Day 4 Thu, June 14, 2018最新文献

{"title":"Parameter Estimation from Sandface Drawdown Temperature Transient Data in the Presence of a Skin Zone Near the Wellbore","authors":"F. Panini, M. Onur","doi":"10.2118/190773-MS","DOIUrl":"https://doi.org/10.2118/190773-MS","url":null,"abstract":"\u0000 The objectives of this study are to develop a new approximate analytical solution for predicting drawdown temperature transient behavior of a fully penetrating vertical well in a radial composite reservoir system and to use it as a forward model for estimating the fluid flow and thermal parameters of the system by nonlinear regression. The analytical solution considers a radial composite reservoir model, where the inner zone may represent a skin zone and the outer zone represents an infinitely extended reservoir. The analytical solution for predicting sandface temperatures is obtained by solving the decoupled isothermal diffusivity (pressure) and temperature equations for the inner and outer zones by using the Boltzmann transformation. The convection, transient adiabatic expansion and Joule-Thomson heating effects are all considered in solving the temperature equation. The developed analytical solution is validated by using both a commercial non-isothermal numerical simulator and a semianalytical solution available in the literature for different synthetic cases. For estimating the system parameters by history matching of observed temperature and/or pressure data with the model, we use the Levenberg-Marquardt method. We investigate the impact of noise in temperature and/or pressure data on the estimated parameters by inspecting statistical measures such as confidence intervals and correlation coefficients between parameter pairs. It is observed that selecting proper initial guesses of parameter is critical for estimating reliable values of the parameters through nonlinear regression of temperature data because the parameters are more correlated in the temperature equation than in pressure equation. Hence, we provide an effective methodology based on semi-log analysis and log-log diagnostic plots of pressure and temperature data to obtain good initial guesses of parameters that will derive the nonlinear regression method to have refined optimized estimates. The results show that the rock, fluid and thermal properties of the skin zone and non-skin zone can be reliably estimated from sandface temperature transient data jointly with pressure transient data in presence of noise, recorded during constant-rate drawdown tests with our approximate solutions and effective methodology proposed for obtaining initial guesses of the parameters.","PeriodicalId":178883,"journal":{"name":"Day 4 Thu, June 14, 2018","volume":"23 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121983998","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":"Silica Nanoparticles Suspension for Enhanced Oil Recovery: Stability Behavior and Flow Visualization","authors":"Shidong Li, N. Hadia, H. Lau, O. Torsæter, L. P. Stubbs, Qi Hua Ng","doi":"10.2118/190802-MS","DOIUrl":"https://doi.org/10.2118/190802-MS","url":null,"abstract":"\u0000 Oil and gas industry is witnessing a rapid increase of interest in application of nanotechnology. Since last few years, nanotechnology is being studied as an alternative enhanced oil recovery (EOR) method and laboratory experiments have shown its potential. However, the adsorption behavior of nanoparticles in porous media and underlying mechanisms for improving oil recovery are still not well understood. The objective of this study was to investigate silica nanoparticles adsorption and displacement mechanisms at the pore scale within a micromodel. Another objective was to stabilize silica nanoparticles in the presence of crude oil at a high salinity and a high temperature for a longer period of time.\u0000 A turbidity scanner was utilized to test stability of silica nanoparticles suspension in the presence of crude oil under 60°C. Turbidity stability index was used to evaluate stability of nanoparticles suspension and hydrochloric acid (HCl) was used as stabilizer to improved stability of nanoparticles suspension. The interfacial tensions (IFT) and contact angle between crude oil and the nanoparticles suspension with stabilizer were also measured. Both single-phase and two-phase flooding experiments were conducted for nanoparticles with and without stabilizer by using glass micromodels to visualize the nanoparticles adsorption and displacement behavior at the pore scale. Oil recovery was determined with image analysis to evaluate the potential of these nanoparticles for EOR applications. In addition, microscope images were taken and analyzed to investigate EOR mechanisms of nanoparticles suspension.\u0000 Results of turbidity scanner showed nanoparticles behavior changed from aggregation to sedimentation. Silica nanoparticles suspension with HCl showed much better stability than the one without HCl under 3.8 wt. % synthetic sea water and 60°C condition. Wettability alteration between crude oil and water were observed with silica nanoparticles. For single-phase visualization flooding experiments, nanoparticles suspension with a stabilizer had less adsorption than the one without a stabilizer, and it could flow through micromodel without significant plugging. Nanoparticles adsorption can alter wettability of the micromodel to more water-wet. For two-phase visualization flooding experiments, injection of silica nanoparticles suspension with a stabilizer had better EOR result under high flow rate and can increase oil recovery about 3%. Wettability alteration and emulsification were proposed as main EOR mechanisms for nanoparticles.