Day 4 Thu, June 06, 2019最新文献

{"title":"Enhanced Recovery of Heavy Oil by a Nano-Catalytic In-Situ Upgrading Process","authors":"S. M. Elahi, Milad Ahmadi Khoshooei, C. Scott, L. Ortega, Zhangxin Chen, P. Pereira-Almao","doi":"10.2118/195474-MS","DOIUrl":"https://doi.org/10.2118/195474-MS","url":null,"abstract":"\u0000 Simultaneous in-reservoir upgrading and recovery of heavy oil are experimentally studied by using a continuous setup filled with carbonate cores. Upgrading reaction products as well as the recovered oil are analyzed in order to investigate the recovery mechanisms associated with this process.\u0000 In-situ upgrading technology (ISUT) is based on injection of high molecular weight (low quality) cut of oil, e.g., vacuum residue (VR), together with ultradispersed nano-catalyst and hydrogen. By injecting VR, catalyst, and hydrogen, the catalytic nano-particles deposit in the rock around an injection well, where the upgrading reactions occur. In this study, first, upgrading reactions happen inside a core packed container at the temperature, pressure, and residence time of 360 °C, 10 MPa, and 36 h, respectively. Subsequently, the hot reaction products are directed into another cylinder filled with carbonate cores to displace the heavy oil in place.\u0000 There are two main steps in a reservoir during ISUT. First, the injected VR is converted to lighter products during hydroprocessing reactions. Then the upgraded liquid and gaseous products along with hydrogen will displace the heavy oil toward production wells. At the conditions of this experiment in the reactor, 38 wt% of the VR cut is converted to lighter products with 1 wt% gases (mainly H2S and hydrocarbons with 1 to 5 carbon atoms) and 4.8 wt% naphtha cut (hydrocarbons with 5 to 12 carbon atoms). These light products act as solvents in the areas farther from the reaction zone and enhance the recovery of heavy oil. In addition, high temperatures, mechanical push, and rock matrix thermal expansion improve the oil displacement in the carbonate rock.\u0000 By enhancing the oil recovery and permanently upgrading heavy oil in one single stage, the need for diluent addition and steam generation is minimized, which makes ISUT economical and environmentally favorable. In an innovative experimental setup, both upgrading and recovery steps in the ISUT process are carefully analyzed.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"30 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122329587","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Simulation of Injectivity and Fracture Containment: Water Injection in a Turbidite Reservoir, Offshore Ghana","authors":"Jongsoo Hwang, M. Sharma, K. Amaning, A. Singh, S. Sathyamoorthy","doi":"10.2118/195567-MS","DOIUrl":"https://doi.org/10.2118/195567-MS","url":null,"abstract":"\u0000 Understanding injectivity is a critical element to ensure that sufficient volumes of water are being injected into the reservoir to maintain reservoir pressure, to ensure good reservoir sweep and minimize well remediation. It is, however, challenging to describe the large injectivity changes that are sometimes observed in injectors operating under fracturing conditions. This study presents a field case study with the following objectives: 1) explain the complicated injectivity changes caused by fracture opening/closure with injection-rate variations, 2) define a safe operating envelope (for injection pressure and rate) that ensures fracture containment and injection into the target zone, and 3) prescribe how the injection rate should be changed to achieve higher injectivities. Injector operating conditions are developed using results from a full 3-dimensional fracture growth simulation to ensure fracture containment in a multi-layered reservoir.\u0000 We present field injectivity observations, a comprehensive simulation workflow and its results to explain injector performance in a deep-water turbidite sand reservoir with multiple splay sands. Understanding the impact on fracture propagation and containment allows us to make quantitative suggestions for the operating envelopes for long-term injection-production management. Strategies for high-rate injection to sustain the injection well performance long-term are discussed.\u0000 Simulation results show that, at injection rates over 5,000 bwpd, injection induced fractures propagate. Fracture closure induced by injection shut-down is used to compute the bottom-hole pressure decline as a function of time. The fracture opening/closure events and the thermally induced stress were the primary factors impacting injectivity. The simulation results suggested several ways to improve the injectivity while ensuring fracture containment. Injection under fracturing conditions into a single zone at a high rate is shown to be feasible and this allows us to support a substantial increase in injectivity. This must, however, be done at pressures that will not cause a breach in the bounding shales. The 3-dimensional fracture simulations identified the operating pressure and rate envelope to maximize the injection rates while minimizing the risk of breaching the cap rock and inter-zone shales.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"22 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125174332","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Multiscale Integration for Karst Reservoir Flow Simulation Models","authors":"M. Correia, J. Hohendorff, D. Schiozer","doi":"10.2118/195545-MS","DOIUrl":"https://doi.org/10.2118/195545-MS","url":null,"abstract":"\u0000 The significant oil reserves related to karst reservoirs in Brazilian pre-salt field adds new frontiers to the development of upscaling procedures to reduce time on numerical simulations. This work aims to represent karst reservoirs in reservoir simulators based on special connections between matrix and karst mediums, both modeled in different grid domains of a single porosity flow model. This representation intends to provide a good relationship between accuracy and simulation time.