1. Abstract
A critical technology team was assembled with
the goal to develop and massify complex well
architecture, often referred to by the limiting term
“multilateral wells”, in Venezuela. Professionals of
different disciplines were involved during the screening
process to select reservoirs with appropriate geological,
reservoir and production characteristics for the
construction of multilateral wells. The first step was to
review earlier multilateral wells in PDVSA expressly to
identify the reason of the thus far marginal success of
these wells and to research possible candidate reservoirs
in the exploitation units of eastern and western
Venezuela. For this screening several reservoirs were
analyzed with specific production problems where the
development of multilateral technology would be
compelling. Because of the enormous number of
reservoirs in Venezuela, the research was focused on
reservoirs with short-term, high-economic potential
interest in the application of new technologies. A second
focus was the consideration of reservoirs where
multilateral wells have already been drilled or where
(single) horizontal technology has been used widely. This
work suggests that the spectrum of Venezuelan reservoirs
where multilateral technology could be attractive is very
wide, encompassing very different geologies and
production and reservoir aspects.
A major element of this work is the inclusion of
real-time field data for the permanent history matching of
reservoir properties. A novel technique, using state-of-
the-art downhole sensors and surface equipment sensors
has been implemented to automatically incorporate new
field data to the reservoir simulation model. These real-
time monitoring data were networked to project
databases. Incremental reservoir simulation is properly
triggered as new data are collected, indicating the error
between predicted and real data. This technique allows
integrated teams to easily and continuously update
reservoir models. Better reservoir characterization can be
performed as new data arrive. Fine-tuning is possible
since continuous improvement is carried out to
characterize local heterogeneities and flow barriers. It also
allows for better identification of flow units and, thus,
improving recovery. As a result of this multidisciplinary
approach, technical and economic decisions can be
readily facilitated in developing multilateral well
technology in Venezuela at a massive scale.
Introduction
A review of the exploitation plans of Venezuelan
reservoirs allows the identification of potential areas with
production problems or opportunities for which the
implementation of multilateral technology is likely to be
beneficial. The reservoirs belong to the four most prolific
areas of Venezuela: Maracaibo Basin, Apure-Barinas
Basin, Eastern Basin and the Orinoco Belt (Figure 1).
Multilateral technology and appropriate stimulation
methods combined with stress field studies will increase
well productivity in naturally fractured carbonate
reservoirs in the Maracaibo and Apure-Barinas Basins.
PDVSA is now undergoing a change precipitated
by last year’s catastrophic low oil prices and production
cuts. The drilling organization has shepherded project-
oriented well construction teams, that are composed of
professionals belonging to one of eight knowledge
communities (well-planning, well-design, fluids,
cementing, trajectory and geomechanics, workover and
completion, operations and business strategies). These
knowledge communities have helped the company to
understand the current situation and to focus on highly
MULTILATERAL WELLS: EXPERIENCE AND FUTURE DEVELOPMENTS IN
VENEZUELA BY PDVSA
Ana Maria Hernandez, PDVSA-INTEVEP; Juan Carlos Barrios, PDVSA-INTEVEP; Luigi Saputelli, PDVSA E&P; and
Michael J. Economides, University of Houston.
Presented at the 11th
International Conference on Horizontal Technology, Houston, November 15-17, 1999

2. productive initiatives. The same communities are also
responsible for new well design and sizing and novel
technology applications to reduce well cost and to
increase the asset life cycle. New technologies include
complex wells, expandable tubulars, casing drilling and
completion practices, among others.
Multilateral technology may create step change
profitability in PDVSA´s resource base in the next
decade. To meet the declared production target of 6
million bpd within that time, more than 10,000 drainage
points must be added during the next five years.
Furthermore, the country is planning to intensify the
internal gas market, which will imply the reactivation of
one of the world’s largest gas reserve field, Santa Rosa.
Multilateral technology may substantially reduce the
number of required wellheads and mother-holes by
creating novel well architectures, potentially combined
with induced hydraulic fractures. The latter, in
conjunction with the increased reservoir accessibility are
likely to reduce the activation index by 30 to 50%. Under
these circumstances some 4,000 branches may be drilled
in the next decade from 1,000 vertical or horizontal
mother holes.
