Day 2 Tue, June 12, 2018最新文献

{"title":"An Experimental Investigation of Gas Production Rates During Depressurization of Sedimentary Methane Hydrates","authors":"S. Almenningen, P. Fotland, M. Fernø, G. Ersland","doi":"10.2118/190811-MS","DOIUrl":"https://doi.org/10.2118/190811-MS","url":null,"abstract":"\u0000 Sedimentary methane hydrates contain a vast amount of untapped natural gas that can be produced through pressure depletion. Several field pilots have proven the concept with days to weeks of operation, but the longer-term response remains uncertain. This paper investigates parameters affecting the rate of gas recovery from methane hydrate-bearing sediments. The recovery of methane gas from hydrate dissociation through pressure depletion at constant pressure was studied at different initial hydrate saturations in cylindrical sandstone cores. Core-scale dissociation patterns were mapped with magnetic resonance imaging (MRI) and pore-scale dissociation events were visualized in a high-pressure micromodel. Key findings from the gas production rate analysis are: 1) The maximum rate of recovery is only to a small extent affected by the magnitude of the pressure reduction below the dissociation pressure. 2) The hydrate saturation directly impacts the rate of recovery, where intermediate hydrate saturations (0.30 – 0.50) give the highest initial recovery rate. These results are of interest to anyone who evaluates the production performance of sedimentary hydrate accumulations and demonstrate how important accurate saturation estimates are to predict both the initial rate of gas recovery and the ultimate recovery efficiency.","PeriodicalId":339784,"journal":{"name":"Day 2 Tue, June 12, 2018","volume":"19 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128654686","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":"Controlling Parameters for Shale Gas Production Into a Well-Induced Fracture: A Fracture-Matrix Modelling Approach","authors":"D. Berawala, P. Andersen, J. Ursin","doi":"10.2118/190843-MS","DOIUrl":"https://doi.org/10.2118/190843-MS","url":null,"abstract":"\u0000 The purpose of this paper is to investigate the main controlling factors of shale gas production in the context where well-induced fractures, extending from the well perforations, improve reservoir conductivity and performance. A mathematical 1D+1D model is presented which involves a high-permeable fracture extending from a well perforation, through symmetrically surrounding shale matrix with low permeability. Gas in the matrix occurs in the form of adsorbed material attached to kerogen (modeled by a Langmuir isotherm) and as free gas in the nano-pores. The pressure gradient towards the fracture and well perforation causes the free gas to flow. With pressure depletion, gas desorbs out of the kerogen into the pore space and then flows to the fracture. When the pressure has stabilized, desorption and production stop.\u0000 The production of shale gas and mass distributions indicate the efficiency of species transfer between fracture and matrix. It is shown that the behavior can be scaled and described according to the magnitude of two characteristic dimensionless numbers: the ratio of diffusion time scales in shale and fracture α, and the pore volume ratio between the shale and fracture domains β. Properties of fracture and matrix are varied systematically to understand the role of the fracture matrix interaction during production. Further, the role of fracture geometry (varying width) is investigated. Input parameters from experimental and field data in the literature are applied.\u0000 The product αβ expresses how much time it takes to diffuse the gas in place through the fracture to the well compared to the time it takes to diffuse that gas from the matrix to the fracture. For αβ ≪ 1 the residence time in the fracture is of negligible importance and fracture properties such as shape, width and permeability can be ignored. However, if αβ ≈ 1 the residence time in the fracture becomes important and variations in all those properties have significant effects on the solution.\u0000 The model allows intuitive interpretation of the complex shale gas production system. Furthermore, the current model creates a base which can easily incorporate non-linear flow mechanisms and geo-mechanical effects that are not readily found in standard commercial software, and further be extended to field scale application.","PeriodicalId":339784,"journal":{"name":"Day 2 Tue, June 12, 2018","volume":"89 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114707177","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":"Temperature and Geometry Effects on the Fracture Surfaces Dissolution Patterns in Acid Fracturing","authors":"M. Aljawad, D. Zhu, A. Hill","doi":"10.2118/190819-MS","DOIUrl":"https://doi.org/10.2118/190819-MS","url":null,"abstract":"\u0000 Modeling acid fracturing operations in carbonate formations is performed to evaluate the possible improvement in well productivity. Models are developed to mainly estimate the acid penetration length and the fracture surfaces etched-width profile. Variable combinations of these two parameters produce a significant difference in the fracture productivity. To better estimate these parameters, a reliable fracture propagation model should be coupled with the acid reaction/transport model. Simulating weak acids or dolomite formations reactivity requires the inclusion of a heat transfer model. The model provided in this study couples these factors as fractures propagate to finally obtain the fracture conductivity distribution along its length.