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Collaborating Authors
Results
Near-Wellbore and Reservoir Effects in In-Situ Combustion
Chavez, Mario-Luis Rodriguez (OMV) | Glatz, Guenther (Stanford University) | Clemens, Torsten (OMV) | Kovscek, Anthony (Stanford University)
Summary To operate fields under in-situ combustion (ISC), the near-wellbore dynamics and far-field conditions have to be considered. In the near-wellbore region of vertical injection wells, the flow advancement of the combustion front is characterized by high velocities. Farther away from the injection wells, the advancement rate of the combustion front is much smaller. For a line-drive configuration, the advancement of the front slows down from several meters per day near the wellbore to several centimeters per day in the far-field region. To investigate the effects in the near-wellbore region and far-field conditions, laboratory experiments and simulations were performed and compared with the behavior of a Central European field produced by using ISC. The laboratory experiments covered the kinetics in the near-wellbore region as well as the far-field region by applying various heating rates and by preheating a kinetic cell before injecting air. The dynamic effects were investigated with a combustion tube. Mechanistic numerical simulation was based on the kinetics derived from the kinetic-cell experiments and applied to the combustion tube. The same set of conditions was then used to simulate the near-wellbore conditions in the Central European field and far-field conditions. The results show that, in the near-wellbore region, the advancement of the combustion front is fast compared with heat conduction ahead of the front. Hence, low-temperature-oxidation (LTO) reactions and high-temperature-oxidation (HTO) reactions, as derived from the kinetic-cell experiments, are occurring in different distances from the injection well. In the far field, heat conduction ahead of the front and the flow of hot combustion gases preheat the reservoir before oxygen arriving at the combustion front. For these conditions, LTO and HTO reactions are occurring at the same location. In the Central European field produced with ISC, the various operating conditions are shown at an example well. Four different phases of production can be seen: (1) oil production with cyclic steam stimulation (CSS), (2) shut-in of the well to stabilize the combustion front that is approaching, (3) oil-production response of the combustion front, and (4) conversion of the well for air injection. The air-injection rate is slowly increased to avoid too-high temperatures in the early-injection phase (faster advancement of the heat front than heat conduction). The distance of the wells is approximately 70โm to allow sufficient oil recovery per well and speed of the combustion front.
- Europe (1.00)
- North America > United States > California (0.28)
- Asia > India > Gujarat (0.28)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- Asia > India > Rajasthan > Cambay Basin (0.99)
- Asia > India > Gujarat > Cambay Basin > North Cambay Basin > Santhal Field (0.99)
Near Wellbore and Reservoir Effects in In-Situ Combustion
Chavez, Mario-Luis Rodriguez (OMV) | Glatz, Guenther (Stanford University) | Clemens, Torsten (OMV) | Kovscek, Anthony (Stanford University)
Abstract In addition to the physical processes relevant in conventional oil production, additional physical-chemical processes have to be considered for in-situ combustion. These processes include heat conduction, steam drive and the kinetics and thermodynamics of combustion. To determine the kinetic and thermodynamic parameters, kinetic cell and combustion tube experiments were performed. In this study, oil from a commercially producing in-situ combustion field was sampled. A newly developed kinetic cell was used which enabled performing experiments at various heating rates. The large range of heating rates is used for describing the reactions in the combustion tube and near-wellbore as well as for the conditions at the front in a larger distance from the wells. The near-wellbore during in-situ combustion is characterized by fast movement of the combustion front, large heating rates at a given location and spatial separation of low-and high temperature combustion reactions. Once the front propagates further away from the wells, the speed of the front reduces to less than 0.05 m/d. At this speed of the front, heat conduction ahead of the front warms the reservoir up without oxygen being present. Oxygen arriving at the front results in Low and High Temperature Oxidation occurring almost simultaneously. The far-field conditions were mimicked by pre-heating a kinetic cell prior to exposing it to air. These experiments showed that for these conditions, the high and low temperature oxidation reactions cannot be distinguished and could be approximated by a single reaction. This study shows that a simplified reaction scheme might be used to simulate the reservoir effects of combustion whereas for simulating the early phase of an in-situ combustion project, a more exhaustive set of chemical reactions might be required. The results of the study can be used to investigate the start-up phase of an in-situ combustion project (near-wellbore effect focus) and the effects during advancement of the combustion front in the reservoir. Using the example of a Central European field operated using in-situ combustion in a line-drive configuration, the near-wellbore and far field operational aspects are shown.