Future development and challenges are ascribed
to the highly compartmentalized, deep and fractured
reservoirs, widely prevalent in Venezuela. While current
drilling technologies are poised to overcome these
problems, other issues, such as completion, production
reservoir exploitation and, especially, good formation
characterization, need significant improvements and
quantum developments to affect substantially the overall
complex well architecture strategy.
Oriented drilling will be necessary to control
sand production in shallow reservoirs of the Maracaibo
Basin and deep reservoirs of the Eastern Basin. Shallow
reservoirs of the Barinas Basin are candidates for
multilateral wells as a solution to water coning problems.
In reservoirs under secondary recovery located in
Maracaibo and Eastern Basins, multilateral technology
will be necessary to increase the recovery factor and to
design new exploitation plans using injector/producer
combinations adapted to the geological and reservoir
features of the reservoirs. Reservoirs with rapid pressure
decline and depleted and marginal areas are common in
the Maracaibo Basin.
In layered and low-permeability reservoirs that
are common in the Eastern basin, multilateral wells are
likely to greatly increase well productivity. Because of the
recent volatility in the oil price, the search for gas and
gas-condensate reservoirs has picked up in the Anaco area
in the Eastern Basin, and multilateral technology is
expected to increase their production.
In the Orinoco belt, new technologies have been
developed recently to upgrade heavy oil, making these
reservoirs attractive. Exceptionally large reserves of
heavy oil (the resource base in the Orinoco Belt has been
estimated by many to exceed one trillion barrels, 1012
bbls, or more) point towards a very massive activity in the
area. Because the pressure of heavy crude reservoirs,
operating above the bubble point deplete quickly,
increasing the reservoir-to-well contact area is crucial.
Each of four announced projects have estimated 2,000
single horizontal wells for a total of 8,000 wells.
However, multibranched wells are considered far more
appropriate. Because of wellbore stability these wells will
probably have to be Level 4 and higher. Assuming 2.5
horizontal wells to be replaced by one multilateral well,
ultimate Orinoco Belt development may construct several
thousand higher-level multilateral wells, clearly one of the
most massive developments of this type in the world.
Improving the production rate and the ultimate reservoir
recovery requires both a better understanding of the flow
mechanisms through the reservoir and the associated
implementation of new technologies. Reservoir model
construction and the updating of the process is complex
because of the lack of proper integration of technologies
and visualization techniques. In the particular case of
multilateral wells this process is particularly cumbersome.
The vision for the exploitation unit of the future is to be a
totally automated integral unit, from the subsurface to the
client, autonomous and interdependent, with 4D
leadership (Figure 2). The exploitation unit will be able to
take advantage of environmental changes quickly, with
real-time optimization capabilities.
Emerging reservoir technologies are concerned with
data management (type, volumes) and integration,
reservoir performance monitoring (fluid flow and fluid
interfaces) and technologies to obtain real-time systems
with subsurface control through the whole chain of value
(interaction) 9
. Current reservoir technologies are not
integrated to support multi-disciplinary team
collaboration or to handle large amount of data. The
present reservoir characterization cycle is long (2 to 3
years) and usually cannot foment drilling and operational
needs for production maintenance or enhancement (Figure
3). Even when a model is barely built, it is already out-of-
date, because of the new data collection which, usually,
does not match predicted behavior. In a very mature
global resource base, more complex processes arise, such
as enhanced oil recovery projects, infill drilling, complex
well architecture and real-time data acquisition.
Technology integration is a “must” in order to cope with
such diverse knowledge.