\u0000 The fracture propagation model continuously updates the domain for the acid model. A transient acid convection and diffusion equation is solved and the fracture etched-width profile is calculated. An iterative procedure is implemented in a temperature dependent kinetic model which is stopped when both the temperature and acid solutions converge. When injection stops, acid etching and the fluids temperature are updated as the fracture closes. As the final etching profile is drawn, conductivity is calculated using a correlation that considers formation heterogeneity.\u0000 Coupling fracture propagation shows a significant difference on the acid model solutions compared to that assuming constant fracture geometry. For extremely high Peclet number that represents a very retarded acid system, a constant drop in the etched-width value until reaching zero at the fracture tip is theoretically obtainable. For lower Peclet numbers, the etching profile is shown to be sharply declining towards the fracture end. This is in contrast with the non-coupled approach from which a uniform etching profile is obtained at moderate to high Peclet numbers. It is also observed that the simulation of acid injection in non-coupled, constant fracture geometry always overestimates the acid penetration distance. The etched-width distribution and the acid penetration length are temperature sensitive, especially in dolomite formations. Temperature coupling shows that the maximum etching in dolomite formations occurs away from the fracture entrance as acid reactivity increases. It also shows that the cooling effects of the first stage pad fluid on improving the acid penetration distance is limited.\u0000 Simulating acid fracturing operations assuming constant final fracture geometry and an average single temperature is time efficient but results in inaccurate solution. This paper quantifies the effects of integrating fracture propagating and heat transfer models on the acid etching pattern from which, a better estimate of the fracture productivity is expected.","PeriodicalId":339784,"journal":{"name":"Day 2 Tue, June 12, 2018","volume":"94 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115217417","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":"Economic Appraisal of Shale Gas Reservoirs","authors":"Michael Kenomore, Mohamed Hassan, H. Dhakal, A. Shah","doi":"10.2118/190824-MS","DOIUrl":"https://doi.org/10.2118/190824-MS","url":null,"abstract":"\u0000 Natural gas produced from shale formations has increased rapidly in the past decade altering the oil and gas industry markets remarkably. The use of horizontal drilling and hydraulic fracturing has allowed previously unrecoverable shale gas to be extracted. Shale gas development is more expensive compared to conventional developments and as such, understanding the economic feasibility is of greater importance in successfully developing the resource. Using the estimated ultimate recoverable expressed in terms of P10, P50, and P90 from 2751 horizontal well production data (all starting production from 2008) from the Barnett shale, a discounted cash flow economic model (MS- Excel based) was used to quantify the effect of finding and development costs (F&DC) and gas prices on the economic viability of horizontal wells within four out of five basins (Strawn Basin, Ouachita Folded Belt, Forth-worth Syncline and Bendarch Basin) in the Barnett shale. The investment hurdle in the economic model was a rate of return of 20% and a payback period of 5 years or less. This paper helps determine the percentage of wells within basins in the Barnett shale that would be economically viable at various F&DC and gas prices subject to satisfying the prescribed investment hurdle.","PeriodicalId":339784,"journal":{"name":"Day 2 Tue, June 12, 2018","volume":"8 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":"123733905","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":"Cluster Spacing Optimization for Horizontal-Well Fracturing in Shale Gas Reservoirs: Modeling and Field Application","authors":"Lin Ran, Lan Ren, Jinzhou Zhao","doi":"10.2118/190775-MS","DOIUrl":"https://doi.org/10.2118/190775-MS","url":null,"abstract":"\u0000 Multi-stage fracturing in horizontal well is the core technology for commercial exploitation of shale gas reservoir, in which the cluster spacing plays an important role to impact the fracturing performance—undersized cluster spacing might make