- Europe (1.00)
- Asia > India (0.93)
- North America > United States > California (0.68)
- North America > United States > Texas (0.46)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- Asia > India > Rajasthan > Cambay Basin (0.99)
- Asia > India > Gujarat > Cambay Basin > North Cambay Basin > Santhal Field (0.99)
A Simplified Model for Field-Scale Surfactant-Polymer Flooding
Thirawarapan, Chanya (Stanford University) | Thiele, Marco R. (Stanford University, Streamsim Technologies) | Kovscek, Anthony (Stanford University) | Batycky, Rod (Streamsim Technologies) | Clemens, Torsten (OMV E&P)
Abstract Modeling surfactant/polymer (SP) flooding at the field scale remains challenging despite a significant body of experimental and numerical work over past decades uncovering the flow physics associated with this particular chemical flooding approach and its modeling. In our work, we investigate a two-parameter model (the ฯ(CS)-model) relating surfactant concentration directly to the miscibility factor used to modify phase residuals and shapes of the relative permeability functions in SP-flood modeling. We find that despite its simplicity, the ฯ(CS)-model for miscibility factor is able to reproduce results using the prevalent capillary desaturation curve approach (CDC-model). We first study a synthetic, two-dimensional reservoir with three injectors and three producers and then apply our approach to a realistic three-dimensional field example. We use streamline simulation to model the fluid flow in the reservoir, although the miscibility factor model is not limited to streamline simulation. The main feature of the ฯ(CS) model is that the miscibility factor is only a function of surfactant concentration rather than surfactant concentration and Darcy velocity as in the CDC-model. While simpler models, such as the one proposed here are not predictive for core-scale simulations, simple models are the only practical way to find near-optimal solutions under the constraint of geological uncertainty, poor data, and many wells.
- Asia (0.68)
- North America > United States > Texas (0.46)
- North America > United States > Oklahoma (0.28)
Flow of Polyacrylamide Polymers in the Near-Wellbore-Region, Rheological Behavior within Induced Fractures and Near-Wellbore Area
Zechner, Markus (OMV E&P) | Buchgraber, Markus (Stanford University) | Clemens, Torsten (OMV E&P) | Gumpenberger, Thomas (OMV E&P) | Castanier, Louis M. (Stanford University) | Kovscek, Anthony R. (Stanford University)
Abstract The economics of polymer solution injection projects are dependent on the improvement of displacement efficiency over waterflooding, the injectivity of polymer solutions, and reduced lifting costs associated with oil production and reduced water cut. High molecular weight polyacrylamide polymers show shear-thinning behavior when measured in a rheometer while they show shear-thickening behavior in cores. Micromodel experiments were used to investigate the rheological properties of polyacrylamide polymers at the high flow velocity conditions occurring in the near-wellbore region of wells. The results show shear-thickening characteristics. In addition, some plugging of the models by polymers was observed despite filtering of solutions. Also, core flood tests were performed. For the core-flood tests, severe degradation of the polymers was observed for high flow velocities. The data gathered from the experiments was used to interpret the results of a polymer solution injection test performed in the 8 Torton horizon reservoir in Austria. Shear-thickening behavior of the polymers would lead to very high well-head pressures. Through introduction of the degraded polymer viscosity data obtained from the laboratory experiments, the injection pressure observed in the field is explained. The field test showed that after a first phase of polymer solution injection under matrix conditions, a second phase with injection above the formation parting pressure (FPP) exists. To investigate the polymer rheology during this phase, micromodel experiments with various fracture geometries were conducted. The results show that within the induced fractures, polymer solutions show shear-thinning behavior and no substantial degradation of the polymers is seen. Owing to the low flow velocities through the fracture planes into the formation, also within the formation, no severe degradation of the polymers is expected. Hence, high molecular weight polyacrylamide polymers should be injected above the FPP when high flow velocities are expected in the near-wellbore region and such injection is permissible.
