Search for Articles:
Title / Keyword
Author / Affiliation / Email
Journal
Article Type
 
 
Advanced Search
 
Section
Special Issue
Volume
Issue
Number
Page
 
5.5
3.2
Journals
Energies
Special Issues
Characterization of Unconventional Petroleum Reservoirs
energies-logo
Submit to Energies Review for Energies Propose a Special Issue

Journal Menu

► Journal Menu

Journal Browser

► Journal Browser
share announcement

Characterization of Unconventional Petroleum Reservoirs

A special issue of Energies (ISSN 1996-1073). This special issue belongs to the section "H1: Petroleum Engineering".

Deadline for manuscript submissions: closed (20 February 2022) | Viewed by 12957

Special Issue Editors

Dr. R. Marc Bustin

E-Mail
Guest Editor
Department of Earth and Ocean Sciences, University of British Columbia, Vancouver, BC V6T 1Z4, Canada
Interests: geochemistry; geomechanics and petrophysics of unconventional reservoirs
Dr. Gareth Chalmers

E-Mail Website
Guest Editor
School of Science, Technology and Engineering, University of the Sunshine Coast, Sippy Downs, QLD 4556, Australia
Interests: mineralogy; sedimentary processes; diagenesis; electron micrcopy; geochemistry; permeability; pore development; unconventional petroleum resources; sustainability
Special Issues, Collections and Topics in MDPI journals

Special Issue Information

Dear Colleagues,

Unconventional petroleum resources, shale gas/oil, coal seam gas and tight gas have become significant contributors to global hydrocarbon production in the past two decades and are projected to continue to grow in importance for at least the next 30 years. Unconventional hydrocarbon production is complex due to the myriad of geological processes that control reservoir characteristics. These processes include primary depositional environment, diagenesis (mineral and organic matter), and fluid migration and hydrocarbon retention, all of which are, in turn, impacted by the structural and tectonic evolution of the reservoir and its associated strata. Impact questions related to reservoir characterization include varied topics such as the role of organic matter type and maturation in determining sweet spots with respect to hydrocarbons in place and over pressuring, wellbore stability, fracture propagation/containment, proppant embedment related to mineralogy as controls on reservoir permeability, and fluid flow behavior to name a few. To gain a better understanding of how to economically exploit unconventional petroleum resources, a multidisciplinary approach to reservoir characterization and exploitation is needed. This includes understanding the reservoir characteristics at the pore scale, including pore development within the organic matter of shale and coal reservoirs as well as understanding diagenetic processes that enhance the porosity of tight gas reservoirs. Characterization of these unique reservoirs is also needed to understand how they behave and respond to hydraulic fracturing and how the completion fluids and reservoir rocks mutually impact each other during completion and production. Additionally, the economic and real and perceived environmental risks involved in unconventional reservoir development are ongoing challenges in the development of unconventional reservoirs.

Our goal for this Special Issue is to compile a collection of papers that explore the importance of reservoir characterisation on the development of unconventional resources including shale gas/shale oil, coal seam gas, and tight gas plays. Research that applies cutting-edge technologies and novel techniques to investigate unconventional reservoir properties, detailed case studies, and holistic overviews are of interest.

Dr. R. Marc Bustin
Dr. Gareth Chalmers
Guest Editors

Manuscript Submission Information

Manuscripts should be submitted online at www.mdpi.com by registering and logging in to this website. Once you are registered, click here to go to the submission form. Manuscripts can be submitted until the deadline. All submissions that pass pre-check are peer-reviewed. Accepted papers will be published continuously in the journal (as soon as accepted) and will be listed together on the special issue website. Research articles, review articles as well as short communications are invited. For planned papers, a title and short abstract (about 100 words) can be sent to the Editorial Office for announcement on this website.

Submitted manuscripts should not have been published previously, nor be under consideration for publication elsewhere (except conference proceedings papers). All manuscripts are thoroughly refereed through a single-blind peer-review process. A guide for authors and other relevant information for submission of manuscripts is available on the Instructions for Authors page. Energies is an international peer-reviewed open access semimonthly journal published by MDPI.

Please visit the Instructions for Authors page before submitting a manuscript. The Article Processing Charge (APC) for publication in this open access journal is 2600 CHF (Swiss Francs). Submitted papers should be well formatted and use good English. Authors may use MDPI's English editing service prior to publication or during author revisions.

