which Total is involved are operatedby the Group. Most of Totals E&P operations arehistorically located in the Gulf of GuineaespeciallyNigeria and Angolaand in North Africa.

He said Total has also recently strengthened ties

with other African countries, enabling the Group toacquire new exploration permits. Being awardedoperatorship on Block 4 brought Total back to Egyptin 2009 to seek agreements with third parties whichhave discovered resources but not yet developedthem such as the case of Uganda this year.

Deepwater developments are one of Totalsforemost areas of growth in Africa: Usan,Akpo, and Egina in Nigeria, and Pazflor andCLOV in Angola are some examples of Totalsmajor current deep offshore projects.

The overall development plan for CLOV usestechnologies that have already proven effectiveon Girassol, Dalia, and Pazflor.

FOCUS ON LNG

The deep offshore Block 17 is Totals main asset inAngola and the Group also operates the ultradeepoffshore Block 32, in which it holds a 30% stake.

In addition, Total holds a 13.6% stake in the AngolaLNG project for the construction of a liquefactionplant near Soyo, designed to help monetize thecountrys natural-gas reserves. The plant, which isunder construction with production expected to beginin 2012, will be supplied by the associated gas comingfirstly from the fields on Blocks 0, 14, 15, 17, and 18.

Gas produced on CLOV will contribute as feedstockto the plant, which is just one of Totals LNGdevelopments around the world. The Company isnow the second-largest LNG operator globally.

Production from the second train of theUSD 4.5-billion Yemen LNG natural - gas liquefactionplant began in April this year. Combined withoutput from the first train, the plant can produce6.7 million tons of LNG per year, equivalent toa hundred cargoes to be delivered each year over25 years. A 320-km gas pipeline carries feed gas fromBlock 18 in central Yemens Marib region to the Balhaf

liquefaction plant on the countrys southern coast.

Further highlighting its passion for LNG, Total inSeptember signed a USD 750-million agreementwith Santos and Petronas to acquire a 20%interest in the Gladstone LNG (GLNG) project inAustralia. The project consists of extracting coal-seam gas from the Fairview, Arcadia, Roma, andScotia fields, located in the Bowen-Surat basinin Queensland, eastern Australia. The fieldsresources are estimated at more than 9 Tcf of gas.

STRATEGIC

To face this challenge Total is leveraging itscutting-edge expertise in subsea processing and all-electric systems (long-distance power transmission

and distribution, electrical reheating, command-control of the process and wells), with innovativedevelopment projects offering multiphase subseatransport over long distances of more than 100 km.

With regard to the reliability and integrityof subsea installations, innovative and cost-effective subsea tools are necessary in order tooptimize intervention maintenance and repair.

Total has developed the Swimmer, the firstautonomous underwater vehicle that integrates alight world-class ROV [remotely operated vehicle],

designed to provide intervention maintenanceand repair without a support vessel and for long-term subsea deployment without maintenance.This unit has potential applications on the prolific,Total operated Block 17, offshore Angola.

A total of 34 subsea wells will be tied back to theCLOV floating production, storage, and offloading(FPSO) unit, which will have a processing capacity of

160,000 B/D and a storage capacity of approximately1.8 million bbl. The CLOV FPSO, through a uniqueprocessing and storage system, will produce twotypes of oil: one with a 3235API gravity fromthe Oligocene reservoirs (Cravo-Lirio) and theother, more viscous, with a 2030API gravityfrom the Miocene reservoirs (Orquidea-Violeta).



MORE LNG

The GLNG project will develop these fields up toa production plateau of 150,000 BOEPD and theproject also includes transporting the productionover approximately 400 km to a gas liquefactionplant in the industrial port of Gladstone, northeastof Brisbane, on the eastern coast of Australia.

The GLNG liquefaction plant will consist of two trainswith a total production capacity of 7.2 million tonnesa year. Startup date for the first train is scheduledfor 2014. The LNG plant is expected to reach itsplateau production in 2016 for more than 20 years.

In line with the Groups strategy to develop newtypes of partnerships, Total is teaming up with Santosfor its expertise in gas production in Australia andwith state-owned Malaysian oil and gas companyPetronas for its experience in marketing LNG in Asia,said de Margerie. Total will bring to the project itsexperience in successfully managing major projectssuch as the construction of gas-liquefaction plants,and its capacity to market LNG to the Asian market.

As a wave of new LNG projects, includingIchthys in Australia and Shtokman Phase 1,come on stream, Total wants to bump up its

LNG output by 200,000 BOEPD by 2020.The Company is also expanding its activities inunconventional gas and has a 25% stake in theBarnett Shale Joint Venture with Chesapeakein the US. It also has shale-gas explorationpermits in France, Denmark, and Argentina.

TOTAL GETS HEAVY

Highlighting the diversity of its operations around

the world, Total is also involved in the productionof heavy-oil reserves in Canada and Venezuela.

In Canada, the Company operates the Joslynand Northern Lights leases and is a partner inthe Surmont project, all located in the provinceof Alberta. It is also a partner in the Fort Hillsproject as well as operator of the Bemolangalicense in Madagascar and a partner in theQarn Alam and Mukhaizna fields in Oman.

Project

Islay

Pazflor

Usan

Halfaya

Angola LNG

Kashagan Phase 1

Ofon 2

Sulige

CLOV

Laggan/Tormore

Ekofisk South

GLNG

Country

UKCS

Angola

Nigeria

Iracq

Angola

Kazakhstan

Nigeria

China

Angola

UKCS

Norway

Australia

Type

Gas / condesate

Deep offshore

Deep offshore

Liquids

LNG

Liquids

Liquids

Gas

Deep offshore

Deep offshore

Liquids

LNG

15

220

180

535

175

300

70

50

160

90

50

150

100%

40%

20%

20%

13.6%

16.8%

40%

100%

40%

80%

39.9%

20%

Capacity (kboe/d) Totals Share

MAJOR PROJECTS TO 2012



The Rosa project launched in 2004 and is locateddeepwater offshore Angola.

STRATEGIC

On the Surmont lease, 27,000 B/D of bitumen areproduced using steam-assisted gravity drainage(SAGD). Two parallel horizontal wells, a production

well at the base of the reservoir paired with asteam-injection well 5 m above it, are drilled.Heated by the steam, the less-viscous bitumenflows by gravity down to the production well.Developed in phases, the Surmont lease willsee its production rise to 100,000 B/D in Phase2 and 400,000 B/D in the longer run.As Darricarrre explains, improving theenvironmental footprint and energy efficiencyof extra-heavy-oil production is a strategicR&D focus for Total.

The Group is working on several innovativetechnologies to address the challenges and oneexample being studied for potential application

to extra-heavy oils is the first European field testintegrating the complete CO2

capture, transport,and storage chain, in Lacq in southwest France.

The Lacq field test aims to validate the innovativetechnology and process before a larger scaleindustrial deployment is considered. Total is alsoworking on a series of innovative technologiesto improve the energy efficiency of the thermalproduction and upgrading of extra-heavy oil, via,for example, a reduction in the steam/oil ratio,innovative boilers, cogeneration, etc., he said.

In coordination with Totals R&D center inPau, France, the research center in Calgary isworking on pilot processes which include asolvent- steam coinjection pilot project that mayfurther reduce the amount of steam requiredin the SAGD process, therefore reducingrequired water volumes and CO

2emissions.

For mining projects, the main challenge consistsin increasing water recycling, which averages80% on current projects. Our efforts are directed atsafeguarding water resources, recycling at everyopportunity and reducing tailings. The Joslyn

Mine project has been designed to maximize thewater makeup and achieve water consumptionthat is lower than the industry average.

Founded: Compagnie Franaise

des Ptroles in 1924

Operations : E&P activities in more

than 40 countries

Production of oil and gas in 30 countries

Production: 2.28 million BOED

Proved reserves: 10.5 billion BOE

Employs: 96,387 employees Approximately

540,000 French individual shareholders

TOTAL AT A GLANCE


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developments already under construction such

as Pazflor, Usan, Angola LNG, and Kashagan.