\u0000 Silica nanoparticles stability behavior in the presence of crude oil under a high salinity and a high temperature was studied and the stability of nanoparticles suspension was quantified by using turbiscan stability index. Adding HCl as a stabilizer can reduce adsorption of nanoparticles in micromodel and avoid plugging. Enhanced oil recovery mechanisms of nanoparticles were investigated by using visualization micromodel flooding","PeriodicalId":178883,"journal":{"name":"Day 4 Thu, June 14, 2018","volume":"14 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114885828","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":"New Fracture Hydrodynamics and In-Situ Kinetics Model Supports Comprehensive Hydraulic Fracture Simulation","authors":"I. Velikanov, V. Isaev, D. Bannikov, A. Tikhonov, L. Semin, L. Belyakova, D. Kuznetsov","doi":"10.2118/190760-MS","DOIUrl":"https://doi.org/10.2118/190760-MS","url":null,"abstract":"\u0000 We demonstrate the advantages of a new hydraulic fracturing simulator comprising a fine-scale fracture hydrodynamics and in-situ kinetics model. In contrast to existing commercial modeling tools, it has a sufficient resolution and other functionality for adequate representation of modern stimulation technologies: pulsing injection of proppant, mixtures of multiple fracturing materials (fluids, proppants, fibers, etc.), materials degradation, etc. This simulator accounts for the influence of materials distribution on fracture propagation and calculates fracture conductivity distribution. We coupled it with a production simulation model and established a complete framework for hydraulic fracturing treatment design. In addition to the selection of the pumping schedule, this model can be used to define specifications for novel hydraulic fracturing materials. This is a step change tool for wellbore stimulation and production forecast.","PeriodicalId":178883,"journal":{"name":"Day 4 Thu, June 14, 2018","volume":"18 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"117053217","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":"Methodology to Assimilate Multi-Objective Data Probabilistically Applied to an Offshore Field in the Campos Basin, Brazil","authors":"Carlos Eduardo de Aguiar Nogueira Gomes, C. Maschio, V. Paes, M. Correia, P. S. Câmara, A. A. S. Santos, D. Schiozer, Marcia Ida de Oliveira Silva, M. S. D. Santos, Alessandra Silva Anyzewski","doi":"10.2118/190767-MS","DOIUrl":"https://doi.org/10.2118/190767-MS","url":null,"abstract":"\u0000 This work applies a new methodology to assimilate multi-objective data (production, injection and, pressure of all wells) based on five of the twelve steps described by Schiozer et al. (2015) using reservoir simulation and uncertainty reduction for a brown offshore field in the Campos Basin, Brazil. We use probabilistic techniques to assimilate all data simultaneously, improving the performance of the process. The 12-step methodology by Schiozer et al. is based on a closed-loop reservoir development and management process. Steps 1 and 2 construct the model under uncertainties and select the numerical model. Steps 3 to 5 assimilate history data in an iterative process proposed by Maschio and Schiozer (2016). At each iteration, a set of best-matched models is selected to update the probability distributions of the reservoir properties (parameters) based on a correlation matrix. Steps 6 to 12, comprising the decision analysis, were not included in this work. The results reflect a practical application of the methodology, considering a real reservoir with two zones and complex behavior that was captured during reservoir characterization using an uncertainty reduction algorithm. The reservoir was characterized through the probabilistic combination of uncertain variables, based on well logs and seismic data. The probabilistic characterization highlighted the geological variability under uncertainty. A set of three hundred geological realizations with associated porosity, net-to-gross ratio, and permeability distributions was generated for further combination with uncertain dynamic parameters. The method DLHG (Discretized Latin Hypercube combined with Geostatistics) was used during the entire process to build approximately 1000 uncertain scenarios allowing the review of reservoir parameters in any iteration. The data assimilation process was used to update the probability density function for each parameter according to the data match indicators. We significantly reduced the uncertainty and improved production forecast reliability. This paper integrated different areas including reservoir characterization, reservoir simulation and history matching with the associated uncertainty reduction. The methodology was successfully applied in a practical case with several uncertainties, indicating good potential for application in other fields. The matching quality was better than in previous approaches.","PeriodicalId":178883,"journal":{"name":"Day 4 Thu, June 14, 2018","volume":"124 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114489337","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 Sulphates Presence During Application of Smart Water Flooding Combined with Polymer Flooding","authors":"Muhammad Tahir, R. Hincapie, Hendrik Foedisch, H. Abdullah, L. Ganzer","doi":"10.2118/190796-MS","DOIUrl":"https://doi.org/10.2118/190796-MS","url":null,"abstract":"\u0000 Oil recovery using Smart Water technology (SWF) can be maximized by optimizing the composition of injected water. Brine optimization is also believed to improve Polymer Flooding (PF) performance. The present study aims to assess and define the potential impact of combining Smart Water with Polymer Flooding, based on the sulphates presence in formation/injection water and rock composition. In this work, we study the impact of sulphates (sodium sulphates) on polymer viscoelasticity and its performance in porous media, based on oil recovery and pressure response.