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Abstract A live oil sample was subjected to a solid detection system (SDS) to measure asphaltene onset point (AOP) at 3850 psi, and asphaltene content of 1.3%. A high-resolution digital camera was used to measure asphaltene particle size distribution. The result showed that asphaltene particles were not uniform in size, but has a normal distribution of 100–120 μm. Asphaltene reversibility to dissolved back into the oil with increasing pressure was only 35% of the original deposition. Two core samples were examined for formation damage due to asphaltene deposition. A Low permeability core showed significant permeability reduction exceeding 50% of its baseline permeability, and the higher permeability core showed less permeability decline, even with the same asphaltene precipitation.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.47)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Abstract The purpose of this paper is to provide a more relevant solution to the diffusivity equation than the conductive disc/zero potential flow (Exponential Integral) solution, especially for use in predictions of the time that is required for an interference effect to reach an observation well. After explaining the assumptions and theory behind the method, a direct integration of the radius of investigation will be presented, along with a physical explanation of what it is. While presenting multiple examples to support the theory, the results from Exponential Integral method for predicting interference arrival at an observation well will be compared. Finally, it will be demonstrated that the classic radius of investigation equation is more appropriate in interference/communication testing, and that rate, gauge resolution, and the total system pressure drop do not affect the arrival of the interference effect.
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (0.94)
Modeling and Simulation of Nanoparticle Transport in Multiphase Flows in Porous Media: CO2 Sequestration
El-Amin, M. F. (King Abdullah University of Science and Technology) | Sun, Shuyu (King Abdullah University of Science and Technology) | Salama, Amgad (King Abdullah University of Science and Technology)
Abstract Geological storage of anthropogenic CO2 emissions in deep saline aquifers has recently received tremendous attention in the scientific literature. Injected CO2 plume buoyantly accumulates at the top part of the deep aquifer under a sealing cap rock, and some concern that the high-pressure CO2 could breach the seal rock. However, CO2 will diffuse into the brine underneath and generate a slightly denser fluid that may induce instability and convective mixing. Onset times of instability and convective mixing performance depend on the physical properties of the rock and fluids, such as permeability and density contrast. The novel idea is to adding nanoparticles to the injected CO2 to increase density contrast between the CO2-rich brine and the underlying resident brine and, consequently, decrease onset time of instability and increase convective mixing. As far as it goes, only few works address the issues related to mathematical and numerical modeling aspects of the nanoparticles transport phenomena in CO2 storages. In the current work, we will present mathematical models to describe the nanoparticles transport carried by injected CO2 in porous media. Buoyancy and capillary forces as well as Brownian diffusion are important to be considered in the model. IMplicit Pressure Explicit Saturation-Concentration (IMPESC) scheme is used and a numerical simulator is developed to simulate the nanoparticles transport in CO2 storages.
ABSTRACT: The reservoir rock characterization is essential for definition of exploitable hydrocarbon content zone, identifying storage and flow capacity. Therefore a methodology was designed adapted to characteristics and conditions of Cerro Negro field. The Cerro Negro field is located in Carabobo block at the Orinoco Belt Oil, in basin eastern Venezuela, characterized by unconsolidated sands and extra heavy oil. The methodology applied is based on integration different rock characterization techniques : rock type determination by the cluster analysis, Winland and Pittman method's by pore throat size, additionally, it was applied the Kozeny-Carman equation's to determine rock quality index (RQI) and flow zone index (FZI) and obtain the hydraulic units. The aim of apply several techniques is to use the most of the available data, for crosscheck and adjust the rock types differentiated over the column the hydrocarbon, to decrease the uncertainty related to the reservoir rock quality and the hydraulics units. Moreover, the results were validated with vertical and horizontal wells production tests. The study was carried out with 93 vertical wells of the field, among them, 8 wells with conventional and special core analysis. The petrophysics properties (porosity, permeability and water saturation) were obtained through conventional deterministic evaluation (log interpretation), calibrated with core data and mercury injection capillary pressure (MICP). Cerro Negro Field is located in Carabobo Block in Orinoco Heavy Oil Belt at Eastern Venezuela Basin, reservoirs are characterized by unconsolidated sand with extra heavy oil of 8 API (Figure 1). The stratigraphic framework is represented from the base to the top is: Oficina Formation (aged Early Miocene), Freites, Formation, Middle Miocene, Las Piedras Formation (aged upper Miocene) and Mesa Formation (aged Pleistocene-Pliocene). The producing interval is the Morichal Member of Oficina Formation, Morichal Member is divided operationally in three units: Upper Morichal, Middle and Lower Morichal.