Of the five major projects scheduled to kickoff in 2010, three are already under way:

Surmont Phase 2 in Canada, with an expected

production of 110,000 B/D of heavy oil through

a steam-assisted gravity drainage system

The Laggan and Tormore gas fields in the

North Sea, which lie around 140 km west

of the Shetland Islands under 600 m of

water. They have total estimated reserves of

approximately 230 million BOE and production

is to peak at more than 90,000 BOEPD.

Total has very recently announced the

development launch of the CLOV deepoffshore project in Angola and award of

the main contracts. The project involves

the production of four development areas

(Cravo, Lirio, Orquidea, Violeta) in water

depths ranging from 1,100 to 1,400 m. It will

simultaneously produce two oils with different

characteristics (Oligocene and Miocene oils).

For Total, this is the first time that a subsea

multiphase pump system will be installed

in the deep offshore to boost production.

Two other major projects will be launched

later in the coming months in Nigeria:

Ofon II, an offshore development with an

expected production of 70,000 B/D, and

Egina, a major deep offshore project with

an expected production of 200,000 B/D.

How is Total likely to continue its

international expansion?

The Groups efforts in acquiring new exploration

permits have further expanded its playing field.

It has added a number of exploration licenses

to its portfolio over the past 6 or 7 months

in various promising geological regions in

different countries: France, French Guiana,Yemen, Argentina, Brazil, Vietnam, Malaysia,

Indonesia, Kazakhstan, and Azerbaijan.

Not only this, but the kinds of partnership

we enter into these days have changed

no longer just the traditional joint-venture

model between majors putting us in a better

position for international development.

Total supports and accompanies NOCs in their

ambition to develop their activities outside their

frontiers; this is what we did in partnering with

the Chinese company CNPC in Iraq on the

Halfaya field and with Qatar Petroleum in Africa.

Oil demand is expected to show a marked increase

between 2010 and 2020 in emerging countries

or regions, such as in China or the Middle East,but decrease in North America and Europe.

As for gas, the economic crisis has temporarily

curbed the regular increase observed in world

gas demand. Consumption fell by approximately

1.5% in 2009 compared with 2008.

We expect demand to resume its regular progress

from 2010 on, with a dynamic growth rate of more

than 2% during 20102020. However, this will

depend on an increase in unconventional- gas

production and the development of LNG,

where there is a need for further investment

so as to avoid potential shortages.

Finally, as gas production has a lesser impact

on the environment than oil production, there

will be a natural preference for gas.

What does Total see as its main focus

area for the upst ream in the future?

While Total continues to invest in conventional

hydrocarbons, we also intend to build on positions

in highpotential sectors in countries with promising

resources. Our portfolio is well-balanced in terms

of risks (geographical situations, technologiesused, project profitability) and has consolidated

the Groups strengths, particularly in:

The deep offshore (Congo, Nigeria,

Angola) where technology and integrated

project management are essential

LNG (Australia, Russia, Nigeria) where

integrated project management and upstream/

downstream marketing integration, as well

as technology, are the keys to success

Heavy oils (Canada, Madagascar) where

technology, integration with refining, and

stewardship of natural resources (water,air, energy, etc.) are mandatory

Complex/unconventional-gas plays

such as high-pressure/high-temperature

(HP/ HT) (North Sea), tight gas (Algeria),

and shale gas (US and applications

in Europe) where, again, advanced

technology and expertise are required.

What big upstream projects are due

on stream and what technology

challenges do they present?

Some 40 developments of different sizes andimportance will be brought on stream over

the next 5 years, some of them being major

STRATEGIC


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The only exceptions are clearly Prudhoe Bay andadjacent fields and very rare oil tests such as Goliathin the Barents Sea. There the two excellent marine oil

prone sourcerocks have generated an exceptionallyhigh quantity of oil in stacked fluvial channeldeposits, sandstone reservoirs of Triassic age. BothTriassic and Jurassic source rocks are within the oilwindow as exhibited by the maturation indexes.

Other oil discoveries are possible in the offshore partof this basin even if these source rocks are withoutany doubt much more deeply buried (>5,000 m). Butliquids could be present as condensate given theprobable high pressure (600 to 800 bars) and nature ofthe source rock. More than 1 billion bbl of condensatehas been calculated on the Dinkum South undrilled

area where the excellent Sadlerochit reservoirseems present and thickens from south to north.

The Beaufort Sea basin in Canada is also markedby an important orogenic compressive event inMid-Tertiary followed by an important progradingTertiary delta linked to the paleo and presentMackenzie River. Mainly gas discoveries havebeen found in Tertiary platform or turbiditic sandyreservoirs associated with gas prone source rocks.

Northwards more distal conditions should prevailaccording to Totals paleogeographical

reconstructions. Therefore oil prone marinesource rocks could be encountered. Huge foldedstructures are present there and should intersectdistal channel and levee turbiditic complexesmainly in the Oligo-Eocene series. Therefore bothDinkum and North Beaufort clearly exhibit promisingplays for the present decade of exploration.

The Hammerfest basin in northern Norway is wellknown through the development and productionof the most northwards LNG production to date,the Snohvit field complex. But it is above allthe perfect example of a basin, rich in excellent

marine oil-prone source rocks both in Triassic andabove all in Jurassic layers and finally very poorin oil discoveries except for Goliath field on thesouthern edge of the basin. The Snovhvit complex,however, has been fed with oil as witnessed bythe numerous oil shows located below the gaspool in the presently water-bearing zone. Severalhypotheses have been contemplated for explainingthis result, the first one being the past oil flushed bythe subsequent gas generation with consequent oilmigrating towards the southern updip basin edge.

ASSESSMENTSOF THE ARCTIC

ENDOWMENT

The Arctic Polar Regions owe their principalbathymetric and orographic features to twooceans, the North Atlantic Ocean andthe Arctic Ocean (figure 1 p. 15).

The geological organization results fromgeologically speaking recently created oceaniccrusts in Cretaceous times for the EasternCanadian basins and in early to late Tertiarytimes for the Atlantic and the Arctic Oceansthat have triggered off the separation of the

North American plate and the Eurasian plate.

These oceanic openings and continental drifts havebeen preceded by tectonic tension phases sinceMiddle Triassic, having created rift and grabenstructures followed by platform sags. This historyis similar in a lot of Arctic basins, the differencescoming mainly from presence of Tertiary orogenicevents north of Alaska and East Siberia.

Such a structural configuration induces fourmain post-Hercynian petroleum systems linkedto four source-rock deposits (figure 2 p. 15):

Late Triassic marine source rocks extendedin practically all the known already drilledbasins from the Chukchi Sea westwardto the Yamal Peninsula eastward.

Late Jurassic exceptionally rich marinesource rocks spread over the Barents,West Siberian, Yamal, and probably Karaseas (the well-known Bazhenov sourcerock) as well as in the North Slope.

Then in Upper Cretaceous marine sourcerocks are known in North Canadian and

North Alaskan basins as well as possiblyin western Greenland and Baffin Bay.

And finally, since Oligocene deltaic sourcerocks, more gas prone, were depositedin big northward-prograding deltas likethe Mackenzie and Lena rivers.

When source rocks are superimposed with alreadydiscovered fields, an amazing anticorrelationappears between largely predominant marine,oil prone source-rocks and gas fields, implyingthat mechanisms other than the nature of sourcerocks are needed to explain the gas discoveries.

STRATEGIC



This induced a beginning of hydrocarbon migrationsouthwards and gas expansion due to shallow burialand a decrease of reservoir pressure. But more strikinghave been the onsets of a thick ice cap associatedwith permafrost in Quaternary that has increasedthe pressure at depth particularly of the cap rockinducing important leakage and within the reservoirgenerating fluid shrinkage. Melting of the ice cap inrecent times induced again a pressure decrease andgas expansion and therefore generalized gas caps.

The amplitude of these phenomena of icing andmelting has been so huge in Quaternary with somany periods of green and icehouse effect thatit has been detrimental to the presence of oil.

As a consequence oil could be found only onthe edges of the basins or at very importantdepth where hydrocarbons always remainin monophasic (critical fluids) phase.

