bluuebunny/crossref_metadata_2025_split huggingface dataset:
Hydraulic Fracturing Simulations in Zhahaquan, Qaidam Basin, P.R. China: Can Early Screen-Outs be Avoided With Model Based Design?
Authors: Weng Dingwei , Falser Simon , Ding Yunhong , Xu Yun , Liang Hongbo , Wang Liwei , Lin Hai 
Published: November 2015

Abstract
The Zhahaquan tight oil field is located in the late tertiary siltstone of the Qaidam Basin, Gansu Province, P.R. China. The field's conventional and tight reservoirs are currently being appraised with an aggressive drilling campaign. Despite an average plug permeability of about 0.3 mD and a modestly overpressured reservoir (12–16 kPa/m), hydraulic fracturing (HF) stimulations are deemed necessary to produce the light oil (31° API) at commercial rates. Stress modelling and fracture diagnostics confirm a predominately normal faulting stress regime throughout the basin, but vertical stress contrasts between formation layers highlight no potential frac barriers.
Initial hydraulic fracturing stimulations in 8 vertical wells resulted in 6 out of 11 stages screening out prematurely, while the remaining 5 could only be completed with light proppant concentrations below 10% of fluid volume, resulting in only modest production rates. Subsequent well stimulations were designed based on refined modelling results, with which screen- outs could be avoided and initial production rates tripled.
This study puts forward the modelling and execution of one horizontal well with 27 perforation clusters divided into 10 stages, in which the effects of fluid rheology, proppant concentration and injection rate on the resulting fracture geometry are highlighted. The study further shows that unlike in preceding simulations, the cluster- and stage spacing were optimised with respect to the stress interference between parallel fractures.
The Influence of Cleat Demineralisation on the Compressibility of Coal
Authors: Balucan Reydick D. , Turner Luc G. , Steel Karen M. 
Published: November 2015

AbstractThe natural fracture system of coal is the primary conduit for gas flow. Low permeability is in many cases attributed to low fracture porosity and/or connectivity. Mineral occluded coal cleats are known to considerably reduce coal permeability. Whilst cleat demineralisation has been found to increase coal permeability, its influence on compressibility is poorly understood.In this study, we investigated the influence of mineral dissolution and secondary mineralisation on the compressibility of coal (Cf) following acidification with hydrochloric and hydrofluoric acid (HCl-HF). In-situ HCl core flooding and core immersion in 3% and 15% HF yielded a less compressible core (Cf = 0.006 from 0.020 bar-1) with sustained, enhanced permeability to brine (k = 0.40 from 0.10 mD). We attribute improved stress resilience and better fluid flow characteristics to the dissolution and subsequent secondary mineralisation of the core's circumferential periphery.Predictive geochemical speciation using OLI Analyzer 9.1, for surveying mineral solubilities and precipitation tendencies, identified the formation of radio-dense neofluoride salts K2SiF6 and CaF2 Structural modifications and mineralogical changes detected from scanning electron microscopy-electron diffraction spectroscopy (SEM-EDS), confirmed the presence of these salts. Results suggest that mineral alteration and subsequent secondary mineralisation of the core periphery following HCl-HF acidisation yielded well-formed crystalline salts, apparently serving as in-situ generated proppants buttressing newly created void spaces for enhanced fluid flow and improved resistance to increasing confining stress.
Evaluation of Molecular Diffusion Effect by Using PVT Experimental Data: Impact on Gas Injection to Tight Fractured Gas Condensate / Heavy Oil Reservoirs
Authors: Ohata Tomoya , Nakano Masanori , Ueda Ryo 
Published: November 2015

