Day 3 Wed, June 08, 2022最新文献

{"title":"A Semi-Analytical Model for the Prediction of CO2 Injectivity into Saline Aquifers or Depleted Hydrocarbon Reservoirs","authors":"T. Whittle, P. Park, C. Coll","doi":"10.2118/209628-ms","DOIUrl":"https://doi.org/10.2118/209628-ms","url":null,"abstract":"\u0000 As carbon dioxide (CO2) is injected into a reservoir (for CO2 sequestration in a saline aquifer or depleted reservoir, or even for enhanced oil recovery in the case of a less depleted reservoir), a region around the well becomes saturated and expands with time. From a pressure transient perspective, by making some simple assumptions the resulting reservoir configuration at any given moment can be approximated by a two-region radial composite system. As well as its radial extent, the inner region is defined by its diffusivity and mobility, both of which differ from those of the outer region as a result of the CO2 saturation. The CO2 viscosity and compressibility at reservoir pressure and temperature are the essential properties that impact the diffusivity and mobility. Knowing the three variables, radius, diffusivity ratio and mobility ratio, the constant rate pressure transient response is readily computed from existing analytical radial composite model solutions. These are commonly used in the petroleum industry to analyse well test behaviour and can be configured with a variety of boundary conditions (no flow, constant pressure or infinite, usually in the shape of a rectangle).\u0000 The problem with CO2 injection is that the radius and properties of the inner zone vary with time and hence any single radial composite model does not apply. The solution approach in this paper is to apply superposition. At each discretised time step, the well is simultaneously injected at a constant rate assuming the current configuration and shut in with the previous configuration. The shut-in \"cancels out\" the previous model and the current model applies. At each time step, the injected volume is calculated, the material balance and associated reservoir pressure computed along with the new inner zone radius, diffusivity and mobility and hence the model for the next time step is defined. An additional iterative loop allows for the injection rate to decrease if the injection pressure exceeds a maximum constraint.\u0000 The method is simple and fast and appears to match the pressure response of numerical simulations of the same problem using more detailed physics, without the associated noisy derivative often associated with grid-based solutions. It implicitly assumes a piston like displacement which results in an unrealistic saturation profile that differs from the more rigorous numerical models where gravity and capillary effects are included. However, comparisons with such models indicate that the prediction of well pressure and hence injectivity is sufficiently accurate for practical purposes despite this approximation.\u0000 The application of superposition in time - a method usually associated with solving linear problems – is demonstrated to adequately solve the complex non-linear problem of CO2 injectivity and, because the method includes material balance, it can help to define storage efficiency factors which are critical for the evaluation of storage capacity.","PeriodicalId":311361,"journal":{"name":"Day 3 Wed, June 08, 2022","volume":"49 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132234867","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":"Integrated Field Development Modelling to Improve Recovery from a Complex Fractured Carbonate Reservoir with Potential for Low Salinity Waterflooding EOR","authors":"M. Al-Subaihi, Tahani Al-Rashidi, R. Prasad, Dipankar Dutta, A. Kshirsagar, Tushar Patil, Malvika Nagarkoti, Christopher Burns, C. Cranfield","doi":"10.2118/209669-ms","DOIUrl":"https://doi.org/10.2118/209669-ms","url":null,"abstract":"\u0000 Integrated field development studies were performed to increase oil recovery from the Marrat reservoir in the Umm Gudair field, a large, low permeability, complex, naturally fractured and highly faulted carbonate reservoir. The studies involved rebuilding the static model, creating and history matching a new dynamic model and using it to examine redevelopment scenarios. These included well interventions and workovers under primary depletion, secondary waterflood and, following a screening exercise, low salinity flooding (LSF).\u0000 A new structural interpretation of 3D seismic data provided a revised static geological model and yielded insight into the number, geometry and origin of the many faults intersecting the reservoir. Rock types defined from core analysis were distributed in the static geological model using trends from Bayesian lithofacies classification based on pre-stack inversion of seismic data. Porosity and permeability were modelled by rock type. Saturation-height functions for each rock type were developed from mercury injection capillary pressure (MICP) data; and the reservoir free water level was varied so that these functions honoured the log-based water saturation interpretation.