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A vital but

Challenging resource…… EXTRA-HEAVY OILS, THE CHALLENGES OF MAXIMIZING RECOVERY IN

ORINOCO BELT-VENEZUELA

Date:30th December 2013 Authored By:

ASIM KUMAR GHOSH; DGM (P)

ONGC VIDESH LTD

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A vital but

Challenging resource…… EXTRA-HEAVY OILS, THE CHALLENGES OF MAXIMIZING RECOVERY IN

ORINOCO BELT-VENEZUELA

Heavy Crude oils

Heavy crude oil has been defined as any liquid petroleum with an API gravity less than

20°. Physical properties that differ between heavy crude oils and lighter grades include

higher viscosity and specific gravity, as well as heavier molecular composition. In 2010

the World Energy Council(WEC) defined extra heavy oil as crude oil and is commonly

defined as oil having a gravity of less than 10° and a reservoir viscosity of no more than

10000 centipoises. When reservoir viscosity measurements are not available, extra-heavy oil

is considered by the WEC, to have a lower limit of 4° API.(WEC 2007) i.e. with density

greater than 1000 kg/m3 or, equivalently, a specific gravity greater than 1 and a reservoir

viscosity of no more than 10,000 centipoises. Heavy oils and asphalt are dense non

aqueous phase liquids (DNAPLs). They have a "low solubility and are with viscosity and

density higher than water."Large spills of DNAPL will quickly penetrate the full depth of the

aquifer and accumulate on its bottom."

Heavy oil is petroleum that has become extremely viscous as a result of biodegradation:

bacteria active at the low temperatures associated with shallow deposits consume the lighter

hydrocarbons, leaving behind the more complex compounds such as resins and

asphaltenes.

At viscosity values up to 10,000 centipoise (cP), the oil is highly viscous but remains mobile

in reservoir conditions. This is termed ―extra-heavy‖ oil, and can be recovered using cold

production methods. Petroleum with viscosity above 10,000 cP is called bitumen, and is so

viscous that it is immobile at reservoir conditions. Mining methods are feasible to extract the

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bitumen to a depth of up to 100 metres. For deeper deposits, thermal recovery methods are

required to mobilize the oil by heating it.

• 2 characteristics by definition:

- Gravity: very dense, between 7 and 25° API

- Viscosity (reservoir conditions): highly viscous, from 10 up to over 10,000 cP

• 3 categories of heavy oil:

Categories Definition

‗A‘ Class Gravity < 25° API

Heavy oil 10 < Viscosity < 100 cP

Mobile ‗B‘ Class Gravity < 20° API

Extra-heavy oil 100< Viscosity < 10,000 cP

Non-mobile ‗C‘ Class 7 < Gravity < 12° API

Oil sands - bitumen Viscosity > 10,000 cP

For convenience purposes, in general terms « heavy oils » include categories

A+B+C, and « extra-heavy oils » include categories B+C, i.e. extra-heavy oils and oil

sands.

Resource Background: The Americas, from North to South

Some 80% of all heavy oils are extra-heavy (EHCO); these include oil sands, which are

highly complicated as well as costly to develop. Although found in all parts of the world (e.g.,

Russia, USA, Middle East, Africa, Cuba, Mexico, China, Brazil, Madagascar, Europe and

Indonesia), the largest accumulations of EHCO in the form of oil are located in Venezuela

(the Orinoco Belt) and as Oil Sands at Canada (Province of Alberta). Combined, these two

regions represent nearly 3,000 billion barrels of oil-in-place. They also account for 95% of

global production of heavy oils (2.2 -2.8 million barrels per day in 2008-2012, two-thirds of

which are in Canada and one-third in Venezuela). Although less than 1% of these resources

are produced or under active development today, output should nearly quadruple, reaching

at least 7 or 8 Mb/d by 2030.

Given the considerable resources they represent, extra-heavy crudes and oil sands are a

major potential source of supplying world energy demand. While industrial performance is

part of the equation, energy intensive production of these heavy oils also presents an

important environmental challenge which must be addressed.

At the current rate of production, conventional oil reserves are expected to last for fifty years.

Heavy oils can supply an additional twenty years‘ worth of production. However, these oils

are complex to extract, and there are a number of technical and environmental issues that

must be addressed in order to develop them responsibly.

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Heavy oils are an essential component of the world‘s future energy mix. The volume of oil-in-

place is estimated to be between 4,000 and 5,000 billion barrels (Gb), translating to

resources of up to 600 Gb. These figures reflect the enormous potential of heavy oils: they

are equivalent to 60% of global reserves of conventional crude oil and account for 20 to 25%

of the world‘s petroleum resources (source:EIA) .

Reserves for The Future

Heavy oils account for approximately 25% of the world‘s petroleum resources, equivalent to

approximately 20 additional years' worth of hydrocarbon reserves. These unconventional

oils, concentrated mainly in Venezuela and Canada, are becoming an essential component

of the energy mix.

Growing Energy Needs

Proven global reserves of conventional oil amount to one thousand billion barrels – enough

for up to 50 years supply at the current rate of production. However, as predicted by the

―peak oil‖ scenario, conventional oil and gas exploration targets are becoming increasingly

rare.

Indeed, as production from conventional acreage declines at a rate of about 5% per

year, global demand is rising at a steady rate of 1 to 1.5% per year, driven especially by

China, India and Brazil.

