Day 1 Mon, September 30, 2019最新文献

{"title":"Reducing Cost of BOE and Extending Field Life with Intelligently Controlled Multilaterals","authors":"G. Mark, Grossmann Andreas","doi":"10.2118/196165-ms","DOIUrl":"https://doi.org/10.2118/196165-ms","url":null,"abstract":"\u0000 While many factors in the reservoir cannot be controlled, there are three controllable factors in field development that make a significant impact. More reservoir contact leads to more oil produced. Controlling sand and water means lower treatment costs, and in-situ reservoir management leads to higher cumulative production. While the underlying technologies have been around for up to 20 years, it is only recently that their synergies and true value are understood. This paper will demonstrate the effect each of these technologies has on increasing overall production rates, improving recovery, and reducing the cost per Barrel of Oil Equivalent (BOE).\u0000 The successful implementation of multilaterals in the North Sea will be analyzed. Since 1996, over 300 multilateral junctions have been installed on the Norwegian continental shelf fields with currently approximately 30 junctions completed each year.\u0000 Additionally, simulations will be used to demonstrate the incremental improvements in oil recovery that can be obtained by using properly designed advanced completions that include multilaterals, sensors, and passive/active flow control equipment.\u0000 The paper will evaluate production performance of a vertical well field development base case against scenarios using horizontal and multilateral wells. It will show how fields can be optimized, leading to increased oil and decreased water production.\u0000 Production rates can be significantly improved by combining multilaterals with other advanced completion techniques, such as intelligent completions and inflow control devices. The subject field simulation can be further optimized to manage gas and water production.\u0000 With a tailored multilateral field design, combined with properly designed advanced completions systems, the simulation succeeds in terms of achieving maximum contact with the oil reservoir and meeting improved ultimate recovery objectives.\u0000 It can be concluded that as reservoir contact is increased, a reduced decline in production rate is observed leading to both a higher Estimated Ultimate Recovery (EUR) and optimized drawdown profile distributions. Additionally, results will be presented that have considered oil production and a method to lower production of unwanted fluids or gas.\u0000 This paper also demonstrates the value of field development design from the perspective of reservoir simulation. It is through reservoir insight that a level of understanding is created that can help define the optimum well and completion design to meet field expectations.\u0000 Advanced multilaterals continue to grow in popularity with many operators, and it therefore becomes important to evaluate the value of different field development methods. This knowledge can aid operators in unlocking new reservoir targets and optimizing field development, and ultimately will improve recovery factors and overall field economics.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"114 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121895547","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Analytical Model for Rate Transient Analysis in Low-Permeability Volatile Oil Reservoirs","authors":"Le Luo, Shiqing Cheng, John W. Lee","doi":"10.2118/195900-ms","DOIUrl":"https://doi.org/10.2118/195900-ms","url":null,"abstract":"\u0000 This paper presents a simple yet rigorous analytical solution for two-phase (gas-oil) flow in closed volatile oil reservoirs. The solution includes all flow regimes over the life of a multi-fractured horizontal well, including the usually long-duration early transient flow followed by the transition and the boundary-dominated flow regimes. The solution will be particularly useful in rate transient analysis of production data and production forecasting for horizontal wells with multiple fractures in ultra-low permeability reservoirs, such as shales. We formulated the governing, non-linear partial differential equations (PDEs) for simultaneous gas-oil flow with an inner boundary condition of constant bottom-hole pressure (BHP). We then defined pseudo-variables to transform the non-linear PDEs to linear forms. By developing deterministic models for calculation of fluid properties using multi-regression analysis of PVT data and relative permeability curves, we were able to find analytical solutions by the separation of variables method for specified initial and outer boundary conditions. We obtained a production rate-time relation which can be used to generate type curves or to provide a basis for history matching production data and forecasting future production. Under constant bottom-hole pressure producing condition, the resulting solutions that describe the relationship between dimensionless rate and dimensionless two-phase pseudotime indicate a complicated decline with an exponential relation inside an infinite series. We validated the solutions through comparisons with compositional simulation using commercial software; the satisfactory agreements demonstrated the accuracy and utility of the analytical solutions. Our results indicate that the production performance in multi-phase flow is far different than performance in single-phase flow, and that formation properties interpreted using techniques appropriate for single-phase flow can be seriously in error when applied to two-phase flow situations. Finally, we found that our analytical solution yielded reasonable interpretations of actual field data from the Midland Basin.