\u0000 The concept follows the Embedded Discrete Fracture Model (EDFM) developed by Moinfar, 2013; however, this work extends the approach for karst reservoirs (Embedded Discrete Karst Model - EDKM) by adding a representative volume through grid blocks to represent karst geometries and porosity. For the extension of EDFM approach in a karst reservoir, we adapt the methodology to four stages: (a) construction of a single porosity model with two grid domains, (b) geomodeling of karst and matrix properties for the corresponding grid domain, (c) application of special connections through the conventional reservoir simulator to represent the transmissibility between matrix and karst medium, (d) calculation of transmissibility between karst and matrix medium.\u0000 For a proper validation, we applied the EDKM methodology in a carbonate reservoir with mega-karst structures, which consists of non-well-connected enlarged conduits and above 300 mm of aperture. The reference model was a refined grid with karst features explicitly combined with matrix facies, including coquinas interbedded with mudstones and shales. The grid block of the reference model measures approximately 10 × 10 × 1 meters. For the simulation model, the matrix grid domain has a grid block size of approximately 100 × 100 × 5 meters. The karst grid domain had the same block size as the refined grid. Flow in the individual karst grid domain or matrix grid domain is governed by Darcy's equation, implicitly solved by simulator. However, the transmissibility for the special connections between karst and matrix blocks is calculated as a function of open area to flow, matrix permeability and block center distance. The matrix properties were upscaled through conventional analytical methods. The results show that EDKM had a considerable performance regarding a dynamic matching response with reference model, within a reduced simulation time while maintaining a higher dynamic resolution in the karst grid domain without using an unconstructed grid.\u0000 This work aims to contribute to the extension of EDFM approach for karst reservoirs, which can be applied to commercial finite-difference reservoir simulators and it presents itself as a solution to reduce simulation time without disregarding the explicit representation of karst features in structured grids.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"56 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116374265","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"The Feasibility Appraisal for CO2 Injection and Storage in Condensate Gas Reservoir: Mechanism Studies and Case Analysis","authors":"Ying Jia, Shi Yunqing, Lei Huang, Jin Yan, Lei Sun","doi":"10.2118/195493-MS","DOIUrl":"https://doi.org/10.2118/195493-MS","url":null,"abstract":"\u0000 The YKL condensate gas reservoir is one of the biggest condensate gas reservoirs in China and has been developed more than 10years. At present, the combination of subdivision layer, production speed optimization and horizontal well drilling has been the key to economically unlocking the vast reserves of the YKL condensate gas. The primary recovery factor, however, remains rather low due to high capillary trapping and water invasion. While primary depletion could result in low gas recovery, CO2 flooding provides a promising option for increasing the recovery factor.\u0000 The objective of this work is to verify and evaluate the effect supercritical CO2 on enhancing gas recovery and analyze the feasibility of CO2 enhance gas recovery (CO2 EGR) of condensate gas reservoir.\u0000 Firstly, novel phase behavior experimental procedures and phase equilibrium evaluation methodology for gas-condensate phase system mixed with supercritical CO2 with high temperature were presented. A unique phase behavior phenomena was also reported. Then, CO2 floodingmechanism in condensate gas reservoir was analyzed and clarified based on experiments. Finally, a series of numerical simulation work were conducted as an effective and economical means to maximize natural gas recovery with the lowest CO2 breakthrough by varying strategies, including CO2 injection rate, injection composition, andinjection timing. Meanwhile the CO2 storage volumes of different strategies were calculated.\u0000 The results show that higher gas recovery factor can be achieved with CO2 injection through appearing interphase between two fluids, maintaining reservoir pressure, driving gas like \"cushion\" and controlling water invasion. All strategies have moderate to significant effects on gas production. The control of injection and production ratio needs to be balanced between pressure transient and CO2 breakthrough over the producer to obtain the maximum gas production. The varying injection pressure shows a positive effect of enhancing gas production. Numerical simulation indicated that the recovery of gas reservoir was improved by around 10 percent. The total CO2 storage would be around 30-40% HCPV.\u0000 The research showed that CO2 flooding presents a technically promising method for recovering the vast condensate gas while extensively reducing greenhouse gas emissions.