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Results
Enhancing Waterflooding Performance Using a combined Data Driven and Physical Modeling Approach
Grijalva, R. (SLB, Quito, Pichincha, Ecuador) | Tellez, C. (SLB, Quito, Pichincha, Ecuador) | González, C. (SLB, Quito, Pichincha, Ecuador) | Parra, J. (SLB, Quito, Pichincha, Ecuador) | Eremiev, F. (SLB, Quito, Pichincha, Ecuador) | Florez, F. (SLB, Abingdon, Oxfordshire, United Kingdom) | Frorup, M. (SLB, Abingdon, Oxfordshire, United Kingdom) | Khataniar, S. (SLB, Abingdon, Oxfordshire, United Kingdom) | Biniwale, S. (SLB, Abingdon, Oxfordshire, United Kingdom) | Elfeel, M. (SLB, Abingdon, Oxfordshire, United Kingdom) | García-Teijeiro, X. (SLB, Abingdon, Oxfordshire, United Kingdom)
Abstract The waterflooding implementation in an Amazonian oil field has been a game-changer in the field development strategy, becoming the main production drive mechanism and investment focus. About 40% of the daily oil production comes from waterflooding projects. Hence, it is imperative to preserve integrated reservoir and field operation management through a customized pattern balancing methodology that accounts for a need to optimize the injection-extraction relationship minimizing early water breakthrough and avoiding operational issues. This article presents a waterflooding pattern analysis tool that combines data-driven and physics-based Machine Learning models with a smart optimization workflow. This publication focuses on the theoretical foundation of the deployable prototype, which is based mainly on the application of an innovative physics data driven and ML model as well as its testing procedure. The tool has been tested in an area with nine deviated water injector wells and thirty-six deviated/horizontal producer wells, enabling quick analysis response based on different What-If and optimization scenarios. Users can assess the impact on production and waterflooding response by modifying operational parameters such as injection rates or liquid flow rates, or how to react if an oil-producing/water-injection well fails. The engineering and operation teams use and share a tool that avoids personalized spreadsheets with off-dated information and non-auditable metrics behind the results. The data preparation capabilities of the new tool speed up the interaction of data-driven and physics models and make a more efficient data flow process integrated with Capacitance Resistance Model (CRM) (Yousef et al. 2005) analytic model. The teams experienced a step-change in productivity by reducing a complete iteration analysis from 23 to 5 hours. The optimization workflow generates possible injector-producer relationships for pattern analysis and short (weekly) and mid-term (90-day) forecasts. Users can test different scenarios, choose the optimum, and submit subsurface focused well-operating recommendations to field operations.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.35)
- South America > Ecuador > Oriente Basin (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (22 more...)
Pressure-Transient Analysis for Waterflooding with the Influence of Dynamic Induced Fracture in Tight Reservoir: Model and Case Studies
Wang, Zhipeng (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum (Beijing)) | Ning, Zhengfu (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum (Beijing) (Corresponding author)) | Guo, Wenting (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum (Beijing)) | Cheng, Qidi (Xinjiang Oil Field Company)
Summary It is well known that waterflooding will create fractures. The created fractures are divided into hydraulic fractures (artificial fractures with proppant) and induced fractures (formed during waterflooding without proppant). There is no proppant in the induced fracture, so it will close as the pressure decreases and extend as the pressure increases. We call it a dynamic induced fracture (DIF). Because of reduced pressure, the DIF will be closed during the shut-in pressure test (well testing). The current conventional well-testing model cannot describe the dynamic behavior of the DIF, resulting in obtaining unreasonable parameters. Thus, this work proposes a DIF model to characterize the DIF behavior during well testing (the injection well will shut in, resulting in a reduction in bottomhole pressure and induced-fracture closure). It is worth noting that a high-permeability zone (HPZ) will be formed by long-time waterflooding and particle transport. The HPZ radius will be greater than or equal to the DIF half-length because the waterflooding pressure can move particles but not necessarily expand the fracture. The point source function method and Duhamel principle are used to obtain the bottomhole pressure response. Numerical simulation methods are used to verify the accuracy of the model. Field cases are matched to demonstrate the practicability of the DIF model. Results show a straight line with a slope greater than the unit, a peak, a straight line with a slope less than one-half, and an upturned straight line on the pressure derivative curve. This peak can move up, down, left, and right to characterize the induced fracture’s dynamic conductivity (DC). The straight line with a slope greater than the unit can illustrate a fracture storage effect. The straight line with a slope less than one-half can describe the closed induced-fracture (CIF) half-length. The upturned straight line can describe the HPZ and reservoir permeability. The obtained parameters will be inaccurate if they are incorrectly identified as other flow regimes. Field cases are matched well to illustrate that identifying the three innovative flow regimes can improve the parameters’ accuracy. In conclusion, the proposed model can characterize the dynamic behavior of induced fracture, better match the field data, and obtain more reasonable reservoir parameters. Finally, two field cases in tight reservoir are discussed to prove its practicality.