Keywords

  • mineral composition
  • diagenetic processes
  • depositional environments
  • geomechanics
  • fracture stimulation
  • porosity
  • permeability
  • rock-fluid interactions
  • geochemistry
  • enhanced hydrocarbon recovery

Published Papers (6 papers)

Download All Papers
Order results
Result details
Show export options expand_more Show export options expand_less
Select all
Export citation of selected articles as:

Research

46 pages, 72846 KiB  
Article
Geology and Geochemistry of the Hydrocarbon Compositional Changes in the Triassic Montney Formation, Western Canada
by Gareth R. L. Chalmers, Pablo Lacerda Silva, Amanda A. Bustin, Andrea Sanlorenzo and R. Marc Bustin
Energies 2022, 15(22), 8677; https://0-doi-org.brum.beds.ac.uk/10.3390/en15228677 - 18 Nov 2022
Cited by 3 | Viewed by 2124
Abstract
The geochemistry of produced fluids has been investigated in the Triassic Montney Formation in the Western Canadian Sedimentary Basin (WCSB). Understanding the geochemistry of produced fluids is a valuable tool in the exploration and development of a complex petroleum system such as the [...] Read more.
The geochemistry of produced fluids has been investigated in the Triassic Montney Formation in the Western Canadian Sedimentary Basin (WCSB). Understanding the geochemistry of produced fluids is a valuable tool in the exploration and development of a complex petroleum system such as the Montney Formation. The petroleum system changes from in situ unconventional reservoirs in the west to more conventional reservoirs that contain migrated hydrocarbons to the east. The workflow of basin modeling and mapping of isomer ratio calculations for butane and pentane as well as the mapping of excess methane percentage was used to highlight areas of gas compositional changes in the Montney Formation play area. This workflow shows the migration of hydrocarbons from deeper, more mature areas to less mature areas in the east through discrete pathways. Methane has migrated along structural elements such as the Fort St. John Graben as well as areas that have seen changes in higher permeability lithologies (i.e., well 14-23-74-8W6M). Excess methane percentage calculations highlight changes due to fluid mixing from hydrocarbon migration. The regional maturation polynomial regression line was used to determine the gas dryness percentage for each well on the basis of its maturation level determined by the butane isomer ratio. The deviation from the calculated gas dryness according to the regression was determined as an excess methane percentage. The British Columbia (BC) Montney play appears to have hydrocarbon compositions that reflect an in situ generation, while the Montney play in Alberta (AB) has a higher proportion of its hydrocarbon volumes from migrated hydrocarbons. The workflow provides a better understanding of the hydrocarbon system to optimize operations and increase production efficiency. Understanding the distribution of gas compositions within a play area will provide key information on the liquid and gas phases present and an understanding of how gas composition may change over the well life, as well as helping to maximize liquid recovery during well operations. Full article
(This article belongs to the Special Issue Characterization of Unconventional Petroleum Reservoirs)
►▼ Show Figures

Figure 1

35 pages, 20189 KiB  
Article
Accessibility of Pores to Methane in New Albany Shale Samples of Varying Maturity Determined Using SANS and USANS
by Tomasz Blach, Andrzej P. Radlinski, Phung Vu, Yeping Ji, Liliana de Campo, Elliot P. Gilbert, Klaus Regenauer-Lieb and Maria Mastalerz
Energies 2021, 14(24), 8438; https://0-doi-org.brum.beds.ac.uk/10.3390/en14248438 - 14 Dec 2021
Cited by 6 | Viewed by 1691
Abstract
The accessibility of pores to methane has been investigated in Devonian New Albany Shale Formation early-mature (Ro = 0.50%) to post-mature (Ro = 1.40%) samples. A Marcellus Shale Formation sample was included to expand the maturation range to Ro 2.50%. [...] Read more.
The accessibility of pores to methane has been investigated in Devonian New Albany Shale Formation early-mature (Ro = 0.50%) to post-mature (Ro = 1.40%) samples. A Marcellus Shale Formation sample was included to expand the maturation range to Ro 2.50%. These are organic matter-rich rocks with total organic carbon (TOC) values of 3.4 to 14.4% and porosity values of 2.19 to 6.88%. Contrast matching small-angle neutron scattering (SANS) and ultra-small angle neutron scattering (USANS) techniques were used to generate porosity-related data before and after pressure cycling under hydrostatic (in a vacuum and at 500 bar of deuterated methane) and uniaxial stress (0 to ca. 350 bar) conditions. Our results showed that the accessible porosity was small for the samples studied, ranging from zero to 2.9%. No correlation between the accessible porosity and TOC or mineralogical composition was revealed, and the most likely explanation for porosity variation was related to the thermal transformation of organic matter and hydrocarbon generation. Pressure caused improvements in accessible porosity for most samples, except the oil window sample (Ro = 0.84%). Our data show that densification of methane occurs in nanopores, generally starting at diameters smaller than 20 nm, and that the distribution of methane density is affected by pressure cycling. Full article
(This article belongs to the Special Issue Characterization of Unconventional Petroleum Reservoirs)
►▼ Show Figures