- Europe > Austria (0.68)
- North America > United States > Texas (0.47)
- Europe > Austria > Vienna > Vienna Basin (0.99)
- Europe > Austria > Vienna Basin > Matzen Field (0.99)
- Europe > Austria > Lower Austria > Vienna Basin (0.99)
Pore-Scale Evaluation of Polymers Displacing Viscous OilโComputational-Fluid-Dynamics Simulation of Micromodel Experiments
Clemens, Torsten (OMV) | Tsikouris, Kostas (Icon) | Buchgraber, Markus (Stanford University) | Castanier, Louis (Stanford University) | Kovscek, Anthony (Stanford University)
Summary The recovery of viscous oil can be significantly improved by injecting polymer solutions. The processes leading to increased oil production occur on a large scaleโimproving vertical and areal sweep efficiencyโbut they begin on a microscale. Micromodels with realistic pore geometries have been created. These micromodels were saturated with viscous oil, and the displacement of the oil by water and polymer solutions was investigated experimentally. Polymer injection reduced fingering compared with water injection and increased sweep efficiency accordingly. The micromodel pore-network geometry was digitized with scanning electron microscopy (SEM). The digitized model was used to perform computational-fluid-dynamics (CFD) simulation of the displacement processes. The displacement efficiencies and displacement patterns of the CFD simulations with water, polymer solutions, and polymer solutions after water breakthrough at the outlet end to displace oil were very similar to the results of the micromodel experiments. Then, the CFD simulations were used to investigate the displacement at the pore scale. Water injection leads to the creation of fingers along slightly more-permeable flow paths. The number and length of the fingers decrease if polymer solution is injected. Even for polymer injection after water breakthrough, the fingering is reduced, polymer solutions are diverted into less-favorable flow paths, and sweep efficiency is increased. CFD simulations can also be used to look into non-Newtonian fluid behavior at the pore scale. The polymers injected in the micromodel experiments exhibited shear-thinning behavior. On a pore scale, CFD simulations showed that the shear stress and viscosity of the polymer solutions accordingly are significantly lower in the pore throats than in the pores. Thus, the displacement efficiency of the polymer solutions is affected by the shear-thinning behavior. The CFD simulations are in remarkable agreement with the micromodel experiments and can be used to quantify the displacement processes at pore scale.
- Europe (1.00)
- Asia (1.00)
- North America > United States > California (0.47)
- North America > United States > Texas (0.46)
Pore-Scale Evaluation of Polymers Displacing Viscous Oil โ Computational Fluid Dynamics Simulation of Micromodel Experiments
Clemens, Torsten (OMV) | Tsikouris, Kostas (Icon) | Buchgraber, Markus (Stanford University) | Castanier, Louis (Stanford University) | Kovscek, Anthony (Stanford University)
Abstract Recovery of viscous oil can be significantly improved by injecting polymer solutions. The processes leading to increased oil production occur on a large scale โ improving vertical and areal sweep efficiency โ but they begin on a micro scale. Micromodels with realistic pore geometries have been created. These micromodels were saturated with viscous oil and the displacement of the oil by water and polymer solutions investigated experimentally. Polymer injection reduced fingering compared with water injection and increased sweep efficiency accordingly. The micromodel pore network geometry was digitised using Scanning Electron Microscopy (SEM). The digitised model was used to perform Computational Fluid Dynamics Simulations (CFD) of the displacement processes. The displacement efficiencies and displacement patterns of the CFD simulations using water, polymer solutions, and polymer solutions after water breakthrough at the outlet end to displace oil were very similar to the results of the micromodel experiments. Then, the CFD simulations were used to investigate the displacement at the pore scale. Water injection leads to creation of fingers along slightly more permeable flowpaths. The number and length of the fingers decreases if polymer solution is injected. Even for polymer injection after water breakthrough, the fingering is reduced, polymer solutions are diverted into less favourable flow paths and sweep efficiency is increased. CFD simulations can also be used to look into nonNewtonian fluid behaviour at the pore scale. The polymers injected in the micromodel experiments exhibited shear-thinning behaviour. On a pore scale, CFD simulations showed that the shear stress and viscosity of the polymer solutions accordingly are significantly lower in the pore throats than in the pores. Hence, the displacement efficiency of the polymer solutions is impacted by the shear-thinning behaviour. The CFD simulations are in remarkable agreement with the micromodel experiments and can be used to quantify the displacement processes at pore scale.