- South America > Venezuela > Anzoátegui (1.00)
- South America > Argentina > Santa Cruz Province (1.00)
- South America > Argentina > Mendoza Province (1.00)
- (2 more...)
- Geology > Geological Subdiscipline > Stratigraphy (0.35)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.30)
Research and Application of Nano Polymer Microspheres Diversion Technique of Deep Fluid
Tian, Yuqin (Yangtze University Petroleum Engineering College) | Wang, Lushan (Shengli Oilfield Oil Production Technology Institute) | Tang, Yanyan (Shengli Oilfield Oil Production Technology Institute) | Liu, Chengjie (Shengli Oilfield Oil Production Technology Institute) | Ma, Chao (Yangtze University Petroleum Engineering College) | Wang, Tao (Shengli Oilfield Oil Production Technology Institute)
Abstract Nano polymer microspheres are a new oil profile control system, which can be adjusted according to the formation pore throat. After hydration and swelling, the microspheres would reach the designed size and have relatively strong intensity. When the size of the microspheres is bigger than that of the formation pore throat or bridged blockage is formed, reliable blockage can be formed. The microspheres are elastic, which can deform and move forward under certain pressure, so that fluid diversion can be realized step by step and the request of movable agent is satisfied. The microspheres can resist high temperature to 110°C and high salinity to 200000mg/L (Ca+Mg=3000 mg/L). To test its effect, this polymer microspheres technology is used at a serious heterogeneous and high temperature reservoir. The temperature of the test block is 98°C, and the salinity of injection water is 16380mg/L. The average permeability is 932×10μm, and the permeability contrast is obvious (high permeability is 4μm, low permeability is 0.8μm). Therefore, two sizes of microspheres are designed. The combination system of polymer microspheres and surfactant are injected, and the system is divided into five slugs. Double tubes physical modeling experiments are done, and the results show that the block off capacity of this design is competent, increasing oil recovery dramatically. Thanks to the accordant microspheres design and the rational injection design, this polymer microspheres technology has become the effective method for profile control and water plugging to serious heterogeneous and high temperature reservoirs.
Modeling and Simulation of Nanoparticles Transport in a Two-Phase Flow in Porous Media
El-Amin, M. F. (King Abdullah University of Science and Technology (KAUST)) | Salama, A.. (King Abdullah University of Science and Technology (KAUST)) | Sun, S.. (King Abdullah University of Science and Technology (KAUST))
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE International Oilfield Nanotechnology Conference held in Noordwijk, The Netherlands, 12-14 June 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited.
- North America > United States (1.00)
- Europe > Netherlands > South Holland > Noordwijk (0.24)
Study of Particle Straining Effect on Produced Water Management and Injectivity Enhancement
Aji, K.. (Australian School of Petroleum, The University of Adelaide, Australia) | You, Z.. (Australian School of Petroleum, The University of Adelaide, Australia) | Badalyan, A.. (Australian School of Petroleum, The University of Adelaide, Australia) | Bedrikovetsky, P.. (Australian School of Petroleum, The University of Adelaide, Australia)
Abstract Theoretical and laboratory studies are performed aiming at the development of a predictive model for transport and retention of particles from produced water and crude oil/gas based on grain size distribution and particle sizes only. The particle capture by straining is thoroughly investigated. In the laboratory, injections of different sized particles suspended in fluid with different salinity and pH values have been carried out into the newly designed porous media holder with single-layer grains and into the column packed engineering porous media. The retained particles are filmed using microscope; their breakthrough concentrations are measured by particle counter. A new mathematical model accounting for pore connectivity and triangular pore throat shape is derived and applied to the experimental conditions. Agreement between test data and modelling results supports application of the model to the evaluation of straining effect on the produced water management and injectivity enhancement.