Previous Multilateral Experience in PDVSA
In the period between 1995 and 1998 PDVSA drilled
five multilateral wells in different reservoirs around the
country (Figure 4). This previous experience with the
technology showed very marginal success and only two of
the five wells are producing now (Wells 1 and 4 of Figure
4). The first multilateral well in Venezuela, drilled in
1995, is shown schematically in Figure 5 10
. It was

3. intended to be a four-branch well in a non-consolidate
sandstone reservoir. The well collapsed and produced
sand during the drilling of the third lateral. Well 1, now
producing, (Figures 4 and 6) was drilled in a fractured
carbonate reservoir with water production problems
emerging during the completion of the lateral hole. The
well was fixed and is now producing 800 BPD from the
vertical hole, alone. Well 4 (Figures 4 and 7) was planned
as a level 3 multilateral well to substitute two very close
horizontal wells. In this case, the completion system
failed and the well started to produce sand 10
. To fix it, the
well was converted to level 5, increasing the cost and
using an unnecessary hydraulic isolation because the two
laterals were draining the same reservoir. Because of the
failure of the completion system the well is now
performing as a very expensive horizontal well.
Two other wells, drilled in non-consolidated
sandstone reservoirs (Wells 3 and 5, Figure 4), also had
problems with the junction stability.
The previous multilateral experiences in Venezuela
show that multilateral technology should be adapted to the
special conditions of Venezuelan reservoirs to avoid
expensive failures.
Screening Criteria
The search for possible reservoirs for multilateral
technology in Venezuela has yielded screening criteria for
candidate recognition. Current price of oil and the
transformation in progress in PDVSA produce a
conservative and cautious attitude to probe and develop
new technologies. Several reservoir and production
strategies, already in progress, are planning the drilling of
multilateral and, even, intelligent wells. However, there is
a tendency to postpone the decision because of budget
cuts, lack of awareness of new technologies and the
previous marginal experiences. During the screening
process several possibilities in different types of settings
were identified:
• Short-term interest from PDVSA (exploitation units
with multilateral well proposals in progress)
• A set of locations with up to-date reservoir,
production, drilling and geological data
• Existing multilateral or where multilateral wells are
planned
• Indicated massification of the horizontal technology
Geological Issues On The Future Development Of
Multilateral Technology In Venezuela
Venezuela presents several complex structural
and stratigraphic geological scenarios in the four main
prolific areas where multilateral technology could be
applied. From the lithological point of view, several
carbonate and clastic reservoir were analyzed. To-date
multilateral technology has been tested with success in
carbonate reservoirs worldwide because of the possibility
to drill less complex multilateral wells 6,7
. Thus, several
Venezuelan carbonate reservoirs were analyzed and
proposed as candidates. Production and reservoir data of
several naturally fractured carbonate reservoirs in both the
Maracaibo and the Apure-Barinas Basins were studied,
considering the importance of the knowledge of the
orientation of the main natural fractures/faults and the
possibility to combine multilateral wells with hydraulic
fracturing technology (Figure 1).
There is also an obvious application to develop
multilateral wells in other geological frameworks such as
braided and meandering sand reservoirs, mainly in
shallow unconsolidated sands and deeper consolidated
sand reservoirs, which are common in Venezuela.
Configurations such as “fishbone”, opposing laterals and
right-angle laterals are indicated.
Such well architecture will represent a challenge
for the service companies in Venezuela, where
improvement of existing multilateral technology will be
necessary to design wells adapted to the geological
features of Venezuelan clastic reservoirs.
In deeper consolidated reservoirs, mainly in the
North Monagas oil fields, re-entries have been considered
as the best option to date, so a review of wells with
mechanical problems has been undertaken. These
reservoirs are usually compartmentalized either by
faulting or sedimentation or both, and their structural
complexity and facies architecture will generate several
options for multilateral wells in deeper reservoirs
(multibranch, multilateral, spider wells at the top of the
structures3
).
However, current practices offer few drilling
possibilities in deep and high-pressure reservoirs in
constructing multilateral wells. Additional production
problems may emerge such as borehole stability, sand
production, asphaltene and paraffin deposition, high-
damage skin or tubing corrosion. These reservoirs, in
additional to operational challenges also provide
exploitation challenges4
(reservoir simulation applied to
multiple reservoirs, completion and drilling aspects in
wells with complex well architecture and injector-
producer configurations).
Consolidated shallow sands with light oil have
been considered for multilateral technology. Unswept
areas and reservoir sand pockets in fluvial shallow
reservoirs are common in Venezuela, and multibranch and
multilateral wells that will penetrate several channel sands
either at the same stratigraphic level or at different levels
are indicated.