Abstract
Molecular diffusion is one of the most important factors to be considered when predicting oil recovery by application of gas injection. In this paper, a fluid characterization methodology including the estimation of molecular diffusion coefficients, which directly express the effect of molecular diffusion under reservoir conditions, is presented. In addition, the impact of diffusion on oil recovery by considering gas injection to a tight fractured gas condensate / heavy oil reservoir is also examined. We estimated the Fickian molecular diffusion coefficients from a combination of experimental data using a PVT cell and simulation matching based on coefficients calculated by the Leahy-Dios and Firoozabadi (2007) equation. As a result, we successfully estimated the coefficients and found that they largely deviated from the anticipated values. By an extension of a published study (Imai et al., 2012), using actual field oil and methane under different pressure conditions, we found that diffusion coefficients were smaller under higher pressure conditions. This implies that the higher the density and viscosity of the oil, the smaller the coefficients. Moreover, the diffusion processes in heavy oil systems were almost 10 times slower than those in light oil systems. Considering a tight fractured gas condensate reservoir and a heterogeneous heavy oil reservoir, a flow case study with gas injection accounting for the tuned coefficients was numerically simulated. The simulation study showed that the fractured case with molecular diffusion resulted in an oil recovery improvement of almost 10% as compared to the case with no molecular diffusion. The improvement was, moreover, larger than that in the case without experimentally tuned coefficients. This result implies that accurate estimation of the molecular diffusion coefficients under reservoir conditions is crucial for estimation of oil recovery with gas injection.
An Innovative Technique for Estimation of Permeability of Shale Gas Reservoirs
Authors: Yuan Yudong , Rahman Sheik , Wang Junjian , Doonechaly Nima Gholizadeh 
Published: November 2015

AbstractCharacterization of flow processes in multi-scale porous system (nanopores to mesopores) in tight rocks, such as the shales, is challenging because of the coexistence of various flow regimes in the porous media. Although some methods based on dusty gas model (DGM) have been applied to determine the apparent gas permeability of shales (Javadpour 2009, Freeman et al. 2011, Sakhaee-Pour and Bryant 2012, Chen et al. 2015), they fail to describe gas flow process in nanopores in detail. In this paper, we present an innovative methodology for estimating apparent gas permeability of shales by coupling multiscale flow mechanisms. The Lattice Boltzmann Method (LBM) with effective viscosity and a general second-order boundary condition is used to analyze the various flow regimes involved in the single microchannel. The desirable agreement between the simulation results and that from the DSMC studies for the rarefied flow prompts the application of the derived correction factor for estimating permeability of shale gas reservoirs. In order to realize this, the porous medium is represented by a bundle of capillaries with diameters determined by mercury injection capillary pressure (MICP) curves. The porous flow is simulated by Darcy's law with derived correction factor; the surface diffusion of adsorption gas in kerogen pores is simulated based on Langmuir model and Fick's law. An extensive integration based on fractal dimension is performed to estimate the total flow rate and thereby the apparent permeability of typical shale samples. MICP and a transient pressure pulse technique are employed on 7 shale samples to obtain the pore size distribution and permeability. The result shows that the estimated gas permeability matches well with the measured permeability with a 20% variation, indicating that the physics based model presented in this paper is highly effective in predicting gas permeability of tight formations, such as the shales.
Effects of Sample Holding Time, Storage and Preservation on Sample Integrity for Source Rock Analysis: Experimental Results
Authors: Bhosle Balaji , Crozier Peter , Flynn Kevin 
Published: November 2015

