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Results
Abstract The potential for a gas-in-riser situation to become uncontrollable by the rapid displacement of mud out of the riser is extremely high if the riser-top is left open. The unloading can be catastrophic in synthetic-based mud (SBM) or oil-based mud (OBM) when the gas remains dissolved and undetected till pressure reduction causes sudden desorption of dissolved gas closer to the surface. This work demonstrates, investigates, and provides insights into the riser gas unloading phenomena with the help of full-scale gas migration experiments. A 5200 ft deep vertical test well (9 5/8" x 2 7/8" casing/drill-pipe) at LSU instrumented with 4 down-hole PT gauges was used for the tests. Tests were carried out in water, and SBM. Each test started by injecting a fixed volume of nitrogen gas (5 to 15 bbl) at a low (0.3 bbl/min) or high flow rate (4 bbl/min) from the bottom of the annulus while keeping the annulus open. After the influx, the annulus was either closed at the surface to study the effects of gas migration under shut-in conditions or left open to study the effects of gas migration under open-top annulus conditions. The rate of pit-gain reduced during the low-void-fraction gas tests in water, and SBM-filled-annulus when gas influx stopped (closing of subsea BOP). However, for the high-void-fraction test in SBM, the pit-gain stopped once influx stopped and remained negative from 6.5 minutes to 35.5 minutes due to a reduction in mud level caused by the dissolution of gas in SBM. The pit gain later resumed and continued to increase. Keeping the annulus open resulted in a rapid exponential increase in pit-gain as the gas-front neared the surface requiring an immediate shut-in of the annulus to avoid unsafe rapid discharge. The final estimated outflow rate based on cumulative pit-gain (Coriolis) was 160gpm for the high-void-fraction test in SBM. Pressure, and differential pressure data from pairs of gauges were used to make real-time decisions during the tests and to estimate the location and migration velocities of gas-front and tail. The model developed for analysis and comparison of test results in water is used here to explain the behavior of gas migration under open-top conditions. A thorough investigation with the help of gauge data and pit gain has explicated our understanding of gas migration behavior and its effect on the dynamics of gas-liquid equilibrium from influx to impending unloading situation. The interesting results from the tests are extremely useful in explaining the dangers of using open-top annulus on rigs.
Abstract Enhanced oil recovery technique for carbonate or sandstone reservoirs using inflow control technology are often affected by undesired production of water and gas. Limited density and viscosity differences between oil, water and gas is often a challenge for most autonomous and passive inflow control technology due to limited fluids performance ratio between oil, water and gas when breakthrough happen. The fluid performance ratio describes how the ICD (Inflow Control Device) and AICD (Autonomous Inflow Control Device) preferably choke the unwanted fluid (water/gas) compared with oil. Different ICD/AICD are utilizing both density and viscosity that effect the flow behavior difference in the valve to differentiate the pressure drop for oil, water, and gas. Different designs have been tested in single phase and multiphase full-scale flow loop testing that replicates downhole operating conditions. In order to understand the ICD/AICD behavior in reservoir environments for the duration life of the well, a wellbore model where the effect of fluids performance ratio is included. The model also includes the effect of mobility ratio and how this affects the importance of the fluid performance ratio. Well completion has a critical role to optimize the well performance and enhanced oil recovery. In today’s engineer toolbox, a wide variety of inflow control technology completion options are available including various ICD and AICD. A new methodology and workflow have been developed to compared different type of inflow control technology completion to understand the capability to reduce unwanted water and gas production without needing detailed information about rock property variation along the wellbore in the reservoir. These methods are based on laboratory flow performance data from each device and will compare various downhole inflow control tools based on their fluid phase performance ratio to produce oil, choke water and/or gas and express the fluid preference by ratio in percentage. Experimental flow loop results illustrate a significant different in fluids performance ratio of conventional ICD and AICV. AICD with dynamic flow area are choking water breakthrough more effectively, resulting in better sweep along the wellbore section that were not previously being produced. By limiting the water and gas production operators are therefore able to apply higher drawdown to increase oil recovery significantly. This improves the economics of thin-oil rim development and benefits of reduced environmental impact per oil produced due to less un-needed water and gas being produced to surface.
