Day 4 Thu, June 06, 2019最新文献

{"title":"Hydraulic Fractures Simulation and Stimulated Reservoir Volume Estimation for Shale Gas Fracturing","authors":"Lin Ran, Lan Ren, Jinzhou Zhao, Y. Tao, X. Tan, Jiangyu Zhao","doi":"10.2118/195547-MS","DOIUrl":"https://doi.org/10.2118/195547-MS","url":null,"abstract":"\u0000 Multi-stage & multi-cluster fracturing in horizontal well drilling is the core technology in for commercial exploitation of shale gas resevoir. According to vast field data, there is remarkable positive correlation relationship between stimulated reservoir volume (SRV) and shale gas production. Hence, estimating the SRV is essential for both pre-fracturing design and post-fracturing evaluation. However, the forming process of SRV involves with many complex mechanisms, making it is difficult to be simulated.\u0000 In this paper, we establish a mathematical model to estimate the SRV by simulating multiple hydraulic fractures propagate, formation stress change and reservoir pressure rise; consequently, the stress and pressure change might make natural fractures occur tensile failure or shear failure, generating a high-conductivity zone (i.e., SRV) in the shale reservoir.\u0000 To solve the model, displacement discontinuity method (DDM) is applied to simulate non-planar propagation of multiple hydraulic fractures and calculate formation stress change. Finite difference method (FDM) is used to compute reservoir pressure rise. The natural fractures failure state is determined by tensor formulae derived from Warpinski's failure theory. This SRV estimation method involves a variety of complex but crucial physical mechanisms during shale fracturing process which include unequal flow-rate distribution in different hydraulic fractures, non-planar hydraulic fractures propagation under stress interference, reservoir permeability increases with SRV expanding, two types of natural fracture failure and so on.\u0000 A field case study was performed to show the dynamic processes of hydraulic fractures propagation, reservoir permeability increase, and the SRV expansion during shale gas fracturing. Then we compared the simulation results with analytical solution, published papers and on-site microseismic monitoring data to verify our model. Finally, the influence of geological condition and engineering parameters on SRV was investigated by sensitivity analysis.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"121 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":"122825286","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":"Coupled Hydrodynamic-Geomechanical Modelling of CO2-WAG Field Development at Farnsworth Unit: A Case Study","authors":"Marcia D. McMillan, R. Will, W. Ampomah, R. Balch, P. Czoski","doi":"10.2118/195484-MS","DOIUrl":"https://doi.org/10.2118/195484-MS","url":null,"abstract":"\u0000 The SWP project is located in a mature waterflood undergoing conversion to CO2-WAG operations at Farnsworth, Texas, USA. Utilized CO2 is anthropogenic, sourced from a fertilizer and an ethanol plant. Major project goals are optimizing the storage/production balance, ensuring storage permanence, and developing best practices for CCUS.\u0000 This paper provides a review of work performed toward development of a 3D coupled Mechanical Earth Model (MEM) for use in assessment of caprock integrity, fault reactivation potential, and evaluation of stress dependent permeability in reservoir forecasting. Mechanical property estimates computed from geophysical logs at selected wellbores were integrated with 3D seismic elastic inversion products to create a 3D \"static\" mechanical property model sharing the same geological framework as the existing reservoir simulation model including 3 major faults. Stresses in the MEM were initialized from wellbore stress estimates and reservoir simulation pore pressures. One way and two way coupled simulations were performed using a compositional hydrodynamic flow model and geomechanical solvers.\u0000 Coupled simulations were performed on history matched primary, secondary (waterflood), and tertiary (CO2 WAG) recovery periods, as well as an optimized WAG prediction period. These simulations suggest that the field has been operating at conditions which are not conducive to either caprock failure or fault reactivation. Two way coupled simulations were performed in which permeability was periodically updated as a function of volumetric strain using the Kozeny-Carmen porosity-permeability relationship. These simulations illustrate the importance of frequent permeability updating when recovery scenarios result in large pressure changes such as in field re-pressurization through waterflood after a long primary depletion recovery period. Conversely, production forecasting results are less sensitive to permeability update frequency when pressure cycles are short and shallow as in WAG cycles.\u0000 This paper describes initial work on development of a mechanical earth model for use in assessment of geomechanical risks associated with CCUS operations at FWU. The emphasis of this work is on integration of available geomechanical data for creation of the static mechanical property model. Preliminary coupled hydro-mechanical simulations are presented to illustrate some of the key diagnostic output from coupled simulations which will be used in later work for in depth evaluation of specific risk factors such as induced seismicity and caprock integrity.