Accordingly where thick ice caps have expandedassociated with uplifts and erosion at the edges ofthe newly created oceans, gas probability will behigh. Total has developed a model based on ice packhistory allowing to define these gas prone areas(dark blue in figure 3). These regions encompassa large part of the Russian arctic basins, whereasthe light blue areas would be more oil prone andmainly located in the US, Canada, and Greenland.

INFLUENCE OFBARENTS SEA UPLIFT

The picture could be more complex if weremember the last several million years historyof this basin, which underwent a large erosionof more than 1,000 m in Tertiary (figure 3).

Figure 3: Barents sea: influence of

uplift and ice cap on fluid preservation



Figure 4: Why somuch gas? Direct

impact of present

Arctic conditions?

Figure 5: Arctic/Frontier basins;expected prevailing fluids

STRATEGIC


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22/12422 BEST PAPERS / January 2012

2007, when CLOV was designated a project. The teamis headed by Project Director Genevieve Mouillerat,who was previously FPSO package manager on Dalia.

At CLOV, however, the Oligocene reservoirsaccount for three-quarters of the total oil reserves of505 MMbbl. At 0.5-0.6 cp, this oil is some of the best-quality in block 17, with a gravity range of 32-35API,a low wax content, and no sulfur. Temperature and

pressure is also favorable, in the range 75-80C(167-176F) and 300 bar (4,351 psi). CLOVs Mioceneoil, which represents a quarter of the reserves, ismore viscous and lower quality, with 20-30APIgravity, with lower reservoir temperatures (around50C, or 122F) and pressure (200 bar, or 2,900 psi).

The combination is not ideal, Mouillerat said, butwe can separate the commingled crudes in onetopsides train. At Dalia, when the effluent arrived atthe FPSO, we had to re-heat it to achieve separation.With CLOV, however, the temperature on exiting thereservoirs is high enough to make this unnecessary.

Schematic shows CLOV FPSO, subsea wells and associated risers/flowlines

DESIGN CHANGES

CLOV stands for Cravo, Lirio, Orquidea, and Violeta,four fields in the northwest of Block 17 that werediscovered and appraised between 1998 and 2006.They are situated 140 km (87 mi) offshore Luanda and40 km (24.8 mi) northwest of the Dalia field, in waterdepths ranging from 1,100-1,400 m (3,609- 4,593 ft).

Lirio and Cravo contain high-quality Oligocenecrude, in Lirios case overlain by a large gas cap.At one point, the partners considered a phaseddevelopment of these fields via the Girassolfacilities; but when it emerged that the Miocenecrude volumes on Orquidea and Violeta werelarger than expected, a new concept gained favorinvolving a hub on Cravo/ Lirio, drawing in reservesfrom Orquidea and Violeta at a later stage.

In early 2006, after integrating new reservoir data,Total leaned towards a simultaneous development

of all four fields, and this was confirmed in February

STRATEGIC

TechnoHUB 2 / February 2012


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STRATEGIC

Acergy (now Subsea7) was awarded a $1.2-billioncontract to engineer, fabricate, and install theSURF spread. FMC is providing 36 subsea trees,

wellheads and controls, all eight manifolds, plusassociated tie-in/tooling systems, and workovercontrol systems for the two rigs. Mouillerat describesthe subsea production facilities at least for theOligocene reservoirs as conventional, in terms ofwhat Total has done before on block 17, althoughwe do make improvements as we go along andimprove our knowledge of the reservoirs, he noted.Total opted for riser towers following a designcompetition. This solution was first devised forGirassol in the late 1990s the systems therehave performed well, she points out. A furtherconsideration was the need to maximize use of

Angolan labor the Sonamet yard has unrivalledexperience of assembling and loading out thesestructures, which are roughly 1,200 m (3,937 ft)high. Compared with the previous structuresdelivered for Dalia, there will be improvementsthis time in design/assembly relating to thebuoyancy tanks and use of a guide-frame.

Another local organization, Technips subsidiaryAngoflex, will manufacture CLOVs 80-km(49.7-mi) network of dynamic and static productionand water injection umbilicals at its base in Lobito.

MIOCENE DRIVE

After 18 months to two years of production, the flow ofMiocene fluids from Orquidea/Violeta (50,000 b/d) willbe boosted by a 28-metric ton (30.9-ton) multi-phasepumping (MPP) system supplied by Framo, whichwill be installed around 2-3 km (1.2-1.8 mi) from theFPSO. On Pazflor, Total opted for subsea separationand boosting pumps, but multi-phase pumping in

a deepwater setting is a first for the Company.

The Orquidea-Violeta MPP system will comprisea pumping station moored to the seabed via asuction anchor. This will contain two helico-axialpumps, one for back-up, operating at 45 bar(652 psi), with shaft power of 1.8 MW transmittedfrom the FPSO through a 10.6-km (6.5-mi) powerand control umbilical. Unlike the equipment onPazflor, the MPP system will be capable of pumpingall effluents, liquids and gas (582 Am3/h), witha gas volume fraction of 53%. The equipment isdesigned for a 20-year service life in water.

Use of MPP also reduces the need for gas lift onOrquidea/Violeta. With most of CLOVs associatedgas allocated to Angola LNG, there is no scope for gas

injection, with only modest amounts of gas set asidefor power on the FPSO. Doing without gas injectionsaves the cost of one well, Mouillerat says, but onthe other hand, its technologically quite challengingto start production without this although it isbetter for the environment. We will never needgas injection on CLOV. We also have a policy of noflaring during normal operating conditions for thisproject. We have a flare system for safety, but therewill be no pilot light, which is again a challenge.Instead, we will have a complex ignition package.

POWER MANAGEMENT

The FPSO will be fitted with 100 MW of installedpower for operations topsides and subsea. GEwas awarded a $114-million contract to supplyfour LM2500 plus G4 SAC aero-derivative gasturbines for power generation, and five processcompressors. The latter, like the water injectionand multi-phase pumps, will be electrically driven

by variable-speed drive (VSD) systems. This willrepresent a first for an FPSO anywhere, accordingto the equipment supplier, Converteam.

The Paris-based Company is providing mediumvoltage drives from its MV7000 range, based onthe latest press-pack IGBT (PPI) technology andincorporating a PWM 3-level inverter. Accordingto Converteam, the adjustable PWM patterns andfrequency allow for wide-ranging flexibility, i.e. lowswitching losses, low motor THD (total harmonicdistortion), high-frequency operation (up to 300Hz),and negligible amplitude of torque pulsation

at the motor shaft. The VSDs are water-cooled,optimizing use of high-capacity diodes and PPI,and operating with very low noise levels. They alsooccupy less space than aircooled VSDs, with theirattendant ventilation/air conditioning equipment.



On CLOV, the arrangement will be:

Four 9.6 MW HP compressors fed by

MV7609, 24-pulse diode front-end andasynchronous motor (6 kV/1,717 rpm)

One 4.8 MW LP compressor fed byMV7304, 12-pulse diode front end andasynchronous motor (6 kV, 1,717 rpm)

Two 8.7 MW water injection pumps fedby MV7309, 24-pulse diode front end andasynchronous motor (3 kV/1,900 rpm)

Two 2.3 MW subsea multiphase pump unitsfed by MV7304, 12-pulse diode front-endand asynchronous motor (6 kV/3, 800 rpm).

The all-electric approach, Mouillerat explained,is proven to be easier for production personnelto operate particularly during early fieldoperations, when there will be regular spells ofequipment stopping and starting. In addition,these VSDs will enable us to use exactly andonly the required amount of power. And theywill help us towards the end of productionwhen our power requirements will be lower.

Also new for Total is the offshore installation ofthe Minox de-oxygenation system that DSMEhas ordered from Grenland Group in Norway forthe compact water treatment module, due to bedelivered early next year. This will be used to treat280,000 b/d of seawater for injection. VWS Westgarthin East Kilbride, UK, is supplying an associatedultrafiltration system and a sulfate removal package.

The variable-speed drive

configuration, suppliedby Converteam, which

will regulate power onthe FPSO.

According to Mouillerat, CLOVs topsides layoutis determined by safety needs. There will be nomore space available than on the other block

17 floaters some areas have been left toaccommodate future tiebacks, but that is thesame for any FPSO. What is different is thelocation of the settling tank for oil treatment inthe hull, which leaves us with more room.

