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ENGINEERING (1307 journals)                  1 2 3 4 5 6 7 | Last

Showing 1 - 200 of 1205 Journals sorted alphabetically
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Bharatiya Vaigyanik evam Audyogik Anusandhan Patrika (BVAAP)     Open Access   (Followers: 1)
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Boundary Value Problems     Open Access   (Followers: 1)
Brazilian Journal of Science and Technology     Open Access   (Followers: 2)
Broadcasting, IEEE Transactions on     Hybrid Journal   (Followers: 12)
Bulletin of Canadian Petroleum Geology     Full-text available via subscription   (Followers: 13)
Bulletin of Engineering Geology and the Environment     Hybrid Journal   (Followers: 14)
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Carbon Resources Conversion     Open Access   (Followers: 1)
Case Studies in Engineering Failure Analysis     Open Access   (Followers: 6)
Case Studies in Thermal Engineering     Open Access   (Followers: 6)
Catalysis Communications     Hybrid Journal   (Followers: 6)
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Catalysis Science and Technology     Free   (Followers: 8)
Catalysis Surveys from Asia     Hybrid Journal   (Followers: 3)
Catalysis Today     Hybrid Journal   (Followers: 7)
CEAS Space Journal     Hybrid Journal   (Followers: 2)
Cellular and Molecular Neurobiology     Hybrid Journal   (Followers: 3)
Central European Journal of Engineering     Hybrid Journal  
Chaos : An Interdisciplinary Journal of Nonlinear Science     Hybrid Journal   (Followers: 3)
Chaos, Solitons & Fractals     Hybrid Journal   (Followers: 3)
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Combustion, Explosion, and Shock Waves     Hybrid Journal   (Followers: 15)
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Journal Cover
Bulletin of Canadian Petroleum Geology
Journal Prestige (SJR): 0.314
Citation Impact (citeScore): 1
Number of Followers: 13  
 
  Full-text available via subscription Subscription journal
ISSN (Print) 0007-4802
Published by GeoScienceWorld Homepage  [16 journals]
  • Foreword: The Montney Play of Western Canada: Deposition to Development
    • Authors: Moslow TF; Euzen T, Caplan M.
      PubDate: Fri, 01 Jun 2018 00:00:00 GMT
       
  • Recent advances in routine core analysis on the Montney Formation
    • Authors: Russell P.
      Abstract: The Montney Formation in Alberta and British Columbia presents many challenges for core analysis. Its high saline and sub-irreducible formation water, organic matter content and type, nanometer sized pores, and friability from laminations prevent core analysis from being dependable. Despite this, Routine Core Analysis (RCA) is still commonly performed without modifying the techniques to address these challenges.Over the past five years, RCA has been conducted and examined by the author on over thirty Montney cores. Each step of RCA has been assessed to identify and quantify sources of error and uncertainty. The Montney Formation has been found to be very sensitive to errors that are associated with the limitations of RCA methods. Excluding standard errors, the combination of inappropriate analysis types, ineffective RCA processes, and RCA method limitations, can lead to additional absolute porosity errors that range from -0.8% to +0.6%. The presence of unobservable fractures has been found to incorrectly increase permeability up to three orders of magnitude. The low porosity and permeability of the Montney Formation magnify the relative errors which significantly affect the accuracy stated by American Petroleum Institute Recommended Practice 40 (API RP 40) (1998).Modifications to the RCA process have been made to minimize errors and uncertainties. The techniques discussed were developed to improve accuracy on the Montney Formation, but most are applicable to any rock types that are suitable for RCA.
      PubDate: Fri, 01 Jun 2018 00:00:00 GMT
       