- North America > United States (0.28)
- Europe > Norway (0.28)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > Vana Basin > RL 088 BS > Block 25/4 > Alvheim Field > Lista Formation > Våle Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > Vana Basin > RL 088 BS > Block 25/4 > Alvheim Field > Lista Formation > A2 North Heimdal T60 Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > Vana Basin > RL 088 BS > Block 25/4 > Alvheim Field > Hermod Formation > Våle Formation (0.99)
- (21 more...)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Flow control equipment (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Reducing Environmental Footprint of Borehole Seismic Acquisition by Using DAS on Hybrid Logging Cable
Duque, Helman (Ecopetrol S.A, Bogotá, Colombia) | Briceño, Alexander López (Ecopetrol S.A, Bogotá, Colombia) | Perez, Alexander Duarte (Ecopetrol S.A, Bogotá, Colombia) | Villasmil, Jose (Ecopetrol S.A, Bogotá, Colombia) | Useche, Manuel (SLB, Bogotá, Colombia) | Martinez, Alejandro (SLB, Bogotá, Colombia) | Ruge, Susy Mercado (SLB, Bogotá, Colombia) | Ordoñez, Andrea (SLB, Bogotá, Colombia) | Sanchez, Diego (SLB, Bogotá, Colombia) | Marin, Dilan (SLB, Bogotá, Colombia)
Summary Borehole seismic data from vertical seismic profiles (VSP) provide valuable information in different stages of reservoir evaluation. Land VSPs are generally acquired using a wireline-specific run involving a logging unit, a downhole geophone-based tool, and vibrator truck operating 10 hours to 1 day for typical zero-offset VSP surveys (ZOVSP). Nowadays, novel technologies, such as fiber optic cable, allow geoscientists to get VSP measurements while reducing logging times to minutes and reducing the environmental footprint of the operation. Distributed acoustic sensing (DAS) and electric hybrid logging cable allow borehole seismic information to be efficiently obtained over the entire well in a fraction of the time required by conventional methods. The land ZOVSP surveys discussed in this work were acquired while conveying various logging tools with a hybrid optical heptacable by Ecopetrol S.A. in Colombia onshore. In many of these jobs, data acquisition is carried out in areas close to communities, houses, or infrastructure that may be impacted by closing roads or by vibrations emitted by the seismic source. Also, high levels of noise for long periods could distress nearby inhabitants. The reduction of carbon footprint is a direct benefit when using this technology. Less operating time can reduce CO2 emissions over 90% in a VSP acquisition. ZOVSPs with conventional geophone technology were estimated to take in average 17 hours in wells with the profiles considered here. In contrast, with DAS on hybrid logging cable, this operation takes 1.5 hours, which immediately translates into a lower carbon emission footprint equating to an estimated 95% CO2 reduction per job.
- South America > Colombia (0.50)
- North America > United States > Texas (0.28)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Near-well and vertical seismic profiles (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- (3 more...)
Downhole Water Sink at High Mobility Ratio: The Tambaredjo Field Pilot Test
Niz-Velasquez, E. (Dunia Technology Solutions, Paramaribo, Suriname) | Nagesar, H. S. (Staatsolie Maatschappij N.V., Paramaribo, Suriname) | Bhajan, R. V. (Staatsolie Maatschappij N.V., Paramaribo, Suriname) | Nandlal, B. (Staatsolie Maatschappij N.V., Paramaribo, Suriname)
Abstract This study discusses the development and results of the Downhole Water Sink (DWS) pilot test in two wells of the Tambaredjo Field (Suriname). It includes the mechanical completion, design and execution of operating strategy, well performance and forecast, and reservoir simulation employing an oil-in-water emulsion formulation. The DWS process, well and reservoir information and properties are introduced. The problem of heavy oil production in oil-water contact (OWC) areas is explained. The results in terms of production data and its analysis, and issues encountered, are presented. A reservoir simulation model capable to handle transport of oil components in water phase is described and used to history-match the production performance. Then, conclusions are drawn from the information presented. Although the water sink is expected to work under stable displacement conditions, the results of the pilot test show that DWS could successfully reduce water coning at the prevalent unstable mobility ratio. It also promoted inverted coning of oil from the transition zone to the water leg completion. This was confirmed by direct measurements of oil content in the fluid produced from the water leg completion. The physical mechanism that allows such phenomenon is hypothesized to be the flow of oil droplets of size smaller than that of the typical pore throat. Such mechanism was numerically modeled and found to be consistent with the pressure and rate measurements at both wells. Early measurement and completion issues in the first well were overcome later on and in the second well. This paper presents the first results for DWS in a heavy oil reservoir with highly adverse mobility ratio. The results will serve as a guidance for implementation of DWS in heavy oil reservoirs overlying an oil-water contact.