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134251407","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":"Identifying Depleted Induced Fractures from Offset Wells Using Common Drilling Data","authors":"K. Wutherich, S. Srinivasan, R. Downie, B. Katon","doi":"10.2118/196189-ms","DOIUrl":"https://doi.org/10.2118/196189-ms","url":null,"abstract":"\u0000 This paper presents a new methodology that takes readily available drilling data, to identify the location and relative magnitude of localized depletion that is likely caused by induced fractures that are intersected by a newly drilled well. This paper describes the process used to identify the fractures and presents a case study in the Utica Shale that validates the results.\u0000 In recent years, mechanical specific energy (MSE) has been used to assess mechanical properties of rocks. It is further known that changes in reservoir pressure will also influence MSE. This new process analyzes a modified mechanical specific energy, and looks for anomalous increases in MSE, which should be present when drilling through a depleted fracture. To verify the existence of depleted fractures, a set of three wells were analyzed using this technique, a parent well, and two child wells.\u0000 Analysis showed that there were no signs of depleted fractures detected in the parent well, while the two child wells both contained multiple drilling signatures that were consistent with depleted fractures. The location of the apparent depleted fractures in the child well were not only consistent with the location of the parent well, but also sections in the parent well that were most likely to create dominant fractures.\u0000 The identified fractures in the child wells, also were consistent in location, magnitude and area of effect across both wells. These consistencies further promote the conclusion that dominant fractures created while completing the parent well, being penetrated and identified in both child wells.\u0000 Based on the work done, there is clear indication that the proposed methodology can potentially be used to identify depleted fractures. This information can further be used in order to design completion strategies aimed at reducing both the probability and severity of parent-child fracture interactions such as frac hits.\u0000 The paper presented will describe the first successful attempt to characterize depleted induced fractures using standard drilling data, without the use of any additional tools being run in the wellbore. This process will provide significant impact, not only in designing completions for parent-child well pairs, but will also further the understanding of far field fracture effects such as the extent of fracture extension, depletion around a fracture, and implications for well spacing.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131130118","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":"12 Months of Real-Time Digital Chemistry in 3-Phase Flow - Lessons Learned and Plans Forward","authors":"John Lovell, Omar Kulbrandstad, Sai Madem, M. Godoy","doi":"10.2118/196062-ms","DOIUrl":"https://doi.org/10.2118/196062-ms","url":null,"abstract":"\u0000 By miniaturizing and ruggedizing equipment used for quantum paramagnetic spectroscopy, it is now possible to take a real-time chemical snapshot of molecules flowing through the wellhead or other surface fixtures. The digital time-series captures unique chemical properties of the fluid, such as the percentage of asphaltene in the oil, the oil-water ratio and gas-oil ratio. That data can be transmitted via industry-standard cloud protocols and be monitored from a global service center. 12 months of real-time data has been collected from operations around the world and the real-time monitoring has enabled prompt feedback for upgrades in both hardware and software. In a three-phase well configuration that had high rates of both water (over 90%) and gas (~1 MMSCf/day), this feedback drove some significant hardware modifications in order to optimize the consistency of asphaltene data.\u0000 The heart of the system is a microwave resonator that was designed to receive fluid at wellhead conditions with minimal reduction from wellhead pressure and temperature. The parameters of the resonator were optimized to maximize microwave intensity for typical oilfield fluids. A tailor-made set-up of fluid accumulator and control-valves upstream of the resonator ensured that the resonator could obtain samples that were mostly oil. By combining the resonator with a solenoid that created a large magnetic field across the oil, the resulting system provided spectroscopic data similar to that available in chemical laboratories but in a smaller package and one that tolerates some gas and conductive water in the oil. The combined quantum data is now provided continuously to the operator via a cloud or other communication architecture of operator choosing. It is anticipated that the resulting Internet of Things (IoT) system will make possible the optimization of chemical program and asphaltene remediation by incorporating system data with integrated flow assurance management. Qualification for offshore is ongoing with 5ksi pressure certification already achieved.