\u0000 The dynamic model input description was based on available and interpreted data for the assumed oil wet reservoir. The history matching was aided by sophisticated application of decline curve analysis (DCA) and used an Opportunity Index approach to optimise well placement. The history matching led to a simplified and effective solution for characterising the locally naturally fractured reservoir nature. The effect of high permeabilities associated with increased fracture density was accommodated by introducing facies-based and distance from fault-related permeability modifiers, while maintaining geological rigour.\u0000 The dynamic model was used to examine a range of field redevelopment scenarios. This showed that LSF could enhance field recovery and achieve a three-fold increase in estimated ultimate recovery, in conjunction with other improved reservoir management strategies. The results provided support for specialised laboratory and dynamic modelling investigations as a precursor to LSF pilot trials. A low cost source of LSF injectant was identified which could contribute to lowering the overall carbon footprint.","PeriodicalId":311361,"journal":{"name":"Day 3 Wed, June 08, 2022","volume":"105 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128318393","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":"Viscosity from Geochemical Techniques: A Case Study for a Heavy Oil Field on the UKCS","authors":"Ian Cutler, A. Cely, Julian Moore, Tao Yang, Nicholas Birch, P. Ablard","doi":"10.2118/209690-ms","DOIUrl":"https://doi.org/10.2118/209690-ms","url":null,"abstract":"\u0000 Heavy oil fields are characterised by complex chemistries and exhibit a wide range of physical properties (especially oil viscosity). This paper describes the development of two innovative and cost-effective data acquisition methods: the optimised use of mud gas data and the geochemical characterisation of cuttings extracts, both as an alternative data source for oil viscosity determination. Applications of these methods can lead to the cost reduction of data acquisition programs and potentially improvements in oil recovery.\u0000 The mud gas provides real-time surface logging data. Due to the nature of heavy oil in the case study wells, the mud gas compositions contain mainly C1-C3. By comparing with the reservoir oil samples from the exploration and appraisal wells, we investigated the possibility of using mud gas while drilling to identify if the reservoir oil belongs to the high viscosity or medium viscosity group. For cutting analysis, we thoroughly investigated solvent extracts from cuttings from the exploration and appraisal wells and correlated them with the oil viscosity from the corresponding PVT samples. When such a correlation is established, we can then apply the correlation to predict oil viscosity from the cuttings of new production wells.\u0000 We achieved excellent results for both real-time oil viscosity identification from mud gas data and post well oil viscosity prediction from the extraction of cuttings. The C1/(C2+C3) is the key parameter for oil viscosity identification from the standard mud gas data in the field. For the past wells, the mud gas interpretation has high accuracy for determining if the reservoir oil belongs to the high viscosity or medium viscosity regions. We established a strong correlation between the biomarkers and the oil viscosity from the exploration and appraisal wells. When we applied the correlation to new production wells, the oil viscosity prediction was very close to the viscosity measurement from the wellhead PVT samples.\u0000 The geochemical techniques provide oil viscosity for critical decisions regarding well placement and reservoir management modelling. The new source of reservoir fluid data from mud gas and cuttings provides real-time fluid interpretation while drilling and close to PVT sample quality oil viscosity prediction after drilling. This new approach is cost-efficient and has a large potential to replace the downhole fluid sampling or expensive downhole logging tools for production wells.","PeriodicalId":311361,"journal":{"name":"Day 3 Wed, June 08, 2022","volume":"14 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133306904","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":"IAST Modelling of Competitive Adsorption, Diffusion and Thermodynamics for CO2-ECBM Process","authors":"M. Asif, Lei Wang, R. Hazlett, Galymzhan Serikov","doi":"10.2118/209636-ms","DOIUrl":"https://doi.org/10.2118/209636-ms","url":null,"abstract":"\u0000 \u0000 \u0000 The CO2 emission is one of the main causes for the global warming and it may be controlled by sequestrating CO2 into the geological formation. The coalbed formation provides a dual advantage for CO2 sequestration as CO2 may be stored in coal forever with enhancing the coalbed methane recovery. Thus, the cost of CO2 sequestration may be offset completely or partially. The main objective of the paper was to comprehend