the stimulated reservoir volume (SRV), activated by different hydraulic fractures, excessively overlap with each other, while oversized cluster spacing might leave unstimulated regions between neighboring hydraulic fractures; in either case the fracturing would be inefficient. However, most current cluster spacing design methods are imperfect without a reliable SRV estimation model. This paper established a numerical model to estimate the SRV by simulating four key processes during multi-stage fracturing—hydraulic fractures propagation, formation stress changing, reservoir pressure lifting, and natural fractures failure. Then, based on this SRV model, an optimization method for cluster spacing was proposed and applied in Fuling shale gas field in Southwest China. We analyzed the influence of geological conditions and fracturing parameters on the optimal cluster spacing, and drew the reference charts for cluster spacing design in Fuling gas field. This research developed an effective cluster spacing optimization method, reduced the uncertainty in cluster spacing design, and provided some new insights on the optimal design of multi-stage fracturing in horizontal shale gas well.","PeriodicalId":339784,"journal":{"name":"Day 2 Tue, June 12, 2018","volume":"16 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":"123874865","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":"Investigating the Uniformity of In-Situ Asphaltene Deposits in Sandstone Rocks","authors":"J. J. Abraham, M. Mehana, M. Fahes","doi":"10.2118/190785-MS","DOIUrl":"https://doi.org/10.2118/190785-MS","url":null,"abstract":"\u0000 The stability of asphaltene molecules is tied to the changes induced by temperature, pressure or composition. Therefore, the precipitation of these molecules is expected during various operations and at different stages of well life. While the deposition and remediation of asphaltenes in wellbores and pipelines are well-addressed, the deposition phenomena in reservoir rock and its impact on rock characteristics and fluid dynamics is still not well-developed. We have developed an experimental workflow to create a uniform deposit of asphaltene inside the core sample. The results show that injecting oil or a heptane/oil mixture results in a non-uniform deposition of Asphaltene, which was quantified using the TOC and density measurements. Uniform exposure to crude oil and deposition was obtained through vacuum saturation of the cores. However, permeability impairment is evident in both cases; whether the deposition is developed using vacuum-saturation or injection. Interestingly, the absolute permeability damage could be mitigated by reversing the injection flow direction which suggest that pore throat plugging is the main damage mechanism, while deposition onto the rock surface is the secondary damage mechanism for absolute permeability.","PeriodicalId":339784,"journal":{"name":"Day 2 Tue, June 12, 2018","volume":"223 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":"121566828","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":"Comprehensive Evaluation of the Dynamic Sealing Capacity of Clayey Caprocks in a Large Underground Gas Storage","authors":"Junchang Sun, Dewen Zheng, Jie-ming Wang, Jiandong Liu, Lei Shi, Hongcheng Xu, Chun Li, Rong Zhong, Kun Zhao","doi":"10.2118/190838-MS","DOIUrl":"https://doi.org/10.2118/190838-MS","url":null,"abstract":"\u0000 An effective caprock is crucial for safe operation of an underground gas storage (UGS). However, the caprock's initial seal capacity can be changed due to many factors such as micro-deformation of the caprock's pore structure and fatigue damage under cyclic loading caused by UGS annual storage which may all lead to gas leakage. Consequently, the caprock's dynamic sealing capacity including capillary sealing effciency and mechanical integrity under alternating stress must be comprehensively evaluated.\u0000 A total of 21 clayey caprock plugs drilled from the HB large UGS in western China were prepared to perform laboratory tests. Nitrogen breakthrough (BT) pressure was both measured before and after 50 cycles’ loading-unloading on the fully kerosene-saturated plugs. Specially, the cyclic amplitude was designed based on the UGS planned operational pressure bounds and local dynamic in-situ stresses. Triaxial compression fatigue and subsequent failure tests were conducted to investigate the strain dynamic evolution and its effect on the mechanical behaviors of clayey caprocks. Seventeen sandstone reservoir plugs were also selected to carry out mechanical tests as a comparison.