- North America > United States (1.00)
- South America > Suriname > North Atlantic Ocean (0.61)
- South America > Guyana > North Atlantic Ocean (0.61)
- Europe > United Kingdom > North Sea > Central North Sea (0.40)
- South America > Suriname > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- South America > Guyana > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- South America > Brazil > Parnaiba Basin > Block PN-T-68 > California Field (0.97)
- North America > United States > Texas > East Texas Salt Basin > East Texas Field > Woodbine Formation (0.97)
Abstract Usually when the Production Engineer needs to follow a DrawDown Curve to maximize production of the well, a methodology to calculate dynamic pressure at sand face (PWF) is needed. To calculate PWF, the Gas and Liquid Rate and wellhead conditions need. On many occasions, there is no separator to run a production test so, as a consequence, a methodology to calculate production rates becomes vital. This paper uses the choke correlation developed by Bellini et al. to calculate total mass and use a workflow to find Water Cut and GOR using Equation of state to split total mass in Gas, Oil and Water mass, and transform them to volumetric rates. In Non-Conventional fields, wellhead chokes are widely used to, for example: regulate the flow rate of the well, to impose sufficient back pressure on the face of the sand so as not to exceed values excessive drawdown. Many authors use choke correlation to find Gas or Liquid Rates but not all at same time and uses many times wrong correlation with error higher than 20%. The workflow presented in this paper, combines high confidence multiphase choke correlation to predict mass rate and use Equation of State (EOS) to predict GOR and Water Cut relations, this combinations of both make sure best confidence calculations. This new workflow was tested with several oil wells at non-Conventional reservoir and its performance is more confidence to existing methodology used nowadays. The Volumetric rates calculation need to use the best technical practices combining fluids thermodynamic and production knowledge to reach the minimal error we can do. Examples and back test of volumetric rate calculation vs separator measurements on wells from "Vaca Muerta" Formation, will be compared a showed as result of this job. Finally, an application of Well performance analysis will be showed, in order to evaluate choke sensitivities to maximize liquid production rate and maintain Well DD into optimal Drawdown Curves to make sure maximize EUR as we can.
- North America > United States (1.00)
- South America > Argentina > Patagonia Region (0.61)
- South America > Argentina > Neuquén Province > Neuquén (0.61)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (0.76)
Investigation of Carbonate Rock Thermal Conductivity as a Function of Temperature, Porosity and Fluid Saturation Using a Comparative Approach
Madani, Seyed Ali (Department of Chemical and Petroleum Engineering, University of Calgary, AB Canada) | Fayazi, Amir (Department of Chemical and Petroleum Engineering, University of Calgary, AB Canada / PERM Inc. TIPM Laboratory, AB, Canada) | Shor, Roman (Department of Chemical and Petroleum Engineering, University of Calgary, AB Canada) | Kantzas, Apostolos (Department of Chemical and Petroleum Engineering, University of Calgary, AB Canada / PERM Inc. TIPM Laboratory, AB, Canada)
Abstract Carbonate rocks are common formations in hydrocarbon reservoirs, and thermal recovery methods are often employed to enhance production. The success of a thermal project is highly dependent on comprehensive knowledge about the thermal behavior of any involved component. Consequently, the availability of reliable and accurate thermal property data, such as thermal conductivity, improves optimization and operation procedures in these types of operations. Measurement of thermal conductivity of carbonate rock has been a matter of extended research, yet different techniques result in different measurements and the understanding of the effect of elevated temperatures is limited. Prior researchers used transient approaches in the thermal conductivity measurements, which resulted in poor accuracy, despite having low measurement time. Moreover, the thermal conductivity of the saturated carbonate samples has not been investigated, as the existing research mainly focused on dry samples. In this study, first, thermal conductivity is measured of five different carbonate samples with a wide range of effective porosity (from 5 to more than 30 %) using a steady-state approach within a wide range of temperatures (from 40 to 150 ˚C). Then the same procedure was repeated for saturated samples to investigate the effect of saturation in different porosity and temperatures on the thermal conductivity trend and