the CO2-ECBM displacement using the three concepts viz. competitive adsorption, diffusion, and thermodynamic modelling of coal\u0000 \u0000 \u0000 \u0000 In this paper, the pure gas isotherm on coal for CH4, and CO2 was evaluated using manometric method. The binary gas isotherm or competitive adsorption was studied using IAST modelling. MATLAB code was developed for the solution of IAST model and Newton Raphson approach was followed. The IAST modelling was done by taking 50%/%50 mole fraction of CH4/CO2. By analyzing the binary gas isotherm, the optimum injection pressure was evaluated. On the same injection pressure, co adsorption isotherm was drawn at different mole fraction of CO2 in gas phase. Separation factor was calculated by taking ratio of CO2 and CH4 in the gas and adsorbed phase respectively. Furthermore, adsorption data was used for discussing the sorption kinetics in coal and diffusion coefficient was evaluated. Furthermore, the thermodynamic parameters were also calculated and integrated with above noted parameters for the methane displacement in CO2-ECBM process.\u0000 \u0000 \u0000 \u0000 The CO2-ECBM displacement is very much dependent on the competitive adsorption and diffusion process in coal. The surface potential and Henry constant are important parameters for defining the CO2-ECBM displacement. The coadsorption isotherm was drawn at the optimum injection pressure and it shows that methane displacement would be the optimum by taking 11 %/89% mole fraction of CO2 and CH4 for two temperatures i.e., 288 K, 308 K. It is identified through diffusion regime that diffusion coefficient for the binary gas isotherm is the average of the diffusion coefficients of pure CO2 and CH4.\u0000 \u0000 \u0000 \u0000 This is the first kind of study which provides the completely integrated approach for describing the methane displacement in CO2-ECBM process. This novel study promotes our understanding of the complex mechanisms of CO2-ECBM displacement process.\u0000","PeriodicalId":311361,"journal":{"name":"Day 3 Wed, June 08, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129781902","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":"Thermodynamic Model Evaluations for Hydrogen Pipeline Transportation","authors":"A. Cely, M. Hammer, H. Andersen, Tao Yang, P. Nekså, Ø. Wilhelmsen","doi":"10.2118/209626-ms","DOIUrl":"https://doi.org/10.2118/209626-ms","url":null,"abstract":"\u0000 Equations of state and transport property models for hydrogen and hydrogen mixed with natural gas components relevant for pipeline transport have been evaluated by comparing to experimental data and reference equations of state. The evaluated properties are density, speed of sound, Joule-Thompson coefficient, the isobaric and isochoric heat capacity, viscosity, and thermal conductivity. A temperature span of −10 to 50 °C and a pressure span of 1-300 bara has been set as the target range for pipeline transport. Viscosity and thermal conductivity models have been evaluated for binaries where experimental data are available. The goal of this work was to determine if models already available in commercial simulators can predict fluid properties accurate enough for engineering purposes.\u0000 The classical cubic equations of state of Soave-Redich-Kwong (SRK) and Peng-Robinson (PR) with van der Waals mixing rules have been tested with parameters extracted from the common commercial simulations tools Hysys, Unisim, PVTsim Nova and Multifash. In general, the different parameter sets give similar performance. One exception is the H2-CH4 binary, where both Unisim and Multifash use a non-optimal kij interaction parameter. Neither the SRK, nor PR can describe the Joule-Thompson coefficient of hydrogen, and the error lies in the range 50%-100%. The Joule-Thompson coefficient is however small, and the effect of this misprediction on pipeline simulations might not be significant.\u0000 For viscosity and thermal conductivity predictions, the SuperTRAPP model in REFPROP 10 as well as simpler viscosity models LGE, LBC and a corresponding-state-principle model of PVTsim Nova have been evaluated. The SuperTRAPP model in REFPROP 10 was found to predict viscosity and thermal conductivity within a reasonable accuracy for pure hydrogen. The simpler viscosity models LGE and LBC overestimate the viscosity of hydrogen by 65% to 90% in the transport domain of interest. For the hydrogen binary systems studied, the SuperTRAPP model for the thermal conductivity and viscosity had errors around 20% at high pressures. Comparing corresponding-state-principle viscosity models with the SuperTRAPP model gave relative deviations in the range 3.9% to 13%. The SRK equation of state is found to perform better than the PR equation of state, with a relative density error below 1% for hydrogen rich systems.