- Asia (1.00)
- North America > United States > Texas (0.46)
- Europe > United Kingdom > North Sea (0.28)
- North America > United States > Louisiana > Hudson Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 23/27 > op (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 23/22a > op (0.99)
- (6 more...)
- Well Completion > Hydraulic Fracturing (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)
- (3 more...)
Proxy Capacitance-Resistance Modeling for Well Production Forecasts in Case of Well Treatments
Gubanova, Anna (Skolkovo Institute of Science and Technology (Corresponding author)) | Orlov, Denis (Skolkovo Institute of Science and Technology and LLC Digital Petroleum) | Koroteev, Dmitry (Skolkovo Institute of Science and Technology and LLC Digital Petroleum) | Shmidt, Sergei (Salym Petroleum Development N.V.)
Summary We disclose a new-age field-scale production forecast model that handles complex treatment of wellbores during their life cycle. Predictive production models have been an object of increased interest and research for a long time due to the need for a fast tool for forecasting production rates or choosing an optimal field development scheme. The existing approaches based on the material balance equation have several limitations and are not very applicable for real objects. Full-scale reservoir modeling is relatively slow and requires large computing resources. In this paper, we propose a proxy model based on advanced capacitance-resistance approach. The model predicts multiphase flow rates based on the available historical data of field production and information about well treatments. In addition, it provides preferable transmissibility trends, the presence of sealed or leaking faults, and the degree of dissipation between injector-producer well pairs. The advanced feature of the model is time-dependent weight coefficients, which have not been studied previously. They help in accounting the shut-in and workover periods and can be found during the optimization procedure simultaneously. Another feature is fast calculations due to a vectorized form of the model and application of modern optimization techniques. All these options allow modeling real oil fields with a large number of wells and a complex system of production control. Introduction The whole period of reservoir development consists of three stages: primary, secondary, and tertiary recovery. A common process to maintain pressure is waterflooding (secondary recovery) or natural gas injection (tertiary recovery). To complete a reservoir modeling at the stage of secondary production, there is a need to reveal the geological properties of the reservoir system. For that, one has to identify the presence or absence of faults, the distribution, orientation, and length of high-and low-permeability layers.
- North America > United States > California (0.28)
- North America > Canada > Alberta (0.28)
Contribution of the Water Weakening Effect to Plastic Strain: Case Studies from Danish North Sea Chalk Fields
Amour, F. (Danish Offshore Technology Centre, Danish Technical University) | Hajiabadi, M. R. (Danish Offshore Technology Centre, Danish Technical University) | Nick, H. M. (Danish Offshore Technology Centre, Danish Technical University)
ABSTRACT: The experimental studies highlighting the strength weakening of chalk when water replaces oil in pore space have incited geomodellers to systematically solve for the effect of water saturation on chalk strength at each simulation step to estimate reservoir compaction. The present study demonstrates quantitatively for the first time the important role played by the water weakening effect on the deformation of several producing fields in the Danish North Sea. Although non-negligible, the water weakening effect in the studied fields is caused by the initial water saturation of chalk rather than by its changes through time. Representative of numerous Danish North Sea reservoirs, the outcome of this study suggests that a preliminary assessment of the potential magnitude of the water weakening effect during production should be first performed prior to compaction simulation. If considered negligible, the adjustment of the rock strength according to the saturation conditions at each simulation step can be ignored, thereby reducing the computing time required to perform coupled geomechanical and fluid flow modelling. 1. INTRODUCTION Waterflooding of reservoir is a common stimulation technique to enhance the recovery factor of hydrocarbon fields within chalk intervals of the North Sea. The resulting increase in water saturation in pore space leads to a softening of the mechanical properties of the rock, such as the pore collapse stress, a process referred to as the water weakening effect. This process has been extensively studied in laboratory during the last three decades and the underlying mechanisms are still under debate. Nevertheless, the adsorption of ions and water molecules from the aqueous phase at the surface of calcite particles that involves an additional repulsive force between grains favouring grain -to-grain slippage is commonly pointed out as the main mechanisms. Laboratory studies have shown that the pore collapse stress of oil-saturated outcrop samples is consistently reduced by 50-60% when saturated with water, thereby causing additional strain. Triaxial tests conducted on core samples from the North Sea have also demonstrated the dependency of the pore collapse stress to water saturation.
- Research Report > New Finding (0.74)
- Research Report > Experimental Study (0.74)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.51)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > Block 2/8 > Valhall Field > Tor Formation (0.99)
- (11 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Integration of geomechanics in models (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)