Abstract
The effects of sample holding times, sample storage, and sample preservation in the laboratory have considerable effects on the final results of standard SRA (source rock analysis). This research was primarily directed to determine the potential effects of delay in processing and analysis. For example, over time; will the volatile hydrocarbon content (S1) and hydrocarbon generative potential (S2) [which is used to calculate Hydrogen Index (HI) and Production Index (PI)] show consistent results? In total fifteen samples were analysed for source rock analysis using the industry standard SRA-TPH/TOC instrument to test the effect of wait time on SRA results.
Results from experiments conducted for variations in the sample holding time in shale rock samples show statistically meaningful changes. The samples that were processed and analyzed within one to three days show significant S1 and S2 values whereas the same samples analysed after four weeks and subsequently after three months show declining trends. The change between the four week and three month analysis is almost negligible. The noted average change in S1, S2 and S3 values ranges between 2% to 14%, 1% to 9% and 0% to 12%, respectively. Since the HI and PI are calculated from the S1 and S2 values, they also show lower values, averaging 5.26% and 3.75%, respectively.
The same samples were also analyzed for clay contents and brittleness. The samples with high clay content and lower brittleness index show greater decline in the S1 and S2 values, and conversely, low clay content at higher brittleness show less decline in the S1 and S2 values. Therefore, more lithified/cemented samples show less variability over long holding times. In addition, the experimental results obtained indicate that sample holding time also demonstrate there are considerable effects on the final results when the S1 and S2 values are especially high.
In order to avoid the sample degradation and data consistency issues, there is an industry-wide need to reassess sample collection, storage, processing, and analysis time. Although the data set analyzed may not be sufficient to make broad conclusions concerning the changes in the data, as there are several other confounding factors to take into account. However, the approaches demonstrated in this study will assist future researchers with more comprehensive data sets.
Production Simulation of Complex Fracture Networks for Shale Gas Reservoirs Using a Semi-analytical Model
Authors: Jia Pin , Cheng Linsong , Huang Shijun , Xue Yongchao , Ai Shuang 
Published: November 2015

Abstract
Interacting with the pre-existing natural fractures, multi-stage hydraulic fracturing along horizontal wells creates complex fracture networks. Gas flow for these fracture networks in shale gas reservoirs is significantly complex due to more flow mechanisms, including the interplay of flow between the interconnected fractures, seepage, diffusion, adsorption/desorption and stress-dependent permeability within the fractures. The objective of this paper is to present a semi-analytical model for production simulation of complex fracture networks coupled with above processes in shale gas reservoirs. The fractures within the networks are represented explicitly rather than idealized as a dual-porosity medium. The model dynamically couples a numerical fracture network model with an analytical reservoir model. This approach allows us to simulate the networks with complex geometry and varying fracture conductivity. Seepage, diffusion and gas adsorption/desorption in the matrix are taken into account. Fracture deformation is implicitly coupled with numerical network flow model to reflect stress-stress dependent of fracture permeability. A synthetic fracture network is simulated in the rectangular reservoir. The results indicate that for the same fracture network volume a very low conductivity will generate very large pressure drops in the fractures surrounding the wellbore resulting in less effective fracture network compared to high conductivity. The contribution of diffusivity flow of the matrix is not appreciable on the log-log plot for transient response for km=10−4md. The adsorption compressibility has a great influence on the middle and later production periods and gas recovery may be significantly enhanced by adsorption/desorption. When the fracture is closed with pressure drop, the permeability is still sufficient to transmit the volume of fluid available to flow due to the infinite-conductivity effect compared with the shale-matrix for km=10−4md. Finally, a field example from the Barnett Shale shows the capacity of the model to simulate more complex fracture networks in shale gas reservoirs.
Plugging CSG Wells with Bentonite: Review and Preliminary Lab Results
Authors: Towler Brian F. , Firouzi Mahshid , Mortezapour Amin , Hywel-Evans Paul D. 
Published: November 2015

Abstract
Oil and gas wells are required to be plugged when the production of these wells is no longer economical. Cement is the current standard method for plugging wells. However, this process has limitations because cement is expensive and prone to cracking and unsealing. This paper aims to review and investigate the use of a naturally occurring clay called bentonite to plug CSG wells in Queensland as well as oil and gas wells in general. Bentonite is cheaper and easier to handle and when hydrated it creates a more reliable plug because it is malleable and self-healing when disturbed.
We also experimentally and theoretically investigate the mechanisms for failure of bentonite plugs. The plug failure mechanisms can be determined by comparing the measured dislodgement pressure and the predictions of the theory developed in our group. Based on our preliminary results we found that the hydrated plugs can be made significantly stronger by restricting the expansion space. This allowed us to measure the internal swelling pressure at 8 MPa which corresponded to measurements reported in the literature at a reduced density of 1.6755 g/cm3.
The Next Generation of Water and Fluid Management for Unconventional Exploration and Appraisal: Building on the Successes of Queensland Coal Seam Gas
Authors: Hudson Nick 
Published: November 2015

