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Collaborating Authors
Production logging
Abstract Co-injection of solvent with steam in SAGD has shown promise for enhancing oil rates as well as in reduction of energy and water consumption. Modeling and optimization of hybrid steam-solvent recovery processes with commercial numerical simulators can be very time consuming. In addition, the complex interaction of heat and solvent effects in mobilizing heavy oil at the vapour chamber boundary are often difficult to ascertain from the numerical models. Semi-analytical mathematical models can provide insight into the physics of the processes and may be used to estimate production rates and thermal efficiency in much less time. In this study, an unsteady-state semi-analytical model was developed to predict the oil flow rate in the steam-solvent assisted recovery process. The model assumes a curved interface with transient temperature and solvent distribution in the mobile zone. It also accounts for transverse dispersion and concentration-dependent molecular diffusion for solvent distribution. The oil flow rate and interface profile are predicted at each time in an iterative fashion. The results show that the coefficient of diffusion-concentration function significantly affects the solvent penetration depth and its distribution. The semi-analytical model was able to predict oil production rates using different solvents co-injected with steam, in agreement with reported experimental data. The proposed model reveals the complex interaction of heat and solvent solubility and diffusion as they affect mobilization and production of viscous oil. This model may be used to find the optimal operation parameters for the process over a range of different reservoir qualities and pressures, in a very time-efficient manner. The final outcome may lead to an efficient design of a steam-solvent recovery process that utilizes less water and reduces the amount of energy and gas emissions per barrel of oil produced.
- North America > United States (1.00)
- North America > Canada (0.69)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Steam-solvent combination methods (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > Oil sand/shale/bitumen (1.00)
Russkoe High Viscous Oil Field - Production And Performance Optimization
Lachugin, D. S. (JSC "Tyumenneftegaz") | Edelman, I. Y. (Rosneft) | Shandrygin, A. N. (Gazprombank) | Aksenov, M. A. (JSC "Tyumenneftegaz") | Lachugina, Y. V. (JSC "Tyumenneftegaz") | Abramochkin, S. A. (Schlumberger) | Davidovskiy, A. D. (Schlumberger)
Abstract The Russkoe oil and gas field was discovered in 1968. It is one of the biggest and complex fields in Russia. It has yet to be put to production, however the development is already concerned by a number of geological and operational issues, such as high crude viscosity, remote location (beyond the Polar Circle), considerable heterogeneity, compartmentalization of poorly cemented sandstones as well as the presence of extensive gas cap, bottom water, and thick permafrost zone. OJSC "Tyumenneftegaz", a subsidiary of Rosneft, has been responsible for the pilot works to seek operational solutions for full-field development. Intensive pilot wells drilling and testing have been performed since 2007 in different zones of the field. In 2009-2012 23 wells, including 16 horizontal ones, were drilled in these pilot areas. Additionally cold and hot water injection tests have been conducted in one of the pilot areas. The main goal of these studies was to learn and reduce geological risks and to find an effective system for full-field development. The article presents the data and results of pilot operations as well as the methods and equipment for monitoring of the pilot works including multi-phase measurements of flow rates of producers using Vx tool, measurements of flow rates of injectors, tests of injectivity/inflow profiles in horizontal sections using DTS and PLT systems, measurements of bottom hole pressure dynamics and parameters of PCPs and ESPs using high precision metering systems. Effectiveness of different control and monitoring methods and of different production technologies has been analyzed. As a result applicability of these methods for the development of viscous oil fields under difficult weather conditions has given using the example of the Russkoe field.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.34)
- 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)
- Management > Asset and Portfolio Management > Field development optimization and planning (0.92)
- (3 more...)