\u0000 Brine composition is optimized after having synthetic sea water (SSW) as a base brine. Brine optimization is performed by doubling the amount of sulphates, whilst diluting (in fresh water) the SSW-brine to a tenth of its initial concentration. Thus, four brines were utilized: 1) SSW (formation water), 2) SSW but double sulphates, 3) SSW/10 and 4) Brine 2/10. The workflow included core plugs aging prior core flooding. Secondary tertiary and quaternary mode experiments were performed to evaluate the feasibility of applying both processes.\u0000 The SSW-brine optimization (a tenth of its initial concentration) resulted in a salinity of 4.2 g/L which is in good agreement with previous studies (≤5 g/L), to guarantee additional oil recovery using SWF. Polymer rheological characterization was performed over wide range of shear rates and temperatures. Sodium sulphates showed increase in polymer viscosity as compare to sodium chloride or divalent cations. Enhancement in polymer linear viscoelasticity is observed with an increase in sulphate ions concentration. Furthermore, viscosity analysis over temperature has advocated to perform the core flood experiments at 45°C. Fluids were optimized/selected using a comprehensive rheological evaluation (ηoilηpolymer=2). Optimized Smart Water with higher amount of sulphates ions has shown additional oil recovery in both secondary and tertiary mode. Moreover, polymer injection in tertiary mode after smart water injection has shown significant additional oil recovery.\u0000 This study focuses on the influence of sulphates ions on SWF and PF performance for application in sandstone reservoirs. Previous studies have mainly focused the evaluation of sulphates ions impact only in carbonate reservoirs. It is of importance to further understand/clarify the effect of sulphates for field applications of SWF and PF combined. This in turn, could lead to improve the economics of project performance, by means of incremental oil and the less polymer required.","PeriodicalId":178883,"journal":{"name":"Day 4 Thu, June 14, 2018","volume":"359 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122758211","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":"Study of the Feasibility of the Carbon Dioxide Injection in a North Sea Petroleum Reservoir","authors":"Wael Al-Masri, Christos Papaspyrou, A. Shapiro, V. S. Suicmez","doi":"10.2118/190783-MS","DOIUrl":"https://doi.org/10.2118/190783-MS","url":null,"abstract":"\u0000 Carbon dioxide injection has recently been considered as a promising method for enhanced oil recovery. The supercritical carbon dioxide is often miscible or nearly miscible with the oil under reservoir conditions, which facilitates high recovery. Underground injection of carbon dioxide is also of a significant ecological advantage, and utilization of CO2 results in a noticeable reduction of the taxation of the petroleum companies. On the other hand, application of carbon dioxide under conditions of the North Sea petroleum reservoirs for enhanced oil recovery (EOR) is hindered by multiple practical problems: availability of the CO2 sources, logistics of the delivery offshore, corrosion resistivity of the installations, and other. Previous studies of CO2 EOR for the reservoirs of the North Sea region, including core-flooding experiments and reservoir simulations, indicate that the deployment of CO2-EOR can significantly enhance the recovery of hydrocarbons. However, CO2 must be generated from anthropogenic sources, which affects the feasibility of the projects.\u0000 The current study evaluates the potential of a CO2-EOR project under the conditions of a specific petroleum reservoir of the Danish sector North Sea. Geological characteristics of the reservoir and the detailed oil properties lie in the ground of the study. The minimum miscibility pressures between CO2 and the reservoir oil are evaluated with the help of the in-house software (SPECS 5.70) and the commercial reservoir simulator (ECLIPSE 300). The results are verified in the slimtube simulations. The effect of the different oil characterizations and its lumping into the different numbers of components is investigated. The oil is found to be miscible with the carbon dioxide under reservoir conditions.\u0000 Several injection scenarios have been tested on the 2-D and 3-D reservoir models. Waterflooding was compared to injection of carbon dioxide, as well as water-alternate gas injection. An optimal scenario with regard to water-gas ratio under WAG was selected for further studies.