\u0000 It was not obvious before installation, but once the 3-phase system was installed and the data transmitting in real-time, it became clear that software to automatically extract asphaltene information from spectral data needed to be able to cope with sudden and large changes in both asphaltene level and water-cut/gas-oil ratio which in turn required building an adaptive software model. Asphaltene percentage at one producing well was seen to vary from 0.3% to 3% in a single day. It was also discovered from the cloud-based monitoring that daily temperature variation introduced a phase variation in the shape of the sensor response. Correct derivation of spectral voltages was achieved through the combination of machine learning, model-based analysis and additional diagnostic data such as the quality factor of the resonator and its resonance frequency. As a consequence, the AI-based software could extract the not only the ","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129479100","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":"Data-Driven Model for the Drilling Accidents Prediction","authors":"Ksenia Antipova, Nikita Klyuchnikov, A. Zaytsev, E. Gurina, Evgenia Romanenkova, D. Koroteev","doi":"10.2118/195888-ms","DOIUrl":"https://doi.org/10.2118/195888-ms","url":null,"abstract":"\u0000 Majority of the accidents while drilling have a number of premonitory symptoms notable during continuous drilling support. Experts can usually recognize such symptoms, however, we are not aware of any system that can do this job automatically. We have developed a Machine learning algorithm which allows detecting anomalies using the drilling support data (drilling telemetry). The algorithm automatically extracts patterns of premonitory symptoms and then recognizes them during drilling.\u0000 The machine learning model is based on Gradient Boosting decision trees. The model analyzes real time drilling parameters within a sliding 4-hour window. For each measurement, the model calculates the probability of an accident and warns about anomaly of particular type, if the probability exceeds the selected threshold.\u0000 Our training sample comes from 20+ oilfields and consists of sections related to 80+ accidents of the following types: stuck pipe, mud loss, gas-oil-water show, washout of pipe string, failure of drilling tool, packing formation, that occurred while drilling, trip-in, trip-out, reaming.\u0000 We have designed the prediction model to work during drilling new wells and to distinguish the normal drilling process from the faulty one. One can configure the anomaly threshold to balance amount of false alarms and the number of missed accidents.\u0000 To evaluate quality of the model we measure such data science metrics as ROC AUC score and confusion matrices. While testing model can identify 24 accident from 30 with high confidence, whereas for the others there is still a room for improvement. Our findings suggest that including more accidents of underrepresented types will improve quality. Other data science metrics also support aptitude of the model. Finally, having data from multiple heterogeneous oilfields, we expect that the model will generalize well to new ones.\u0000 This paper presents a good practice of development and implementation of a data-driven model for automatic supervision of continuous drilling. In particular, the model described in the paper will assist specialists with drilling accidents prediction, optimize their work with data and reduce the nonproductive time associated with the accidents by up to 20%.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130245604","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":"An In-Depth Study of Proppant Transport and Placement with Various Fracturing Fluids","authors":"D. Anschutz, Terry Lowrey, M. Stribling, Pat Wildt","doi":"10.2118/196073-ms","DOIUrl":"https://doi.org/10.2118/196073-ms","url":null,"abstract":"\u0000 Within the last decade, technical advancements in horizontal drilling have created an environment in the hydraulic fracturing industry resulting in a paradigm shift for the completion of unconventional wells. This shift away from conventional, vertical, bi-wing fractures with large diameter proppant, to the current unconventional design of multi-zone laterals, requires a new generation of proppants and carrying fluids. This proposes a challenge to the industry to successfully place proppant into the far field regions of potentially multiple fracture networks. To meet this challenge the industry has dedicated numerous resources to study proppant transport behavior and carrying agent behavior to better understand and apply materials that will economically optimize well completions.\u0000 This paper focuses on how proppant is transported with different fracturing fluids using a combination of pipe flow and patent-pending slot flow tests to study their behavior in various sections of a simulated fracture, including near-wellbore and far-field (low shear) fracture environments.