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"24 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128684698","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Impact of Upscaling on Numerical Estimation of Polymer Increments","authors":"M. Bourgeois, J. Hild, R. Bursaux","doi":"10.2118/195556-MS","DOIUrl":"https://doi.org/10.2118/195556-MS","url":null,"abstract":"\u0000 Two upscaling exercises performed in 2013-14 and 2017-18 on two onshore green fields with conventional to viscous oil are presented, for which the upscaling tried to compensate the effects of grid coarsening, in particular the increase of numerical dispersion and the decrease of heterogeneity. Our methodology was to adjust the water/oil relative permeabilities called pseudo KRs in the coarse scale simulation, in order to reproduce the behavior in terms of pressure, rates, saturations and concentrations of the fine scale model, which was using microscopic rock KRs based on laboratory data.\u0000 As the upscaling depends on the fluid injected, it was done separately for waterflood and polymer flood. When done with polymer flood, the concentration of polymer had to be history matched also mainly by adjusting the Todd-Longstaff mixing parameter in addition to the KRs. As upscaling is case dependent, it was performed on several geological models, varying heterogeneity and grid size, but also rock KRs and even precocity of the polymer flood after some waterflood, to test the robustness of the approach.\u0000 It was found that pseudo-KRs for waterflood could be slightly degraded for viscous oils, whereas the upscaling was more neutral for conventional oils. This correlates well with field observation for viscous oils, where water production occurs generally a bit quicker than what numerical simulation predicts when using rock KRs, in absence of upscaling.\u0000 For polymer floods, which were considered in secondary or early tertiary mode, pseudo KRs were generally improved, mainly because the polymer steepened the saturation fronts, which can be well represented only with small lateral grid size.\u0000 The result of both upscaling exercises was that the increment of polymer flood versus waterflood was noticeably higher when computed on high resolution modelling. This is equivalent to saying that when using pseudo KRs resulting from this high resolution matching, the polymer increment on coarse grid is significantly higher than if computed without pseudo KRs. This improves the economic evaluation of the project, increasing the willingness to de-risk and implement early polymer floods on these fields.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"415 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"117301801","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Analytical Solution of Chemical Flooding in Heterogeneous Non-Communicating Layers With a Focus on Low Salinity Water Flooding","authors":"H. Al-Ibadi, K. Stephen, E. Mackay","doi":"10.2118/195446-MS","DOIUrl":"https://doi.org/10.2118/195446-MS","url":null,"abstract":"\u0000 As an enhanced oil recovery method (EOR), chemical flooding has been implemented intensively for some years. Low Salinity WaterFlooding (LSWF) is a method that has become increasingly attractive. The prediction of reservoir behaviour can be made through numerical simulations and greatly helps with field management decisions. Simulations can be costly to run however and also incur numerical errors. Historically, analytical solutions were developed for the flow equations for waterflooding conditions, particularly for non-communicating strata. These have not yet been extended to chemical flooding which we do here, particularly for LSWF. Dispersion effects within layers also affect these solutions and we include these in this work.\u0000 Using fractional flow theory, we derive a mathematical solution to the flow equations for a set of layers to predict fluid flow and solute transport. Analytical solutions tell us the location of the lead (formation) waterfront in each layer. Previously, we developed a correction to this to include the effects of numerical and physical dispersion, based on one dimensional models. We used a similar correction to predict the location of the second waterfront in each layer which is induced by the chemical's effect on mobility. In this work we show that in multiple non-communicating layers, material balance can be used to deduce the inter-layer relationships of the various fronts that form. This is based on similar analysis developed for waterflooding although the calculations are more complex because of the development of multiple fronts.\u0000 The result is a predictive tool that we compare to numerical simulations and the precision is very good. Layers with contrasting petrophysical properties and wettability are considered. We also investigate the relationship between the fractional flow, effective salinity range, salinity dispersion and salinity retardation.\u0000 This work allows us to predict fluids and solute behaviour in reservoirs with non-communicating strata without running a simulator. The recovery factor and vertical sweeping efficiency are also very predictable. This helps us to upscale LSWF by deriving pseudo relative permeability based on our extension of fractional flow and solute transport into such 2D systems.