  • Permeability of the Montney Formation in the Western Canada Sedimentary
           Basin: insights from different laboratory measurements
    • Authors: Cui X; Nassichuk B.
      Abstract: Permeability is a critical parameter for evaluating unconventional shale or tight gas and oil reservoirs such as the Montney Formation in the Western Canada Sedimentary Basin. Permeability is also one of the most difficult parameters to be accurately and consistently determined in the laboratory and field as it is a second-order tensor and is dependent on many factors (e.g. test methods, sampling or testing scales, heterogeneities in fabrics, pore networks and pore-throat size distribution, transport mechanisms, pore pressure and confining stress). Although laboratory permeability measurement is limited to samples on the scale of centimeters or less, it provides valuable insights on hydrocarbon transmissibility of the reservoir matrix rock. Several methods have been developed for permeability measurements of unconventional reservoirs but each method has limitations and specific applications and often yields different permeability values even for the same sample.In this study, various permeability measurements on samples from 46 Montney wells in Alberta and British Columbia are examined. The permeability data set has primarily been obtained using transient pressure fall-off and pressure pulse-decay methods due to the relatively low permeability seen throughout the Montney Formation. A unique data set of permeability determined from canister desorption tests is also analyzed and compared to other permeability measurements. Direct permeability measurements obtained using different techniques are further compared with permeability values predicted using models based on mercury intrusion capillary pressure (MICP) data. The results show that the pressure fall-off (kpf) or GRI (kgri) permeability to helium correlates strongly with porosity. The kpf of crushed samples (20/35 meshes) ranges from <5e-6 md to >1e-3 md with porosity increasing from 3% to 13%. The pressure fall-off permeability (kpf) of plug samples is about two orders of magnitude higher than kpf of crushed samples. Pressure pulse-decay permeability (kpdp) under initial in-situ effective confining stress conditions is generally higher than the pressure fall-off permeability of crushed samples but lower than that of core plugs. Pressure pulse-decay permeability (kpdp) of visually intact samples varies over two orders of magnitude for a given porosity, which is likely a result of variable sample characteristics (e.g. with or without micro fractures, net confining stresses applied due to different sample depths and regional locations, mineralogy, amount and type of organic matter, and pore-throat size). The pulse-decay permeability of fractured samples varies widely over three orders of magnitude and is up to three orders of magnitude higher than kpdp of intact samples, indicating favorable enhancement of permeability by unpropped fractures in the Montney Formation. Out of eight MICP-based permeability models tested in this study, the Winland model (Kolodzie, 1980) and the modified Winland model by Di and Jensen (2015) predict the most comparable permeability to the pulse-decay permeability measured on intact samples, and the rest models also predict acceptable values if proper conformance and compaction corrections are done to MICP data. The permeability from these models has stronger correlations with pressure fall-off permeability measured on both intact and fractured core plugs than the other models. For the Montney Formation, the strong dependence of gas permeability on pore pressure and confining stress is also highlighted. The pore pressure and stress dependence of permeability is characterized by a modified Klinkenberg effects correction equation. Liquid permeability to decane or oil is about one order of magnitude lower than gas permeability under similar confining stresses. Variable permeability from different methods, even on the same Montney samples, underlines the limitations and specific applications of each method, and implies the strong heterogeneities in mineralogical fabrics, organic matter distribution and pore size distributions of the Montney samples. The implications of different laboratory methods for formation evaluation are further discussed, and a practical fitfor purpose approach is recommended for the measurement of permeability, which allows for a more rigorous evaluation of in-situ matrix permeability of the Montney Formation and other unconventional shale and tight reservoirs.
      PubDate: Fri, 01 Jun 2018 00:00:00 GMT
       
  • Application of pore throat size distribution data to petrophysical
           characterization of Montney tight-gas siltstones
    • Authors: Akai T; Wood JM.
      Abstract: Pore throat size distribution (PSD) is a fundamental characteristic that influences the large-scale petrophysical properties and reservoir quality of tight rocks in unconventional plays. Here, we use PSD data obtained from mercury intrusion capillary pressure (MICP) and nuclear magnetic resonance (NMR) measurements of Montney tight-gas siltstones to investigate the relationship of pore throat size to several other petrophysical attributes including porosity, permeability and total organic carbon (TOC) content. We find that pore size correlates positively with porosity but negatively with TOC. Additionally, we evaluate methods to estimate absolute permeability and gas relative permeability from MICP data and compare the modeled results with measured data. Estimates of absolute permeability using peak pore throat diameter in the bundle of tortuous tubes model are found to closely match measured permeability values when a tortuosity factor of 3 is applied. Estimates of relative permeability using MICP data in a modified Purcell approach are found to be comparable to measured values only if gas is considered as the wetting phase rather than the non-wetting phase. Hydrocarbon-wet reservoir conditions and the negative correlation of porosity with TOC are both consistent with the presence of solid bitumen/pyrobitumen as a pervasive pore-filling phase (Wood et al., 2018, this issue).
      PubDate: Fri, 01 Jun 2018 00:00:00 GMT
       