In this environment, heavy oils can play an instrumental role in hydrocarbon reserve

replacement. As a part of tomorrow‘s energy solution, they can extend the world‘s energy

reserves by 20 years.

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High Concentrations in Venezuela and Canada

Extra-heavy oils and oil sands make up 80% of all heavy oils, and are both complicated and

costly to produce and upgrade.

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Although found in all parts of the world, the largest extra-heavy oil reserves are concentrated

in Venezuela and Canada.

More specifically, the two most prolific regions are:

The Orinoco Belt in Venezuela,

The province of Alberta in Canada.

Together, these two regions represent a total of nearly 3,000 billion barrels in place –

translating to reserves of 440 Gb. That is almost double the reserves of Saudi Arabia

(260 Gb), the country with the greatest volume of conventional reserves.

Heavy Oil Resources of the Orinoco Oil Belt, Venezuela One of the Largest Recoverable Oil Accumulations in the World

The Orinoco Oil Belt Assessment Unit of the La Luna-Quercual Total Petroleum System

encompasses approximately 50,000 km2 of the East Venezuela Basin Province that is

underlain by more than 1 trillion barrels of heavy oil-in-place. As part of a program directed at

estimating the technically recoverable oil and gas resources of priority petroleum basins

worldwide, the U.S. Geological Survey estimated the recoverable oil resources of the

Orinoco Oil Belt Assessment Unit. This estimate relied mainly on published geologic and

engineering data for reservoirs (net oil-saturated sandstone thickness and extent),

petrophysical properties (porosity, water saturation, and formation volume factors), recovery

factors determined by pilot projects, and estimates of volumes of oil-in-place. The U.S.

Geological Survey estimated a mean volume of 513 billion barrels of technically recoverable

heavy oil in the Orinoco Oil Belt Assessment Unit of the East Venezuela Basin Province; the

range is 380 to 652 billion barrels. The Orinoco Oil Belt Assessment Unit thus contains one

of the largest recoverable oil accumulations in the world.

Reserves comparison of major Oil Producers

Source:BP Stats

One Trillion Barrels of Heavy Oil

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The Orinoco Oil Belt Assessment Unit (AU) of the La Luna-Quercual Total Petroleum System

encompasses approximately 50,000 km2 of the East Venezuela Basin Province that is

underlain by more than 1 trillion barrels of heavy oil-in-place (fig. 1). As part of a program

directed at estimating the technically recoverable oil and gas resources of priority petroleum

basins worldwide, the U.S. Geological Survey (USGS) estimated the recoverable oil

resources of the Orinoco Oil Belt AU.

This estimate relied mainly on published geologic and engineering data for reservoirs (net

oil-saturated sandstone thickness and extent), petrophysical properties (porosity, water

saturation, and formation volume factors), recovery factors determined by pilot projects, and

estimates of volumes of oil-in-place.

Figure 1. Map showing the location of the Orinoco Oil Belt Assessment Unit (blue line); the La Luna-Quercual Total Petroleum System and East Venezuela Basin Province boundaries are coincident (red line). USGS image

The East Venezuela Basin

The East Venezuela Basin is a foreland basin south of a fold belt (fig. 2). The progressive

west-to-east collision of the Caribbean plate with the passive margin of northern South

America in the Paleogene and Neogene formed a thrust belt and foreland basin that together

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composes the East Venezuela Basin Province. Thrust faults associated with the fold belt

caused lithospheric loading and basin formation, and the resulting burial placed Cretaceous

and possibly older petroleum source rocks into the thermal window for the generation of oil.

The oil migrated up dip from the deeper basin to the shallow southern basin platform,

forming the Orinoco Oil Belt. The oil is considered to be concentrated along a fore bulge that

formed south of the foreland basin.

Figure 2. Schematic structural cross section of the East Venezuela Basin showing the updip position of the Orinoco Oil Belt relative to the deeper part of the East Venezuela Basin. Oil generated from thermally mature Cretaceous and possibly older source rocks in the deeper part of the basin migrated updip to form the accumulation in the Orinoco Oil Belt (after Jacome and others, 2003). USGS image

The Miocene Oficina Formation

The heavy oil in the Orinoco Oil Belt AU is largely contained within fluvial, near shore marine,

and tidal sandstone reservoirs of the Miocene Oficina Formation. The reservoir sandstones,

although porous and permeable, are characterized by several depositional sequences with

considerable internal fluid-flow heterogeneity caused by juxtaposition of different facies and

by shale barriers that reduce recovery efficiency. Sandstone reservoirs range in depth from

150 to 1,400 meters, and they contain heavy oil with a range of gravities from 4 to 16

degrees API. Viscosities are generally low, ranging from 2,000 to 8,000 centipoises.

Oil Resource Assessment Methods

In addition to the standard USGS methodology for assessing continuous oil accumulations

such as those in the Orinoco Oil Belt, we used reservoir data, petrophysical data, oil-in-place

estimates, and recovery factors taken from studies of the Orinoco Oil Belt to develop five

other approaches for estimating recoverable resources and to adequately represent the

geologic and engineering uncertainty in the assessment. Key data used in the assessment

are summarized in table 2. The estimates of volumes of recoverable oil and associated gas

reported here reflect the distribution of mean estimates obtained by the six methodologies

applied to the Orinoco Oil Belt AU (table 3).