Abstract
Water for the unconventional Exploration and Appraisal (E&A) lifecycle, from Spud to Plug and Abandon, has always presented a fundamental challenge. None more so than the recent major unconventional play of Queensland's (QLD) Coal Seam Gas (CSG).
Water management has always been an important surface component of E&A, from supporting drilling and stimulation effort, through to managing production water. However, in Queensland, water became a critical obstacle, initially driven by compliance and stakeholder issues. It became apparent methodologies from North America and even the conventional Central Australia experiences did not offer solutions to the challenge. Water issues from both regulator and landholders were more significant than expected. The consequence of this led to delays in data acquisition and significant cost escalation of planned E&A activity. Ultimately the boarder industry responded to the challenge by understanding the issues, then applying a fair amount of innovation.
Moving forward the general challenge still stands for new unconventional plays. Solving this requires recognition that water management is often a localized issue. Particularly as many new unconventional resources are in remote and isolated areas, with little supporting infrastructure. The McArthur Basin Shale Gas Play, in Australia is an obvious example.
This paper presents the challenges and learnings in E&A water management from the QLD CSG experience. One of the key learnings is that planning was critical. In recognition of that fact, a simple five-part water field development planning tool is proposed to support successful E&A. With costs of E&A now more important than ever, and not withstanding the enduring need to maintain the operator's license to operate (both regulator and community), getting all aspects water management right is a fundamental key to success.
An Evaluation of Coiled Tubing Fracturing Compared to Traditional Completion Techniques in Horizontal Wells
Authors: Lewis Bryan J. 
Published: November 2015

Abstract
In this time of uncertainty within the industry, operators are under increasing pressure to reduce cost and increase operating efficiency. The cost in both time and resources for hydraulically stimulating a well is a substantial part of the total expenses for the well and the economic success of the investment, as most formations being drilled presently in North America (NA) are incapable of economic returns without multi-stage hydraulic fracturing. Coil tubing (CT) deployed hydra-jet perforated pinpoint stimulation methods both aim to improve the success of hydraulic fracturing treatments and deliver increased versatility in terms of the treatment design of the well. This is achieved by specifically targeting each section of the well with a customized treatment plan and fracture placement to optimize the formation return. This paper presents a summary of various pinpoint stimulation technologies and methods. An economic comparison to a traditional plug-and-perf stimulation is provided based on total treatment time, hydraulic horsepower (HHP) requirements, and percentage of treatment time spent in fracturing, perforating, setting plugs, drilling out plugs, and other necessary activities. Using these metrics, each of the pinpoint stimulation methods outperformed the plug-and-perf operation, with the addition of a reduced capital expense for equipment on location, reduced wear on tubular and tools in the wellbore, and the elimination of the cost, international importation challenges, and health, safety, and environment (HSE) risks with explosive shape charge perforation guns.
Isotherms, Gas Contents and Diffusion Coefficients of Coals and Shales
Authors: Gray Ian , Wood Jeff , Shelukhina Iuliia , Zhao Xiaoli 
Published: November 2015