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"7 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":"117112007","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":"Application of Algebraic Multigrid in Fully Implicit Massive Reservoir Simulations","authors":"Suha N. Kayum, M. Cancelliere, M. Rogowski, A. Al-Zawawi","doi":"10.2118/195472-MS","DOIUrl":"https://doi.org/10.2118/195472-MS","url":null,"abstract":"\u0000 Algebraic Multigrid (AMG) methods have proven to be efficient when numerically solving elliptic Partial Differential Equations (PDE). In reservoir simulation, AMG is used together with the Constrained Pressure Residual (CPR) method to solve a partially decoupled pressure system. Recently, effort has been focused on improving the robustness of the AMG-CPR solver. This paper presents the performance of different AMG-CPR strategies for massive reservoir models. In addition, a solver selection analysis is conducted, proving that dynamic selection of solvers has the potential of increasing the overall efficiency and robustness of the simulation.\u0000 Numerous decoupling/preconditioning algorithms exist and have been shown to influence the pressure matrix properties, some resulting in matrices more suitable to the characteristics favorable to AMG. Several decoupling/preconditioning strategies are investigated, such as Alternate Block Factorization (ABF), Quasi-IMPES (QI), and Dynamic Rowsum (DRS). The extracted pressure matrix could be suitable or unsuitable for AMG, depending on the matrix row sum, the diagonal signs, and the signs of the off-diagonal values.\u0000 The advantage of using AMG as a preconditioner is demonstrated by running the SPE10 case. The recommended AMG settings that result in the optimal performance for SPE10 are shared. A speedup is seen of up to 4X when using AMG with optimal settings versus the default solver in the in-house reservoir simulator with the improvement range depending on the number of processors used. SPE10 is a highly heterogeneous model resulting in matrices favorable for AMG, i.e., pressure decoupling produces positive definite pressure matrices, which is not necessarily representative of industry models. A comparison is then made with a selection of models with a wide range of characteristics and finally an examination of the convergence behavior of key industry cases with different decoupling strategies is presented. The overall convergence behavior of the pressure and full system are shown and the top decoupling algorithms for the particular models are discussed. Finally, the applicability and performance gain of selectively using AMG during a run is demonstrated.\u0000 Recent developments have been made in regard to AMG methods, but their applicability in a wide range of massive real cases is yet to be explored. In this work, different decoupling methods are tested, the AMG behavior on real field massive models is analyzed, the scalability is investigated, and AMG is selectively activated during a simulation run shedding light on the potential of future work entailing the use of Artificial Intelligence (AI) to dynamically select the optimal solver choice.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"15 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":"125253113","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 the Severity of Wax Deposition in Bend Pipes Under Subcooled Pipelines Conditions","authors":"N. Makwashi, K. Sarkodie, S. Akubo, D. Zhao, P. Diaz","doi":"10.2118/195559-MS","DOIUrl":"https://doi.org/10.2118/195559-MS","url":null,"abstract":"\u0000 Curved pipes are essential components of subsea process equipment and some part of production pipeline and riser. So far, most of the studies on of wax deposition and the possible mitigation strategies have been carried out using straight pipelines, with little attention given to curved pipes. Therefore, the objective of this study is to use an experimental flow loop designed and assembled in the lab to study and understand the mechanisms and variable parameters that affect wax depositional behaviour under the single-phase flow. Series of experiments were carried out with pipes curvatures of 0, 45 and 90-degree at different flow rates (2 and 11 L/min). The sequence in which the bends are incorporated creates non-uniformity of boundary shear, flow separation, and caused isolation of fluid around the bends that affect wax deposition, which depends on flow regimes – Reynolds number along with the radius of curvature of the bend. Prior to the flow loop experiment, the waxy crude oil was characterized by measuring the viscosity, WAT (30°C), pour point (25.5°C), n-Paraffin distribution (C10 - C67), and the saturated/aromatic/resin/asphalte (SARA) fractions\u0000 Results of this study shows that the wax deposit thickness decreases at higher flow rate within the laminar (Re<2300) and turbulent (Re>2300) flow regimes. It was observed that the deposition rate was significantly higher in curved pipes, about 8 and 10% for 45 