\u0000 A TIBCO Spotfire® visualization dashboard has been developed for easy access to the evaluation results of the large amount of data and thermodynamic models. A steady-state thermohydraulic analysis for Europipe (Norway to Europe) has been performed to evaluate the effect that using different equations of state and viscosity models have on the thermohydraulic estimations. After a review of the thermodynamic model's performance, clear guidance on model selection for hydrogen transportation is provided.","PeriodicalId":311361,"journal":{"name":"Day 3 Wed, June 08, 2022","volume":"128 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129900626","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":"Density Changes at Supercritical and Near-Critical Conditions by Increasing CO2 Content in Synthetic Hydrocarbon Mixtures – A Comparison Between Experiments and Simulation Predictions","authors":"P. Aslanidis, D. Marinakis, T. Puntervold, Vasilis Gaganis, Nikolaos Varotsis","doi":"10.2118/209663-ms","DOIUrl":"https://doi.org/10.2118/209663-ms","url":null,"abstract":"\u0000 Carbon dioxide (CO2) injection is a well-known EOR-method to reduce residual oil in the pore network of oil reservoirs. It is also increasingly used as a means of mitigating the greenhouse gas emissions problem by storing it in geological formations. A key parameter to such attempts is the density of the rich CO2 mixture, which is formed downhole in the injection well, since it affects the swelling potential, oil formation volume factor, viscosity, hydrostatic gradient, fluid distribution and formation pore pressure. The density of the crude oil-CO2 mixture depends on the pressure-temperature conditions, the CO2 concentration and the dominant hydrogen compounds in the crude oil, i.e. whether they are aliphatics, aromatics, or naphtenics (cyclic structures). The PVT properties of the different CO2-hydrocarbon mixtures vary greatly and the available experimental data for tuning PVT simulators are scarce, especially for ternary mixtures at high pressures and CO2 concentrations.\u0000 This study investigates the effect of CO2 concentration on the density of ternary mixtures containing CO2, methane, and a pure liquid hydrocarbon, which is either an alkane, aromatic or cycloalkane compound. The liquid hydrocarbons used in the study were normal heptane (n-C7), toluene (Tol) and cyclohexane (c-C6). The measurements were conducted at variable compositions, at temperatures of 50, 70, and 90 °C, and at pressures ranging between 100 and 517 bar. The ternary mixtures were:\u0000 Methane, toluene and CO2 at 1:1 molar ratio and CO2 concentrations of 14%, 27% and 72%, Methane, cyclohexane and CO2 at 1:1 molar ratio and CO2 concentrations of 19%, 47% and 68%. Methane, n-heptane and CO2 at constant molar hydrocarbon ratio (C1/n-C7) of 2:1 and varying CO2 concentrations of 23% and 75%,\u0000 Some of the rich CO2 mixtures exhibited retrograde condensation behaviour at high temperatures. The results were compared against predictions from an EoS model (Peng Robinson Equation of State), coupled with volume shift parameters. The comparison between the simulation calculations and the experimental data indicated good agreement in the densities, but significant deviations in the boiling point pressures (Pb). As a result, the EoS model can be safely used to predict the CO2 mass storage potential of reservoirs of known pore volume such as the depleted ones.","PeriodicalId":311361,"journal":{"name":"Day 3 Wed, June 08, 2022","volume":"32 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122883897","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":"Dynamic Behavior of Salt Dissolution and Its Effect on Imbibition in Inter-Salt Oil Reservoir Due to Fracturing Fluid Injection","authors":"Xiliang Liu, Hao Chen, Jin Yang, Shenglai Yang","doi":"10.2118/209641-ms","DOIUrl":"https://doi.org/10.2118/209641-ms","url":null,"abstract":"\u0000 Billions of tons in proven reserves for inter-salt shale oil has been recognized as crucial strategic resources. The fracturing fluids injection triggers unique salt dissolution chemical phenomena, which on the one hand improves the reservoir pore structure and on the other hand easily induces formation collapse. However, there is no research on triggering mechanism and controlling factors of salt dissolution, and effect of slat dissolution on extremely important imbibition function in inter-salt shale formation is lack of understanding. Herein, the complex mechanism of inter-salt shale dissolution reaction was revealed based on microcosmic pore structure network. The effect of salt dissolution on imbibition in inter-salt shale formation was assessed from various angles, which was conducted by online nuclear magnetic resonance (NMR), high-quality focused ion beam scanning electron microscopy (FIB-SEM), and CT technologies. The results indicate that high temperature improves slat dissolution reaction and enhances the seepage capacity by more than 60 times, which sharply exceeds the influence of fracturing fluid salinity, flow rate and pressure in inter-slat formation. Three kinds of pores for imbibition recovery contribution were 48.17%, 46.39%, and 5.44%, namely micropore, mesopore and macropore, respectively. Additionally, salt