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Table 1:Faja Orinico Belt Data (source:Petroleum Society)

Geology Units FAJA OOIP developed 10

6 bbls 100000 +

Depth m. 450-650

BHSP MPa 4.5-6.5

BHST C 60

Avg. Porosity % 31%

Sw % 14%

Permeability D 5-15

Thickness of each sand body ft 20-80

k.h / ft.md / cp 40 - 1000

Fluids 0 API 8—10

Viscosity @ Pr and Tr c P 1000-5000

R s Scf / bbl 50 - 80

Production rates

Spacing vertical wells Mt ?

Vertical wells conventional rates bopd/sand 20-250

Wells rates bopd 1000-2000 (Horzn)

Recovery

Primary recovery factor % 8-12 (Horzn)

Ultimate % ?

Minimum Median Maximum

Orinoco oil-in-place (BBO) 900 1,300 1,400

Recovery factor (%) 15 45 70

Net oil-saturated sandstone thickness (ft) 1 150 350

Porosity (%) 20 25 38

Water saturation (%) 10 20 25

Formation volume factor 1.05 1.06 1.08

Gas/oil ratio (scf/bbl) 80 110 600

Table 2. Key input data for assessment of Orinoco Oil Belt Assessment Unit.

Oil (BBO)

F95 F50 F5 Mean

380 512 652 513

Gas (TCFG)

F95 F50 F5 Mean

53 122 262 135

NGL (BBNGL)

F95 F50 F5 Mean

0 0 0 0

Table 3. Orinoco Oil Belt Assessment Unit assessment results. [BBO, billion barrels of oil; TCFG, trillion cubic feet

of gas; NGL, natural gas liquids; BBNGL, billion barrels natural gas liquids. Results shown are fully risked estimates. F95 represents a 95 percent chance of at least the amount tabulated. Other fractiles are defined similarly]

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Permeabilities and kh/α Values

The Venezuelan reservoirs range from 2 to 15 Darcy in permeability based on back-

calculations from tests on wells in the northern part of the Faja,, and most of the Heavy Oil Belt

reservoirs are from 1 to 3 Darcy average permeability. Samples of Faja sand that were medium

grained (D50 ~ 250αm) and quite free of clay gave permeability values of less than 10 D.

Venezuelan reservoirs in the Faja del Orinoco are of substantially higher quality than Canadian

heavy oil reservoirs: they have higher permeability, slightly higher porosity and oil saturation,

slightly higher formation compressibility, higher average gas contents, lower clay content.The

mobility of the oil in the Venezuelan deposits appears to be from 2 to 3 times more than in the

Canadian heavy oil deposits. The individual beds in the Venezuelan reservoirs of the Faja del

Orinoco have productivity potentials that are on the order of several times to ten times those in

Canada. In units of ft-mD/cP (commonly used in Venezuela), Canadian Heavy Oil Belt

reservoirs typically have values of 14-140, whereas the beds in the Faja have values on the

order of 40-1000. Clearly, the production potential of the Faja reservoirs is far greater than the

Canadian reservoirs.

It is anticipated that there is an active foamy oil drive mechanism in these Faja wells, and that

this provides an additional component of well productivity. These effects include the presence

of a strongly negative skin zone developing because of some sand production, and the

consequences of a strong foamy drive because of the dissolved gas.

Rising Production

Venezuela and Canada together account for 95% of the global output of extra-heavy oils and oil

sands (2.2 -2.8 million barrels per day in 2008-2012, two-thirds of which are in Canada and

one-third in Venezuela; Source: U.S E.I.A).

Although less than 1% of these resources are produced or under active development

today, output should nearly quadruple, reaching at least 7 or 8 Mb/d by 2030. The increasing

prevalence of extra-heavy oils in the global energy mix is inevitable. It also presents significant

challenges.

Limiting Environmental Impacts

The processes involved in extracting and up- grading these oils requires huge quantities of

energy and water. For this reason, developing them sustainably on a large scale poses major

economic, environmental and technological challenges. Improvements focus on driving down

technical costs; enhancing recovery factors and energy efficiency; curbing CO2 emissions and

limiting water consumption and the footprint of these huge developments.

There is no question that the complexity of these challenges is of another order of magnitude

compared to conventional oil developments. Backed by Engineering and Research &

Development of technological front can steer the skills and innovative capacities to develop

these promising resources responsibly.

Exploration and production

Energy Information Administration (EIA),U.S estimates that the Venezuela produced around

2.47 million bbl/d of oil in 2011. Crude oil represented 2.24 million bbl/d of this total, with

condensates and natural gas liquids (NGLs) accounting for the remaining production. Estimates

of Venezuelan production vary from source to source, partly due to measurement methodology.

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For instance, some analysts directly count the extra-heavy oil produced in Venezuela's Orinoco

Belt as part of Venezuela's crude oil production. Others (including EIA) count it as upgraded

syncrude, whose volume is about 10 percent lower than that of the original extra-heavy

feedstock.

Venezuela's conventional crude oil is heavy and sour by international standards. As a result,

much of Venezuela's oil production must go to specialized domestic and international refineries.

The country's most prolific production area is the Maracaibo basin, which contains slightly less

than half of Venezuela's oil production. Many of Venezuela's fields are very mature, requiring

heavy investment to maintain current capacity. Industry analyst estimate that PdVSA must

spend some $3 billion each year just to maintain production levels at existing fields, given

decline rates of at least 25 percent.