The other main challenge on this project has been toraise local content to new levels of participation. Allpipe double-jointing line pipe is to be performed inAngola, close to the installation site, she points out.When the FPSO arrives from South Korea in 2013,it will be moored in a quayside for installationof the water treatment module on the topsides,

which will also be fabricated in Angola.

Altogether, Total estimates that CLOV will provide9 million man-hours of work for Angolans,representing 20% of global cost of the project for localfabrication and assembly. Angolan labor will accountfor 64,000 metric tons (70,548 tons) of fabrication andassembly including 7,704 m tons (8,492 tons) forthe FPSO and nearly 60% of the SURF package.

Total E&P Angola operates block 17 with a 40%interest, in partnership with Statoil (23.33%), EssoExploration Angola (20%), and BP Exploration

Angola (16.67%). Sonangol is the concessionaire.


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HSE


In general, there is not a broad variety of proven,efficient means of environmental monitoring inthe vicinity of offshore oil and gas productionfacilities. It is often problematic to measure thechemical, physical and biological conditions

of the environment in order to control anddemonstrate that exploration and productionoperations are meeting expectations. In recentyears, much work has been undertaken to developnew methods to supplement the existing means.

Total R&D, in collaboration with the HSEdepartment, Total E&P Congo, Total E&PNorway, PERL and others, has undertakena project to test and evaluate severalmonitoring methods intended to facilitateTotals compliance with corporate andregulatory monitoring requirements.

This study combined four innovative methodsof environmental monitoring, all of which areon the verge of technical validation. Thesemethods were applied concurrently aroundan oil platform in Congo, and then comparedto existing conventional monitoring methods.

The study was called the Super-Monitoringproject because for the experimental design,applications of innovative and conventionalmethods were superimposed upon each other.The objective of the Super-Monitoring project

was to compare, validate and better understandhow these novel monitoring methods cansupplement existing techniques, while providinggreater insight into their field of application.

The following article presents an introductionto the various methods applied duringthe Super-Monitoring program, includingforaminiferal assessment, biomarkers,ecotoxicological testing and passive samplers.Another publication planned for 2012 in apeer-reviewed journal will present the results,comparisons and validation of these methods.

CONTEXT


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A CHALLENGING ACTIVITY

Environmental monitoring around offshore E&Pactivities is expensive compared to the equivalentfor land based activities. This means monitoringtypically yields fewer samples and is performedless often. The principle contributor to cost islogistics, including a vessel from which to conductactivities. Shipping costs to offshore installations,transport, and analytical costs also push up theexpense of marine environmental monitoring.

Spatial and temporal heterogeneity of the watercolumn and seabed makes statistical significanceof the data and results coming from these studies

a challenge. Often the interpretation of monitoringdata must rely on observed trends rather thanstatistically significant datasets. Consider that watercolumn monitoring from a single sampling point mayyield entirely different result on consecutive days,merely from a change in direction of ocean current.

Finally, it is not just cost and variability of thesampling zone that creates challenges. Roughseas, deep waters, arctic conditions, difficulty insampling around an operating platform, bottomhazards such as pipes and risers, all combine to makeenvironmental monitoring in the marine environment

a planning challenge. Occasionally, unanticipateddelays or errors caused by these complex situationscould mean data is lost or costs rapidly increase.

A NEED FORNEW METHODS

The use of conventional sampling methods at seapersists partly due to the good data they provide,but also in the case of water column analyses, noalternatives have been available until recently.

With changing regulatory, technical, and other dataneeds, elaborated methods are needed, particularlyin new environments like arctic and deep offshore.They should be cheaper and easier to apply. Theyshould provide additional figures against whichindices or guidelines may be measured. They alsomay provide new types of data, such as informationabout the ecosystems condition. To meet these

requirements, new methods have been developedand are starting to see wider application.

When attempting to use a new method, advancetesting and study are required and may includea bibliography, lab testing, and pilot studies.The parameters to be reported should be wellunderstood and quantifiable to known limits ofdetection and uncertainty. Equally important arethe spatial and temporal time scales for whichthe data will be considered valid. Whetherresults are for physical or chemical parametersshould be clear as well as their significance tothe ecosystem. Finally, it should be understoodwhich environmental compartment resultsare indicative (water or sediment).

Once a method is well known, the preferred methodto pilot a study is a comparative test. The concurrenttesting of monitoring methods permits directcomparison of results and thus validation of a method.

CURRENT MONITORING METHODS

Conventional methods of water, benthicsediment, and benthic invertebrate sampling(the conventional sampling methods) are theworkhorses of environmental sampling both

offshore and onshore (lakes and rivers). Theygenerally are robust and are considered valid byregulators and stakeholders. These monitoringtechniques measure concentrations of substancesassociated with anthropogenic discharges,including PAHs, BTEX, nutrients, salts, and more.

The analysis of water and sediment samplesprovide data against which indices or guidelinesmay be compared, and also can be interpretedby biologists to give an idea of the functioning ofthe ecosystem and indications of perturbation.

The conventional approach of benthic invertebratesampling provides data for community structureindices used to interpret ecosystem function. Indices

such as Shannons or density can reveal nutrientdeficiency or enrichment. The principle drawbacksare that these methods are costly, time consuming,and do not indicate the short-term response, butrather the response from years of exposure.

HSE


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TECHNICAL

What are the worlds current hydrocarbonreserves? This has always been one of the majorquestions the oil and gas industry has had toaddress, and it remains topical today. Indeed, theglobal economy would like to know the volume of

yet-to-find resources to calculate how much fossilenergy the planet still has available. Companieslike Total are also keen to determine whichpetroleum provinces should be the focus of theirexploration efforts, and where they should targetlarger hydrocarbon resources. Yet summingthe proven, unproven, probable and possibleresources is a difficult exercise. Every basin differsby its location, its geometry, its compositionand its history. As for the gentle cooking ofsediments that started millions years ago beneathour feet in the bowels of the Earth, variations inthe many intrinsic parameters temperature,

pressure, presence of a trap, permeability,carrier beds serving as drains for hydrocarbonmigration, accumulation in sealed reservoirs all influence the yet-to-find hydrocarbonquantities. Experts have been working on waysto evaluate hydrocarbon resources for many


GEOLOGY

years. Given the wide variations in publishedestimates (from 275 to 1,469 billion barrels), anyother predictions based on these data are rathersketchy. To obtain a more precise appraisal, a toolhas been developed to better predict the worlds

yet-to-find hydrocarbon figures. It is the result offive years spent studying, comparing data anddeveloping statistics on conventional resourcesin discovered, prospective and speculativefields in 170 sedimentary basins worldwide.This method is not merely a sum of barrels;it gives access to the source rocks productionpotential according to the type ofsedimentary basin using two new numbers,the Source Potential Index (SPI) andthe Petroleum System Yield (PSY).

CONTEXT


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Over geological time, a change in the compositionof organic material can be identified from fossilevidence. It corresponds to the evolution of

different life forms and the acmes of particulargroups, such as the appearance of algae inthe Proterozoic (Precambrian), the evolutionof land plants from the Paleozoic (Silurian,440Ma), and the dominance of Angiosperms(flowering plants) from the Late Cretaceoustime (65Ma) up to the present time.

Unlike coals, which stem from the organicmetamorphism of mainly woody material,hydrocarbons (gases and liquids) come fromdifferent types of organic matter and can bedivided into several genetic families. Over 95%

of organic matter that has not decomposed isdeposited in an underwater medium (marine,lacustrine, deltaic, river, or lagoon) and ismainly of vegetal origin (plankton, algae, planttissue, wood, resins) in the form of cell wallfragments. Plant-derived organic matter isproduced by photosynthesis and is part of thecarbon cycle, which means that hydrocarbonsare basically concentrated forms of solar energy.

This organic matter ends up in sediment interstratified, disseminated, orconcentrated in the form of kerogen,

which is subsequently buried under the massof accumulated overlying sediments.