dissolution enlarged seepage channel so that spontaneous imbibition occurred in micropores, which was considered as conventionally unmovable areas. Besides, the salt dissolution effect mainly promoted oil discharge in the second stage of imbibition process, leading to 15.83% higher imbibition recovery. These results can furnish an in-depth understanding the nature of complicated mechanisms in inter-slat shale oil reservoirs with fracturing fluids injection.","PeriodicalId":311361,"journal":{"name":"Day 3 Wed, June 08, 2022","volume":"11 4","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"120986622","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":"Miscibility Study of Flue Gases for a Coupled CCS-EOR Project","authors":"Alfonso Gonzalez-Perez, Manuel Barrado, Rosario Rodriguez Pardo, Jesus Montes Ruiz","doi":"10.2118/209645-ms","DOIUrl":"https://doi.org/10.2118/209645-ms","url":null,"abstract":"\u0000 Miscible hydrocarbon (HC) rich gas injection is a common EOR technique included in the development plan of many Abu Dhabi oil fields. This technology, that provides a very high oil recovery, requires the supply of a gas that is very valuable for other uses or its commercialization. Utilization and storage of flue gases rich in CO2 and N2 can play a key role in lowering the overall reservoir emissions by coupling carbon capture and storage (CCS) with EOR techniques. Thus, the substitution of hydrocarbon gas by these gases is of great environmental and industrial interest. Nevertheless, the change of the injection gas is not straightforward and requires a previous study to ensure the gas miscibility.\u0000 The aim of this piece of research is to estimate the minimum miscibility pressure (MMP) of the studied gas, in order to clarify if miscibility conditions are achieved at reservoir pressure. Thus, a comprehensive study was performed applying three different approaches to predict/estimate the MMP:\u0000 Empirical correlations from the literature based on experimental results. Experimental measurements with Slim Tube tests. Computer modeling based on equations of state for phase-behavior calculations.\u0000 Miscibility of CO2 and N2 was successfully investigated through the three approaches. In the case of CO2, miscibility at reservoir pressure was totally ensured at 120°C since MMP was estimated to be the bubble pressure of the studied oil, more than 100 bar below reservoir pressure. Otherwise, the conclusion of the nitrogen miscibility studies is that N2 gas flooding is not a feasible EOR technique since MMP is far above reservoir pressure. Before completely discarding the use of nitrogen, miscibility of mixtures of HC rich gas and N2 was first studied by PVT simulations. Thermodynamic modelling was compared against experimental Slim Tube tests evaluating HC+N2 mixtures. Laboratory work led to conclude that mixtures with 42% of N2 could be injected at miscible conditions and revealed that simulations overestimate the minimum miscibility pressure of the studied gas mixtures. Finally, miscibility of CO2 and N2 mixtures with typical compositions of flue gases from post-combustion processes were studied using the thermodynamic model retuned with previous experimental measurements.\u0000 This work presents a thorough study of minimum miscibility pressure of CO2 and N2 in oil from Abu Dhabi, which is the first step of any EOR project coupled with CCS. The developed methodology covered the three different approaches and the results provide a broad comparison amongst correlated, measured and simulated MMP.","PeriodicalId":311361,"journal":{"name":"Day 3 Wed, June 08, 2022","volume":"21 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133807384","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 Practical Approach to Maximise UGS Storage Efficiency in Order to Secure Energy Supply","authors":"Limin Li, Huijuan Yu, A. Kshirsagar, Ayman Samy, Chuanqin Mao, Lin Qu, Agung Kuswiranto, F. Gui, D. Cook","doi":"10.2118/209658-ms","DOIUrl":"https://doi.org/10.2118/209658-ms","url":null,"abstract":"\u0000 The Underground Gas Storage (UGS) working gas capacity is one of the important design parameters for a UGS project. The objective of this paper is to demonstrate a case study from Sichuan area, China, where a fractured carbonate gas reservoir was used for UGS and show the key factors that should be considered to optimize UGS working gas capacity and help to secure energy supply during peak season.\u0000 The dynamic simulation model was history matched on both depletion and storage. This model was coupled with 4D Geomechanics effects. It was then employed to capture the key parameters that will affect the working gas capacity. Based on the 4D Geomechanical integrity and facility assessment results, the forecast model was created using the subsurface and surface facility constraints. The study workflow included setting up the forecast model, uncertainty analysis and sensitivity analysis to capture the key driving parameters for the working gas volume. This study also included sensitivities of emergency gas supply during peak winter season.