Orinoco heavy oil belt Venezuela contains billions of barrels in extra-heavy crude oil and

bitumen deposits, most of which are situated in the Orinoco Belt in central Venezuela.

According to a study released by the U.S. Geological Survey, the mean estimate of recoverable

oil resources from the Orinoco Belt is 513 billion barrels of crude oil. PdVSA began the 'Magna

Reserva' project in 2005, which involved dividing the Orinoco region into four areas and further

divided into 28 blocks and quantifying the reserves in place. This initiative resulted in the

upgrading of Venezuelan reserve estimates by more than 100 billion barrels. Following figures

depict the facts:

Production Comparison of Oil major countries

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“Venezuela has one of the highest Reserves-to-Production (R/P) ratios making it one of

the most sought after countries for E&P activities”…….

Venezuela plans to develop further the Orinoco Belt oil resources in the coming years. In 2009

Venezuela signed bilateral agreements for the development of four major blocks in the Junin

area. Last year the country awarded two more major development licenses in the Carabobo

region. The Carabobo Area is located within the onshore Orinoco Belt of Eastern Venezuela.

The Orinoco Belt covers a huge area of approximately 55,000 km2 and is reported to contain

over 1 trillion barrels of extra heavy (7.5 to 8.5 0API) crude oil in place with an estimated 235

billion barrels recoverable. Carabobo belt is considered to be one of the most prolific areas in

the belt with certified reserves of 32 billion barrels. The Carabobo area is currently producing

362,000 barrels per day. Within the Carabobo Area, there are 5 undeveloped blocks referred to

as Carabobo 1 through 5 and three developed blocks called Petromonagas, Cerro Negro and

Petro Sinovensa. Venezuela expects these projects to add more than 2,000,000 bbl/d of heavy

oil production capacity by the end of the decade (see table).Blocks in Ayacucho & Boyaca in

Faja Orinoco Belt are also in the offing for production of EHCO.

Venezuelan projects are being developed by long horizontal wells with multilaterals, placed in

the optimum zones (highest kh/α). This is feasible because of the excellent reservoir conditions

and because it is now technically possible to place wells in the best zones for their entire

length. Such wells are expected to produce as much as 2000 bbl/d initially, and should keep

producing for many years, expected to gradually decline to in 5-7 years. Operating expenses

for these wells are less but the great majority of the costs are in the development of the wells,

surface facilities and transportation, and upgrading of the viscous oil.

However, on average only 40-65% (depending on the site) of the oil-bearing strata in the Faja

are suitable for development using this technique. Other beds are too thin, have too low kh/α

values, have unfavorable kv/kh ratios because of clay laminations.

Existing and Under Development Orinoco Belt projects

Grouping Project Projected

start up date

Planned production

of EHCO(bbl/D)

Partners

ACTIVE PROJECTS

Petroanzoategui

(Petrozuata)

1998 107,000 PdVSA(100%)

Petromonagas 1999 104,730 PdVSA (83.34%),BP* (16.66%)

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(Cerro Negro)

Petrocedeno (Sincor) 2000 144,000 PdVSA (60%), Total (30.3%), Statoil (9.7%)

Petropiar (Hamaca) 2001 131,100 PdVSA (70%), Chevron (30%)

U

N

D

E

R

D

E

V

L

M

T

Petromarcarco 2012 200,000 PDVSA (60%),Petro-Vietnam(40%)

PetroSinovensa 2012 400,000 PDVSA (60%), CNPC (40%)

Petrojunin 2013 240,000 PDVSA (60%), ENI (40%)

Petromiranda 2014 450,000 PDVSA (60%),Russian Comp (40%)

PetroCarabobo-1 2013

400,000 PDVSA (60%), Indian Comp (18%),

Petronas(11%)**,Repsol YPF (11%)

Petroindependencia

Carabobo-3

2013 400,000 PDVSA (60%), Chevron(34%), Japanese Consortium (5%),

Suelopetrol (1%)

Petrobicentanario 2022 350,000 PDVSA (60%), ENI (40%)

OVL & RELIANCE of India have signed MoU/intent in Oct 2013 to acquire more blocks in Ayacucho 3 & 8 respectively.

*BP sold shares to TNK-BP

**Petronas had quit the project in July 2013; Sources: PdVSA, Global Insight, Wood Mackenzie

Heavy/Extra Heavy Oil Production Methodology: Usually in the field technology of production of Heavy/Extra heavy oil following processes are

adopted depending upon crude characteristics and depth of field/mines for oil sand

(bitumen),they are:

CHOPS:Cold Heavy Oil Production with Sands

CSS :Cyclic Steam Stimulation

SAGD :Steam Assisted Gravity Drainage

THAI :Toe to Heel Air Injection

VAPEX :Vapor Extraction

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RECOVERY PROCESSES

NON-THERMAL PRIMARY THERMAL

COLD PRODUCTION CHOPS

STEAM BASED CSS

FLOODING SAGD

COMBUSTION FIRE-FLOODING THAI

WATER FLOODING CHEMICAL FLOODING VAPEX

Steam Based Thermal Recovery Processes are most extensively used

CHOPS:Cold Heavy Oil Production with Sands CSS:Cyclic Steam Stimulation SAGD:Steam Assisted Gravity Drainage THAI:Toe to Heel Air Injection VAPEX:Vapor Extraction