  • Chemostratigraphy, petrography, and SEM investigations of the Lower
           Triassic Montney Formation in Alberta: Implications for a new and revised
           diagenetic and depositional model
    • Authors: Wüst RJ; Tu S, Nassichuk B, et al.
      Abstract: High resolution chemostratigraphy of the Montney Formation across Alberta identifies three unique and distinct chemostratigraphic units, referred to as CS1-3, with several subunits (i.e. CS1a, 1b, 3a, 3b). The lowermost two units (CS1-2) are mostly monotonous, finely laminated dolomitic “siltstones” with low geochemical (e.g. element, ratio, factor) variability except for CS1b, where both sedimentary and geochemical variability is present. The overlying units (i.e. CS3a-3b) contains dolomitic siltstones with sandy beds that show abundant sedimentary variability, pervasive bioturbation and abundant geochemical variability. This study focuses on the lowermost units (CS1a, 1b, 2) of the Montney Formation in Alberta, deposited during the Triassic Induan Period and proposes a new depositional model that largely contradicts the current depositional models of a basinal turbidite system. Evidence for a new model are derived from geochemical, petrographic and SEM data. Geochemical data (i.e. Si/Ti, As/Zr ratios, etc) suggest that the lower chemostratigraphic units (CS1-2) had minimal terrestrial influx and geostatistical analysis infers three distinct sources during the time of deposition, i.e. 1) marine benthic carbonates; 2) planktonic siliceous ooze; and 3) terrestrial material. Petrographic/SEM analyses of CS1-2 corroborate the geochemical findings revealing the dominance of authigenic minerals of quartz, dolomite, feldspars and pyrite, with few detrital grains of quartz, mica, feldspars and clay. Hence, the depositional model for the Lower Triassic Montney Formation in Alberta proposes a back-arc, semi-restricted shallow carbonate shelf with prolific benthic/planktonic shell productivity due to limited species diversity following the Permian-Triassic extinction event and limited terrestrial influx (varies locally). High benthic biogenic productivity suggests oxic bottom water conditions and possibly elevated salinity (to limit species diversity) that led to excess NaCl in the pore waters after deposition. Trace elements and total organic carbon (TOC) contents support oxic to sub-oxic sea water conditions, contradicting previous hypotheses of bottom water anoxia. Mineralogical, geochemical and organic carbon data also suggest limited influx of terrestrial and volcanic material. Since the majority of the CS1-2 sediments examined in Alberta display finely laminated dolomitic siltstones, diagenetic processes that generate dolomitic quartz-feldspar laminae from initial bedded shell debris are elaborated upon. A new proposal for the diagenetic pathway is based on findings from isolated carbonate concretions that demonstrate how in-situ porous biogenic debris (metastable aragonite, high Mg-calcite, biogenic silica and rare detrital and organic matter) can transform diagenetically during burial to “pseudo-laminated dolomitic siltstones”.
      PubDate: Fri, 01 Jun 2018 00:00:00 GMT
       