\u0000 This study showed that the main factors that determine the UGS working gas capacity are the initial gas in place, tubing head pressure (THP) during withdrawal phase, bottom hole pressure (BHP) during injection phase, well pattern and well count. It was observed that each injection/production cycle is affected by the previous cycles. The simulation showed that the incremental working gas volume represented as a trend can be better fitted by a power function with both THP and BHP. It also demonstrated that lowering the THP limitation is more effective than increasing the BHP limitation. However, this may require surface facility upgrading. The optimum operating condition was identified by considering all engineering and geomechanical constrains such as erosion, wellbore integrity and cap rock integrity. This is used to guide the UGS daily operations with optimum production/injection rate of each well in a safe manner. The study recommended to implement a stepwise strategy to reach the working gas capacity.\u0000 This paper presents a novel practical workflow and methodology to implement increased UGS reservoir working capacity. It also provides a practical way to forecast the operational pressure range and quickly predict the deliverability of emergency gas supply under various market demands.","PeriodicalId":311361,"journal":{"name":"Day 3 Wed, June 08, 2022","volume":"161 7 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129087282","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":"Drilling Control System Automation to Control Axial Velocity Optimises Tripping and Drilling Performance","authors":"R. Bacon, Stewart MacKinnon, E. Abrahamsen","doi":"10.2118/209712-ms","DOIUrl":"https://doi.org/10.2118/209712-ms","url":null,"abstract":"\u0000 The purpose of this paper is to document an ongoing project to optimize the drill-string tripping and casing running speeds, with the view to tripping as efficiently and quickly as the rig limitations allow, but doing so in a safe manner that prevents nonproductive time, both visible and invisible, and retains at all times the wells integrity and allows safe operations.\u0000 There are many factors that contribute to nonproductive time, these include but are by no means limited to Lost circulation, formation influx, pack-offs and other stuck pipe events which cause delays, problems, lost time, and generally increase risk, and cost of the well, during drilling operations. Such situations can, sometimes, escalate into serious problems that may result in expensive and undesirable technical sidetracks. Couple this with ever more complex wells, (whether they be long horizontal sections, multi-laterals, etc.), drilled in ever smaller and more challenging reservoirs, such as those which are depleted, or at high pressure and or high temperature.\u0000 Modelling software offers forward-looking simulations that can be used to predict drilling problems and assess the likely effects of remedial options. During real-time monitoring, advanced monitoring and trend analysis software can use downhole conditions and mud properties to forecast hole cleaning, equivalent circulating density (Estimated Circulating Density (ECD)), and temperature changes for the next depth/time interval, based on three tightly coupled real-time dynamic models - hydraulic, mechanical and thermodynamic - that simulate wellbore condition and characterize improvement or deterioration during drilling. These models continuously assess drilling performance, borehole conditions, and associated risks based on real-time symptom detection.\u0000 The solution and concept presented in this paper showcases a modelling approach which allows all of these situations to be accurately modelled in a transient setting, and then also compared and back modelled using all the available real time high frequency data. This coupled with an automated drilling control system has resulted in safe, record-breaking drilling achievements in the North Sea. The models allow updated safeguards to be applied to the drilling control system to maintain a downhole pressure within the acceptable limits of the open hole formations. It also automatically stops the movement of the drill string in case of abnormal hook loads or surface torques. Since automatic actions can be triggered in case of an unexpected situation, some standard procedures have been fully automated, including friction tests and back-reaming. In prior papers and technologies, the peak surge seen when pipe is first moved and gels are ‘broken’ has been used as the limit for safe tripping, however that precluded further optimization that exists once gels are broken and pipe and fluid is in motion. This optimization process will be discussed in detail in this paper.\u0000 This ‘du","PeriodicalId":311361,"journal":{"name":"Day 3 Wed, June 08, 2022","volume":"14 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121673602","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}