HEAVY OIL RECOVERY PROCESSES DILUENT SUPPLY FOR PRIMARY

Source: www.HeavyOilinfo.com

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Single well operation • Injection/production cycle: - Steam injection -Shut-in (soak)- Oil production • Recovery factor (RF) ~15%

OOIP (original oil-in- Place)

CYCLIC STEAM STIMULATION (CSS)

Source: www.HeavyOilinfo.com

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Multi-well operation in regular pattern • Inject steam into one or more wells • Drive oil to separate producers • Recovery factor (RF)~ 50% OOIP

STEAM FLOODING

Source: www.HeavyOilinfo.com

Steam Assisted Gravity Drainage (SAGD)

Horizontal well pair near bottom of pay of - Upper steam injector - Lower oil producer • Steam chamber rises upward,then, spreads sideway • Oil drains downward to drains of producer • Recovery factor (RF) > 50% OOIP

Source: www.HeavyOilinfo.com

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Steam- Based Thermal Recovery Processes

Very energy intensive and inefficient

Thermal Efficiency for Each Stage:

Steam Generator (75-85%)

Well to Reservoir (80-95%)

Flow in Reservoir (25-75%)

Final Efficiency: 11-58%

Significant environmental impacts - Land: Surface footprint - Air : Greenhouse gas (GHG) emission - Water: Water usage and disposal

Source: Butler, "GravDrain's Blackbook", (1998)

Green House Gas Emission

GHG emission from steam generation at 250°C - Burning natural gas (CO2 emission = 0.532 tonne/Mscf)

0

20

60

100

160

CO2 Emission(Kg)/Oil Recovery(bbl)

158.1

131.8

105.4

79.1

52.7

26.4

CSS & Steamflooding

SAGD

1 2 3 4 5 6

Steam-Oil Ratio(SOR)

Reduced GHG Emission

Improved SOR

Environmental Canada Data

Source: www.HeavyOilinfo.com

Transmission to Well (75-95%)

Steam Generator (75-85%)

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CHOPS is attractive for the lower permeability and finer-grained zones that generally make

up from 20 to 60% of the sequence of oil-saturated beds in the sequence of stacked Faja

reservoirs.

SAGD (and VAPEX) use horizontal wells, and the current Faja exploitation method involves

1500 m long mother wells, developed with a slotted liner.

There are two options: Drill a vertically offset well (above or below the mother well) within 5

m and use double-well SAGD, or attempt to initiate single-well SAGD. It is believed that the

latter is an attractive option to attempt first, and is likely to succeed if properly implemented.

DEVELOPING PROJECTS AT CARABOBO

In the Orinoco Oil Belt, situated in the central area of Venezuela in the states of Monagas, Anzoátegui and Guárico, the Carabobo area is located on the east side of the Orinoco Oil

Belt. Carabobo is one of four production areas in the belt and is in the early stages of

development. The other three areas are Junín, Boyacá, and Ayacucho. The Carabobo

area covers approximately 1,200 square kilometers and extends through the States of

Anzoátegui and Monagas.

6

2

1

3

5

4

6

5

4

3

2

1

0

Water Usage & Disposal Water usage for steam generation

Water Usage (bbl) / Oil Recovery (bbl)

CSS & Steamflooding

SAGD

Reduced Water Usage

Steam-Oil Ratio(SOR)

Improved SOR 1 2 3 4 5 6

Source: www.HeavyOilinfo.com

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Carabobo1 Project, Petrocarabobo comprises the Carabobo1 North and Carabobo1

Central Blocks; Petroindependencia the other project is comprised of three blocks: 5, 2S

and 3N located in the Eastern region of Petroliferous Faja of the Orinoco. The

Petroindependencia production facilities will be located to the south of the

Petrocarabobo, Petromonagas, and Petro Sinovensa facilities and north of the Orinoco

River. The Upgrader will be located at Falconero and the export terminal at Araya.

These twin projects are being developed in identical fashion and just the mirror image with

projected plateau production of 400,000 bopd.

SPECIFICATIONS OF PRODUCT STREAMS: AREA CARABOBO

1.Extra Heavy Crude Oil (EHCO) Specification:

PROPERTIES EHCO(Note1) TYPICAL(Note2) UNITS

API Gravity 8.5 +/- 1o

0 API

Specific Gravity @ 60°F 1.0064 Molecular Weight UOP K Factor 11.33 Kinematic Viscosity @ 100°F 73,000 cST Kinematic Viscosity @ 120°F 19,000 cST Sulfur 3.9 Wt% Mercaptans 25 ppmw Basic Sediment and Water BS&W 1.0% (max) 9 Vol % Salt Content as NaCl 17,200 ppmw Inorganic Chlorides ppmw Nickel 79 ppmw Aluminum ppmw Vanadium 434 ppmw Iron ppmw Nitrogen 6420 ppmw Sodium ppmw H2S ppmw Acid Number 3.12 mg KOH/g Back Blended Acid 2.06 mg KOH/g Asphaltenes (C7) 13.3 %wt Paraffin's Content %wt Conradson Carbon Residue 18.5 %wt Reid Vapor Pressure psi Flash Point

oF

Pour Point 84.1 oF

Source: Notes: 1. Chevron Hamaca EHCO analysis. Viscosity per PDVSA

Reservoir Fluids Study Cerro Negro CH-26 & PVTs. 2. Schlumberger Fluid Analysis Well Head Sample Well CIS-1-0 Morichal Zone 0-12

for Sinovensa

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The Diluted Crude Oil (DCO),17°API is obtained by the mixture of 200,000 BOPD of Extra