- Asia (0.93)
- North America > United States > California (0.47)
- North America > United States > Texas (0.47)
The Displacement of Viscous Oil by Associative Polymer Solutions
Buchgraber, Markus (Mining U of Leoben) | Clemens, Torsten (OMV Exploration/Production Ltd) | Castanier, Louis Marie (Stanford University) | Kovscek, Anthony Robert (Stanford University)
Abstract About half of world oil production results from waterflooding. The remaining resources, however, are more viscous and less amenable to waterflood as conventional oil reserves are produced. In offshore and Arctic environments improved methods of cold production for viscous oil are needed because the introduction of heat to thin viscous oil appears to be unlikely. Unfavorable mobility ratio and sweep is modified by use of polymer solutions. Of the various EOR polymer formulations, newly developed associative polymers show special promise. We investigate pore and pore network scales because polymer solutions ultimately flow through the pore space of rock to displace oil. We conduct and monitor optically water/oil and polymer solution/oil displacements in a two-dimensional etched-silicon micromodel. The micromodel has the geometrical and topological characteristics of sandstone. Conventional hydrolyzed polyacrylamide solutions and newly developed associative polymer solutions with concentrations ranging from 500 ppm to 2500 ppm were tested. The crude oil had a viscosity of 210 cP at test conditions. Our results provide new insight regarding the ability of polymer to stabilize multiphase flow. At zero and low polymer concentrations, relatively long and wide fingers of injectant developed, leading to early water breakthrough and low recoveries. At increased polymer concentration, a much greater number of relatively fine fingers formed. The width to length ratio of these fingers was quite small and the absolute length of fingers decreased. At a larger scale of observation, the displacement front appears to be stabilized; hence, recovery efficiency improved remarkably. Above a concentration of 1500 ppm, plugging of the micromodel by polymer and lower oil recovery was observed for both polymer types. For tertiary polymer injection that begins at breakthrough of water, the severe fingers resulting from water injection are modified significantly. Fingers become wider and grow in the direction normal to flow as polymer solution replaces water. Apparently, improved sweep efficiency of viscous oils is possible (at this scale of investigation) even after water flooding. The associative and conventional polymer solutions improved oil recovery by about the same amount. The associative polymers, however, showed more stable fronts in comparison to conventional polymer solutions. Introduction Effective polymers for high salinity environments and chemical costs are major concerns when modifying the viscosity characteristics of aqueous injectants for oil recovery. So-called associative polymers have been tested in this study. The term associative polymer is a broad classification (Glass, 2000). Here, we refer to water-soluble associative polymers that have undergone some hydrophobic modification so that they contain both water-soluble (hydrophilic) and water-insoluble components of varying levels of hydrophobicity. Associative polymers possess a unique thickening mechanism and most are environmentally benign. Broadly speaking, polymer networks form in solution and consist of intra- and inter-molecular hydrophobic junctions (Tripathi et al., 2006). These polymers hold the promise of high resistance against salinity and greater in-situ viscosities (Fig.1) in comparison to conventional polymers at similar concentrations. Buckley and Leverett displacement theory (Lake, 1989) assumes that water displaces oil with a piston-like shock followed by a rarefacting water saturation. Viscous fingers, however, are common features of unstable displacements where water is more mobile than oil. In general, viscous fingers refer to the onset and evolution of instabilities that evolve during the displacement of fluids in a porous system. Most often instabilities are linked to mobility differences between phases. Because mobility is inversely related to phase viscosity, viscous structures typically consist of fingers invading into the displaced fluid and propagating through the porous medium and leaving clusters of the displaced fluid behind. Clearly, heterogeneities in rock exacerbate unstable displacement.