and 90-degree, respectively in comparison to the straight pipe for all flow conditions. Increase elevation of the curved pipe, however, led to a more wax deposition trend; where a higher percentage of wax deposit was observed in 45-degree compared to 90-degree curved pipe. This trend was due addition of gravity forces to the frictional forces - influenced by the physical mechanisms of wax deposition mainly molecular diffusion, shear dispersion and gravity settling. From the results of this study, a new correlation between wax deposit thickness and pressure drop was developed. A relationship was established between wax deposit thicknesses, bend angle in pipes and wax deposition mechanisms with a reasonable agreement with published data, especially for steady state condition. Therefore, this study will enhance the understanding of the wax deposition management and improve predictions for further development of a robust mitigation strategy.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"11 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":"123669462","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":"Assessing Waterflood Efficiency with Deconvolution Based Multi-Well Retrospective Test Technique","authors":"A. Aslanyan, Fedor Grishko, V. Krichevsky, D. Gulyaev, E. Panarina, A. Buyanov","doi":"10.2118/195518-MS","DOIUrl":"https://doi.org/10.2118/195518-MS","url":null,"abstract":"\u0000 A waterflood study has been performed on a heterogeneous oil deposit with a rising water-cut and production decline after 10 years of commercial production.\u0000 The objective was to analyze the efficiency of waterflood patterns across the field and suggest injection optimization opportunities.\u0000 The production is facilitated by ESP with Permanent Downhole Gauges (PDGs) which provides an opportunity to analyze the productivity index and cross-well interference.\u0000 The PDG analyzes was performed in PolyGon pressure modelling facility and followed Multi-well Retrospective Testing (MRT) workflow which is based on the mathematical procedure of multiwell deconvolution (MDCV).\u0000 MDCV trains the correlation between bottom-hole pressure (BHP) variations from PDG data records and rates variations from daily production history of a given well and other wells around it.\u0000 This provides a robust short-term predictor for production response for different rate/BHP scenarios and makes a basis for injection optimization opportunities.\u0000 MDCV allows reconstructing formation pressure and productivity index back in time, pick up the changes and understand if they were caused locally (by skin) or massively (by transmissibility).\u0000 The diffusion modelling of deconvolved data allows a robust quantification of some reservoir properties in cross-well intervals, such as the current drained volume around each well, potential drained volume (as if the offset wells are shut-down), apparent cross-well transmissibility, boundary types and compare them against the various geological scenarios and possible well-reservoir contact scenarios.\u0000 The quantitative analysis allows picking up anomalously high cross-well interference which may be caused by thin-bedding circuiting or induced fracture. It also provides a strong hint for thief-injection and thief-production in cases of poor cross-well interference.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"52 7 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":"126006165","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":"Development and Application of an Artificial Neural Network Tool for Chemical EOR Field Implementations","authors":"M. Abdullah, Hamid Emami‐Meybodi, T. Ertekin","doi":"10.2118/195492-MS","DOIUrl":"https://doi.org/10.2118/195492-MS","url":null,"abstract":"\u0000 The field-scale design of chemical enhanced oil recovery (cEOR) processes requires running complex numerical models that are computationally demanding. This paper provides an efficient screening platform for the cEOR feasibility study by presenting five artificial neural network (ANN) based models. We constructed 1,100 ANN training cases using CMG-STARS to capture the variation in reservoir petrophysical properties and the range of injected chemicals properties for a five-spot pattern. The design parameters were coupled with the reservoir properties using several functional links to optimize the ANN models and improve their performances. The training cases were employed using back-propagation methods to construct one forward model (Model #1) and four inverse models. Model #1 predicts reservoir response (i.e., oil rate, water cut, injector bottomhole pressure, cumulative oil) for known reservoir characteristics (i.e., permeability, thickness, residual oil saturation, chemical adsorption) and project design parameters (i.e., pattern size, chemical slug size and concentration), Model #2 predicts reservoir characteristics by history matching the reservoir response, and Model #3 predicts project design parameters for known reservoir response and characteristics. Models #4 and #5 predict project design parameters for a targeted cumulative oil volume and project duration time, which is useful for economical evaluation before the implementation of cEOR projects.