The generation of new exploitation plans with
new technology is critical to increase the recovery factor.
In heavy oil, unconsolidated sand, reservoirs several

4. candidates were considered for the massification of the
multilateral technology either by doing multibranch wells
to compartmentalize the reservoir or to install wells for
steam-assisted gravity drainage, SAGD1,5,8,11
. We have
already mentioned that single horizontal wells are likely
not sufficient for these formations. Embarking on
multilateral wells in the Macaibo Basin and the Orinoco
Belt will create a very massive activity. Already opposing
horizontal wells, a clear precursor to multilateral
configuration have been drilled in these areas 2
.
In layered and compartmentalized reservoirs of
the fluvial-deltaic sequences of the Eastern Basin, new
exploitation plans using multilateral technology are now
planned with the goal to increase the recovery factor of
gas reservoirs. More than 700 stratigraphic compartments
are associated with these large gas reserves.
As a result of this work more than 20
Venezuelan reservoirs in the four main prolific areas have
been identified as candidates for multilateral technology.
An economic matrix of these reservoirs is now generated
with the goal to prioritize the development of the
technology in fields with technical-economic priority.
New Reservoir Technologies Collateral to Multilateral
Wells
Smart Reservoirs
The interest of real-time data acquisition leans on the
“Smart Reservoir” philosophy in which downhole assets
are fully instrumented and integrated to upper decision
systems, such as numerical reservoir simulators, desktop
project management and integrated reservoir management
environments (Figures 8 and 9).
Data and information is hence properly treated and
automatically analyzed to produce instant reservoir
strategies to control field equipment. Time-lapse
information is critical to predict the movement of fluid
fronts.
Benefits of the smart reservoir include minimum time
for analyzing reservoir data, fast troubleshooting
responses, and proactive rather than reactive resource
optimization.
We believe that with the development and availability
of new information technologies, the smart reservoir
philosophy will be the main approach to many reservoir
and field operations, minimizing cost and optimizing
resources. This practice will, for example, allow reservoir
engineers to anticipate which horizons are swept by the
displacing fluid. Proper actions on the injection profile
can be made to improve sweep efficiency.
Smart reservoir technologies also include data mining
from history databases, in which knowledge is hidden
through huge amounts and qualities of data. Real-time
data may upgrade history databases with new reservoir
information, allowing additional value creation from
existing resources.
Real-Time Data Acquisition
In the past decade the need of real-time downhole
properties has emerged. Current reservoir management
techniques do not include the systematic analysis of real-
time data and it is obvious that such data are necessary for
the optimization of operations.
Parameter measurements are given good results in the
laboratory, but temperature limitations and deployment
methods have not been very successful in field
applications.
Temperature Profile
Downhole permanent distributed temperature
monitoring is performed by deploying a specially covered
fiber cable into a ¼” coiled stainless steel tubing. The
tubing is previously attached along the production tubing
or casing.
A laser bean is sent through the fiber cable. A
computer collects its reflections, which transform light
into distributed temperature profile information.
Distributed temperature profile when compared to
resistivity logs easily indicates and correlates which pay
zones are contacted by heat.
PDVSA has recently installed two fiber optic
temperature profile systems for performance monitoring
in a pair of SAGD horizontal wells at the Tia Juana Field
in Western Venezuela (Figure 10).
Real-Time Reservoir Simulation
Current reservoir technologies overwhelm engineers with
bunches of new information. Decisions are usually taken
with the analysis of just a fraction of the available
information. Integrated reservoir studies consider most of
the field information including the use of historical data to
match reservoir properties.
Historical data (pressure, oil, water and gas
production) are usually collected monthly or weekly
throughout the field life and gathered among many other
types of data (PVT, core data) prior to a reservoir study.
Reservoir study results are finally considered to predict
future field performance. However, predicted field
profiles are not valid for the long term. When additional
data are collected (i.e. new wells, more production data),
the forecast of performance is compared with new field
data.
