bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Comparative Study of Pore Size Distribution in Gas Shales
Authors: Zolfaghari Ashkan , Dehghanpour Hassan 
Published: November 2015

AbstractPetrophysical characterization of unconventional rocks is an important challenge faced by the industry for reservoir evaluation. In particular, characterizing the pore size distribution (PSD) of tight rocks is challenging due to their small pore size and presence of clay minerals. In this paper, we compare the PSD of shale samples using both of the adsorption and desorption isotherms of water (H2O), nitrogen (N2), and carbon dioxide (CO2).The shale samples are collected from three wells completed in the Horn River Basin. A setup is designed to obtain the water sorption (adsorption and desorption) isotherms for shale samples. The model developed by Zolfaghari and Dehghanpour (2015) is used to calculate the PSD of shale samples from water sorption isotherms. BET (Brunauer-Emmett-Teller) analysis is used to obtain the N2 and CO2 sorption isotherms, and their corresponding PSDs. Also, SEM (Scanning Electron Microscope) images of the shale samples are utilized to visualize the pores of the shale samples.The comparative analysis of PSDs indicates that different methods give different PSDs. All of the calculated PSDs indicate that majority of the pores are smaller than ~10 nm. The portion of pores less than than ~1.5 nm is larger when the PSDs are calculated using the water sorption isotherms compared to that of the BET analysis. The PSDs calculated from the water sorption isotherms also show pores of larger than ~40 nm, which is in agreement with the SEM images of the shale samples. However, BET does not detect these large pores.
Effect of Well Interference on Shale Gas Well SRV Interpretation
Authors: Pang Wei , Ehlig-Economides Christine A , Du Juan , He Ying , Zhang Tongyi 
Published: November 2015

Abstract
The stimulated reservoir volume (SRV) estimated from daily production rate and pressure is a vital parameter for appraising shale gas wells’ fracturing effect and production potential. However, when well interference occurs, the SRV estimation from rate-normalized pressure (RNP) analysis is compromised. This paper illustrates diagnosis of well interference and how it affects SRV calculation.
China is the third country to exploit the shale gas technology breakthrough after the United States and Canada. The Jiaoshiba shale gas play is the most successful shale gas reservoir in China with some wells’ cumulative production over 0.1 billion cubic meters in the first year. Production rate data has shown jumps in water production during hydraulic fracturing of neighboring wells. By combination of hydraulic fracturing process and production data, we detect the existence of well interference from the adjacent well, when well interference happens and the influence it imposed on the target well. We analyzed two pairs of target and neighboring shale gas well pairs using the RNP and its derivative. The log-log diagnostic plots for nearly all of the wells see unit slope, indicating boundary dominated flow within 1 year. Some wells see two unit slopes possibly indicating a change in the SRV after hydraulic fracturing in a neighboring well.
Well interference may be caused by interaction between primary hydraulic fractures and/or secondary natural fractures activated during hydraulic fracturing. Interwell interference has had a significant influence on the SRV interpretation.
Well interference has drawn people's attention in recent years, but its impact on SRV interpretation is rarely reported. This research may help to characterize shale gas's SRV and related parameters and to optimize well spacing.
Estimation of the Propped Volume Through the Geomechanical Modeling of Multiple Hydraulic Fractures Interacting with Natural Fractures
Authors: Raymond S.. , Aimene E. Y. , Ouenes A.. 
Published: November 2015

Abstract
The application of a new Material Point Method (MPM) approach to model the proppant distribution in a reservoir where hydraulic fractures interact with natural fractures is presented and validated with an Eagle Ford well. The new MPM approach uses particles to represent the slurry and its effects on the hydraulic and natural fractures. The particles are injected in the hydraulic fractures and their action causes the hydraulic fractures to propagate and interact with the natural fractures thus providing new pathways for the proppant to move away from the wellbore when optimal natural fracture orientations are encountered. Elementary tests showed that long fractures oriented in 30 and 60 degree from the hydraulic fracture directions facilitate the proppant placement. However, the stress anisotropy seems to have little effects for fractures oriented in 30 and 60 degree but allows a better proppant placement for fracture oriented 90 degrees from the hydraulic fracture. The application of the new technology to an entire Eagle Ford well shows that the simulated proppant indicates a large propped volume towards the heel and a poor proppant placement at the toe stages as indicated by other methods. These field validated results, show that the macroscopic modeling of proppant distribution using the coupled solid/fluid MPM technology could be used in improving our understanding of the complex hydraulic fracturing process and the resulting proppant distribution that provide the needed initial stimulated permeability.
Investigation of Fracture Tip Behaviour in Visco-Elastic/ Visco-Plastic Shale Rocks and Its Effect on Fracture Propagation
Authors: Song Huifang , Gholami Amin , Bazunu Gamaliel , Rahman Sheik S. 
Published: November 2015