Abstract Steam-assisted gravity drainage (SAGD) is the preferred thermal recovery method used to recover bitumen from Athabasca deposits in Alberta, Canada. In SAGD, steam injected into a horizontal injection well is forced into the reservoir, losing its latent heat when it comes into contact with the cold bitumen at the edge of a depletion chamber. Heat energy is transferred from steam to reservoir, reducing the viscosity of the bitumen, which flows under gravity toward a horizontal production well. Conduction is the main heat transfer mechanism in early SAGD, and reservoir thermal conductivity is a key parameter in conductive heat transfer. Conductive heat transfer occurs at a higher rate across reservoirs with higher thermal conductivity, which in turn affects the temperature profile ahead of the steam interface. Consequently, a reservoir with higher thermal conductivity will result in higher reservoir heating rates, and higher oil production rates. When the oil sands reservoir undergoes a temperature change from reservoir temperature to steam chamber temperature the thermal conductivity decreases up to 25% (depending on the initial reservoir and steam temperature), which affects the temperature profile and conductive heating within the reservoir. This study provides a modified Butler's model which includes a temperature-dependent thermal conductivity value. A simplified method is suggested using the thermal conductivity at average temperature of steam and reservoir will keep error under 1% for the range of SAGD applications. This novel approach is the first of its kind to incorporate a temperature-dependent thermal conductivity within the reservoir to a SAGD analytical model.
- North America > United States (1.00)
- North America > Canada > Alberta (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Abstract In Cyclic Steam Stimulation (CSS), steam is usually injected above fracturing pressure into oil sands to achieve desired injectivity; thus fractures are generally induced. The induced fractures will affect heating and flow patterns and thus affect the choice of well spacing and steam injection strategies. Therefore, it is critical to evaluate fracture length for successful CSS projects. Transient Temperature Analysis (TTA) is a technique which uses well-bore transient temperature data to estimate reservoir/wellbore characteristics. This paper discusses the feasibility of using TTA to evaluate the lengths of steam-induced fractures in cold lake oil sands by using wellbore transient temperature data in the soaking period of CSS. Numerical simulation model was first established based on history matching production data of a typical well in cold lake oil sands. Then the effect of different fracture lengths on temperature response in soaking phase was examined. Simulation results shows, in the middle and later period of soaking phase, linear relationships are found when temperature drop versus square root time are plotted. However, the correlation between fracture length and the slope is not clear. Based on the heated zone size and heated zone shape analysis at the very first moment of soaking phase, it is found the combined impact of reservoir permeability, reservoir thermal conductivity and fracture length determines the shut-in temperature response, which can be reflected on the slopes of the plots, with certain injection volume. But the qualitative representation of slope using fracture length, permeability and thermal conductivity cannot be found based on the results of finite difference based simulator. Aside from Finite difference method, simulation tools based on other numerical methods can be attempted to conduct TTA to evaluate the lengths of steam-induced fractures in CSS process.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Clearwater Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Cold Lake Field > Clearwater Formation > 995053 2D Cold Lake 2-10-63-2 Well (0.97)
- North America > United States > Montana > Western Canada Sedimentary Basin > Alberta Basin (0.96)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Abstract Recently different models have been proposed to describe two- and three-phase flow at the edge of a steam chamber developed during a SAGD process. However, two-dimensional scaled SAGD experiments and recent micro model visualizations demonstrate that steam-condensate is primarily in the form of micro bubbles dispersed in the oil phase (water-in-oil emulsion). Therefore, the challenging question is: Can multiphase Darcy equation be used to describe the transport of water as a discontinuous phase? Furthermore, the physical impact of water as a continuous phase or as micro bubbles on oil flow can be different. Water micro bubbles increase the apparent oil viscosity, while a continuous water phase decreases the oil relative permeability. Investigating the impact of these two phenomena on oil mobility at the steam chamber edge and overall oil production rate during a SAGD process requires development of relevant mathematical models that is the focus of this paper. In this paper, we develop an analytical model for lateral expansion of steam chamber that accounts formation and transport of water-in-oil emulsion. It is assumed that emulsion is generated due to condensation of steam, which is penetrated into the heated bitumen. The emulsion concentration decreases from a maximum value at the chamber interface to zero far from the interface. The oil viscosity is affected by both temperature gradient due to heat conduction and micro bubble concentration gradient due to emulsification. We conduct a sensitivity analysis by using the measured data from scaled SAGD experiments. The sensitivity analysis shows that by increasing the value of m (viscosity temperature parameter), the effect of emulsification of oil flow rate decreases. Comparing the proposed model with previous analytical models reveals that emulsification effect should be included in the SAGD analysis. We also use the proposed model to estimate the oil flow rate measured in several fields, published in the literature and find a reasonable match. The proposed mathematical model and its application to field and experimental data help the industry to understand the effect of emulsification on oil mobility during SAGD processes. Based on this understanding, steam chamber growth rate and oil production can be estimated more accurately.