For diverging results, further static and dynamic
characterizations are required to match actual
performance. Nevertheless, the model update process is
complex due to a lack of proper integration technologies
and visualization techniques (Figures 2,11).

5. New Approach
Accuracy of the simulated model obviously depends on
the characteristics of the model and on the robustness and
completeness of reservoir description. It is important,
therefore, to spend some time estimating the quality of the
simulation to determine whether it is adequate for the
intended use. The best way to calibrate a model is to
constantly validate it with real field data.
This paper addresses the inclusion of permanent field
data into reservoir simulation prediction models.
Field data are collected through permanent field
instrumentation systems. The data are remotely accessed
from anywhere in the company’s network through a
specially designed web interface. The generic interface
collects data in real time.
Field data (bottom-hole and wellhead pressure, fluid
rates) are permanently compared to simulation predicted
profiles. Simple programming triggers selected time step
calculations to estimate new bottom-hole and block
pressure values for those given field flow rates (oil, water
and gas).
Per every additional time-lapsed collected data (i.e.
more production data) forecast of performance is
compared with new field data. For this, predicted field
profiles are validated for a longer reservoir life cycle and
hence, simulation models.
Diverging results indicate that the model is no longer
valid for current field conditions, and therefore, proper
static and dynamic characterization is required to match
actual scenarios. Adjustment then may include relative
permeability end-point adjustment, cell pore volume
reduction, or transmissibility reduction from one of the
near well faults.
Because of the non-uniqueness of reservoir
simulation, it may be necessary to run different case
scenarios to validate field data. It is also possible that
different models may be validated in different periods of
the life of the reservoir.
New real-time flow and pressure data do not mean
second-to-second data, or millions of values per hour.
These field measurements often occur once a week or
once a month. The idea is to keep on validating field and
simulation profiles and, at least, to make use of data that
are often collected but are, at times, ignored
Economic Evaluation of Multilateral Wells
Multilateral wells are intended to accelerate the
petroleum production rate, to increase the recovery factor
and, to minimize reservoir problems such as water and
gas coning. Consequently, any of these results will create
attractive economic expectations for developing an oil
field. However, there are several economic issues that
should be resolved prior to the demonstration that
multilateral wells will be a suitable solution. The Net
Present Value (NPV) is assumed to be the most
reasonable economic indicator to evaluate the financial
feasibility for a multilateral well project. To use NPV, it is
first required to estimate the project cash flow in terms of
well construction costs, oil production rate income and,
work-over costs for both multilateral and conventional
wells, as shown in Figure 12. A multilateral well project
to be attractive should result in a higher NPV. Also
ultimate recovery is expected to increase up to 15% and
initial investment costs decrease by as much as 40% when
building multilateral wells as re-entries in existing wells7
.
NPV calculations should consider oil production rate
uncertainties coming from reservoir simulations,
unpredictability of work-over costs, unscheduled drilling
costs due to junction failures, and geological
uncertainties. Oil production rate accuracy depends on the
well architecture. Th initial investment or well
construction costs depend on drilling technology and
geological complexity, while work-over costs depend on
reservoir hydraulic characteristics and well completion
technology. To account for these uncertainties in NPV
calculation, all risks involved during the planing, well
construction and well operation phases should be
identified, and corresponding costs should be established,
so that the NPV is risk weighted. This process is referred
to as a Quantitative Risk Analysis (QRA). Economic
expectations are more reliable when uncertainties in
geological characteristics and reservoir properties are
minimized, well productivity modeling simultaneously
takes into account reservoir properties and well
architecture effects. It is also helped if operational risks
are predictable during the well design phase and are
monitored during well construction. Multilateral well
implementation is attractive only as a “massive” approach
in the reservoir exploitation plan.
Conclusions
1. Economic attractiveness of multilateral wells can be
realized only if massive application of the technology
is undertaken.
2. Because of the earlier marginal success of
multilateral technology in Venezuela a
multidisciplinary approach is necessary to facilitate
the development of the technology.
3. Screening criteria were established to identify
reservoir candidates for multilateral technology in
Venezuela.