KEROGEN MATURATION

Over time, and providing it is present in thesedimentary basin and heated, kerogen willgradually turn into hydrocarbons. Next comes theprimary migration phase, where the newly-formedhydrocarbons are expelled from the source rockif they are sufficiently concentrated (a minimumhydrocarbon saturation of the porous network isrequired). Then in the secondary phase, driven

by buoyancy forces, the hydrocarbons will moveupwards or laterally following permeabilitygradients and differences of rock entry pressures.Some may reach the surface, creep, and naturallypollute the surrounding area of land or sea,although this is not always noticeable; others maybe completely altered by bacterial action. Whenthis happens, the petroleum system has completedits sequence, from beginning through to death.

Some of the hydrocarbons, however, may moveinto a reservoir rock in a hydrocarbon trap, wherethey will remain stored for millions, sometimes

hundreds of millions of years, retained by a sealof impermeable cap rock, the most efficient in terms of entry pressures being evaporitic

rocks. The maturation of kerogens involves highlycomplex physico-chemical processes relating tosediment compaction, the regional thermal regime,

the kinetics of the chemical reactions occurringin the source rocks, and the expulsion of theirhydrocarbons. This is what has been called thegeopetroleum sequence, which describes all theprocesses from the heating of kerogens to themigration of hydrocarbons towards petroleum traps.

As the kerogen becomes buried even deeperdown and its temperature rises still higher,the expelled hydrocarbons become lighter andtheir gas content increases. The relative carboncontent decreases, while the percentage ofhydrogen increases. It is at this point that the

classic oil kitchen turns into a gas kitchen.

MIGRATION AND THERMODYNAMICS

The phase equilibria of the hydrocarbons duringtheir formation and during their secondary migrationthrough carrier beds are regulated by the temperatureand pressure in the porous rock of reservoirs andthe pore pressure of the caprock and source rock.The thermodynamic controls on the process andthe phase equilibria determine the gas-to-liquidratios of the trapped fluids, whether the fluid inthe reservoir is gas or oil (or both) or, under certain

pressure and temperature conditions, a critical fluid.

HYDROCARBON ENTRAPMENTAND POSSIBLE DESTRUCTION

Sometimes the hydrocarbons end up completelydestroyed and this signals the end of the petroleumsystem. There may be several reasons for this:

An active biodegradation process, wherebythe hydrocarbons are broken down by bacteria,usually at a low temperature (generally under80C). Biodegradation can occur at every stage

in kerogen and hydrocarbon development.

Dry gas is often produced as a resultof the biodegradation process.

The temperature rises too high (beyond170200C) and the oil fraction changesinto gas; this is the secondary crackingprocess, during which kerogen and oil canbe completely transformed into gas,leaving a residue which corresponds tocoke and sometimes to pyrobitumens,also in case of multi-pulse charge.

A phase of structural deformation which may

change the geometry of the initial efficient trap(and at the same time its retention capacity),allowing the hydrocarbons within to escape.



PETROLEUMSYSTEM CONCEPTAND SPI AND PSY

Invented by Alain Perrodon in 1980, the petroleum

system (PS) concept corresponds to the dynamicsequence of all the combined geological elements andprocesses which, from a source rock using the sameplumbing system (migration pathways) to one or morereservoir/seal pairs (the definition of the petroleumplay), leads to the formation of a geneticallyrelated family of hydrocarbon accumulations.

The corresponding generative system can bequantified by its initial total organic carbon (TOCi)and its initial petroleum potential (S2i) obtainedfrom TOC-RockEval data. These figures need to berecalculated in their initial kerogen depositional

stage because measurements on source sectionsgive figures that correspond only to the present stageof maturity of the rock. In the case of non-maturesource rocks, the figures are the same. This work wasperformed using measurements obtained from Rock-Eval and equivalent vitrinite reflectance values, thetype of organic facies and appropriate kinetic lawsrelated to the classical I, II, and III organic mattertypes, and any intermediate mixtures in the kerogen.

The source potential index (SPI) represents theinitial generative capacity of a source rock. It isdefined in our method by the following formula.

It is not the same as G. Demaisons definition whichessentially sums the S1 and S2 figures fromRock Eval. SPI = S2i * Source rock density * Source

rock net thickness (SRNT), where density is chosenat a value of 2.5 gram per cubic centimeter for shalysources and of 2.3 gram per cubic centimeter for

coaly layers, and where SRNT is the overall intervalthickness having an initial TOCi exceeding 0.3%.The SPI is calculated in metric tons per km2.

We then qualified the yield of a given petroleumsystem (Petroleum System Yield: PSY) as the ratiocalculated between the accumulated hydrocarbons(HCA) and the related generated hydrocarbons(HCG) on a per-basin basis. Generated andaccumulated hydrocarbons are expressed in metrictons and reconverted into barrels of oil equivalent(boe) using an average hydrocarbon density (tonper m3). PSY = HCA/ HCG. This is a dimensionless

figure, which is measured as a percentage.

The HCG are calculated by gathering the SPIof the source rock, the extension of the relatedkitchens, and an average transformation ratio (TR)characterizing the source rocks mean maturity equivalent Vitrinite Reflectance (VRo eq.) inthe basin and using this third main formula:

HCG = SPI * TR * kitchen surface area (in km2).

To summarize this method, the PS as definedimplicitly includes the concept of petroleum system

yield (PSY), which represents for a given petroleumsystem the ratio between hydrocarbons generatedfrom a given source rock and those trapped in it.The PSY numbers are directly related to theefficiency of the generative system and its abilityto expel hydrocarbons once the accumulation ofoil molecules in the porous rock has reached itssaturation point. To achieve this, the source rockhas to reach a minimum degree of maturity, whereits pores are saturated with hydrocarbons, a pointgenerally obtained for liquid hydrocarbons at atemperature of about 120C. This oil window liesbetween 120 and 160C in normal thermal conditions.

Yield also depends on other parameters of thepetroleum system, as we will demonstrate later on:

Secondary migration efficiency, in otherwords, the movement of the hydrocarbonsalong the migration pathways, which inturn depends on the proximity of the sourcerock and the hydrocarbon: the closer thesource rock to the reservoir/ cap-seal,instead of the more efficient the system.

The impermeability (retention ability)of the cap-rock.

A pressure increase in the reservoir that maycause loss of the cap rock integrity: this isthe natural hydraulic fracturing process.

Hydrocarbons may also leak out if thecap rock cracks either during or afterthe structuring phase, or be forced outof the trap after a reservoir undergoes astructural uplift combined with a matchingdecrease in pressure, causing an increasein volume and leakage from the structure.

For all the reasons, and because of the complexmechanisms driving the birth, life, and death ofpetroleum, the quantities of hydrocarbons lost overtime are generally much bigger (often in a hugeproportion) than those trapped in accumulations.

We now move on to the baseline of these fiveyears work: the yield of a petroleum system.

GEOLOGY



Figure1: Relationship between SPI

and age of the source rocks.

Uusually, Type II are transformed as maturityincreases with burial depth, in a range of vitrinitereflectance of 0.6/0.7 and 1% and are termed

oil-prone, i.e., inside the oil window. Type-IIIorganic matter has much more delayed kinetics(only 30% of the organic matter is transformed at1% VRo) and, chiefly for this reason, is consideredas more gas-prone despite the fact that the Nigerdelta, for example, has delivered considerableamounts of liquids (oils and condensates).

Looking first at the statistics in Type II organicmatter case studies and SPI variations overgeological time, it is easy to recognize theimportance of six main time stages (figure 1):

Silurian, with its well-known hot shaleradioactive layers, identified in NorthAfrica and in the Arabian Platform, whereintervals correspond to trangressive marinemaximum flooding surface layers.

Devonian and Frasnian/Famennian, alsoexhibiting typical radioactive hot-shaleflooding layers, are well calibrated in NorthAfrica and South America (shelf deposits).

Kimmeridgian is a major contributor in theNorth Sea (Kimmeridge clay), in WesternSiberia (Bazhenov formation), and in theSouth Aquitaine Basin (Lons or Lituolidae

formations), but is absent as source rock faciesin the southern flank of the Pyrenees in Spain.