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Abstract Even temperature conformance along the length of the horizontal well is key to maximizing Steam Assisted Gravity Drainage (SAGD) production rates. When temperature logs are run in SAGD producers, temperature variations of greater than 50°C between the hottest and coldest spots are commonly observed. We theorize that this temperature distribution is related to an inflow distribution, and that production rates could be improved if this temperature variance was narrowed. It is difficult to influence conformance with traditional SAGD producer well design. Flow areas are large, and liquid velocities are low, resulting in small frictional pressure losses. It is not possible to impose a materially different drawdown on hot and cold spots along the horizontal with typical well completion methods. A field trial is ongoing at the Firebag project in which a production well is equipped with intelligent completion technology. The test well's horizontal liner section is split into four hydraulically isolated zones, with each zone having the ability to provide flow or isolation from the reservoir. The well completion is equipped with optical pressure and temperature (P/T) gauges and distributed temperature sensing (DTS) technology which monitors each segment's performance during operations. The capability to independently and immediately manipulate each segment's production inflow will provide the operator the ability to evaluate the influence of an intelligent completion design on a well's conformance and ultimate oil recovery.
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Surmont Field (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Orion Oil Sands Project (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > McMurray Formation (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Firebag Oil Sands Project > Wabiskaw-McMurray Formation (0.99)
- Well Drilling > Drilling Operations (1.00)
- Well Completion > Completion Monitoring Systems/Intelligent Wells (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Abstract A tractable, predictive modeling approach for Cold Heavy Oil Production with Sand (CHOPS) remains a significant practical challenge. In CHOPS, instabilities of oil-sand interactions lead to formation of meso-scale structures, such as wormholes or other defects. The sand stress concentration around these structures often leads to sand failure, and production of sand in the process. The failure and motion of sand alter the permeability, and hence affect the oil production. Because these structures result from the instability of the oil-sand interactions, sizes, shapes and locations of these structures are unpredictable. One can only describe them using the statistical methods. Furthermore, in typical well-drainage scale or multi-well-scale numerical simulations these mesoscale structures are typically below the level of resolution and must be modeled as sub-grid-scale effects. Rigorous well-drainage-scale averaged governing equations can be easily derived, but closure models for the sand stress and sand production cannot be adequately developed without proper description of the sub-grid effects. The sub-grid momentum balance equation for sand demands that the divergence of the sand stress balances the gravity, pressure gradient and oil drag. Since gravity is a constant, and for a given mesoscale structure, the oil flow rate and hence the drag is determined by the imposed macroscopic pressure gradient, without information from sub-grid-scale pressure variation, we assert that the pressure gradient is the only independent variable affecting the stress and failure in sand. This leads to the proposition of closing the well-drainage-scale averaged governing equations in terms of the pressure gradient without explicitly involving the sand stress. Based on this proposition we derive a well-drainage-scale pressure diffusion equation without explicit representation of the sand stress. To develop the closure models, we can extract information from both explicit full-physics simulations of the sub-grid-scale effects with resolved sand stress and from pilot scale production data. Full physics simulations using the multiphase material point method are shown to adequately model lab-scale wormhole experiments. History matched simulations at the well-drainage scale are shown to track transients in pilot data and are a measure of the success of the modeling approach.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.89)
Specifics and Challenges of Heavy oil Production in Northen Siberia Illustration Based on Biggest Heavy Oil Project in Russia
Aksenov, M.. (CJSC ROSPAN INTERNATIONAL) | Lachugin, D.. (CJSC ROSPAN INTERNATIONAL) | Nukhaev, M.. (Schlumberger) | Rymarenko, K.. (Schlumberger) | Telkov, V.. (Gubkin Russian State University of Oil and Gas) | Gaidukov, L.. (TNNC) | Vologodskiy, K.. (TNNC) | Khramov, D.. (Schlumberger)