  • Laboratory-based characterization of pore network and matrix permeability
           in the Montney Formation: Insights from methodology comparisons
    • Authors: Ghanizadeh A; Clarkson CR, Vahedian A, et al.
      Abstract: This work presents results from an ongoing laboratory study investigating pore network characteristics and matrix permeability of selected intervals within the Montney Formation (Western Canada). The primary objectives are to: 1) compare different laboratory-based methodologies for determination of porosity and matrix permeability; 2) characterize the pore network attributes (porosity, pore size distribution (PSD), dominant pore throat size, specific surface area) and matrix permeability of the selected target intervals; and 3) analyse the effects of different controlling factors (anisotropy, effective stress, bitumen saturation) on matrix permeability. Eight selected pairs of core plugs, drilled vertically and horizontally, are analysed in this study. These core plugs are obtained from a vertical interval of 15 m within the fine-grained intervals of the Upper Montney Formation in British Columbia (Canada). The experimental techniques used for characterization include: bitumen reflectance (BRo); RockEval pyrolysis; helium pycnometry; Archimedes, caliper and 3D laser scanner analyses; low-pressure gas (N2) adsorption; pulse-decay; and crushed-rock gas (N2, He) permeability measurements.Excluding one of the samples (a laminated vertical core plug): 1) the slipcorrected pulse-decay gas (N2) permeability values (measured at effective stress of 15.8 MPa) and apparent crushed-rock gas (He) permeability values generally increase with increasing porosity (4.2–8.1%), ranging from 1.4·10−5 to 8.6·10−4 mD: and 2) the slip-corrected pulse-decay (N2) permeability values (1.2·10−4−8.6·10-4 mD) are consistently higher than apparent crushed-rock (He) permeability values (1.4·10−5−1·10-4 mD). Pulse-decay (N2) permeability values measured parallel to bedding (horizontal core plugs) are consistently between 10% and 25 times higher than those measured perpendicular to bedding (vertical core plugs). Based on a single pair of laminated core plugs analysed in this study, the degree of permeability anisotropy (ratio between parallel and perpendicular permeability values) appears to be significantly higher for the laminated core plugs (up to 25 times) than bioturbated core plugs (up to 3.5 times). Compared to pulse-decay (N2) permeability values, there is a minimal discrepancy (considering the maximum experimental error margin) between the crushed-rock gas permeability values that were measured on pairs of horizontal/vertical core plugs after crushing/sieving. In a gross sense, slip-corrected pulse-decay (N2) permeability values decrease with increasing bitumen saturation.Applying multiple analysis techniques on a selected suite of core plugs and crushed-rock materials derived from them, this study provides: 1) valuable insight into the causes of observed variations in porosity/permeability values obtained from laboratory-based techniques; and 2) an integrated description of pore network characteristics and matrix permeability for selected fine-grained intervals within the Montney Formation.
      PubDate: Fri, 01 Jun 2018 00:00:00 GMT
       
  • Organic petrography and scanning electron microscopy imaging of a thermal
           maturity series from the Montney tight-gas and hydrocarbon liquids fairway
           
    • Authors: Wood JM; Sanei H, Haeri-Ardakani O, et al.
      Abstract: Organic petrography and field emission scanning electron microscopy (FESEM) images of drill-core samples from five wells comprising a thermal maturity series through the Montney Formation are used to document and interpret the thermal evolution of migrated secondary organic matter (bitumen and oil) from the late oil window into the dry gas window. The present-day organic matter (OM) consists almost entirely of pore-filling secondary OM that migrated into the organic-lean siltstones of the Montney Formation as liquid hydrocarbons. With increasing burial depth and changing temperature, pressure and compositional conditions, the originally introduced oil became unstable and dissociated into different fractions. These dissociated hydrocarbon fractions underwent secondary cracking resulting in a range of solid and fluid hydrocarbon products including: natural gas, condensate, light oil, fluid-like hydrocarbon residue (FHR) and solid bitumen and pyrobitumen. The solid to semi-solid secondary OM products have distinct characteristics in each of the late oil, wet gas and dry gas windows. The wide range of OM textures observed undoubtedly reflect a complex interplay of many organic maturation mechanisms: however, petrographic observations in this study suggest important distinctions in how the different dissociated fractions of the original oil matured. The dissociated asphalt-rich fraction, which precipitated as globular or granular aggregates in the central portions of large open pores, matured and consolidated into solid bitumen (oil and wet gas windows) and pyrobitumen (dry gas window). Solid bitumen/pyrobitumen accumulations have different degrees of organic porosity that partially reflect the variable composition of the precursor asphalt fraction. The early paraffin-rich heavy oil fraction matured into paraffin wax (late oil window), FHR (wet gas window) and carbon residue (dry gas window) that coats grain surfaces and fills the finer interstices of the original pore network. Differences in OM maturity operated at the micrometer scale such that, in the dry gas window, non-porous pyrobitumen in large pores is commonly observed next to highly porous pyrobitumen associated with clays in smaller pores.
      PubDate: Fri, 01 Jun 2018 00:00:00 GMT
       
