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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 cP 1000-5000
Rs 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-THERMALPRIMARY 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 o
F
Pour Point 84.1 o
F
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,
0
API
Sp.Gavity@ 60
0
F
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
0
F,cST 125(187) 298
Kinematic Viscicity@122
0
F,cST 73(103) 147
Kinematic Viscicity@210
0
F,cST 30 21
Diluted Crude Oil Specification:
PROPERTIES VALUE
0
API Gravity, at 15
0
C 17
Molecular Weight 467
Density at 161
0
C, Kg/m
3
852
Viscosity at 161
0
C,cST 3.2
Viscosity at 100
0
C,cST 12.9
Sulfur,%wt 3.25
Nitrogen,wt ppm 5364
BSW, vol% 2%
Flash Point,
0
F 78
Pour Point,
0
F 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
0
API 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

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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 0
C), 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

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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

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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

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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
.