Figure 1

21 pages, 15688 KiB  
Article
Depositional Heterogeneities and Brittleness of Mudstone Lithofacies in the Marcellus Subgroup, Appalachian Basin, New York, U.S.A.
by Izhar Ul Haq, Eswaran Padmanabhan and Omer Iqbal
Energies 2021, 14(20), 6620; https://0-doi-org.brum.beds.ac.uk/10.3390/en14206620 - 14 Oct 2021
Cited by 2 | Viewed by 1658
Abstract
Organic-rich rocks of the Marcellus subgroup in the study area consist of a diverse suite of mudstone lithofacies that were deposited in distinct facies belts. Lithofacies in the succession range in composition from argillaceous to siliceous, calcareous, and carbonaceous mudstone. Heterogeneities in the [...] Read more.
Organic-rich rocks of the Marcellus subgroup in the study area consist of a diverse suite of mudstone lithofacies that were deposited in distinct facies belts. Lithofacies in the succession range in composition from argillaceous to siliceous, calcareous, and carbonaceous mudstone. Heterogeneities in the succession occurs in the form of varying mineralogical composition, slightly bioturbated to highly bioturbated chaotic matrix, organic-rich and organic-lean laminae, scattered fossil shells in the matrix, and fossils acting as lamination planes. Lithofacies were deposited in three facies belts from the proximal to the distal zone of the depositional system. Bedded siliceous mudstone (BSM) facies occur in the proximal facies belt and consists of a high quartz content in addition to clay minerals and pyrite. In the medial part of the facies belt lies the laminated argillaceous mudstone (LAM), bedded calcareous mudstone (BCaM), and bedded carbonaceous mudstone (BCM). The size of detrital mineral grains in the lithofacies of the medial facies belt is larger than bedded argillaceous mudstone (BAM) of the distal facies belt, characterized by clay-rich matrix with occasional fossil shells and horizontally aligned fossils. Two types of horizontal traces and one type of fecal string characterize the proximal mud-stone facies, whereas only single horizontal trace fossil is found in the mudstones of the medial and distal facies belt. Parallel alignment of fossil shells and fossil lags in lithofacies indicate that bed-load transport was active periodically from the proximal source of the depositional system. Bioturbation has heavily affected all of the lithofacies and presence of mottled burrows as well as Devonian fauna indicate that oxic to dysoxic conditions prevailed during deposition. The deposition of this organic-rich mudstone succession through dynamic processes in an overall oxic to dysoxic environment is different from conventional anoxic depositional models interpreted for most of the organic rich black shales worldwide. Total organic content (TOC) varies from top to bottom in the succession and is highest in BCM facies. The brittleness index, calculated on the basis of mineralogy, allowed classification of the lithofacies into three distinct zones, i.e., a brittle zone, a less brittle zone, and a ductile zone with a general proximal to distal decrease in the brittle behavior due to a decrease in the size of the sediments. Full article
(This article belongs to the Special Issue Characterization of Unconventional Petroleum Reservoirs)
►▼ Show Figures

Figure 1

35 pages, 9206 KiB  
Article
Defining Uncertainty: Comparing Resource/Reserve Classification Systems for Coal and Coal Seam Gas
by Tim A. Moore and Mike C. Friederich
Energies 2021, 14(19), 6245; https://0-doi-org.brum.beds.ac.uk/10.3390/en14196245 - 30 Sep 2021
Cited by 3 | Viewed by 2542
Abstract
Transparent, objective, and repeatable resource assessments should be the goal of companies, investors, and regulators. Different types of resources, however, may require different approaches for their quantification. In particular, coal can be treated both as a solid resource (and thus be mined) as [...] Read more.
Transparent, objective, and repeatable resource assessments should be the goal of companies, investors, and regulators. Different types of resources, however, may require different approaches for their quantification. In particular, coal can be treated both as a solid resource (and thus be mined) as well as a reservoir for gas (which is extracted). In coal mining, investment decisions are made based on a high level of data and establishment of seam continuity and character. The Australasian Code for Reporting of Exploration Results, Mineral Resources and Ore Reserves (the JORC Code) allows deposits to be characterised based on the level of geological and commercial certainty. Similarly, the guidelines of the Petroleum Resource Management System (PRMS) can be applied to coal seam gas (CSG) deposits to define the uncertainty and chance of commercialisation. Although coal and CSG represent two very different states of resources (i.e., solid vs. gaseous), their categorisation in the JORC Code and PRMS is remarkably similar at a high level. Both classifications have two major divisions: resource vs. reserve. Generally, in either system, resources are considered to have potential for eventual commercial production, but this has not yet been confirmed. Reserves in either system are considered commercial, but uncertainty is still denoted through different subdivisions. Other classification systems that can be applied to CSG also exist, for example the Canadian Oil and Gas Evaluation Handbook (COGEH) and the Chinese Standard (DZ/T 0216-2020) and both have similar high-level divisions to the JORC Code and PRMS. A hypothetical case study of a single area using the JORC Code to classify the coal and PRMS for the gas showed that the two methodologies will have overlapping, though not necessarily aligned, resource and reserve categories. Full article
(This article belongs to the Special Issue Characterization of Unconventional Petroleum Reservoirs)
►▼ Show Figures