\u0000 Finally, a cash flow model by Monte Carlo simulations and a sensitivity analysis on the impact of oil and CO2 price and discount rate, certify the feasibility and attractiveness of a CO2-EOR project in the West Flank of the Dan field.","PeriodicalId":178883,"journal":{"name":"Day 4 Thu, June 14, 2018","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125508291","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":"Performance Prediction for Dynamic Autonomous Flow Control Valves","authors":"Ivar Leander Johannessen Sørheim, Stian Morken Askvik, H. Åsheim","doi":"10.2118/190816-MS","DOIUrl":"https://doi.org/10.2118/190816-MS","url":null,"abstract":"\u0000 Flow forces controls this valve by moving a plate to adjust the opening. Viscous oil tends to open the valve, while less viscous water and gas make it choke. It also chokes at high flow rates. Such features are useful for inflow control along horizontal well. It may also have wider applications.\u0000 Pressure drops were measured across a test valve, for different flow rates and fluids. Measurements were compared to an analytic solution, relating performance to fluid properties, valve geometry and dimensions.\u0000 For water and oil, the measurements generally confirmed the analytic solution, but also revealed certain deviations. Measured performance with air showed phenomena not properly predicted by the analytic solution, which does not include compressibility\u0000 Published data for a commercial flow control valve of similar geometry indicate poorer performance than for the current experimental valve. Since the construction and dimension of the commercial valve are kept under cover, reasons becomes speculative","PeriodicalId":178883,"journal":{"name":"Day 4 Thu, June 14, 2018","volume":"47 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126263756","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":"Evaluation of Aluminium Oxide and Titanium Dioxide Nanoparticles for EOR Applications","authors":"Alexander Sebastian Hogeweg, R. Hincapie, Hendrik Foedisch, L. Ganzer","doi":"10.2118/190872-MS","DOIUrl":"https://doi.org/10.2118/190872-MS","url":null,"abstract":"\u0000 Utilization of nanoparticles in EOR have gained high attention recently, with good but controversial results reported on improving oil recovery. Within this work two types of nanoparticles are selected and assessed, to determine its effect in oil mobilization. The experimental evaluation is performed using micromodels (EOR chips), in combination with a detailed nanofluids characterization. The workflow presented is a useful approach that can extended among different laboratories as preliminary evaluation.\u0000 The workflow comprises a set of interrelated steps: 1) Selection and preparation of the Aluminium Oxide (Al2O3) and Titanium Dioxide (TiO2) nanofluids, influenced by recent literature comparisons, 2) Detailed rheological evaluation of nanofluids and oil, 3) Investigation of the Fluid-Fluid interaction by means of the interfacial tension (IFT) and nanoparticles effects in oil viscosity, 4) Two-phase flow experiments using EOR chips (breakthrough and mobilized oil vs PV injected), 5) Image processing analysis, leading to 6) Quantitative and qualitative analysis of the experimental data.\u0000 As expected, we observed that diluting nanoparticles in fresh water increased the stability compared to brine. It was required the use of a stabilizer to optimize nanofluids characteristics. Unlike reported in the literature where Polyvinylpyrrolidone (PVP) is used, we found that adding Poly(ethylene oxide)-(PEO) leads to a more stable nanofluids. There, seemed to be a tendency for the Al2O3 nanoparticles to reduce the viscosity of the aqueous-phase, when combined with PEO. Moreover, when Al2O3 was added to the oleic-phase increased its viscosity, with a strong dependency of soaking process. The image process analysis allowed to generate algorithms to calculate concentrations and saturations among the two-phase flow experiments. These algorithms proved to be highly beneficial enabling qualitative and also quantitative analysis of mobilized oil zones, as well as plugged areas. The experimental results did not show a significantly strong increase in mobilized oil due to Titanium Dioxide nanofluids, but slightly better results were observed with the Alumnium Oxide nanofluid in a low concentration.\u0000 Much research in recent years has focused on the study of Silica nanoparticles. Since different other nanoparticles can be commercially found, this work presents additive information to the existing body of literature. Moreover, the workflow presented can be used by fellow researchers as preliminary tool for laboratory evaluations. These, to obtain potential useful insights from oil mobilization by the application of nanoparticles flooding.","PeriodicalId":178883,"journal":{"name":"Day 4 Thu, June 14, 2018","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130211059","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":"Mitigation of the Remote Gauge Problem in Temperature Transient Analysis","authors":"A. Dada, K. Muradov, Hong Wang, E. Nikjoo, E. Villarreal, D. Davies","doi":"10.2118/190863-MS","DOIUrl":"https://doi.org/10.2118/190863-MS","url":null,"abstract":"\u0000 The continuous stream of data from wells completed with multiple permanent, downhole sensors has created new monitoring possibilities. One new workflow, TTA (Temperature Transient Analysis) has proven to be particularly valuable for allocation of flow rates and phase cuts as well as for analysis of the properties of the near-wellbore formation. However, the measured temperature signal suffers considerable attenuation when the gauge is installed distant from the producing layer. This loss in signal quality has to be accounted for before carrying out TTA.