WORLDWIDESPI STATISTICS

Generally, as G. Demaison has done, we candefine and rank SPI figures which are less than2.5 million metric tons per km2 (a threshold thatrepresents a risk of associated hydrocarbonundercharge) as low. Values between 2.5 and7.5 million metric tons per km2 are consideredas moderate (normal hydrocarbon charge),while SPI ranging between 7 and 15 millionmetric tons per km2 are classified as high (alsorecognized as hydrocarbon supercharge).

We compiled SPI statistics, differentiating Type IIkerogens (mainly algal marine organic matter)from Type III kerogens (composed of continentalhumic materials, generally related to deltas orsubstantial fluvial fairways with a large influxof sediments originating from the continent).

Generally speaking, PSYs are clearly fairly low,at just a few percent. This is because losses occurthroughout the system, first of all in the source

rock, then along the migration pathways, andfinally in the petroleum trap. Our study incorporatesextensive in-house statistics on SPI and calculationsof PSY which illustrate in the rest of this paper.


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Figure 7: Example of the South Aquitaine Basin,France. Stratigraphic chart in Biteau et al., 2006.

GEOLOGY



Figure 8: Example of differentiatedtypologies and related PSY.

TWO CASE STUDIES

We will now illustrate these assessments withtwo examples extracted from the database builtduring our study: the Aquitaine basin (Biteauet al., 2006) and a compilation of some AfricanBasins located in North and Sub-Saharan areas.

AQUITAINE BASIN

Despite the low SPI of its main generative system(of the order of 1 million metric tons per km2),the South Aquitaine Basin offers a fine exampleof a really efficient compact system (PSY=12%),exhibiting a short distance between source and

plays, i.e., Kimmeridgian source and Barremian-TithonianKimmeridgian reservoirs, associatedwith a foreland area and a main vertically-driven hydrocarbon migration process.

AFRICAN BASINS

Typological differences and associated yields arealso well evidenced by the comparison of some ofthe West and North Africa basins, see figure 8.

DISCUSSIONON YTF FIGURES

It is typically in the framework of a worldwide YTFhydrocarbon evaluation project (inventory andranking of remaining hydrocarbon volumes) that ourPSY method has been put into practice since 2005.It enabled us to calculate the maximum remainingexploration potential of some underexplored basinson which we cannot comment in detail here.

We will present here the main conclusions fromthis study and describe two case studies toillustrate our comments and indeed highlightthe principal advantage of this method.

The most striking results concern the offshoreextension of well-calibrated onshore basins suchas the Sirt Basin in Libya or others with a clearlydifferentiated exploration history, for example inBrazil and Australia. For the other basins, the choiceof a pertinent geological and petroleum analogueis the most crucial criterion in their PSY selection.

In poorly calibratedfrontier areas, the methodremains sensitive tothe lack of identified

source rocks, poor SPIknowledge, and sourcematurity uncertainties. Inthese contexts, it is morechallenging to correctlycalculate the generatedvolumes. Core drillsand outcrop samplinghave proved to be veryuseful references andhave further enhancedour evaluations. Forexample, we were able

to identify the EastGreenland Basin as oneof the anomalies (possibleremaining explorationpotential) in line with arecently published USGSdocument (USGS, 2000).


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Figure 11: The Gavbendi High

hydrocarbon dysmigration andremobilization concept

(Biteau et al., 2009b).

Figure 12: Quantitative approach:

how to discard a single source rock

concept (Biteau et al., 2009).

REFERENCES

And reini et a l. [2008]Understanding the future,Geosciences serving society. Nanc y Schoo l o f Geo logy ,Editio ns Hirle.

Bitea u, J.J., Perrod on, A. a nd Cho pp in d e Ja nvry G. [2003]The Petroleum System: a fundamental tool.Oi l and G as

Journal, 11 Aug ust.

Bitea u J.J., Le M arrec , A. Le Vo t, M. a nd Ma sset, J.M. [2006]The Aquitaine Basin. Petroleum Ge oscienc e, 12(3), 247-273.

Bitea u et al. [2007]The Petroleum System, a globalquantitative approach at Basin and field scales, whichlessons for some of the Lower Congo Basin Petroleumsystems. DOWAC, Luanda .

Bitea u et al. [2008]African Petroleum Systems: richnessand efficiency key drivers at continent scale. AAPG, Cap eTown.

Bitea u et a l. [2009a]The Gulf of Guinea Petroleum Systems,pre-salt and post-salt dichotomy. AAPG, Rio de Janei ro .

Bitea u et al. [2009bThe Khuff play related PetroleumSystem between the Qatar arch and the Fars area. IPTC ,Doha .

Dem a ison, G . [1984]The generative basin concept. InDemaison, G.and Murris, R.J ., (Eds) Petroleum ge oc hem istry andba sin eva luation. A APG M em oir, 35, 114.

Dow , W.G. [1974]Application of oil correlation and sourcerock data to exploration in Williston basin. AA PG Bullet in, 58, 7,12531262.

Klem m e, H.D. [1994]Petroleum Systems in the world that involve

Upper J urassic source rocks. AA PG Mem oir, 60, 5172.

Ma go on, L.B. [1988]The Petroleum System A classificationscheme for research, resource assessment. USGS Bulletin, 1870,215.

Ma go on, L.B. and Dow , W.G. [1994]The Petroleum System.AAPG M em oir, 60, 323.

Ma go on L.B. and Va lin Z.C. [1994]Overview of Petroleum Systemcase studies. AA PG Me m oir, 60, 329338.

Ma go on L.B. et a l. [2002]Petroleum Systems of the Alaskan NorthSlope a progress report. AA PG Bulletin, 6, 86, 1151 (Abstrac t).

Perrod on A . [1992]Petroleum systems, models and applications.Journal of Petroleum G eo logy, 15(3), 319326.

USGS [2000]World Petroleum assessment 2000 Description andResults. USGS Digita l Da ta Series, 60.


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Borehole image logsfor turbidite faciesidentification:core calibrationand outcrop analogues

In exploration, appraisal, and developmentof hydrocarbon fields, the understanding ofthe sedimentary model requires increasinglysophisticated techniques and analysis to interpretthe geometry, facies, and petrophysical properties

of the reservoirs. The objective is to understandthe reservoir flow properties for making optimumdecisions during field development. For this purpose,the use of high resolution image logs providedby service companies has become essential insedimentary interpretation. When they are correctlycalibrated against known facies, image logscan replace coring operations, which are time-consuming, expensive, and limited in the depthinterval sampled. Recent examples of applicationhave proved highly successful for exploration wells.

Now mature fields can be reinterpreted in the light ofthe new understanding gained, enabling developmentplans to be revised with enhanced recovery methods.As a result of the success of this approach,imagebased facies interpretation is now included in

the standard procedure for evaluation of data fromexploration, appraisal, and development wells.

Jean-Bernard JOUBERT1* and Valrie MATAN1

1 Total Technical Centre, Avenue Larribau, 64 018 Pau, France.*Corresponding author, E-Mail: [email protected]

EXTRACTFirst Break

Vol 28

Issue 6

June 2010

ABSTRACT



Figure 1: Work flow of an image logs study showing integration of these data (facies and dips) in the sedimentary model.

Each sedimentary body will be ascribed petrophysical properties in the reservoir model for oil volume calculation.

INTRODUCTION

In recent years, the need for improved reservoirknowledge from deep exploration wells has becomeacute because of the general requirement for fast-track discovery evaluation coupled with the lackof nearby outcrops of reservoir rocks. In addition,the high heterogeneity of turbidite reservoirsposes special problems for reserves estimation andfluid-flow prediction. Since starting explorationin deepwater areas offshore Africa in the 1990s,Total has carried out intense coring acquisitionprogrammes in more than 20 turbidite oil fields.Coring remains the best reservoir calibrationreference, because the mineralogical and

petrophysical characteristics of the sediments canbe determined unambiguously from core. Duringthe same period, image logging in oilbased mudhas become possible, albeit providing images oflower resolution. This technological developmenthas made it possible to interpret facies in detail overthe complete drilled section in many more wells.