Abstract Russkoye heavy oil field is located in the northern part of Siberia. The field was discovered in 1968. It is characterized by the huge reserves: more than 1.3 billion tonn of oil in place and remote location (the field is located to the north from the polar circle). Main challenges for the field development are: unconsolidated formation, gas cap, high heterogeneity of formation, permafrost zone and heavy oil. This paper covers latest experience (2007-2012) obtained during field development pilot project implementation at the representative part of the Russkoye field. Pilot stage results will be used for the further field development strategy building. Effectiveness of different approaches has to be estimated, considering specifics of the field. Traditional field instrumentation did not provided reliable data for the analysis. New technologies (such as fiber optic distributed temperature sensors, specifically adopted multiphase metering etc.) were implemented for the building of the proper data acquisition system. During the pilot stage specific injection schedules, cold and hot water injection, various well completion applications were implemented. Depletion rate estimation based on real production data, determination of critical drawdown and numerous well testing activities including conventional buildup/drawdown pressure transient analysis and interference testing were made. Special attention is paid to the comparison of the cold and hot water injection and to the methods of control/monitoring of the well production. Monitoring and effectiveness estimation of the tested technology should be based on flow rate measurements data (MPFM), distributed pressure and temperature sensors (DP/TS) in horizontal production wells. Numerous new technologies were used for the pilot project. Paper describes approaches for integrated data acquisition implementation; development techniques comparison and new technologies adaptation workflow to the specific field conditions. New technologies application allowed to see specific field behavior and to estimate effect of various field development and management approaches tested. The results obtained during the pilot project will be used for the Russkoye field development planning, technical solutions will be implemented for the field monitoring and managing. Successful development of the first biggest heavy oil field should lead to initiation of development of other numerous challenging heavy oil fields in Russia.
- Europe (1.00)
- Asia > Russia > Ural Federal District > Yamalo-Nenets Autonomous Okrug (0.57)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.56)
Determination of Thermal Conductivity of Carbonate Cores
Chen, Joyce (Alberta Innovates - Technology Futures) | Donald, James (Alberta Innovates - Technology Futures) | Huang, Haibo (Alberta Innovates - Technology Futures) | MacDonald, Jeff (Osum Oil Sands Corp.) | Jiang, Qi (Osum Oil Sands Corp.) | Rabin, Mark (Osum Oil Sands Corp.) | Yuan, Jian-Yang (Osum Oil Sands Corp.)
Abstract The difficulties of accurately measuring thermal properties, such as thermal conductivity of fractured and/or vuggy rocks are well known. Many commercially available methods are suitable only for liquids or re-packed sands. Others either require samples to be fairly uniform or are potentially destructive due to sample size limitations. In-situ measurements are possible, but can be costly. It can also be affected by in-situ distributions of fluids in the fractures and vugs, such as water, oil and possibly gas. In order to adapt the highly non-uniform nature of the carbonate cores without having to create further destruction of these cores, we developed a non-destructive method for measuring thermal conductivity of highly vuggy and moderately fractured carbonate cores in their whole diameter. In this paper, we report the theoretical background of this methodology; laboratory observations of thermal behaviours; data analysis and resulting thermal conductivity values of carbonates cores. Using this method, we measured 20 cleaned carbonate cores (88 mm in diameter) from Grosmont C and D Formation in Saleski area. Measured thermal conductivity values ranged from 1.00 to 2.87 W/m•K in Grosmont C, and 0.82 to 3.16 W/m•K in Grosmont D. These values were determined to be a strong function of porosity rather than mineralogy, as the Grosmont Formation typically consists of greater than 95% dolomite. These measurements are also shown to be in good agreement with prior studies on non-fractured dolomite reservoirs. A correlation for thermal conductivity was derived which can be used for numerical simulation models.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.47)
- Geology > Mineral > Silicate (0.46)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.46)
- North America > Canada > Yukon > Beaufort-Mackenzie Basin (0.99)
- North America > Canada > Northwest Territories > Beaufort-Mackenzie Basin (0.99)