4. Several geological and reservoir structures will
require different applications of multilateral
technology
5. This paper presents an innovative approach for
including permanent field data into reservoir
simulator prediction models allowing a continuous

6. update to the reservoir model, so necessary for the
construction of complex wells..
SI METRIC CONVERSION FACTORS
cp. x 10* E-03 = Pa.s
ft x 3.048* E-01 = m
ft2
x 9.290 304* E-02 = m2
ft3
x 2.831 685 E-02 = m3
in. x 2.54* E-00 = cm
lbf 4.448 222 E-00 = N
md 9.869 233 E-04 = m2
psi x 6.894 757 E-00 = kPa
bbl x 5.165 E-00 = ft3
* Conversion factor is exact
Acknowledgements
The authors wish to thank PDVSA-INTEVEP for
supporting publication of this paper and the people of the
Multilateral Project Team, exploitation Units and
Technical Management for their contributions to this
work.
References
1. Boardman, D.W.:” Designing the optimal multilateral
well type for a heavy oil reservoir in Lake
Maracaibo, Venezuela” paper SPE 37554 presented
at the SPE International Thermal Operations &Heavy
Oil Symposium, Bakersfield, California, (1997). Feb.
10-12.
2. Consentino, L., Spotting,G., Gonzalez, G. E., Araujo,
Y., Herrera, J. “Cycling Steam Injection Parallel
horizontal well: Geostatistical description, thermal
simulation and field experience”. paper SPE 49017
presented at the SPE Technical Conference, New
Orleans,U.S.A. (1998). Sep. 27-30.
3. Economides, C.A.: “ Techniques for Multibranch
Well Trajectory Design in the context of a three-
Dimensional Reservoir Model" paper presented at the
SPE European 3-D Reservoir Modeling Conference,
Stavanger, Norway. (1996) . April.
4. Economides, M.J., Brand, C.W. and Frick, T.P.:
“Well configurations in Anisotropic Reservoirs,”
SPEFE , Dec. 1996, 257-262.
5. Fernandez, B., Economides, C.A., Economides, M.
J.: “Multilevel Injector/Producer wells in Thick
heavy crude reservoirs” paper SPE 53950 presented
at the VI LACPEC conference, Caracas, Venezuela
(1999), April. 21- 23.
6. Hall, S.: “ Multi-lateral horizontal wells optimizing a
5-spot Waterflood.” paper SPE 35210 presented at
the SPE Permian Basin Oil & Gas Recovery in
U.S.A. (1996) March.
7. Hall, S.: “ Multilaterals convert 5 spot to line drive
waterflood in SE Utah.” paper SPE 48869 presented
at the SPE International conference in China, Beijing
(1998). Nov.
8. Mendoza, H.A., Finol, J.J.: “SAGD, pilot test in
Venezuela” paper SPE 53687 presented at the VI
LACPEC conference, Caracas, Venezuela (1999),
April. 21- 23.
9. Saputelli, L., Ungredda, A..: “ Knowledge
Communities help to Identify best operating
practices” paper SPE 53759 presented at the VI
LACPEC conference, Caracas, Venezuela (1999) ,
April. 21- 23.
10. Tirado,J., Ferrer,J., Velasquez,A., Guimerans,R.,
Yovera,J., Gonzalez,M., Mendez, F., Sandoval, S.
Non Conventional Drilling. Technical Discussions in
PDVSA. Internal Report. (1998) Jun. 3-5.
11. Vasquez, A.R., Sanchez, A., McLennan, J.D., Guo,
Q., Bludun, M.A., Mendoza,H.: “Mechanical and
Thermal Properties of Unconsolidated sands and its
implication to heavy oil SAGD project in the Tia
Juana Field, Venezuela” paper SPE 54009 presented
at the VI LACPEC conference, Caracas, Venezuela
(1999) , April. 21- 23.

7. Figure 1. Location map showing the four prolific
areas of Venezuela and some of their multilateral
technology opportunities.
4-D Leadership
Measurement
and Sensors
Modeling and
Predictions
Operation
Control
Finance and
Economy
• Focalized Centers
• Synergy of efforts
• Better Use of Investments
• Reduction of Uncertainty.