Heavy Crude Oil with Mesa-28/30 or Naphtha Diluent of 47° API during Early Production

stage as per Master Development Plan of field. DCO must meet the specifications shown

below:

Diluted Crude Oil (DCO) Properties of Early Production:

PROPERTIES DCO DCO

Diluent Mesa 28/30 Naphtha

DCO Gravity,0API

Sp.Gavity@ 60 0F

16.0 0.9604

17.3 0.951

Diluent Gravity, 0

API Diluent Flow,MBPD

28/30 51

47 84

XHO Flow,MBPD 50 200

Kinematic Viscicity@104 0F,cST 125(187) 298

Kinematic Viscicity@122 0F,cST 73(103) 147

Kinematic Viscicity@210 0F,cST 30 21

Diluted Crude Oil Specification:

PROPERTIES VALUE

0API Gravity, at 15

0C 17

Molecular Weight 467

Density at 161 0C, Kg/m

3 852

Viscosity at 161 0C,cST 3.2

Viscosity at 100 0C,cST 12.9

Sulfur,%wt 3.25

Nitrogen,wt ppm 5364

BSW, vol% 2%

Flash Point, 0F 78

Pour Point, 0F 10

Nickel,ppm 62

Vanadium,ppm 280

Asphaltene(C7),wt% 8.6

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3. UPGRADED CRUDE OIL (UCO):SYN Crude Specification:

UPGRADED CRUDE OIL PROPERTIES:

UCO (SYN Crude) produced in the Upgrader must meet the properties given in the following table:

PROPERTIES

VALUE

UNITS

Gravity 32-34 0 API

Sp. Gravity@60oF 0.864-0.853

Molecular Weight 207

RVP ≤ 0.5 BAR A

TOTAL SULFUR ≤740/0.07% Wt ppm/ wt/wt

H2S ≤ 1 Wt ppm

Source: MPC-460-FP147001 Basis of Design Tank Farm-Unit 60. Rev. E

Note : Values at normal operation

Properties Value Normal

Operation

NHDT

Unit Upset

DHDT Unit

Shut-Down

MHT Unit

Shut-Down

Flow rate t/h 986.118 493.490 992.770 1001.078 Gravity

0API 32.0 32.0 29.5 27.7

Sulphur wt% <0.1 <0.1 <1.3 <1.6 Bromine Number <0.2 <0.2 <5.1 <1.3 Viscosity @ 38°C cSt 6.41 6.49 7.44 8.63 Viscosity @ 100°C cSt 1.66 1.68 1.79 2.37 RVP bara <0.5 <0.50 <0.5 <0.5 Total nitrogen wt ppm <401 <393 <1097 <2045 Water (H2O) Vol% <0.5 <0.5 <0.5 <0.5 Aromatics Wt% 37.49 37.41 41.69 48.78

H2S wt ppm

<1 <1 <1 <1

C1 wt% 0 0 0 0

C2 wt% 0.005 .005 0.005 0.005

C3 wt% 0.409 0.315 0.375 0.361

C4 wt% 1.362 1.194 1.247 1.203

C5+ wt% 97.732 97.997 98.186 98.131

NHDT:Naphtha Hydrotreater,DHDT: Heavy Distillate Hydrotreater,MHT:Middle distillate Hydrotreater Source: MPC-200-FPC01001 Basic and FEED Petrocarabobo Upgrader Falconero, Anzoategui State,

Venezuela. General Project Information Process Databook Axens Rev 2

22

A DEVELOPMENTAL CASE:

Pushing The Envelope of Cold Recovery Technology: PETROCEDENO PROJECT---TOTAL (47%), PDVSA(38%),STAT-OIL(15%)

It was in Venezuela that TOTAL first tackled the challenge of extracting extra-heavy oils on a

very large scale using "conventional" production techniques. With the Petrocedeño (formerly

Sincor) project, the Group is showcasing its integrated expertise – spanning downhole

technologies, surface facilities and everything in between. This project sets a global

benchmark for the cold recovery of extra-heavy oil.

The Dimensions of a Venezuelan Challenge

December 2000 marked the start of production on Sincor, the huge extra-heavy oil

development in Venezuela. As the most ambitious venture in the Orinoco Belt, the project

has become a global benchmark for the cold recovery of these unconventional oils.

For Total, as operator of Sincor (renamed Petrocedeño in 2008 upon its nationalization),

this was the first experience with large-scale production of extra-heavy oils. The Group‘s

strategy was to optimize the envelope of "existing" cold recovery technologies.

This feat could not have been achieved without drawing on the full range of cutting-edge

expertise from the Exploration & Production segment, from the bottom of the reservoir to

the surface facilities. And the challenges were enormous indeed: extraction by natural

depletion of oil with a viscosity in place of 1,500 to 4,000 cP, from a shallow reservoir,

meaning low initial pressure (40 to 45 bar), in addition to a low reservoir temperature

(about 50° C).