- North America > United States (0.47)
- Europe (0.46)
- Asia > China (0.28)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Viscous Oil Displacement via Aqueous Associative Polymers
Aktas, Fitiz (University of Leoben) | Clemens, Torsten (OMV Exploration/Production Ltd) | Castanier, Louis M. (Stanford University) | Kovscek, Anthony Robert (Stanford University)
Abstract This study investigates the pore-level displacement of medium viscosity oil (200 cP) by brine and aqueous solutions of associative polymers. Associative polymers result in greater aqueous phase viscosities at the same concentration as conventional polymers. Studies are conducted in two-dimensional etched-silicon micro-models under a reflected light microscope. The pore network pattern of the micro-model replicates Berea sandstone. Results include the sweep pattern, oil recovery, and the pore-level distribution of residual oil. Generally, we find that brine and conventional polymer solutions at low concentrations result in severe fingering of the displacing fluid through the oil phase. Associative polymers lead to more stable displacement characteristics, apparently due to greater phase viscosity. Additionally, injection of associative polymers after breakthrough of brine mitigates fingering and improves viscous oil displacement. Experimental results show that associative polymers are a promising method to improve the displacement efficiency of viscous oils. Introduction Waterflooding accounts for about half of all oil recovered, but is generally limited to lighter oils with relatively low in-situ viscosity. A large number of fields holding viscous crude oil exist world-wide. These fields suffer from low recovery factors due to unfavorable mobility ratios in addition to low oil-phase mobility. Application of water injection for viscous oil recovery suffers from the high mobility of water leading to unstable displacement (Riaz et al., 2007). Heterogeneities in reservoir rock exacerbate unstable displacement. Nevertheless, for some situations such as Arctic and offshore reservoirs with viscous oils, there are perceived to be relatively few recovery process options except a water-based injectant. Addition of polymer to injection water reduces injected-phase mobility and provides a first-order solution to the problem of unstable displacement. Injection of viscous aqueous polymer solutions to improve volumetric sweep efficiency is a relatively mature concept. The extensive survey of Manning et al (1983) summarized field results of more than 250 polymer augmented water floods. Over the past decade, interest in polymer flooding has seen a resurgence and the oil volumes produced that are attributed to polymer flooding have grown, Principally, in the Daqing field (China), more than 250,000 bbl/d are produced by polymer injection and incremental oil recovery of up to 14 % is reported (Chang et al., 2006; Yupu and He, 2006). The mechanisms of polymer enhanced oil recovery have been studied with various methods and on various scales. Hele Shaw cells were used to visualise displacement of unfavorable mobility ratio floods (Benham and Olson, 1963; Allen and Boger, 1988). The processes involved in unstable flooding have been described theoretically (Sorbie et al., 1987; Araktingi and Orr, 1993) and examined experimentally (Tang and Kovscek, 2005; Riaz et al., 2007). The advantages of a stable displacement on volumetric sweep have been shown (for example) via streamline simulation (Wang et al, 1999) and field applications of polymer floods were simulated to improve interpretation of flood dynamics (Takaqi et al., 1992). A major cost for polymer injection projects is that of the polymer. In a typical application, 1 kg of polymer may be required to produced 1 m of incremental oil (i.e., 2.84 bbl oil / lb polymer) (Lake, 1989) Hence, an economical polymer should be injected resulting in the greatest oil recovery at the lowest polymer concentration.
- North America > United States (1.00)
- Asia > China > Heilongjiang Province > Daqing (0.24)
- Europe > France > Chateaurenard Field (0.99)
- Europe > Austria > Vienna Basin > Pirawarth Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)