\u0000 The objectives for the project are defined as: Identify proppant transport characteristics (40/70 and 100 mesh frac sand) through an open channel of high shear, low shear, leak off and low-to-zero shear environments with various fluids (slickwater, HVFR, linear gel and crosslinked gel).Determine how changes in geometry (incline, decline, dead-end, drop-off, and banking) impact proppant placement.Determine the carrying capabilities of various fluids with 40/70 and 100 mesh proppants.\u0000 Comprehensive testing was performed on three separate test designs: pipe flow, standard 4′x8′ slot flow and patent-pending 4′×8′ slot flow with obstructions inside the structure. Test procedures are designed to simulate a typical West Texas unconventional well with 100 bbl/min, 5 ½″ casing, 15,000′ of casing. Fluids are conditioned to well specifications prior to entering the test design. Fluid and proppant are trapped, and the equipment is disassembled for further analysis after each test. The collected data includes shear rates, fluid viscosities, mean particle diameter, proppant distribution, proppant concentration, pictures and videos.\u0000 Observations and conclusions include, but are not limited to, the changes/lack of changes of mean particle diameter of the proppant within the structure, comparative analysis of the carrying capabilities of slickwater, high viscosity friction reducers (HVFR), linear gel and crosslinked gel. Noteworthy differences between 40/70 and 100 mesh behavior are evaluated. An in-depth study on the carrying capabilities of high concentrations of HVFR (4 gpt and 6 gpt) is also included.\u0000 The goal of this project is to add further knowledge and insight into the design of unconventional completion techniques and to evaluate new and/or novel proppant and fracturing fluids. With the rapid shift to fine mesh proppants and a lack of comparative production data (ranging from 12-24 m","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"41 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116203166","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 Utica Case Study: The Impact of Permeability Estimates on History Matching, Fracture Length, and Well Spacing","authors":"G. Fowler, M. McClure, C. Cipolla","doi":"10.2118/195980-ms","DOIUrl":"https://doi.org/10.2118/195980-ms","url":null,"abstract":"\u0000 Maximizing economic performance in shale requires optimal selection of well and cluster spacing, among other parameters. Reservoir engineering calculations can be used to optimize spacing, but these calculations are impacted by uncertainties in input parameters. System permeability is particularly important and difficult to measure. Diagnostic Fracture Injection Tests (DFIT's) are often used to estimate permeability because they provide a direct, in-situ measurement. However, in recent work, it was shown that conventional DFIT interpretation techniques can overestimate permeability in gas shale by two orders of magnitude. In this study, the impact of the permeability estimate is demonstrated using a dataset from the Utica/Point Pleasant. Production data is history matched with models assuming high and low permeability. It is possible to history match both models because of non-uniqueness between fracture area and permeability. Sensitivity analysis simulations are performed to assess the impact of well and cluster spacing on net present value. Relative to the high permeability model, the low permeability model has a greater optimal well spacing and a tighter optimal cluster spacing. The comparison shows that improved accuracy in the permeability estimate significantly improves economic performance. The low permeability model has much earlier production interference than the high permeability model because the low permeability model requires greater effective fracture length to match production. This is consistent with the operator's experience that outer wells outproduce inner wells within weeks or months from the start of production.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"33 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114774176","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":"Pseudo Formation Volume Factor: A Consistent and Continuous Volumetric Assessment Across Multiphase Reservoirs, a Wet Gas to Black Oil Duvernay Formation Example","authors":"Aaron White, Nina Prefontaine, F. B. Thomas","doi":"10.2118/195924-ms","DOIUrl":"https://doi.org/10.2118/195924-ms","url":null,"abstract":"\u0000 This paper presents a hydrocarbon volumetric assessment approach for multiphase reservoirs. The methodology is based upon mass material balance in both gas condensate and wet gas systems and permits for oil/condensate volumetric determination utilizing a novel concept referred to as pseudo formation volume factor (Bo*). This method allows for a continuous oil/condensate volumetric assessment across all four hydrocarbon phases: black oil, volatile oil, gas condensate, and wet gas. A Duvernay field application example is presented.\u0000 In conventional oil/condensate volumetric methods, a discontinuity is observed at the boundary between undersaturated gas and oil systems when you move across the mapped phases. The discontinuity results from an inconsistent oil/condensate volumetric approach between oil and gas primary phases. Oil/condensate volumetrics is a function of an oil formation volume factor (Bo) in oil systems while, in comparison, a function of a condensate-gas ratio (CGR) in gas systems. This volumetric assessment inconsistency is exemplified in areas of multiple phases, where operators are mapping oil/condensate from wet gas to black oil over a localized area. Realistically, a distinct boundary between in-situ fluid phases does not exist; rather, this change in phase is gradual.