Abstract
The measurement of gas content of coals has been dominated by the standard methods of core desorption described by ASTM D7569 and AS3980 (1999). In this paper the limitations of these procedures are discussed with particular reference to the partial gas pressure the gas content is being referred to. Because the gas content is always quoted as an absolute value measured to an undefined gas partial pressure as opposed to a value at atmospheric pressure it brings into question the nature of the isotherm model being used at pressures below atmospheric. The generally accepted Langmuir model is found to be lacking at these lower pressures and alternative options are considered.
The current practise of measuring isotherms is also questioned, particularly with respect to mixed gas types where the extended Langmuir or IAS models are found wanting.
To overcome these deficiencies the process of measuring gas contents to known partial pressures of seam gas is used. So too is the process of measuring native isotherms on initial desorption of core. This is extended to the measurement of laboratory isotherms at reduced pressures.
The results of isotherm testing indicate that the native isotherms are generally not the same as isotherms derived from laboratory testing though they are more similar where the seam gas is of a single composition. By undertaking isotherm tests to lowered pressures we can see that there are shortcomings in the Langmuir equation and that gas storage at lowered pressures may vary substantially from this model. The measurement of gas content by conventional desorption needs to be measured to a known partial pressure and this needs in turn to be related to the isotherm.
This paper uses some basic science to produce better solutions to gas content analysis. Along with these developments comes the analysis of desorption of a sample and how this relates to the diffusion coefficient and core fracturing. This leads in turn to an improved process to determine the lost gas on core retrieval for coals and shales.
Geological and Petrophysical Characterization of Tight Oil Reservoirs: A Case Study from Upper Triassic Yanchang Formation, Ordos Basin in North China
Authors: Zhao Huawei , Ning Zhengfu , Zhao Tianyi , Yu Lei , Zhang Rui , Dou Xiangji , Hou Tengfei 
Published: November 2015

AbstractTo evaluate the exploration potential of tight oil reservoirs in the Upper Triassic Yanchang Formation, a combined research was done to investigate the source rock distribution, diagensis, pore systems, petrophysical parameters. To begin with, the horizontal distribution and vertical thickness of the reservoir were clarified with data from well drilling and regional geological background. After that, X-ray diffraction and scanning electron microscopy experiments were conducted to study the pore types and morphologies. Then the pore size distribution was calculated based on mercury injection capillary pressure data. Finally, porosity and permeability were tested. Also, the causes of the tight sandstone, the controlling factor of petrophysical parameters and the fracability were discussed.The Upper Triassic Yanchang Formation is rich in tight oil reserves and shows good exploration potential. Horizontally, reservoir is accumulated at the centre of the lake deposit with an area of 7.5×103 km2; vertically, reservoir is in Chang 6, Chang 7 and Chang 8 member with total depth 25–80m, among which Chang 7 member acts as the main source rock. Sediments are mainly fine grained sand, cements including clays, calcite and dolomite. After early stage mechanical compaction and late stage cementation, the reservoir becomes quite tight. Pores are classified into four types, residual interparticle pores, intraparticle grain pores, clay dominated pores, and micro fractures. Residual interparticle pores and clay dominate pores are main pore types for storage and flow; existence of micro fracture can improve permeability and is a good indication of fracturing potential. Porosity is between 6.12–13.80% and air permeability normally smaller than 0.3 mD, the early stage compaction is the main reason of porosity reduction, while combination of compaction and cementation results in dramatic decreasing in permeability. This reservoir can be commercially developed with horizontal well and hydraulic fracturing stimulation.This study provides a workflow to fully characterize the storage and transport properties of a tight oil reservoir, and the workflow can act as reference to other similar reservoirs.
Effect of Wettability Alteration on Productivity Enhancement in Unconventional Gas Reservoirs: Application of Nanotechnology
Authors: Naik Saurabh , You Zhenjiang , Bedrikovetsky Pavel 
Published: November 2015

AbstractIn unconventional water-wet gas reservoirs with very low permeability, water entrapment or blockage can occur near the wellbore due to the capillary end effect, resulting in low gas production. A reduction in capillary forces through wettability alteration of reservoir rock surface is proposed as an effective approach to reduce water blockage and enhance gas production. The method can be applied to accelerating dewatering and preventing drilling and fracturing fluid leak-off as well. Analytical models for steady-state water-gas linear and radial flows are developed in the current paper. The effects of contact angle on capillary pressure and relative permeabilities have been included. The new model is validated using experimental data. Applications to fully and partially treated regimes show the competition between viscous and capillary effects on productivity of gas and water, which leads to an optimal contact angle for the maximum productivity index for each phase. This study shows the potential for optimising unconventional gas productivity through wettability control. Application of nanotechnology to rock wettability alteration is proposed.