  • Geochemically focused integrated approach to reveal reservoir
           characteristics linked to better Montney productivity potential
    • Authors: Chatellier J; Simpson KK, Perez RR, et al.
      Abstract: A multidisciplinary study addressed the unconventional Montney reservoir with new or modified tools invoking geochemical data. More than 1100 metres of cores from the Altares and Cypress fields in northeast British Columbia gave a solid stratigraphic framework to test reservoir parameters such as rock fabric, pore throat sizes, brittleness and hydrocarbon fill, integrating petrophysical data with XRF, XRD, brittleness core measurements and mercury injection capillary pressures.Organic geochemistry was key to understand and calibrate pore throat sizes using a phase envelope comparison of isotube and isojar gas compositions; larger differences being linked to smaller pore throats. This was combined with Pittman R30 pore throat calculations from logs and with bitumen content calculated from NMR indicating that some Upper Montney units with larger pore throats are filled with bitumen that corresponds to an early migration of liquid hydrocarbon. Bitumen rich zones have been associated with enrichment in sulfur and samarium. Pore size restriction in the Lower Montney is linked to high clay content and to quartz cement as determined by XRF analysis.Brittleness prediction (Young’s modulus) using XRD has been achieved with a new formula specific to the Altares Field in which only Feldspars have a positive relationship with brittleness; all published XRD base formula gave much poorer results. Brittleness prediction was also achieved using one single XRF element: chromium which is proxy to clay content and as such has a negative relationship. The reason for the poor predictability using other single XRF elements is the difference in lithological content and textures of the Upper and Lower Montney.Isotope compositions gave supporting evidence for high reservoir pressure gradients associated with secondary gas cracking overpressure, allowing recognition of fault bounded reservoir compartments. Isotope data also revealed the presence of horizontal detachments confirmed by increased bed dips seen on image logs.Open fractures filled with dry gas found associated with compressive structures have been identified using gas chromatography; no microseismic events have been found associated with the identified zones of open fractures and, in one well with production logs, 92% of the production came from unstimulated intervals.Among the novelties of the present work are the analyses of data in 3–D and even 4–D (time) whereas previous work had remained static or studied in a 2–D context; thus, carbon isotopes and DFIT data were analyzed in 3–D or against TVDss.
      PubDate: Fri, 01 Jun 2018 00:00:00 GMT
       
  • Practical application of neural networks in assessing completion
           effectiveness in the Montney unconventional gas play in northeast British
           Columbia, Canada
    • Authors: Cai J; Cole J, Young A.
      Abstract: A methodology leveraging Neural Networks has been developed to identify completion optimization potential in the development of a mature Montney Gas Asset providing well specific and field-wide completion effectiveness analysis. This paper presents an approach that can be applied to obtain a better understanding of the relationship between practices used in hydraulic fracturing and well performance, and to highlight methods to optimise well production, based upon a dataset of 56 wells, all completed in the same stratigraphic zone of the Upper Montney, within a developed area of 200 km2 in NE British Columbia.A combined Principal Component analysis — Artificial Neural Network modelling technique (PCA-ANN) has been used in this work to identify key completion-related drivers of well performance, along with some geologically related indicators, and apply neural network modelling to predict well performance as defined by estimated ultimate recovery (EUR), from a “matrix” of completion related data. The results can be used to identify optimal hydraulic fracture design parameters for new wells to enhance production, and potentially also wells that may be candidates for recompletion.Eight key completion-related variables are identified by the PCA method from a total of 31 considered: these include geologically related ones of breakdown pressure (BrdPr) and instantaneous shut-in pressure (ISIP), along with engineering/operational parameters including cluster spacing, perforation number, proppant amount, sand concentration, fluid volume and pumping rate. Using these variables in a sensitivity analysis to measure/predict the EUR shows that for the dataset studied, the dominant production drivers are cluster spacing and proppant amount, which are related to controllable aspects of the hydraulic fracturing process.When applied to evaluate existing producing wells and optimise completions, the approach identifies the lower performing wells that potentially could have better performance if their completion parameters were optimised. Furthermore, the PCA-ANN technique indicates how to achieve optimal results by identifying which parameters should be changed and by how much. As such, this predictive model delivers a series of charts for selecting and evaluating different completion parameters and designs.
      PubDate: Fri, 01 Jun 2018 00:00:00 GMT
       
 
 
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