values. Results showed that in the dry samples, there is a downward trend for the thermal conductivity of all five samples as the temperature increased. For samples at similar temperatures, as the porosity of the sample increased, an increase was observed in the thermal conductivity values in dry cases, and for the porosity values above a certain value, it started to go down as we expected, and it was interpreted as the effect of mineralogy which is another crucial parameter beside the porosity in the ultimate thermal conductivity value of a porous medium. We measured effective porosity; however, the total porosity of the sample plays a much more important role in the heat transfer along the sample, and the relationship between these two porosities depends on the samples’ pore connectivity. Thermal conductivity measurement for the saturated cases carried out by a modification in the setup. Results showed a similar trend as the temperature was increased and the values were higher compared to corresponding dry sample which revealed the incapability of averaging methods as a generalized approach for saturated rock sample thermal conductivity prediction.
- North America > Canada (0.29)
- Asia > Middle East > Turkey (0.29)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Geological Subdiscipline (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Influence of Wettability and Flow Rate Changes in the Mass Transfer for Simulation of Fractured Reservoirs
R. Soler, Sharon A. (University of Campinas) | Lamas, Luís F. (Santa Catarina State University) | Koroishi, Erika T. (University of Campinas) | Ruidiaz, Eddy (University of Campinas) | Vidal Trevisan, Osvair (University of Campinas) | Valladares de Almeida, Rafael (Repsol Sinopec Brasil) | Perin Munerato, Fernando (Repsol Sinopec Brasil) | Gruenwalder, Markus (Repsol Technology Lab)
Abstract An accurate understanding of the matrix-fracture mass transfer is fundamental to the modeling of fractured reservoirs. Nevertheless, the difficulty in an appropriate representation of this process comes from the fact that matrix and fracture interact in a particular manner depending on physical mechanisms as capillary imbibition. Capillary imbibition is considered through wettability in several mass transfer formulations (also called transfer functions) as the main mass driving force between matrix and fracture. This paper provides simulation results of waterflooding in two different scales of fractured models: Core plug models and extended models (a quarter of 5-spot), aiming to evaluate the influence of wettability and flow rate alteration on the matrix-fracture mass transfer. The methodology applied is based on sensitivity analyzes of wettability and flow rates scenarios, comparing parameters involved in matrix-fracture mass transfer: capillary continuity, fluid transfer rate, and hydraulic conductivity of the fracture system. The methodology is divided into three main parts. Initially, single-porosity models with an induced longitudinally fracture at laboratory scale are simulated, to obtain accurate models in terms of representative responses for wettability and flow rate changes. Secondly, dual-porosity/permeability models are constructed also at laboratory scale to analyze and compare answers to mass transfer. As a third stage, extended models are created attempting to analyze the impacts of sensitivity parameters of mass transfer on a larger scale. Results show that the increase of rock preference for water leads to highest oil recovery factors at low and high-water injection rates, benefiting mainly from the water spontaneous imbibition. Notably, the spontaneous imbibition in these cases is more considerable in low-rate scenarios, due to its larger contact time with water and rock. However, the increment on production may not be economically feasible, because of the long time (high pore volumes injected) needed to get this increase. In contrast, intermediate and oil-wet scenarios exhibit low oil sweep and displacement efficiency at low and high-water injection rates. Accordingly, these scenarios reach water breakthrough quickly and exhibit a less accentuated tendency to water saturation alterations if compared with a water-wet scenario. Results from single-porosity models show a good agreement between the water saturation distributions along the length and the effect of the induced fracture, validating its use. Results also reflect the effects of the fractured porous media formulations at both model scales as well as the effects of the shape-factors. In a numerical simulation study, this work shows the importance of close interaction between the wettability, flow rate changes, and the parameters that control matrix-fracture mass transfer. At last, the significance of these sensitive parameters is also demonstrated.