AbstractMost shale plays have to be hydraulically fractured to acquire commercial production. Shales are typically characterised by varying quantities of clay, carbonate and organic material, therefore each shale type has different deformational properties, which lead to different outcomes with respect to hydraulic fracture efficiency. Unconsolidated, high clay content or organic rich shales exhibit visco-elastic or visco-plastic behaviour, acoording to many researchers[1–3]. Although the effect of this time-dependent behaviour on fracture propagation is considerable it has not yet received much attention. The aim of this paper is to address the time-dependent response of shale under hydraulic stimulation, more specifically, to monitor fracture parameters change and deformation at crack tip area depending on the lag time between stress and strain.In this paper, an innovative method to analyse time-dependent deformation of material at fracture tip and its effect on propagation of hydraulically induced fractures by incorporating visco-elastic behaviour is presented. To characterise fracture state, J integral is revised and implemented in the framework of finite element model. The fracture is treated explicitly with refined mesh around the crack tip in order to obtain detailed information in static state. During loading condition, visco-elasticity and visco-plasticity is not differentiated for practical purposes.The results show that under a centain hydraulic pressure a crack creeps rapidly and possibly propagates. It is shown that stress intensity factor and revised J integral has a rapid changing gradient at the beginning and becomes stable over time. The crack tends to be wider and shorter in creeping shale. Propagation process is hindered by viscous energy dissipation and successive cohesive force. In simulation the experimental data from US shale plays are used to study fracture propagation behaviour under viscoelastic behaviour. Results of this study allow industry gain a better understanding of deformational behaviour of shale when fracturing. The know-how derived from this study will assist planning effective stimulation program in the development of shale gas reservoirs.
Sweet Spot Identification and Prediction of Frac Stage Performance Using Geology, Geophysics, and Geomechanics - Application to the Longmaxi Formation, China
Authors: Yang X.. , Wang X.. , Aoues A.. , Ouenes A.. 
Published: November 2015

Abstract
Microseismic data is evaluated with surface seismic and analyzed in addition to treatment data to understand the variance in performance of frac stages at three wells drilled in the Longmaxi formation, China. In well H1, the microseismic is dominated by fault reactivations, and is of little use in analyzing the performance of individual frac stages. In the wells H2 and H3, the use of maximum curvature derived from surface seismic showed strong qualitative correlation with microseismicity. To quantify the effects of shale properties on the frac stage performances, seismic attributes were used to derive geologic models of porosity, total gas, fracture density and Poisson's Ratio which were combined to form the Shale Capacity. The comparison of the Shale Capacity with the production log of H1 demonstarates how the model explains the performance of the frac stages away from the faults. The same observations could be made using the extent of good Shale Capacity away from the faults to explain the important difference in production between H2 and H3. Given the importance of the faults and their geomechanical impact on the performance of the frac stages, a geomechanical workflow able to simulate the interaction between the hydraulic and natural fractures is applied to the H1 well. The resulting strain and J Integral are able to explain the performance of the frac stages in H1 thus confirming the importance of the natural fractures and the need to account for their geomechanical effects.
Optimal Core Retrieval Time For Minimizing Core Decompression Damage
Authors: Hoeink Tobias , van der Zee Wouter , Arndt Stephan 
Published: November 2015

Abstract
The ability to obtain detailed physical measurements from subsurface samples in a controlled laboratory setting crucially depends on the quality of the retrieved core. The key to maximize core quality is to limit avoidable damage during drilling, retrieval, handling, transport and analysis. This paper focusses on the retrieval process, where core integrity can be compromised when the core is retrieved too quickly without allowing sufficient time for pore pressure equalization. Core integrity, in particular avoiding decompression damage, is a distinctive concern for low-permeability shales. A common notion is to retrieve slowly to allow for pore pressure equilibration. Operational considerations, on the other hand, demand the shortest possible retrieval time. This paper discusses a resolution to these two conflicting requirements by identifying the optimal core retrieval time using finite-element modeling and optimization techniques.
In this paper, a core retrieval effort is modeled using an axisymmetric, finite-element representation of a core with pore fluid that is subjected to successively decreasing external pore-pressure boundary conditions and pressure loads. The modeling results are analyzed for the maximum pore-pressure difference and compared with rock strength criteria to predict potential core damage.
The optimal retrieval time for given geometric and material parameters is determined with an optimization algorithm. The combined use of finite element modeling and optimization techniques in a reliability study enables the determination of core damage probability. This technique provides an analytical-based guideline for the shortest core-retrieval times without compromising core quality due to decompression.
100% in the Sweet Section: An Effective Geosteering Approach for Silurian Longmaxi Shale Play in Sichuan Basin
Authors: Liang Xing , Wang Lizhi , Zhang Jiehui , Xian ChengGang , Wang Gaocheng , Zhao Chunduan 
Published: November 2015