In the absence of core, borehole image logging isthe fastest and most precise method for extractingthe data needed for spatial extrapolation to buildthe sedimentary model. Because less coring isrequired when imaging logs are run, there are large

cost saving in field development. The accuracy of

image log interpretation is strongly influenced bythe initial quality of data, which means tight qualitycontrol is mandatory. To avoid mis-interpretation

and over-interpretation, the following checks needto be made before starting to interpret the data:

Logging condition and orientationof the tool in borehole

Proper functioning of the imaginginstrument (sensors, navigation system)

Calculationof the exact position of eachpixel on the cylinder representing theborehole surface (speed correction)

Estimationof the depth of investigationof the sensors

Optimal choice of the false-colour scaleused to image the physical variable

Recognitionof artifacts arising from themeasurement system and data processing

Coupled with compositional information frompetrophysical logs, high resolution boreholeimages provide sedimentary facies descriptionat a level of detail and accuracy which is close tothat obtained from core and outcrop observations.The results can be integrated into a 3D griddedsedimentary model, as illustrated in figure 1.

GEOLOGY



SEDIMENTARY FACIESFROM IMAGE LOGS

The requirement is to predict sedimentary faciesover the complete section of a well. Our methodologyis to define the image sedimentary facies (ISF) in aprocedure which integrates image characteristicswith sedimentological concepts. An ISF correspondsto a specific lithology and depositional mechanismwithin a given sedimentary environment.

A first lithological determination is provided by aclassical multi cut-off method based on a quantitativeestimate of the clay content, sonic and densitylog responses, and the separation of neutron anddensity logs. This determination is mainly, but notonly, dependent on the sand/shale content of theformation, and is made without regional bias. Thenit is refined using a neural network computationbased on the log responses from different tools.The limitations on identification of facies fromsuch lithology determination arises from possibleconfusion between formation with similar sand/shale ratios, such as a basal lag with large shaly

clasts and a sand-rich debris flow, and the limitedresolution of these logs, which do not provide anysedimentological information of the penetrated strata.

Additional information, such as bed thickness and thenature of bed contacts, is obtained by visual analysisof the texture of the images in order to identify the ISF.This information includes the categorization ofimaged surfaces and measurement of their dipazimuths. It is combined with the geologicalinformation obtained at the well site on lithology,grain size, and cement, and the compositional dataavailable from the interpretation of petrophysicallogs. The ISF is more than a wireline neural network-based facies because it is calibrated as closely aspossible to the regional sedimentological macrofacies.

A calibration plate has been designed to defineeach facies to limit the risk of subjective bias by aninterpreter. It summarizes all information concerningthe facies and includes an example of its appearancefor each basic type of imaging tool electricalresistivity in oil-based mud, electrical conductivityin water-based mud, and acoustic reflectivity in bothtypes of mud. Of course, we do not have all the imagetypes from the same well, so the examples have tobe composed from several wells or fields. Figure 2displays part of the ISF calibration plate definingdebris flow facies in a deep marine environment.

At least one image in a calibration plate correspondsto the logs and to the cores shown, but the othertypes of image are also calibrated on cores.

Figure 2: Description and calibration sheet for the debris flow facies, with recognition of typical structures, and

depositional or deformation interpretations on wireline logs, cores, and image logs. The formations appear in

yellow if resistive (oil-bearing sandstone), and brown if conductive (clays/water-saturated sandstone).



The image contrast for electrical imager tools isreferred to as relative conductivity, as obtainedfrom imagers that operate in water-based mud such

as Schlumbergers FMI tool. Conductivity is largelydetermined by fluids, so high values are found inbrine-saturated or shaly intervals and low valuesare found in hydrocarbon-saturated or cementedintervals. Increasing conductivity is represented asincreasing colour saturation, from white to brown.

The low resolution and coverage of imaging toolsfor use in oil-based muds makes their interpretationmuch more difficult than for images obtained fromtools used in waterbased muds. Long experienceand good understanding of drill-site operations,sedimentology, and the physics of acquisition is

therefore required to avoid misinterpretation.

DEFINITION OF IMAGESEDIMENTARY FACIES

High resolution borehole image logs providea sedimentary facies close to that obtainedfrom core and outcrop observations. The ISF iscalibrated as closely as possible to the definition

of the corresponding regional sedimentologicalmacrofacies. Each ISF is defined by specificinvariant characteristic, stable for all interpreters

and valid for all countries and all wells.Consequently, the risk bias due to subjectivejudgement of the interpreter is limited.

The descriptions of facies in this paper useTotals in-house facies nomenclature for turbiditeenvironments. The main types of sedimentaryfacies are: hemipelagites to massive shale,mud turbidites to laminated shale, thin-beddedturbidites, low density turbidites, high densityturbidites, and debris flows. Certain post-depositional features are also recognizable: slumps,sandy injections, and cementation/diagenesis.

Eleven ISFs have been defined for boreholeimage interpretation in a deepwater offshoresedimentary environment. The nomenclature andclassification are illustrated in figure 3 and aregiven in this section. The ISFs were identified inhydrocarbon fields in the Gulf of Guinea. Figures4 to 12 display, by ISF type, examples of imagelogs compared with core and outcrop. Imagesand cores are not presented at the same scale butare within the same interval. The image logs arespeedcorrected and oriented North to North.

Figure 3: Image sedimentary facies (ISF) scheme.

GEOLOGY



ISF 1: MASSIVE SHALE

This facies is deposited as mud settling fromsuspension. On wireline logs, it is detected throughconventional shale indicators (high clay content,large neutron/density separation, and low velocity).The image is mainly conductive, and very thinlylaminated (figure 4). These shales are finely foliatedand dips are picked with a low accuracy. Someunreliable, thin, resistive stringers or halos, dueto bioturbation or diagenetic nodules, cut acrossthe image. This ISF is well discriminated byconventional logs and constitutes a good seal.

ISF 2: MUD TURBIDITESTO LAMINATED SHALE

This facies is described oncores as a shaly formationwith occasional silty bedsor laminae with currentripples. On conventionallogs, these shaly facies arediscriminated by sonic andneutron/density separation.The image shows adominant conductive pattern(brown to orange) with thinresistive layers visible onall pads (figure 5). The dips

are fairly accurately picked.This is not a reservoir facies.

Mud turbidites are oftenmistaken from mud-richdebris flows becauseboth facies display lowresistivity images, andlarge elongated clastswithin debris flows can beconfused with laminationson the image. In addition,dewatering processes

within mud turbidite orheterolithic intervals mayappear similar to debris flowdeposits on image logs.

ISF 3: LOW-DENSITY GRAVITYFLOW DEPOSITS HETEROLITHIC,

SHALE DOMINANT

This facies corresponds to centimetre-scale, siltyto fine sand and shale sequences, with shaledominating. On conventional logs, the facies appearsas variably argillaceous silts. The image showsdominant brown continuous beds and resistivewhite concordant bed contacts (figure 6 p. 52).Dips are homogeneous with plane-parallel bedding.Locally contorted contacts may cause confusion ofthis facies with thin debris flows or conglomerates.This facies has poor reservoir characteristics. Thenet sand-shale ratio is estimated to be rather low

according to conventional wireline logs, quantitativeinterpretation, and regional core calibration.

Figure 4: ISF 1 - massive shale.

Figure 5: ISF 2 - mud turbidites to laminated shale.


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POST-DEPOSITIONALSEDIMENTDEFORMATION

Some post-depositional sedimentary featuresare also recognizable: slumps, sand injections,and concretions (figure 13). Thus identification ofpost-depositional phenomena, such as injectionbreccias (hydraulic brecciation), sand injections,or faulting is sometimes ambiguous, which leadsto uncertainties in the interpretation. Theseuncertainties are discussed in this section.

SILLS/DYKES VERSUSSANDBEDS (METRE SCALE)

Images display anomalous resistive patternswith variable dip and azimuth. Conventional

logs indicate silty to sandy thin beds and theirboundaries are either very sharp or broken up.These features are definitely caused by post-sedimentary events and thus do not representany acquisition or processing artefacts.

The sandy layers appear with non-parallel, mostlysteep upper and lower boundaries. The layersoften cross-cut the bedding/lamination and donot show any internal sedimentary structures.These layers are interpreted as injected sands.