- Asia (0.68)
- North America > United States (0.46)
- South America > Brazil (0.46)
- Europe > Norway (0.28)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.95)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- (2 more...)
Identification of Fluid Flow Zones in the Reservoir and Behind-Casing Through the Second Derivative of the Flowing Temperature
González, José W (Lupatech Oilfield Services) | Linares, Alejandro (Lupatech Oilfield Services) | Meza, Eliana (Ecopetrol S.A.) | Chaparro, Diana (Ecopetrol S.A.) | Monzon, Carlos (Ecopetrol S.A.)
Abstract The objective of this paper is to identify zones of fluid movements in the reservoir and behind the casing using the second derivative of the flowing temperature (T) log in producing wells. Generally, the combination of static and flowing temperature is required in order to detect flow behind the casing, which implies shuting down the well and deferred production. The temperature logs were acquired with a sensor of resolution of 0.018°F and logging speeds at 30, 60, 90 and 120 ft/min. So, the hysteresis of temperature sensor can be analyzed between runs going up and down. The average temperature of the running down logs were derived with respect to the depth (D), where the first derivative is the dynamic temperature gradient and the second derivative is the rate of change of this gradient. In order to identify the flow zones, behavior patterns were settled between production (PLT’s), noise and cementation logs with the second derivative of temperature. For an equilibrium system (non-flow zones) the second derivative values correspond to zero , whilst for a dynamic condition (flow zones) the values are different to zero . The results indicated that there is a direct relationship between the movement of fluids with the second temperature derivative in a reservoir-wellbore system. Besides, there is a 95% consistency with production logging (PLT´s) results. Coupled with this, the open hole gamma ray (GR) log was compared with the cased hole GR, and a radioactivity increment was observed in the water production intervals which match with the changes of the second derivative of the temperature. Based on those outcomes, it was possible to identify in the reservoir-wellbore system leaks, flow behind the casing, fluid contributions in the perforated intervals and aquifer influx. Finally, the results correlate with increased readings in the total Gamma Ray log, and spectral noise log. This methodology does not require to log the static temperature to identify flow behind the casing, which means that it is not necessary to shut down the well. Consequently, the proposed workflow provides an additional tool for PLT’s interpretation and well integrity since the second derivative of temperature can detect small movements of fluids that the flowmeter can not. Additionally, it can also be used to monitor secondary recovery processes.
- Well Completion (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
A Two-Phase Non-Linear One-Dimensional Flow Model for Reserves Estimation in Tight Oil and Gas Condensate Reservoirs Using Scaling Principles
Ruiz Maraggi, Leopoldo M. (The University of Texas at Austin) | Lake, Larry W. (The University of Texas at Austin) | Walsh, Mark P. (The University of Texas at Austin)
Abstract A common approach to forecast production from unconventional reservoirs is to extrapolate single-phase flow solutions. This approach ignores the effects of multi-phase flow, which exist once the reservoir pressure falls below the bubble/dew point. This work introduces a new two-phase (oil and gas) flow solution suitable to extrapolating oil and gas production using scaling principles. Additionally, this study compares the application of the two-phase and the single-phase solutions to estimates of production from tight oil wells in the Wolfcamp Formation of West Texas. First, we combine the oil and the gas flow equations into a single two-phase flow equation. Second, we introduce a two-phase pseudo-pressure to help linearize the pressure diffusivity equation. Third, we cast the two-phase diffusion equation into a dimensionless form using inspectional analysis. The output of the model is a predicted dimensionless flow rate that can be easily scaled using two parameters: a hydrocarbon pore volume and a characteristic time. This study validates the solution against results of a commercial simulator. We also compare the results of both the two-phase and the single-phase solutions to forecast wells. The results of this research are the following. First, we show that single-phase flow solutions will consistently underestimate the oil ultimate recovery factors for solution gas drives. The degree of underestimation will depend on the reservoir and flowing conditions as well as the fluid properties. Second, this work presents a sensitivity analysis of the PVT properties that shows that lighter oils (more volatile) will yield larger recovery factors for the same drawdown conditions. Third, we compare the estimated ultimate recovery (EUR) predictions for two- and single-phase solutions under boundary-influenced flow conditions. The results show that single-phase flow solutions will underestimate the ultimate cumulative oil production of wells since they do not account for liberation of dissolved gas and its subsequent expansion (pressure support) as the reservoir pressure falls below the bubble point. Finally, the application of the two-phase model provides a better fit when compared with the single-phase solution. The present model requires very little computation time to forecast production since it only uses two fitting parameters. It provides more realistic estimates of ultimate recovery factors and EUR, when compared with single-phase flow solutions, since it considers the expansion of the oil and gas phases for saturated flow. Finally, the solution is flexible and can be applied to forecast both tight oil and gas condensate wells.