• Bigger technical support
• Visualization, Manipulation
• Multisensoring Display
• Data Integration
• Collaboration,
Figure 2. Visualization Centers. These centers provide
teams with powerful tools to integrate competences and
knowledge, to take advantage of previous investments and to
reduce uncertainties.
DeliverDeliver
Stablish
Optimum
Exploitation
Plan
Execute
Activities
Monitor
Reservoir
Performance
Review
Exploitation
Plan
• Characterize
• Optimum Plan
• Drilling
• Operation
• Surveillance
• Control
• Update Model
• Review Plan
Figure 3. Production Value Chain. Current reservoir
technologies are not integrated to support team collaboration and
handle large amount of data. The reservoir characterization
cycle is long (2-3 years) and usually does not match drilling and
operational needs.
Figure 4. Map of Venezuela showing the location of the
multilateral well drilled between 1995-98, their recent status and
a summary of their problems.
Figure 5. Diagram with the Well 2 Architecture and Completion
System.
MARACAIBO FIELDS
Pressure Decline
Compartments
Selective Production
BARINAS APURE FIELDS
Water Coning
Fractured Carbonate
Reservoirs
ANACO AREA
Increase Recovery Factor
in Gas- Condensate Reservoirs
ORINOCO BELT
Heavy Oil: New Exploitation
Plans for Enhanced Crudes
Well 1
Well 3
Well 2
Well 5Well 4Water
Production
Junction and Lateral
Collapse/ Sand Production
Sand Production
at the junction
Junction and Lateral
Collapse/ Sand Production
Drilling and
Completion
Problems
In Production
Abandoned

8. Figure 6. Diagram with the Well 1 Architecture and Completion
System. This well is actually producing from the vertical hole
only.
Figure 7. Diagram with the Well 4 Architecture and Completion
System. This well is producing in a heavy oil reservoir of the
Orinoco Belt.
Monitoring
Tools
Rock-fluid Model
Control
Decision &
Strategies
• Information Technology
• Data Storage
• Fast Simulation
• Collaborative Alliances
• Networking capabilities
• Integrated environment
• Integrated Approach
• Multiple domain access
• 3D & 4D Visualization
• Integrated Reservoir
Management
• Efficiency
• Competitive costs
• Resource base
• Short and long term
• Integrated
• Automated Operations
• Non intuitive
• Intelligent sleeves
• Automated packers
• Automated mesh pack
• Permanent Instrumentation
• Fiber Optics
• Remote
• Integrated to Model
Smart
Reservoir
Figure 8. Smart Reservoir Philosophy. Downhole assets are
fully instrumented and integrated to upper decision systems,
such as numerical reservoir simulators, project management
desktop and integrated reservoir management environments.
Control line for carrying the optical cable
is stripped to the production tubing
Control line carries the optical cable
Steam migrating
through reservoir
Steam
Injector
Observation
Well
Producer
Figure 9. Downhole permanent distributed temperature
monitoring. It is performed by deploying specially covered fiber
cable into a ¼” coiled stainless steel tubing.
VERTICAL WELL
8-1/2” @ 6400’
LATERAL
6” @ 6375’
7”
9-5/8” @ 5200’
13-3/8” @ 2000’
LTBS
Window @ 3852’
Lateral # 2 @ 5346’
Azimuth 150°
Liner 4-1/2” 0.015”
9-5/8” @ 3990’
4-1/2”
Lateral # 1 @ 5585’
Azimuth 0°
Liner
5-1/2' 0.015”

9. 13 3/8”
Surface Casing
9-5/8” Casing
12-1/4”
Hole
7” Slotted Liner
2-7/8" Circulation Tubing3-1/2”
Tubing
Pack-off
Nitrogen
Chamber
Nitrogen
Chamber
Stainless Steel
1/4” Tubing with
Fiber optic Cable
U-Type Configuration
Gauge
TPS
Stainless Steel
1/4” Tubing
with Nitrogen
Figure 10. Fiber Optic installation. PDVSA has recently
installed two fiber optic temperature profile systems
performance monitoring in one pair of SAGD horizontal wells.