Abstract
A new geosteering approach significantly improves effectiveness and efficiency of geosteering in shale gas fields such as the Silurian Longmaxi gas shale in the south Sichuan basin, China. This formation presents more challenges than in classical sand/shale formations even when logging while drilling (LWD) imaging is available because of the cyclic gamma ray (GR) response of the targeted shale formation, subseismic microfaults with unknown displacements, and sudden structure changes from subseismic microstructures.
The new approach introduces more geosteering elements including correlation in the true stratigraphic thickness (TST) domain with considerations of the cyclic nature of shale gas zones; conducting multi-scenario modeling to verify the most likely scenario fitting the overall structural trend and the cyclic features; using an 3D geological model as the overall guidance of structural variations; and using a key bed detection strategy when the above methods can't precisely determine structural position.
The sweet section of Longmaxi shale has five sub-zones with respectively regressive or transgressive sequences, and the bottom zone with extremely high GR readings. The cyclic nature often resulted in inconclusive structure correlation based on changes of GR readings only. Field experiences showed numbers of subseismic microfaults with unknown fault displacement, and sudden changes of structural dips due to sub-seismic microstructures can be encountered, which can make the standard geosteering method insufficient to judge the actual position of the horizontal lateral. The new approach especially the multi-scenario modeling method in TST domain and the downward detection geosteering strategy to track the bottom high GR marker shale zone can clarify in-situ geology and minimize potential out-of-zone risk. The new approach has ensured all drilled horizontal wells was implemented 100% in the sweet section during the pilot and factory drilling phases. This paper demonstrates several examples to highlight its capability to handle complex situations for effective geosteering in contrast to the standard approach. The field practices also show this new approach can help to reduce unnecessary changes of drilling directions to ensure a smoother wellbore for subsequent operations. Our experience suggests iteratively updating the 3D geological model with improving accuracy must be treated as part of the overall geosteering strategy. Also a real-time decision making scheme throughout all involved segmens must be ensured for seamless operation.
Architecture of the Fracture Network of Shale Reservoirs by Tracking Exchangeable Cations
Authors: Roshan H.. , Sarmadivaleh M.. , Iglauer Stefan , Curtin U.. 
Published: November 2015

Abstract
The structure of the fracture network formed by hydraulic fracturing operation is one of the key parameter in production from unconventional shale reservoirs. The standard approach to obtain such information is usually through well-testing coupled with micro-seismic monitoring. Unfortunately, the micro-seismic mapping is not always carried out and the conventional well-test techniques often fall short in describing the flow in shale reservoir in particular the contact area of the fractures open to flow.
The other alternative technique to get insight into structure of the fracture network is to use chemical tracer tests. In this study, we propose a new simple and cost efficient technique to estimate the fracture contact area by tracking the major exchange cations in shale reservoirs.
The idea behind the proposed technique is to replace the major cations on fracture surfaces in shale by increasing the concentration of one of the major cation in fracturing fluid. The current technique is satisfied the industry standard practice as the high concentrated K+ is part of hydraulic fracturing fluid composition and therefore cation exchange with other major cations (Na+, Ca++ and Mg++) is expected to occur.
In order to test the feasibility of the proposed techniques, a set of laboratory tests were conducted where a shale sample was milled and sieved to three different sizes to have different contact area. They are then placed in a high pressure cylinder (built for this study) and were washed by concentrated NaCl solution under high pressure and controlled temperature. The effluent was collected successively and analysed for major cations using ICP-MS. Correlation relating the cation exchange mass content to contact surface is proposed and calibrated using the data obtained from laboratory tests.
Taking the Heat out of the Burning-ice Debate: Potential and Future of Gas Hydrates
Authors: Decourt B.. , Alias S.. , Debarre R.. , Askew P.. 
Published: November 2015