\u0000 The traditional Bo is a volumetric comparison of the live-oil volume to the dead-oil volume of an equivalent unit mass of oil. Evolved gas from the live-oil volume creates the volumetric shrinkage observed within the dead-oil volume. The fundamental basis of the Bo is a mass material balance and can be expressed as a ratio of the dead-oil density to the live-oil density if the mass of evolved gas is accounted for. The Bo* approach applies the same mass material balance concept to the recovered standard condition condensate within the gas-condensate and wet gas system. This condensate shrinkage concept, however, is not based upon the evolved gas from the oil, since the primary phase is gas in the gas-condensate and wet gas systems. In contrast, the Bo* concept is a density comparison of the standard condition condensate recovered at the surface to its associated density in the gas phase at downhole pressure and temperature conditions.\u0000 The fundamental assumption in the Bo* mass balance solution is ideal gas behavior. The gross live-fluid gas density is corrected to the live-fluid gas density of the standard condition condensate only. This is based upon a liquid component mass balance ratio within the recombined fluid, applied to the gross live-fluid density. The Bo* however, can also be algebraically solved for, which is the recommended approach. Like the traditional Bo, the Bo* is a strong predictive function of the mapped initial gas-oil ratio (GOR). An apparent boundary transition between the Bo and Bo* correlations is observed in the expected 3,200 SCF/STB range of GOR. Both the Bo and the Bo* can also be predictively linked to the hydrocarbon maturity, press","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"40 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114783508","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":"Examining Hydraulic Fracture Characteristics Based on Induced Microseismicity: A Barnett Shale Case Study","authors":"S. Jia, R. Wong, D. Eaton","doi":"10.2118/195957-ms","DOIUrl":"https://doi.org/10.2118/195957-ms","url":null,"abstract":"\u0000 Microseismicity can be triggered by various dynamic processes related to a hydraulic fracturing treatment. These processes alter the in-situ stress field inside and around the stimulated reservoir volume, due to both creation of new fractures and fluid leakoff into the surrounding rock matrix. The analysis of spatiotemporal dynamics of fluid-induced seismicity can reveal important characteristics of the hydraulic fracturing process. With the knowledge of treatment data, it can be used in conjunction with the reservoir geomechanical theories in hydraulic fracture growth to investigate the fracture geometry and fluid-rock interactions. By applying these theories to a real microseismic dataset, two types of triggering front expansion patterns are evident. With the presence of a dominant hydraulic fracture, the radius of the triggering front expands linearly with time. Moreover, the microseismic event cloud forms a planar shape with low opening angles (failed by shear), indicating fracture slippages around the major hydraulic fracture. On the other hand, in the case of a complex fracture network with the absence of any major hyfraulic fracture, the triggering front grows non-linearly with time. This scenario can be treated as equivalent to a diffusion model and the microseismic events exhibit a higher fracture of tensile components (either opening or closing) and an equidimensional event cloud. In this study, two stages were analyzed and the derived fracture widths and fluid-loss coeffcients fall into a realistic range of general observations in the context of these two theories.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"62 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133026857","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":"High-Fidelity Transient Hydraulics Model for Well Construction","authors":"P. Varadarajan, Ghislain Roguin, Nick Abolins, M. Ringer","doi":"10.2118/196133-ms","DOIUrl":"https://doi.org/10.2118/196133-ms","url":null,"abstract":"\u0000 A mathematical model is developed to capture the dynamic features in the wellbore during drilling operations so that it could be used for real-time computations. The model comprises one-dimensional (1D) mud flow solvers, one for the drillpipe and the other for the wellbore annulus including the volume below the drill bit, integrated point models for the bell nipple, bottomhole assembly (BHA) nozzles, 1D shallow water model for the flowline, and point model for the bypass replicating the hydraulic circuit in the drilling rig. The model assumes compressibility of mud for the wellbore section along with its transient gel characteristics. The equations are solved using appropriate explicit numerical solvers and the results capturing the fast transients of the standpipe pressure, bottomhole equivalent circulating density (ECD), and the flow rates during dynamic drilling operations are presented to illustrate the performance of the model with field data.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"2 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122192718","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}