- Research Report > New Finding (0.88)
- Research Report > Experimental Study (0.66)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.68)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (28 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Abstract The "Oficina" formation is the most important in the Eastern Venezuela Basin and represents the main target for this study, which is to optimize the oil production and increase well productivity by the means of reducing the oil viscosity through the application of downhole electrical heating cable. The main objective of this study is to investigate and quantify the effect of downhole electrical heating cable in the performance of the extraheavy oil reservoir and horizontal wells interaction by lowering the oil viscosity applying a coupled reservoir-wellbore simulation approach. A fully integrated 3D reservoir and discretized mechanistic wellbore simulation approach is carried out in order to estimate downhole heating effect and interaction between reservoir inflow and wellbore performance during the heating inside the wellbore. Bottom hole pressure and temperature profile inside wellbore, productivity index, production fluid rates along horizontal well section are estimated under several sensitivities and optimization process including: heating rate, length and location of the cable inside wellbore. Numerical simulation is performed with commercially available thermal simulation software that has the feature of a wellbore modeling tool that can couple to the reservoir model. Additionally, optimization software is used to perform the sensitivity analysis studies and the automatic optimization of the heating rate, cable length and position. The heating cable simulation approach allowed understanding the importance of considering wellbore heating parameters and the interaction of the highly viscous extraheavy oil in the reservoir by increasing the temperature inside the wellbore. By applying wellbore calculations coupled to the reservoir simulation, it was possible to understand critical aspects of the oil and gas flow in the reservoir due to different drawdown along horizontal well section, pressure lossess along the wellbore due tor friction and the general efficiency of the heating cable and consequences in oil production. Bottom hole pressure, productivity index and production fluid rates along horizontal well section, were estimated under several sensitivities and optimization workflow including the heating cable parameters and location inside wellbore in order to estimate the additional cumulative oil production and increase of the productivity index and bottom hole pressure. Therefore, the dynamic model assessment permitted to define several criterias for well selection candidates and founded the basis for wellbore completion design and monitoring protocol program for pilot test in the Field. Coupling wellbore reservoir simulation is more accurate when compared to a conventional numerical simulation approach since it was possible to conclude that location of the heating in the horizontal section and gas breakthrough could affects negatively the oil production of the wells due to gas expansion inside wellbore with temperature increase. Therefore, it is very important that heating cable assessment consider the fully integrated 3D reservoir and wellbore modeling.
- North America (1.00)
- South America > Venezuela > Caribbean Sea (0.24)
- Europe > Norway > Norwegian Sea (0.24)
- South America > Venezuela > Orinoco Oil Belt > Eastern Venezuela Basin > Carabobo Block (0.99)
- South America > Venezuela > North Atlantic Ocean > Eastern Venezuela Basin (0.99)
- South America > Venezuela > Eastern Venezuela Basin > Oficina Formation (0.99)
- South America > Venezuela > Anzoátegui > Eastern Venezuela Basin > Maturin Basin > Cerro Negro Area Field (0.99)