- North America > United States (0.93)
- Europe (0.69)
- Water & Waste Management > Water Management (1.00)
- Energy > Oil & Gas > Upstream (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)
- Production and Well Operations > Well Operations and Optimization > Produced water management and control (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
- Information Technology > Modeling & Simulation (0.54)
- Information Technology > Data Science (0.34)
Abstract As discoveries of large new oilfields become a thing of the past, the residual oil in old oilfields becomes an increasingly important oil resource. Significant research and development efforts on increasing recovery have however yielded low results. We believe that the main reason for this is that the current models for how residual oil is trapped and mobilized are wrong. Several field observations have shown that mobilized residual oil moves more rapidly through the reservoir than the injected water assumed to be pushing it. This is not possible within the framework of current reservoir simulation models. We here present a new theory for the behaviour of residual oil in sandstone reservoirs. Based on field cases and a laboratory study we argue that the residual oil is collected in continuous oil strands extending from injector to producer and blocked only by water in a pore close to the producer. The blocking water of that pore throat can be removed by applying a pressure pulse to the oil strand or by reducing the capillary force that makes the water adhere to the wall of the pore throat. In a flooding experiment where the flow rate of oil and water was followed with oil and water soluble tracers, the results showed that oil moved 1000 times faster than the injection water through the core. Field observations involved oil fields, where analysis of H2S concentration at the producers showed that H2S had been transported with the oil and moved faster than the water through the reservoir. In an MEOR pilot increased oil production ceased almost immediately after the microbial activity was stopped, showing a continuous oil phase from injector to producer even under residual oil concentration. Applying this new knowledge can considerably increase the recovery from most oil fields.
- North America > United States (1.00)
- North America > Canada > Alberta (0.48)
- Research Report > New Finding (0.48)
- Overview (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral (1.00)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 089 > Block 34/7 > Tordis Field > Tarbert Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 089 > Block 34/7 > Tordis Field > Ness Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 089 > Block 34/7 > Tordis Field > Lunde Formation (0.99)
- (2 more...)
Abstract In mechanistic modeling of foam in porous media, reduced gas mobility is attributed to viscous resistance of flowing foam lamellas to gas flow, while gas trapping significantly modifies relative permeability. By using pore-network models representative of real porous media, we previously developed a relationship between flowing gas fraction and pressure gradient for strong foam (high lamella density). In this study, we expand our model to describe the effects of foam strength and pore-scale apparent gas viscosity models on both relative gas permeability and effective gas viscosity. Dimensional analysis in scaling of these two rheological quantities with pressure gradient and lamella density is discussed. One of our important findings is that relative gas permeability is poorly sensitive to total lamella density while it is a strong non-linear function of flowing gas fraction, opposing to most of the existing theoretical models describing the effect of gas trapping on relative gas permeability. This is consistently observed for all the pore-scale apparent gas viscosity models. It is also found that effective gas viscosity increases exponentially with flowing lamella density. This result implies that the use of the commonly used apparent gas viscosity model for straight capillary tubes is not accurate for foam flow in porous media. In addition, shear thinning foam flow is more obvious at high flowing lamella density while Newtonian flow becomes significant at relatively low flowing lamella density. Furthermore, scaling of effective gas viscosity with flowing lamella density depends on how the later quantity is defined. Both empirical and mechanistic pore-scale apparent gas viscosity models give almost the same functional relationship between flowing gas fraction and pressure gradient. This would facilitate scaling of flow rate with pressure gradient and testing a range of shear-thinning and yield-stress behavior in a simple format. Our results necessitate the need for further improving the existing mechanistic foam modeling methods with focus on process upscaling.
Abstract The permeability prediction is of extreme importance in hydrocarbon reservoir management. The reservoir rocks are made up of grains, cement and pore network. The pore network is made up of larger spaces, referred to as pores, which are connected by small spaces referred to as throats. The pore spaces control the amount of porosity, while the pore throats control the movement of fluids and the quantity of rock permeability. The core analysis data for 219 sandstone and limestone samples were available. The data include porosity, permeability and capillary pressure by mercury injection. These samples represent 21 stratigraphic units. The geologic age varied between Cretaceous and Pliocene. Sandstone reservoirs are represented by 179 samples, while 40 samples represent carbonate reservoirs. The data were collected from different geographic areas within Egypt. Pore-throat size distribution parameters were calculated from the data of capillary pressure. These data were used to approximate the distribution of pore volume accessible by throat of a given effective size. A new definition for micro-porosity was proposed based on pore throat size distribution. These data was used to descriminate the sample porosity into micro and macro porosity based on a pore throat cutoff, which was determined from the relationship between storage and flow capacity of the pore network. The relationship between permeability and aspects of pore geometry; micro-porosity, macro-porosity and pore throat parameters have been analyzed and discussed. The interpretation of the results indicates that the permeability is mainly a function of pore-throat size distribution while the amount of the porosity or the porosity configuration is not the main factor that controls the amount of permeability. A new model for permeability prediction was develpoed which incorporate the pore space and pore throat. The obtained results have shown the great influence of pore throat on permeability prediction.
- Africa > Middle East > Egypt (0.88)
- North America > United States (0.68)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.75)
- Asia > Middle East > UAE > Arab Formation (0.99)
- Africa > Middle East > Egypt > South Sinai Governorate > Lagia Field > Nukhul Formation (0.99)