Figure 1

23 pages, 9927 KiB  
Article
Evaluation of Reservoir Quality and Forecasted Production Variability along a Multi-Fractured Horizontal Well. Part 1: Reservoir Characterization
by Daniela Becerra, Christopher R. Clarkson, Amin Ghanizadeh, Rafael Pires de Lima, Farshad Tabasinejad, Zhenzihao Zhang, Ajesh Trivedi and Roman Shor
Energies 2021, 14(19), 6154; https://0-doi-org.brum.beds.ac.uk/10.3390/en14196154 - 27 Sep 2021
Cited by 3 | Viewed by 2042
Abstract
Completion design for horizontal wells is typically performed using a geometric approach where the fracturing stages are evenly distributed along the lateral length of the well. However, this approach ignores the intrinsic vertical and horizontal heterogeneity of unconventional reservoirs, resulting in uneven production [...] Read more.
Completion design for horizontal wells is typically performed using a geometric approach where the fracturing stages are evenly distributed along the lateral length of the well. However, this approach ignores the intrinsic vertical and horizontal heterogeneity of unconventional reservoirs, resulting in uneven production from hydraulic fracturing stages. An alternative approach is to selectively complete intervals with similar and superior reservoir quality (RQ) and completion quality (CQ), potentially leading to improved development efficiency. In the current study, along-well reservoir characterization is performed using data from a horizontal well completed in the Montney Formation in western Canada. Log-derived petrophysical and geomechanical properties, and laboratory analyses performed on drill cuttings, are integrated for the purpose of evaluating RQ and CQ variability along the well. For RQ, cutoffs were applied to the porosity (>4%), permeability (>0.0018 mD), and water saturation (<20%), whereas, for CQ, cutoffs were applied to rock strength (<160 Mpa), Young’s Modulus (60–65 GPa), and Poisson’s ratio (<0.26). Based on the observed heterogeneity in reservoir properties, the lateral length of the well can be subdivided into nine segments. Superior RQ and CQ intervals were found to be associated with predominantly (massive) porous siltstone facies; these intervals are regarded as the primary targets for stimulation. In contrast, relatively inferior RQ and CQ intervals were found to be associated with either dolomite-cemented facies or laminated siltstones. The methods developed and used in this study could be beneficial to Montney operators who aim to better predict and target sweet spots along horizontal wells; the approach could also be used in other unconventional plays. Full article
(This article belongs to the Special Issue Characterization of Unconventional Petroleum Reservoirs)
►▼ Show Figures

Figure 1

24 pages, 4518 KiB  
Article
Evaluation of Reservoir Quality and Forecasted Production Variability along a Multi-Fractured Horizontal Well. Part 2: Selected Stage Forecasting
by Christopher R. Clarkson, Zhenzihao Zhang, Farshad Tabasinejad, Daniela Becerra and Amin Ghanizadeh
Energies 2021, 14(19), 6007; https://0-doi-org.brum.beds.ac.uk/10.3390/en14196007 - 22 Sep 2021
Cited by 2 | Viewed by 1628
Abstract
The current practice for multi-fractured horizontal well development in low-permeability reservoirs is to complete the full length of the well with evenly spaced fracture stages. Given methods to evaluate along-well variability in reservoir quality and to predict stage-by-stage performance, it may be possible [...] Read more.
The current practice for multi-fractured horizontal well development in low-permeability reservoirs is to complete the full length of the well with evenly spaced fracture stages. Given methods to evaluate along-well variability in reservoir quality and to predict stage-by-stage performance, it may be possible to reduce the number of stages completed in a well without a significant sacrifice in well performance. Provision and demonstration of these methods is the goal of the current two-part study. In Part 1 of this study, reservoir and completion quality were evaluated along the length of a horizontal well in the Montney Formation in western Canada. In the current (Part 2) study, the along-well reservoir property estimates are first used to forecast per-stage production variability, and then used to evaluate production performance of the well when fewer stages are completed in higher quality reservoir. A rigorous and fast semi-analytical model was used for forecasting, with constraints on fracture geometry obtained from numerical model history matching of the studied Montney well flowback data. It is concluded that a significant reduction in the number of stages from 50 (what was implemented) to less than 40 could have yielded most of the oil production obtained over the forecast period. Full article
(This article belongs to the Special Issue Characterization of Unconventional Petroleum Reservoirs)
►▼ Show Figures

Figure 1

Show export options expand_more Show export options expand_less
Select all
Export citation of selected articles as:
 
Displaying articles 1-6
Back to TopTop