AbstractFinding gas hydrates to be a controversial, polarizing subject, the SBC Energy Institute (SBC-EI) developed a fact-based report, presenting: the key concepts; the status of exploration and production technologies; the status of research, development and demonstration (R,D&D); and the environmental and safety challenges associated with the potential exploitation of this resource. In addition to leveraging the long involvement of Schlumberger in gas hydrates R,D&D, the SBC-EI performed a literature review and engaged experts in the gas-hydrate field. The SBC-EI also analyzed patents from 50 offices worldwide, using the Thomson Derwent World Patents Index, and conducted a survey of gas-hydrate stakeholders to present the state of R,D&D and a faithful picture of current thinking among academics and industry players involved in the field. Among various types of deposits, gas hydrates hosted in sand-dominated sediments both within permafrost and offshore stand out as the only resources that may be recovered in the near term. Contrary to common belief, these deposits can largely be identified using existing exploration technologies, with small adjustments. Stakeholders widely agree that depressurization is the best technology for producing gas hydrates from sand reservoirs, whereas interest in CO2-CH4-exchange production techniques have lost momentum. Nevertheless, gas-hydrate exploration and production raise significant technical challenges that, unresolved, could undermine the resource's commercial viability. R,D&D remains a vital part of assessing the potential and economic viability of gas hydrates, and of addressing environmental and safety concerns. It is unlikely that gas hydrates will become competitive in gas-rich areas. But there is a much stronger possibility of commercial development in energy-deficient regions such as Asia, where gas-hydrate projects could alleviate energy-security concerns and strenghten energy independence. This would have revolutionary consequences for the energy sector. However, before this is possible, long-duration production tests are required. Japan is leading the way in this area and is aiming to achieve commercial operation by the end of the decade. This paper provides a fact-based review of existing knowledge on gas hydrates as a potential energy source. It is supported by two innovative analyses: (i) a comprehensive survey of gas-hydrate experts; and (ii) an in-depth examination of worldwide patents of gas-hydrate technologies.
Effect of Suspension Fluid Chemistry on Fracture System Stimulation Using Micro-Sized Proppant Placement
Authors: Keshavarz A.. , Badalyan A.. , Carageorgos T.. , Johnson R. L. , Bedrikovetsky P. G. 
Published: November 2015

AbstractThe physical model and experimental data support the beneficial technology of graded proppant injection into naturally fractured reservoirs to stimulate natural fracture permeability. Injection of particles with increasing size, at poroelastic and hydraulic fracturing conditions, yield deeper penetration and gradual filling of natural fractures with a resulting increase in permeability. This work expands on the concepts and outlines steps to maximize the benefit of graded proppant injection to enhance coal seam gas stimulation by focusing on the effect of the chemistry of injected fluid on the overall performance and the use in conjunction with hydraulic fracturing.Low productivity indices can be observed in many moderate- to low-permeability coal bed methane (CSG) reservoirs due to low aperture and poor connectivity of natural cleats. Graded proppant injection in CSG environments can: stimulate a stress sensitive cleat system below the fracturing pressure as well as enhance a fracturing treatment by invading cleats, lowering fluid leakoff, and maintaining aperture during production. Further, periodic or remedial treatments could to counter effective stress on the cleats improving production by maintaining cleat aperture.Laboratory tests on coal core flooding by water under increasing pore pressure with proppant injection at the maximum pressure have been carried out under different salinities of the injected water. Proppant-proppant and proppant-coal Derjaguin-Landau-Verwey-Overbeek (DLVO) total interaction energies were calculated to optimise the condition for successful proppant placement. Results on the DLVO total energy of interaction showed that conditions favourable for successful proppant placement in coal cleats are suspension ionic strengths between 0.05 M and 0.1 M NaCl. At these conditions no proppant agglomeration and proppant-coal attachment are observed, allowing deeper penetration of proppant into the natural coal cleat system. Lower suspension ionic strengths can lead to natural coal fines migration, cleat plugging and coal permeability reduction.Based on the experimental results and previously developed model a case study has been conducted to evaluate the productivity enhancement using this technique. The results show about four-fold increase in well productivity index at injections below fracturing pressures and may further improve the stimulated reservoir volume when used in conjunction with low permeability coal hydraulic fracturing treatments.
Measurement of Shale Anisotropic Permeability and Its Impact on Shale Gas Production
Authors: Pan Zhejun , Ma Yong , Danesh Nima Noraei , Connell Luke D. , Sander Regina , Down David I. , Camilleri Michael 
Published: November 2015

Abstract
Gas shales act as both the source rock and reservoir for the petroleum. One of the important characteristics of the reservoir is its low permeability, making gas production difficult. Although economic shale gas production has been achieved through horizontal drilling and multistage hydraulic fracturing, shale reservoir permeability is still one of the critical parameters in the evaluation of a shale gas play. In the present work, experimental measurement of shale anisotropic permeability is determined using a cubic shale sample in a triaxial cell. Anisotropic permeability was measured at a series of gas pressures and confining pressures. A permeability model incorporating stress and Klinkenberg effect was applied to describe the data. The model was applied in the reservoir simulator SIMED IITM to investigate the impact of anisotropic permeability and its change on shale gas production. Results are compared between using the vertical permeability, horizontal permeability, or anisotropic permeability as the reservoir permeability. The results show that using vertical permeability will significantly underestimate the gas production rate. This demonstrates that measuring directional permeability and using the most appropriate one is important for evaluating shale gas production and development of shale gas assets.