\u0000 Experimental results indicate that the BT pressure of the HB caprock ranges from 3.88 to 8.79MPa which is much higher than the critical value (~2MPa) for the HB trap seal. Average reduction of the BT pressure is 14.8% after 50 cycles’ loading demonstrating that the alternating in-situ stresses may have a relatively minor effect on the capillary sealing capacity of the HB UGS caprock. This finding is also supported by the mechanical tests that the maximum cyclic loading is always below the yield point of the HB caprock. Compaction is the main deformation behavior and shear expansion has not occurred within the disturbed in-situ stresses variation during the HB UGS operations according to the dynamic evolution of the axial and lateral strain. However, the stress-strain curves exhibit significant hysteresis especially within the first several cycles and the plastic strain continuously develops. The average cumulative plastic strain is around 0.14% after 50 cycles’ loading which is much lower than the 1% benchmark of caprock failure suggested by Schlumberger. However, the cyclic loading has a more severe weakening effect on the caprock mechanical strength parameters and it cannot be neglected in geomechanical simulation compared with the sandstone reservoir plugs.\u0000 This study gives an in-depth understanding of the dynamic capillary sealing capacity and mechanical properties of the clayer caprocks under cyclic loading-unloading. Based on the above experimental finds, the more accurate evaluation will be obtained through 3D geomechanical model simulation.","PeriodicalId":339784,"journal":{"name":"Day 2 Tue, June 12, 2018","volume":"87 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":"122446341","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":"MICP-Based Elastic Rock Typing Characterisation of Carbonate Reservoir","authors":"F. Colombo, A. A. D. Monte, P. Balossino, E. Paparozzi, A. Valdisturlo, C. Tarchiani","doi":"10.2118/190885-MS","DOIUrl":"https://doi.org/10.2118/190885-MS","url":null,"abstract":"\u0000 A workflow applied to achieve a multi-scale characterisation of a carbonate reservoir is presented. Carbonate rocks are strongly heterogeneous due either to complexity of the primary fabric or to diagenetic over-printing. The combination of these features leads to complicated pore systems, thus a proper definition of pore types using either pore size or pore throat size distributions, is important to indirectly capture diagenetic modifications and to get a link to dynamic properties.\u0000 A new approach was developed in order to define a Rock Type classification (RRT) each time the approaches based on Winland's and Hydraulic Flow Unit methods do not give a reliable core facies characterisation when moving to the log scale. Moreover, the proposed workflow accounts for stratigraphy and seismic since RRT are linked to the elastic properties.\u0000 In the new MICP-based Rock Typing workflow, RRT are identified by describing dominant pore types using mercury injection (MICP) curves parameterisation and routine core data (RCA). Clustering and subsequent extrapolation of MICP derived RRT to RCA samples, are the first two stages to achieve a predictable classification into the log domain. Log RRT are then defined at the log scale using curves of elastic properties, like Poisson's Ratio (PR), Frame Stiffness (fk) and Flexibility (γk) Factors. These elastic parameters (calculated with the Extended Biot Theory), can capture the effects of pore structure on the petrophysical properties and link RRT prediction at well position to seismic attributes. Since the RRT are characterised in the elastic space, the facies model – properly upscaled – represents the basis to classify elastic attributes from seismic inversion in a Bayesian framework. The seismic classification can then be used as a driver for RRT distribution in the inter-well space into the 3D model. A further benefit is the direct relationship to the original RRT porosity/permeability distributions, when modelling petrophysical properties.\u0000 This new workflow was a successful solution to define homogeneous reservoir intervals in a carbonate environment characterised by the lack of a significant relationship between depositional facies and petrophysical properties.","PeriodicalId":339784,"journal":{"name":"Day 2 Tue, June 12, 2018","volume":"9 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":"131355855","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":"Systematic Use of Tidal Effects for Reservoir Appraisal and Well Integrity Monitoring in a Near-Coast Onshore Environment","authors":"J. Hailstone","doi":"10.2118/191354-MS","DOIUrl":"https://doi.org/10.2118/191354-MS","url":null,"abstract":"\u0000 Tidal effects in wells have been observed for millennia and have been analysed since the 1970s, following the introduction of high-resolution pressure gauges. Tidal effects are usually more obvious offshore and many papers focus on offshore wells with large tidal signals. This paper demonstrates that pressure changes caused by ocean tides are detectable in near-coast land wells and that, with careful analysis and processing, provide valuable additional information for reservoir characterisation.