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Mastering Complex Geology

The Miocene La Oficina formation in the Orinoco Belt is a complex and heterogeneous

environment. Its reservoirs of unconsolidated sand were formed by the deposition of

fluvial and marine sediments with different petrophysical characteristics. Zones of relatively

fine sand are juxtaposed irregularly with shale barriers. Some sections of the reservoir are

fractured.

There were huge technological challenges involved in developing such reservoirs using a

strategy of intensive horizontal drilling. Advanced technologies (including high-resolution

3D seismic, integrated management of vast amounts of data yielded by core analyses, logs,

and well tests) benefited from the close integration of geoscientific expertise to keep

geologic uncertainties to a minimum.

Understanding the recovery mechanisms at play in the reservoirs helps reduce uncertainties.

Meanwhile, studying the recovery mechanisms at play in these reservoirs has helped to

enhance the reliability of recovery factor predictions. Total relies on the state-of-the-art

instruments of its geology, petrophysics and rock mechanics laboratories to perform these

investigations.

TECHNOLOGY FOCUS: FOAMING OILS

As reservoir pressure declines with production, the gas initially dissolved in the oil comes out

of solution. In the case of extra-heavy oils, the viscosity of the oil prevents the liberated gas

from migrating to the top of the reservoir. Instead, it remains trapped in the oil in the form of

minuscule bubbles (size of the order of a micron). Foaming oil is the result of this intimate

mixture of oil and gas, and it facilitates recovery.

A STRING OF TECHNOLOGICAL FIRSTS

The economically viable production of the extra-heavy oils of the Petrocedeño project was

made possible by the deployment of numerous technological innovations.

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Drilling trajectories of 1,400-metre-long horizontal drains were optimized in real time by

using a satellite link between the drilling rigs and the offices in Caracas – a first in

Venezuela. Tracking the progress of well trajectories in real time on 3D seismic

images improved the positioning of the drains along the sand layers, which were sometimes

of very limited thickness.

Diluent injections into the bottom of the drain, another first, significantly decreased head

loss along the drains, translating to higher well productivity.

Petrocedeño advanced the use of Progressive Cavity Pumps (PCPs) in the Orinoco Belt. In

Venezuela, Total decided to use PCPs, a technology initially reserved for the production of

Canadian oil sands, rather than the more conventional Electrical Submersible Pumps

(ESPs), to ensure better control during the start-up of the wells.

Total made Petrocedeño the leading user of Multi-Phase Pumps (MPPs) to stimulate the

flow of crude at the wellhead. In addition to the savings on surface equipment, this option

affords the advantage of adapting to variations in the flow, temperature and pressure

of the production over the life of the field.

Innovative monitoring was developed to optimize production management over the long

term. Head loss sensors were installed along the drains, which are also fitted with

fiber-optic detection and control of water ingress.

Understanding the recovery mechanisms at play in the reservoirs helps reduce uncertainties

PRODUCTION SYSTEM-ARTIFICIAL LIFT: PROGRESSIVE CAVITY PUMPS (PCP)-Applications Heavy oil and bitumen applications are commonly defined in the

industry as those producing oil with an API gravity less than 20°.

These conditions are common in Canada, Russia, Venezuela and

China. Problems associated with heavy oil and bitumen are high

viscosity, high flow losses, low to moderate flow rates, high sand

cuts and rod string/tubing wear. Directional and horizontal wells are

often used to ensure viable development of the reservoir. PC

pumps are attractive in these conditions due to their ability to

handle viscous, abrasive, multiphase fluids

Progressing cavity pumps are positive displacement pumps

which consist of a helical steel rotor and a synthetic elastomer

stator that is bonded to a steel tube. Rotation of the rotor within the

fixed stator causes a series of sealed cavities to form and move

axially from the pump suction to discharge. The resulting pumping

action increases the pressure of fluid passing through the pump so

that it can be produced to surface. Numerous papers describing PC

pump principles and theory have been presented elsewhere.

Most PC pumping systems are rod driven with the stator run into

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the well on the bottom of the production tubing and the rotor connected to the bottom of the

rod string.

Advantages & Disadvantages

PC pumping systems have some unique characteristics that make them advantageous when

compared to other artificial lift systems. One of the most important characteristics is their

high efficiencies of 55 to 75%. Some additional advantages of PC pumping systems

include:

Ability to produce high viscosity fluids

Ability to produce large concentrations of sand

Ability to tolerate high percentages of free gas

No valves or reciprocating parts to clog, gas lock or wear

Good resistance to abrasion

Low internal shear rates (limits fluid emulsification)

Low capital and operating costs

PC pumping systems also have several disadvantages. The most prominent of these are

limitations with respect to pump capacity, lift and elastomer compatibility with high aromatic

fluids. Some additional disadvantages of PC pumping systems include:

Limited production rates (max 500 m3/day or 3150 bbls/day)

Limited lift (maximum of 3000 m or 9840 ft.)

Limited temperature capability (maximum of 180°C or 350°F)

Sensitivity to fluid environment

Low volumetric efficiency when producing large amounts of gas

Rod/tubing wear in some directional and horizontal wells

Low capital and operating costs

These limitations are rapidly being overcome with the development of new products and

improvements in materials and equipment design.