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"6 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132850775","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A History Matching Approach to Estimate Caprock Morphology Parameters for CO2 Storage in Saline Aquifers","authors":"Masoud Ahmadinia, S. Shariatipour, O. Andersen, Mahdi Sadri","doi":"10.2118/195507-MS","DOIUrl":"https://doi.org/10.2118/195507-MS","url":null,"abstract":"\u0000 To improve the reservoir simulation model, uncertain parameters such as porosity and permeability in the reservoir rock strata need to be adjusted to match the simulated production data with the actual production data. This process is known as History Matching (HM). In geological CO2 storage that is being promoted for use in depleted hydrocarbon reservoirs and saline aquifers, CO2 tends to migrate upwards and accumulate as a separate plume in the zone immediately beneath the reservoir caprock. Thus caprock morphology is of considerable importance with respect to storage safety and migration prediction for the purpose of long-term CO2 storage. Moreover, small scale caprock irregularities, which are not captured by seismic surveys, could be one of the sources of errors while matching the observed CO2 plume migration and the numerical modelling results (e.g. Sleipner). Thus here we study the impact of uncertainties in slope and rugosity (small scale caprock irregularities not captured by seismic surveys) on plume migration, using a history-matching process. We defined 10 cases with different initial guesses to reproduce the caprock properties representing an observed plume shape. The results showed a reasonable match between the horizontal plume shape in calibrated and observed models with an average error of 2.95 percentages","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"148 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134190364","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Validation and Improvement of Numerical Methods to Simulate the Well-Test Response of Reservoir Models for Model Calibration Purposes","authors":"Matteo Scapolo, M. Garcia, J. Mathieu, D. Siffert, O. Gosselin, P. Ackerer","doi":"10.2118/195508-MS","DOIUrl":"https://doi.org/10.2118/195508-MS","url":null,"abstract":"\u0000 Using geostatistical modelling to populate reservoir properties is nowadays the most common approach in the industry and it has received a great deal of attention. A geostatistical reservoir model defines a space of spatial uncertainty, which can be explored by generating many equiprobable reservoir property realisations that are as many possible reservoir models complying with static data. Among them, the relevant models are those that also match the dynamic data, which complete the available data for reservoir model calibration. Finding the relevant reservoir models in the space of spatial uncertainty is a time-consuming process that requires simulating the dynamic (flow) response of many reservoir models. Having a fast and reliable simulation method is then highly desirable to speed up the process of reservoir model calibration. In this context, a new approach has been developed and tested. The method allows easy and fast comparison between interpreted well-test results and equivalent (average) reservoir model properties in terms of transmissivity (k.h) and permeability. The comparison can be used to validate or reject a reservoir model, and to obtain indications on how to modify it to fit the well-test data. This paper presents the method and the results obtained to evaluate its performances and to validate it.\u0000 Well-test-interpreted permeabilities (or transmissivities) are nothing but weighted average permeabilities that are to be calculated from permeabilities defined over closed surfaces properly defined around the well, the weights depending on the flow geometry. The proposed method is based on steady-state flow simulation that is carried out by making the tested well a source term (producing or injecting well) in the centre of a simulation domain (reservoir model region). The latter must be extended enough to contain, or at least overlap, the stabilisation area of the well test in which average transmissivities are to be estimated. The method relies on three key aspects: defining a simulation domain (extension and shape) that is consistent with the actual well-test drainage area, defining relevant boundary conditions to reproduce flow paths that are consistent with those generated by the actual well test, using the new effective-gradient based averaging method to compute average permeabilities over closed surfaces properly defined.\u0000 The method is tested on various synthetic and partly real field cases, for which the transient well-test responses are first simulated and interpreted, then compared with the transmissivities that are predicted using the new method. Sensitivity analysis is also carried out on calculation parameters (flow simulation domain, flow rates…) to check the robustness of the method and identify improvement avenues. All these results tend to confirm the effectiveness of the method, which can combine speed and accuracy. This method is intended to be used as an objective function to perform automatic or assisted reserv","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"617 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116399880","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Experimental Investigation of Integrity Issues of UGS Containing Hydrogen","authors":"E. C. Boersheim, V. Reitenbach, D. Albrecht, D. Pudlo, L. Ganzer","doi":"10.2118/195555-MS","DOIUrl":"https://doi.org/10.2118/195555-MS","url":null,"abstract":"\u0000 Hydrogen is portrayed as the fuel of the future. The storage of hydrogen in porous underground gas storages is a promising solution for large-scale energy storage in Germany. In theory, excess energy sourced from renewable sources would be converted to hydrogen and subsequently stored in underground porous media. This solution provides cost effective solutions whilst providing large capacities in comparison to other energy storage types, however hydrogen interactions in underground gas storage sites (UGS) is a perplexing topic due to its foreign nature and therefore its behavior in the subsurface could be unpredictable.