\u0000 The validation results show that the developed ANN-based models closely predict the numerical results. In addition, the models are able to reduce the computational time by four orders of magnitude, which is significant considering the complexity of cEOR modeling and the need for reliable and efficient tools in building cEOR feasibility studies. In terms of accuracy, Model #1 has a prediction error of 5% whereas the error for other four inverse ANN models is about 20–40%. To enhance the performance of the inverse ANN models, we changed the ANN structure, increased training cases, and used functional links, which slightly reduced the error. Further, we introduced a back-check loop that uses the predicted parameters from the inverse ANN models as inputs in the forward ANN model. A comparison of back-check results for the reservoir response with the numerical results delivers a relatively small error of 10%, revealing the non-uniqueness of solutions obtained from the inverse ANN models.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"11 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":"128477186","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":"Extended Walsh-Towler Algorithm to Compute Black Oil PVT Properties for Volatile Oil Reservoir Fluids","authors":"J. Almeida","doi":"10.2118/195476-MS","DOIUrl":"https://doi.org/10.2118/195476-MS","url":null,"abstract":"\u0000 Walsh and Towler in 1995 presented an algorithm to calculate the modified Black-Oil PVT properties (Bo, Rs, Bg and Rv) of gas condensate reservoir fluids using the experimental data from the Constant Volume Depletion (CVD) test combined with the recovery calculations provided by commercial PVT laboratory reports as part of the PVT study. The purpose of the proposed algorithm is to extend the Walsh and Towler method to volatile oil reservoirs fluids.\u0000 Walsh-Towler algorithm requires as input parameters the gas compressibility factor, the two- phase compressibility factor, the cumulative produced gas, the cumulative produced oil, the volume fraction of liquid condensate, at each pressure depletion stage of the CVD experiment and the initial gas compressibility factor (Zi). The algorithm requires the initial gas compressibility factor (Zi) to calculate the initial moles of hydrocarbon at the saturation pressure, to calculate the remaining mole fraction of gas at each pressure stage as a fraction of the total moles initially present at the saturation pressure and, combined with the two-phase compressibility factor, for the calculation of the total moles of gas and liquid remaining after each stage of depletion.\u0000 For volatile oil samples, the initial gas compressibility factor (Zi) is undefined; to overcome this limitation a modified algorithm is proposed that replaces the use of the two-phase compressibility factor by the wellstream produced cumulative from the CVD experiment where the initial gas compressibility factor, for volatile oil, is not required.\u0000 The proposed algorithm can be applied to calculate the Black-Oil PVT properties (Bo, Rs, Bg and Rv) for both Gas condensate and Volatile oil reservoir fluids.\u0000 The common practice to calculate the black-oil PVT model is by calibrating an Equation of State and export the modified black-oil PVT properties for both gas condensate and volatile oil reservoir fluids. Walsh and Towler presented a valuable tool, that not requires the use of a calibrated EOS, to calculate the black-oil PVT properties for gas condensate. The proposed algorithm extends the method to volatile oil reservoir fluids. The proposed algorithm is rigorous, direct and simple to use and can be applied to both gas condensate and volatile oil.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"13 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":"127065737","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 Study on the Chemo-Mechanical Alteration of Cement in CO2 Storage Sites","authors":"Mohammadreza Bagheri, S. Shariatipour, E. Ganjian","doi":"10.2118/195520-MS","DOIUrl":"https://doi.org/10.2118/195520-MS","url":null,"abstract":"\u0000 The fluid pressure, the stress due to the column of the cement in the annulus of oil and gas wells, and the radial pressure exerted on the cement sheath from the surrounding geological layers all affect the integrity of the cement sheath. This paper studies the impact of CO2-bearing fluids, coupled with the geomechanical alterations within the cement matrix on its integrity. These geochemical and geomechanical alterations within the cement matrix have been coupled to determine the cement lifespan. Two main scenarios including radial cracking and radial compaction, were assumed in order to investigate the behaviour of the cement matrix exposed to CO2-bearing fluids over long periods. If the radial pressure from the surrounding rocks on the cement matrix overcomes the strength of the degraded layers within the cement matrix, cement failure can be postponed, while on the other hand, high vertical stress on the cement matrix in the absence of a proper radial pressure can lead to a reduction in the cement lifespan. The radial cracking process generates local areas of high