New Developments

Metal-to-Metal Pumps

Metal stators were considered years ago, but

only recently have newer manufacturing

techniques and the application of metal-to-metal

PCPs in thermal heavy oil and bitumen recovery

applications, such as steam assisted gravity

drainage (SAGD) and cyclic steam stimulation

(CSS), brought this technology to the forefront.

A metal stator does not have many of the

shortcomings of elastomeric stators--specifically

fluid interactions and temperature limitations.

Metal stators may therefore be used in thermal applications (e.g. 160-350 0C), or

applications with highly reactive fluids. Potential problems which are actively being resolved

by metal-to-metal PCP vendors include vibration and seal ability with low viscosity fluids, the

26

latter due to the fact that metal-to-metal PCPs have a gap between the rotor and stator and

not an interference fit, as normally exists with an elastomeric stator.

Source:SPE(Joslyn Field,McMurray,Canada)

High Temperature Elastomers

One of the major limitations of elastomeric stators is the temperature. At high temperatures

and over time, most elastomers, including the nitriles typically used in PCPs, become hard

and brittle and may not form a seal with the rotor. In these conditions, pumps can fail very

quickly. High temperatures can be caused by the external conditions in the well (from depth,

or from thermal operations), or from internal friction between the rotor and stator in the

absence of sufficient cooling. Fluorocarbon elastomers can operate at higher temperatures

than nitriles, but at the cost of inferior mechanical properties. Research is ongoing into ways

of improving elastomer formulations for PC pumps so that continued operation at higher

temperatures is possible.

Fluidizing Sand

PC pumps are capable of producing large quantities of sand, when the sand flows into the

well on a continuous basis. Sand is known to enter the wellbore in slugs, however, and these

slugs can overwhelm the pumps' capabilities of producing solids, particularly in applications

where sand control is not employed (eg. in producing viscous heavy oil from unconsolidated

sandstone reservoirs). Various methods of "fluidizing" sand to ensure that it can be produced

through the pump have been used, and others are in development. Some methods are: the

addition of a "paddle" rotor extending below the intake to continually agitate the fluid entering

HORIZONTAL WELL COMPLETION OF WORLD’S 1st. (METAL TO METAL) PROGRESSIVE CAVITY PUMPS FOR SAGD PROCESS AT JOSLYN FIELD

27

the pump; a hollow rotor feeding a small portion of produced fluid from the pump discharge

to a jet located at the intake; and a fluidizer pump, where a large displacement-low pressure

pump is installed below the main pump with holes in the tubing joint between the two so that

an excess amount of fluid continually circulates in the annulus of the well and through the

pump intake.

High Speed Pumps

Currently most PCPs are run at

speeds below 500 RPM - with

viscous oils, the limit is normally

even much lower. To produce

larger volumes without exceeding

these speed limits, higher

displacement pumps are needed. Higher displacement pumps are larger in diameter and/or

length, have higher torque requirements, and normally result in increased axial load in the

rod string. Being able to run smaller pumps at higher speeds (i.e. in excess of 500 RPM)

reduces these loading effects, and also opens up "insert able" pumps (where the rotor and

stator are run together on the rod string) to a larger range of applications.

Failure Analysis

Failure analysis is often defined as the process of collecting and analyzing data to determine

the cause of a failure and how to prevent it from recurring .For PCP systems, failure analysis

is the process of identifying the root cause of a PCP system failure and using the results to

identify strategies to increase the PCP system run-life. A PCP system has failed if any of its

components are no longer able to perform the required function. The failure cause is defined

as the circumstances during design, manufacturing or use which led to a failure.

Failure analysis is among the most important means of improving the performance of a PCP

system.

There are three main areas of failure analysis:

failure identification, root causes analysis and selection of remedial actions,

failure tracking and benchmarking.

Failure Description and Identification

It is important that failures are described and classified in a consistent manner so that similar failures can be properly grouped and analyzed.

Stator Failures (Fatigue, Wear, Fluid Incompatibility, ...)

Rotor Failures (Wear, Heat Cracking, Fatigue ...)

Rod String Failure Mechanisms (Fatigue, Excessive Torque...)

Tubing String Failures (Wear, Corrosion)

Failure Symptoms, Root Causes and Remedial Actions

The main process of a failure analysis is to identify symptoms of a failure (no fluid flow, high

torque) that could indicate a system failure. Once a system failure has been identified, it is

28

important to understand what caused the failure. By asking the question 'why' multiple times,

the root cause of the failure can be identified. Only by understanding the root cause can

successful remedial actions be taken to prevent a similar system failure from recurring.

Failure Tracking and Benchmarking

The goal of benchmarking is to improve system performance and to reduce costs.

Benchmarking is a continuous process of measuring and evaluating progress over time to

ensure decisions are made based on facts rather than opinion. Failure tracking is used to

compile and store data upon which benchmarking can be performed. Failure tracking

ensures the collection of quality data that reflects the system as a whole.

REFERENCES:

1.Society of Petroleum Engineers

2.U.S Energy Information Administration

3.Oil & Gas Journal

4. PdVSA, Global Insight, Wood Mackenzie

5.Petroleum Society, Canadian Institute of mining, metallurgy & Petroleum

6.U.S Geological Survey(U.S.G.S)

7.Latin America News Digest

8.PdVSA

9. TOTAL

10.World Oil

11. Worldwide Projects

12. Wood MacKenzi

13.Heavy Oil Wikipedia

14.Chevron/Schlumberger/Baker Huges

.