The thickness of these layers ranges from the

centimetre to metre scale. At the centimetrescale, or thinner, they have a similar response toopen fractures filled with conductive mud filtrate

when water-based mud was used in drilling, orwith resistive mud filtrate in the case of oil-basedmud. Because the fractures are smaller and betterorganized, the risk of confusion is limited.

At the decimetre scale, their recognition issimplified. Strongly injected strata, resulting in

irregular patches of highly resistive sands, couldbe mistaken for a fault zone (conductive shalyclasts floating in a resistive sandy matrix). Diptrends in the host formation as well as the contactswith the overlying and underlying layers are goodindicators to aid the correct identification.

At the metre scale uncertainty can persist,especially if the injection has a low angle comparedto the sedimentary dip. There is even greateruncertainty if loading or dewatering featureshave deformed the sedimentary structures,as are commonly found in soft sediments.

FAULT ZONE VERSUSDEBRIS FLOW

The problem is to distinguish a fault zone (stronglyfissured interval resulting in irregular patches onimage logs) from mud-rich debris flow depositswith conductive clasts floating in a more resistivesandy matrix. The tool resolution and measurementartefacts (due to the radius of investigation,an object is detected by the sensors before it isencountered in the borehole wall) can mask theshape of rock discontinuities: angular in the case offaults, giving rise to a small-scale mosaic effect on

image logs, and rounded clasts in the case of debrisflows. Thin debris flow beds, 1 to 2 m thickness,may correspond toin situ levee destabilization.

Figure 12: ISF 11: injected sand - sandy sills/dykes.

GEOLOGY



BENEFITS OFISF CLASSIFICATION

As the ISFs are calibrated on cores and wirelinelogs, and correlated to outcrop analogues, the studyof image logs is the best link from well data toseismic data. The integration of several independentdata sources gives confidence in the interpretation,but for a good quality study, it is essential thatthe interpreter should apply the following rules:

1. Grain size estimation is provided by conventionalgeological techniques, such as cuttingsdescriptions, calcimetry, sidewall cores, and cores.

2. Lithology is the first guide to facies and is providedby neural- network computation from wirelinelogs. The lithology determination is representativeof the sand/shale content of the formation.

3. Image log interpretation provides structural andtextural information about the formation. Thisinformation complements the determinationof lithology from logs within a range of sand/shale ratio. The only way of discriminatinga sand-rich heterolithic deposit from a sand-rich debris flow is the texture: laminated forheterolithic and chaotic for debris flow.

This approach permits the integration of the variousturbidite nomenclatures and can be applied toexploration wells or mature fields. Each ISF isdefined by specific characteristics that are stablefor all interpreters and valid for all countries andall wells. Consequently, the risk of subjectivebias on the part of each interpreter is limited.

Figure 13: Types of post-depositional sediment deformation.(a) Slumps: eye shape on image logs, different dip trends above

and below. (b) Injected sand: network of sine waves of centimetre

to metre thickness, resistant and cross-cutting the bedding.

(c) Diagenesis: diffuse highly resistive halo, loss of internal fabric,disconformable bed boundary indicating nodular shape, with

typical hard bed response on the logs.

The distinction between a true debris flow associatedwith transport and an early destabilization withinlevees (slip, shearing, slump) depends on the

image quality and is not always possible.

TECTONIC BRECCIATION VERSUSINJECTION BRECCIA

These two different types of facies display similarimages: a dense and fine (centimetre-scale) networkof resistive features. If the well conditions aresuitable for obtaining good quality images, diptrends and magnitudes as well as the nature ofthe bed contacts allow them to be distinguished.

An additional problem is establishment of the

relative chronologies of these events. The interpretedsand injections may have followed pre-existingfracture planes, or they may represent resistivefractures. On the other hand, it is quite possiblethat fracturing and sand injection are geneticallyrelated, thus explaining their coexistence.

Hydraulic brecciation, the possible result of theemplacement of a debris flow, causes sand to beinjected into these debris-flow bed deposits.

To take into account these uncertainties during theinterpretation, three alternative codes were used:

Possible debris flow disturbed imagewith strong and irregular contrasts ofcolour and some scattered dips

Possible injection breccia resulting fromthe hydraulic brecciation in argillaceousor silty-argillaceous levels, occurringmainly in leve or debris flow facies

Possible tectonic brecciation particularlyrelated to the passage of a fault



Figure 14: Contributions of the methodology based on theimage facies atlas to the sedimentary and the reservoir models.

GEOLOGY



Finally, the product is a facies log that isvery similar to a sedimentological log.

Image facies analysis provides a detailedunderstanding of depositional models as wellas depositional environment, palaeocurrents,sandbody geometry, sequence stratigraphy,diagenesis, and post-depositional features.The refinement of a sedimentary model improvescharacterization of reservoir layering andarchitecture: net sand, permeability as a functionof heterogeneity, flow baffles and barriers,and sealing potential of faults/fractures.

It is possible to extrapolate sedimentary bodiesof a facies association from ISF classification by

studying analogue outcrops. The classification allowsthe interpretation of depositional environments(channel, lobe, or levee) and the geometry of thecorresponding sedimentary bodies (size, orientation)for a succession of strata encountered in a well.

That information, associated with the petrophysicaldata defined on exploration key wells (i.e., porositypermeability relationships established on cores by

facies and by sedimentary bodies), is later includedin reservoir models and dynamic simulations.The first estimations are more precise and can berefined after each uncored infill well is drilled.

For fields in the appraisal process, petrophysicaldatasets established since the 1990s allow integrationof uncored wells and old wells. With this atlasof image sedimentary facies, field studies shouldbecome more consistent across the Company. Thepresentation of a common terminology, acceptedand respected by geologists and reservoir engineers/geoscientists, has led to the establishment of the

atlas as a Company-wide reference document.Figure 14 summarizes the contributions of thismethod to the enhancement of sedimentaryand reservoir models.

ConclusionsBorehole image logs, when correctly calibratedagainst cored intervals, can be extrapolatedover uncored logged sections in wells drilledwith either water-based mud or oil-based mud.They provide details for the understanding ofdepositional models by integrating fine-scalefeatures such as facies and bed contacts withlarge-scale features such as sandbody geometry.Finally, the method allows the definition of an ISF.Identification of the ISF helps improve the definitionof reservoir architecture, adding informationabout net-to-gross ratio, heterogeneities, shalybaffles, injected sand, and fault intersections.

Borehole image log analysis is now a maturetechnique, established as a key component ofexploration methodology. The method can be appliedto all stages of field development. For explorationwells, the image logs have become an indispensabletool to mitigate the absence of cores. In developmentwells, interpretation of image logs allows a rapidupdate of the reservoir model. In particular, itpermits the differentiation of massive shaly bedssuch as hemipelagites, which are likely to constitutebarriers of large lateral extent, from laminated siltyshales, which may be channel levees and thereforeindicate the local presence, laterally, of a sand body.Furthermore, if these data are available, maturefields can also benefit from modern sedimentologicalconcepts and from historical petrophysical databases.

Finally, borehole images allow consolidationof the seismic interpretation, particularlyon the scale below seismic resolution.For example, we can differentiate chaotic sandybodies (channels) from debris flows with poorreservoir quality. In our recent experience, thismethod is now considered indispensable inthe sedimentological interpretation of turbiditesequences drilled in deep water offshore areas.

ACKNOWLEDGEMENTS

The autho rs thank Tota l ma nag em ent for pe rmissionto p ubl ish th is pa pe r, and friends, co l lea gue s, andano nymo us review ers for a num be r of usefu l com me nts.

REFERENCES

Boum a, A .H. [1962]Sedimentology of some Flysch Deposits:a Graphic Approac h to Fac ies Interpretation. Else vie r,Amste rdam.

Low e, D.R. [1982]Sedimentation gravity flows: II.Depositional models with special reference to the depositsof high-density turbidity currents. Journal o f Sed ime ntaryResea rch , 52, 279-297.

Mu tti, E. [1992]Turbidite Sandstones. Inst itu to di G eolog ia ,Universita di Parm a & A gip .

Stow , D.A.V. and Shanm uga m, G . [1980]Sequence ofstructures in finegrained turbidites: comparison of recentdeep-sea and ancient flysch sediments.

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