\u0000 The implementation of autoclaves to recreate UGS with added hydrogen is a novel approach to investigate potential integrity issues that may arise during its lifetime. Where autoclaves can simulate conditions similar to UGS to analyze potential changes in the subsurface. The principal idea of autoclaves are to house samples which are exposed to pressures and temperatures equivalent that of typical Underground Gas Storages (max 200 bar, 120°C), allowing the recreation of any reservoir environment.\u0000 The Primary objective is to investigate interactions between subsurface materials combined with reservoir rock and hydrogen. Aforementioned interactions can be interpreted through the analysis of mineralogical, petrophysical, hydrochemical changes to ascertain information regarding to the productivity of the UGS, for examples reviewing changes in permeability and porosity.\u0000 Furthermore, the application of autoclaves can help to estimate the magnitude of hydrogen damage in subsurface equipment by providing insight into identifying key materials necessary to design a system preventing hydrogen damage to the subsurface; Supplementary implementation of conventional component inspection of mechanical properties of steels and cements through tensile strength testing and unconfined compressive strength testing, respectively, enable the extent of hydrogen damage inspection in UGS with added hydrogen. Predominantly API grade steels and API Grade G cement where used for this investigation. Preliminary autoclave experimentation results show that hydrogen can alter the characteristics of UGS, where API steels have shown to experience mild hydrogen damage and reservoir rock and API cement G samples have alterations in their chemical and physical characteristics.\u0000 Autoclaves provide flexible choice in testing parameters and can be used to recreate any UGS with any gas mixtures, allowing for limitless testing possibilities to test for potential integrity issues in porous UGS containing hydrogen.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"36 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129049256","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Investigation of Pore-Scale Mechanisms of Microbial Enhanced Oil Recovery MEOR Using Microfluidics Application","authors":"C. Gaol, J. Wegner, L. Ganzer, N. Dopffel, F. Koegler, Ante Borovina, H. Alkan","doi":"10.2118/195553-MS","DOIUrl":"https://doi.org/10.2118/195553-MS","url":null,"abstract":"\u0000 Utilisation of microorganisms as an enhanced oil recovery (EOR) method has attracted much attention in recent years because it is a low-cost and environmentally friendly technology. However, the pore-scale mechanisms involved in MEOR that contribute to an additional oil recovery are not fully understood so far. This work aims to investigate the MEOR mechanisms using microfluidic technology, among others bioplugging and changes in fluid mobilities. Further, the contribution of these mechanisms to additional oil recovery was quantified.\u0000 A novel experimental setup that enables investigation of MEOR in micromodels under elevated pressure, reservoir temperature and anaerobic and sterile conditions was developed. Initially, single-phase experiments were performed with fluids from a German high-salinity oil field selected for a potential MEOR application: Brine containing bacteria and nutrients was injected into the micromodel. During ten days of static incubation, bacterial cells and in-situ gas production were visualised and quantified by using an image processing algorithm. After that, injection of tracer particles and particle image velocimetry were performed to evaluate flow diversion in the micromodel due to bioplugging. Differential and absolute pressures were measured throughout the experiments. Further, two-phase flooding experiments were performed in oil wet and water wet micromodels to investigate the effect of in-situ microbial growth on oil recovery.\u0000 In-situ bacteria growth was observed in the micromodel for both single and two-phase flooding experiments. During the injection, cells were partly transported through the micromodel but also remained attached to the model surface. The increase in differential pressure confirmed these microscopic observations of bioplugging. Also, the resulting permeability reduction factor correlated with calculations based on the Kozeny-Carman approach using the total number of bacteria attached. The flow diversion of the tracer particles and the differences in velocity field also confirmed that bioplugging occurred in the micromodel may lead to an improved conformance control. Oil viscosity reduction due to gas dissolution as well as changes in the wettability were also identified to contribute on the incremental oil. Two-phase flow experiments in a newly designed heterogeneous micromodel showed a significant effect of bioplugging and improved the macroscopic conformance of oil displacement process.\u0000 This work gives new insights into the pore-scale mechanisms of MEOR processes in porous media. The new experimental microfluidic setup enables the investigation of these mechanisms under defined reservoir conditions, i.e., elevated pressure, reservoir temperature and anaerobic conditions.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129805957","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}