\u0000 This paper investigates the effect of heat transmission in the wellbore on TTA, evaluates existing transient thermal wellbore models and develops models to reconstruct the sandface temperature from the temperature measured by a gauge located at some distance from the sandface. The possibility of estimating the thermal properties of the wellbore and surrounding formation using these models is also studied.\u0000 Two approaches are proposed for mitigating the remote gauge problem. The first approach reconstructs the sandface temperature from the degraded gauge temperature measurement data. Temperature reconstruction was found to be possible providing an accurate model of the wellbore is available. Both numerical, transient, thermal wellbore simulators and analytical thermal wellbore models may be used. Numerical inversion of the analytical transient thermal wellbore model is necessary since analytical inversion is impractical due to the result being very sensitivity to errors in measured gauge temperature.\u0000 The second approach requires producing the well under conditions that minimize the attenuation. Empirical methods may be used to quantify the heat transfer effect, when conditions are such that the transient temperature signal is \"good enough\" for TTA. This approach also also allows estimating the degree of uncertainty (due to wellbore heat transfer) on the TTA.\u0000 This work would extend the application of TTA to wells where analysis was previously impossible because the gauge was installed distant from the producing layer. This extension of TTA further increases the value-added by installing permanent downhole gauges.","PeriodicalId":178883,"journal":{"name":"Day 4 Thu, June 14, 2018","volume":"61 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128512279","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":"Designed Simulations for Optimization of Hydraulic Fracture Design and Production Well Constraints in Shale Gas Reservoirs with Reduced-Physics Metamodeling","authors":"W. Al-Mudhafar, K. Sepehrnoori","doi":"10.2118/190835-MS","DOIUrl":"https://doi.org/10.2118/190835-MS","url":null,"abstract":"\u0000 Tremendous amount of oil and gas left behind in unconventional reservoirs, especially in the United States. Therefore, it is necessary to economically recover these shale-based energy resources by the effective hydraulic fracturing technology. In this paper, a pseudo-component black oil reservoir simulator was used to evaluate the gas production from a synthetic shale gas reservoir through hydraulic fracturing (HF).\u0000 In that reservoir, one horizontal well was placed with 11 hydraulic fractures to predict the future reservoir performance within 22-year prediction period. The base case of HF simulation was set with a default values for the hydraulic fracturing parameters along with default production well constraints. The HF design parameters included are fracture conductivity and permeability, fracture width and half length, layers up and down, and minimum fracture spacing. The production well constraints were minimum bottom hole pressure and maximum gas production rate. Next, Design of Experiments (DoE) and proxy modeling were adopted for the optimization of hydraulic fracturing design through the shale gas production. In particular, these operational controllable parameters were manipulated using the Latin Hypercube Design (LHD-DoE) approach to obtain the optimal gas production and to build the proxy models. Two successive sets of experiments (running cycles) were designed by mixing the levels of these operational parameters using the LHD-DoE.\u0000 The optimization approach significantly increased the cumulative gas production about 1.3734E9 SCF in the 1st running cycle and 3.6583E9 in the 2nd running cycle over the base case of default parameter setting. The 2nd running cycles (640 runs) were successively implemented after refining the range of each parameter based on the outcome of the first running cycle (550 runs). After that, two proxy models were constructed to obtain a simplified reduced-physics metamodel alternative to the complex (full-physics) reservoir simulator: 2nd degree polynomial equation and RBF Neural Network. The two proxy approaches led to accurate matching between the simulator- and proxy-based cumulative gas production. However, RBF-NN was more accurate prediction of cumulative gas production than the polynomial regression.\u0000 Finally, Sobol sensitivity analysis was adopted to determine the most influencing hydraulic fracture parameters and well constraints that impact the shale gas production performance. Sobol analysis was adopted based on the RBF-NN and polynomial proxy models. In descending order, the most influencing parameters are the fracture half-length, layers up, layers down, and the minimum bottom hole pressure in the production well. The other HF had essentially negligible impact on the cumulative gas production performance. The fracture half-length was by far the most influential factor affecting the shale reservoir performance because this parameter is directly related to the total fracture area in which the gas p","PeriodicalId":178883,"journal":{"name":"Day 4 Thu, June 14, 2018","volume":"368 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114785095","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}