Downhole Monitoring
• Pressure,
• Saturation
• Temperature
• Multiphase Flow
• Sand Production
• Asphaltenes
• H2S, Tracers, CO2
DownholeDownhole MonitoringMonitoring
• Pressure,
• Saturation
• Temperature
• Multiphase Flow
• Sand Production
• Asphaltenes
• H2S, Tracers, CO2
Surface & d-hole Control
• Choke, Gas-lift, ESP
• Sleeves on/off
• Packers, Meshes
• Separation
• Reinjection
Surface & d-Surface & d-holehole ControlControl
• Choke, Gas-lift, ESP
• Sleeves on/off
• Packers, Meshes
• Separation
• Reinjection
Reservoir Description
• Static & Dynamic
• Predictions
Reservoir DescriptionReservoir Description
• Static & Dynamic
• Predictions
Field & Model Data IntegrationField & Model Data IntegrationField & Model Data Integration
Project Monitoring
Fluid front advance,
coning,
wellbore instability
Project MonitoringProject Monitoring
Fluid front advance,
coning,
wellbore instability
Field Automation
I - Process Control
II - Supervisory
III - Optimization
IV - Integration
Field AutomationField Automation
I - Process Control
II - Supervisory
III - Optimization
IV - Integration
Figure 11. Smart Reservoir Concept. Real-time systems.
Fig. 12. NPV cash flow analysis for multilateral
versus conventional well
- 6
- 4
- 2
0
2
4
6
1 2 3 4 5 6
TIME [MONTHS]
CASHFLOW[MM$]
Production
Initial
Investment
Workover
Costs
NPV | BASE CASE
CONVENTIONAL WELL MULTILATERAL WELL
NPV |MLT<

10. 13 3/8”
Surface Casing
9-5/8” Casing
12-1/4”
Hole
7” Slotted Liner
2-7/8" Circulation Tubing3-1/2”
Tubing
Pack-off
Nitrogen
Chamber
Nitrogen
Chamber
Stainless Steel
1/4” Tubing with
Fiber optic Cable
U-Type Configuration
Gauge
TPS
Stainless Steel
1/4” Tubing
with Nitrogen
Figure 10. Fiber Optic installation. PDVSA has recently
installed two fiber optic temperature profile systems
performance monitoring in one pair of SAGD horizontal wells.
Downhole Monitoring
• Pressure,
• Saturation
• Temperature
• Multiphase Flow
• Sand Production
• Asphaltenes
• H2S, Tracers, CO2
DownholeDownhole MonitoringMonitoring
• Pressure,
• Saturation
• Temperature
• Multiphase Flow
• Sand Production
• Asphaltenes
• H2S, Tracers, CO2
Surface & d-hole Control
• Choke, Gas-lift, ESP
• Sleeves on/off
• Packers, Meshes
• Separation
• Reinjection
Surface & d-Surface & d-holehole ControlControl
• Choke, Gas-lift, ESP
• Sleeves on/off
• Packers, Meshes
• Separation
• Reinjection
Reservoir Description
• Static & Dynamic
• Predictions
Reservoir DescriptionReservoir Description
• Static & Dynamic
• Predictions
Field & Model Data IntegrationField & Model Data IntegrationField & Model Data Integration
Project Monitoring
Fluid front advance,
coning,
wellbore instability
Project MonitoringProject Monitoring
Fluid front advance,
coning,
wellbore instability
Field Automation
I - Process Control
II - Supervisory
III - Optimization
IV - Integration
Field AutomationField Automation
I - Process Control
II - Supervisory
III - Optimization
IV - Integration
Figure 11. Smart Reservoir Concept. Real-time systems.
Fig. 12. NPV cash flow analysis for multilateral
versus conventional well
- 6
- 4
- 2
0
2
4
6
1 2 3 4 5 6
TIME [MONTHS]
CASHFLOW[MM$]
Production
Initial
Investment
Workover
Costs
NPV | BASE CASE
CONVENTIONAL WELL MULTILATERAL WELL
NPV |MLT<