\u0000 This paper uses a set of observations from multiple near-coast land wells with extended pressure histories acquired as part of campaign of production and interference testing for reservoir characterisation purposes. These pressure records have variable tidal signal and data quality. A variety of methods have been published to smooth tidally influenced pressure data and extract or remove the tidal component. These different tidal filtering techniques are tested on real data, and a preferred data processing procedure is selected appropriate for the large quantity and variable quality of data in the study area. The methodology allows data from multiple wells to be quickly processed and consistently screened.\u0000 This paper gives examples of tidal behaviour in selected wells and compares the results across multiple wells in the study area to show how identification of subtle tidal effects is useful for:\u0000 Field appraisal of a saturated oil-rim with gas cap by examining differences in tidal amplitude in wells in different parts of the field. Estimation of critical gas saturation by comparing tidal amplitudes before and after an extended well test. Monitoring well integrity in a producing field by tidal analysis of annular pressures.\u0000 The paper also recommends a reservoir surveillance programme to obtain useful tidal data in onshore wells.\u0000 This paper will be useful to engineers attempting to find and interpret subtle tidal data, instead of simply removing it. It recommends a systematic approach for using tidal data in wells where tidal signals are small and/or gauge resolution is poor, based on experience with real data with variable data quality. It also provides a case study to show the value and practical application of a surveillance programme to identify tidal data in near-coast land wells.","PeriodicalId":339784,"journal":{"name":"Day 2 Tue, June 12, 2018","volume":"4 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":"132688353","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 the Impact of Lateral Landing, Wellbore Trajectory and Hydraulic Fractures to Determine Unconventional Reservoir Productivity","authors":"P. Pankaj, P. Shukla, Ge Yuan, Xu Zhang","doi":"10.2118/190860-MS","DOIUrl":"https://doi.org/10.2118/190860-MS","url":null,"abstract":"\u0000 Inconsistent production performance from wells completed in similar pay zones has been observed when shale formations are exploited through horizontal wells. Ineffective completion practices, fracture design, and reservoir heterogeneity have generally been blamed for the variability in the performance. Limited importance has been attached to drilling quality and well trajectory placement in the current approaches by the operators. The objective of this study is to demonstrate an engineered lateral landing approach for improved long-term productivity in the unconventional reservoirs.\u0000 Coupling the reservoir model to the wellbore and accounting for the transient flow behavior are important for improving deliverability in horizontal wells. The study in this paper encompasses a field case study of a geocellular and geomechanical earth model in the Permian basin, which involves hydraulic fracturing modeling, reservoir simulation, fluid flowback, and transient wellbore flow modeling. Pressure losses accounted for in the reservoir, in the near-wellbore region, and in the wellbore profile are modeled and calibrated with bottomhole and surface gauge measurements. Complex hydraulic fracture geometry and numerical reservoir simulation are used to characterize the pressure losses in the reservoir. Transient wellbore fluid flow considerations are used to evaluate the pressure losses in the wellbore.\u0000 Based on the fracturing fluid type, the conductivity profile of the hydraulic fractures, connection to the wellbore, and coverage of the pay zone are important criteria in considering the landing location for wells in unconventional reservoirs. However, having the most effective hydraulic fracture design is not enough to decide the well trajectory. Mitigating liquid loading, fluid flowback, proppant settling, and cross-flow of reservoir fluid helps to diagnose the true production potential. Therefore, transient flow models were coupled to the reservoir and fracture models to design a more-effective well trajectory.\u0000 The study demonstrates the need to couple the wellbore model to the reservoir simulation and hydraulic fracturing model in shale formations to optimize well landing, trajectory profile, and long-term productivity.\u0000 The methodology provides the first integrated data workflow for well drilling and trajectory planning in unconventional reservoirs that is generated from the perspective of reservoir potential and deliverability. Although variances exist in completion effectiveness due to reservoir heterogeneity, applying the robust modeling workflow as discussed in this study would help deliver consistent results that can be used in field management and EUR estimates across various shale basins.","PeriodicalId":339784,"journal":{"name":"Day 2 Tue, June 12, 2018","volume":"16 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":"114416713","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}