AbstractA 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 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

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

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 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 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 ReservoirsThe 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).

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 update to the reservoir model, so necessary for the construction of complex wells..

SI METRIC CONVERSION FACTORS

cp. x 10* E-03 = Pa.sft 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 = cmlbf 4.448 222 E-00 = Nmd 9.869 233 E-04 = m2

psi x 6.894 757 E-00 = kPabbl 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.

Figure 1. Location map showing the four prolific areas of Venezuela and some of their multilateral technology opportunities.

4 - D L e a d e r s h i p

M e a s u r e m e n ta n d S e n s o r s

M o d e l i n g a n dP r e d i c t i o n s

O p e r a t i o n C o n t r o l

F i n a n c e a n dE c o n o m y

• F o c a l i z e d C e n t e r s

• S y n e r g y o f e f f o r t s

• B e t t e r U s e o f I n v e s t m e n t s

• R e d u c t i o n o f U n c e r t a i n t y .

• B i g g e r t e c h n i c a l s u p p o r t

• V i s u a l i z a t i o n , M a n i p u l a t i o n

• M u l t i s e n s o r i n g D i s p l a y

• D a t a I n t e g r a t i o n

• C o l l a b o r a t i o n ,

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.

Del

iver

D

eliv

er Stablish

OptimumExploitation

Plan

ExecuteActivities

Monitor Reservoir

Performance

ReviewExploitation

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.

Figure 6. Diagram with the Well 1 Architecture and CompletionSystem. 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

ControlDecision &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

SmartReservoir

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 cableis stripped to the production tubing

Control line carries the optical cable

Steam migratingthrough reservoir

SteamInjector

ObservationWell

Producer

Figure 9. Downhole permanent distributed temperature monitoring. It is performed by deploying specially covered fiber cable into a ¼” coiled stainless steel tubing.

13 3/8”Surface Casing

9-5/8” Casing

12-1/4”Hole

7” Slotted Liner

2-7/8" Circulation Tubing 3-1/2”Tubing

Pack-off

NitrogenChamber

NitrogenChamber

Stainless Steel 1/4” Tubing withFiber optic Cable

U-Type Configuration

GaugeTPS

Stainless Steel 1/4” Tubingwith 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

Downhole Downhole 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 Control Control• 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 MonitoringFluid front advance,coning,wellbore instability

Project MonitoringProject MonitoringFluid front advance,coning,wellbore instability

Field AutomationI - Process ControlII - SupervisoryIII - OptimizationIV - Integration

Field AutomationField AutomationI - Process ControlII - SupervisoryIII - OptimizationIV - Integration

Figure 11. Smart Reservoir Concept. Real-time systems.

Fig. 12. NPV cash flow analysis for multilateral versus conventional well

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NPV | BASE CASE

CONVENTIONAL WELL MULT ILATERAL WELL

NPV |MLT<