permeability around the outer face of the cement sheath. Our simulation results show at the shallower depths the cement matrices resist CO2-bearing fluids more and this delays exponentially the travel time of CO2-bearing fluids towards the Earth's surface. This is based on the evolution of CO2 gas from the aqueous phase due to the reduction in the fluid pressure at shallower depths, and consumption of CO2 in the reactions which occur at the deeper locations.","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":"130383779","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":"Evaluating Acid Fracture Etching Profiles and Formation Mineralogy Composition from Distributed Temperature Measurements","authors":"M. Aljawad","doi":"10.2118/195537-MS","DOIUrl":"https://doi.org/10.2118/195537-MS","url":null,"abstract":"\u0000 Acid fracture operations in carbonate formations are used to create highly conductive channels from the reservoir to the wellbore. Conductivity in calcite formations is expected to be highest near the wellbore, where most of the etching occurs. The near wellbore fracture etched-width profile can be estimated from the measured temperature distribution. Temperature data can be obtained from fiber optic distributed temperature sensing (DTS) installed behind casings to monitor fracturing operations.\u0000 Heat transfer is commonly coupled in acid fracture models to account for temperature's effects on acid reactivity with carbonate minerals. Temperature profiles are usually evaluated during simulations of fracture fluid injection, but seldom during fracture closure. Since most of the acid is spent during injection, many models have assumed that the remaining acid reacts proportionally along the fracture length. Because of this assumption, neither acid spending nor temperature is usually simulated during fracture closure.\u0000 In this study, a fully integrated temperature model was developed wherein both the acid reaction and heat transfer were simulated while the fracture was closing. At each time step, transient heat convection, conduction, and generation were calculated along the wellbore, reservoir, and fracture dimensions. Modeling temperature during this transient period provides a significant understanding of the fracture etched-width distribution. During shut-in, cold fracture fluids are heated, mainly because of heat flow from the formation to the fracture. The amount of fluid stored in the fracture determines how fast the fluid is heated. Wider fracture segments contain larger amounts of cold fracture fluids, resulting in it taking longer to reach the reservoir temperature. Because of this phenomenon, near a wellbore, the vertical fracture etched-width profile can be determined from the temperature distribution. Also, minerals' spatial distributions along the wellbore's lateral can be estimated in multistage acid fracturing. This is done by minimizing the difference between the observed and modeled temperatures.\u0000 This evaluation of etched width profiles at the fracture entrance provides an estimation of fracture-conductive channel locations. Moreover, it has significantly improved the understanding of mineralogy distribution in multi-layer formations. This information will be particularly useful when designing acid fracturing jobs in nearby wells or revisiting the same wellbore for further stimulation.","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":"131167109","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":"Applicability of Models for Liquid Loading Prediction in Gas Wells","authors":"C. Vieira, M. Stanko","doi":"10.2118/195466-MS","DOIUrl":"https://doi.org/10.2118/195466-MS","url":null,"abstract":"\u0000 Liquid loading phenomenon is known as the inability of the produced gas to carry all the co-produced liquid to the surface. Under such condition, the non-removed liquid accumulates at the wellbore resulting in reduction of the production and sometimes cause the death of the well. Several studies were carried out and correlation were developed based on field and experimental data with the aim to predict the onset of liquid loading in a gas well. However, each model provides different indication on the critical gas velocity at which the liquid loading exists. Thus, to have a clear understanding on the difference between most used models, experiments were performed in an upward inclinable pipe section. The 60-mm diameter test pipe was positioned at angles of 30°, 45° and 60° from horizontal. The fluids used were air and light oil. Measurements include fluid velocities and fluid reversal point. High-speed video cameras were used to record the flow conditions in which the onset of liquid loading initiated. Experimental results were compared with existing models by Turner et al. (1969), Barnea (1986), Belfroid et al. (2008), Luo et al. (2014), Shekhar et al. (2017) and with a commercial dynamic multiphase flow simulator from SPT-Group (OLGA2017.1.0®). Prediction using the liquid film models presented acceptable agreement with experimental.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"193 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":"122516233","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}