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Ghanizadeh, Amin (University of Calgary) | Clarkson, Christopher R. (University of Calgary) | Clarke, Katherine M. (University of Calgary) | Yang, Zhengru (University of Calgary) | Rashidi, Behrad (University of Calgary) | Vahedian, Atena (University of Calgary) | Song, Chengyao (University of Calgary) | DeBuhr, Chris (University of Calgary) | Haghshenas, Behjat (University of Calgary) | Ardakani, Omid H. (Geological Survey of Canada) | Sanei, Hamed (Aarhus University) | Royer, Dean P. (Encana Corporation)
The hydrocarbon (HC)-storage capacity of organic-rich shales depends on porosity and surface area, whereas pore-throat-size distribution and pore-throat-network connectivity control permeability. The pores within the organic matter (OM) of organic-rich shales develop during thermal maturation as different HC phases are generated and expelled from the OM. Organic-rich shales can potentially retain a large proportion of the HCs generated during the diagenesis process. Commercial HC production from liquid-rich shale reservoirs can be achieved using completion technologies such as multistage-fractured horizontal wells. However, the ability of industry to identify “sweet spots” along multistage-fractured horizontal wells for both primary and enhanced oil recovery (EOR) is still hampered by insufficient understanding of the effects of type/content of entrained HC/OM components on reservoir quality. The primary objectives of the current study are therefore to establish an integrated experimental workflow to investigate the effect of entrained HC/OM on storage and transport properties of the organic-rich shales, and to provide examples of that experimental workflow through analyzing a selected sample suite from a prolific shale-oil reservoir (the Duvernay Formation) in western Canada.
To accomplish this goal, a comprehensive suite of petrophysical analyses is performed on a diverse sample suite from the Duvernay Formation that differs in OM content (2.8 to 5 wt%; n = 5), before and after sequential pyrolysis by a revised Rock-Eval analysis [extended-slow-heating (ESH) Rock-Eval analysis]. Using the ESH cycle, different HC/OM components can be distinguished more easily and reliably during the pyrolysis process: free light oil (S1ESH; up to 150°C), fluid-like HC residue (FHR) (S2a; 150 to 380°C), and solid bitumen/residual carbon (S2b; 380 to 650°C). The characterization techniques used at each stage are helium pycnometry (grain density, helium porosity); low-pressure gas (N2, CO2) adsorption (LPA) [pore volume (PV), surface area, pore-size distribution (PSD) within micropores, mesopores, and smaller macropores]; crushed-rock gas [helium, CO2, N2] permeability; and rate-of-adsorption (ROA) analysis (CO2, N2). Scanning-electron-microscopy (SEM) analysis is further conducted to verify/support the petrophysical observations. Powder X-ray-diffraction (XRD) analyses were performed on all samples in the “as-received” state and after Stage S2b (thermal pyrolysis up to 650°C) to quantify variations in mineralogical compositions and their possible controls on the evolution of petrophysical properties (i.e., porosity/permeability). Organic petrography was conducted on selected samples to characterize the nature of OM.
Compared with the “as-received” state, porosity, permeability, modal-pore-size distribution, and surface-area increase with sequential pyrolysis stages, associated with the expulsion and devolatilization of free light oil and FHR (S2a; up to 380°C). However, the change in petrophysical properties associated with the degradation of solid bitumen/residual carbon (S2b; up to 650°C) is variable and unpredictable. The observed reduction in porosity/permeability values after Stage S2b is likely attributed to the occlusion of PV with solid bitumen/residual carbon degradation (i.e., coking); sample swelling caused by water loss from the lattice structure of clay minerals (i.e., illite); and sample compaction as a result of OM removal from the rock matrix. Among various stages of the ESH Rock-Eval pyrolysis, the petrophysical properties that are measured after Stages S1ESH and S2a, as they are related to the expulsion of the lighter and heavier free-HC compounds from the rock matrix, are expected to be the most important for primary and EOR applications.
Quantification of the evolution of reservoir quality with HC generation/expulsion has important implications for identifying petrophysical “sweet spots” within unconventional reservoirs, optimizing stimulation design, and targeting specific zones within the reservoir of interest with the OM content/type amenable to maximizing gas storage/transport during cyclic solvent injection for EOR applications. The integrated experimental workflow proposed herein could be of significant interest to the operators of organic-rich shale/mudstone plays (e.g., the Duvernay) as a screening tool for developing optimized stimulation treatments for improving primary and enhanced HC recovery.
Li, Xinyang (OptaSense, Inc.) | Zhang, Jimmy (Encana Corporation) | Grubert, Marcel (OptaSense, Inc.) | Laing, Carson (OptaSense, Inc.) | Chavarria, Andres (OptaSense, Inc.) | Cole, Steve (OptaSense, Inc.) | Oukaci, Yassine (OptaSense, Inc.)
Hydraulic fracturing operations in unconventional reservoirs are increasingly being monitored with fiber-optic (FO) Distributed Acoustic and Temperature Sensing (DAS/DTS). In this paper, we discuss how a single well equipped with fiber optics and DAS can be used as a diagnostic tool to better understand the completions program of three offset wells and the fiber instrumented well.
Strain measurements were initially conducted for seismic studies, then followed by measurements of fluid injections from monitoring wells to better understand placement along the lateral section of the wellbore for programs such as hydraulic fracturing, water flooding, and steam injection. The broadband DAS signals have shown of value for the monitoring of microseismic, as well as thermal and mechanical strain of the fiber over the entire well-pad's completion process. During well stimulation, as a fracture propagates to an offset wellbore with fiber deployed, the DAS measurements can be used to monitor very small changes of strain on the fiber. Analysis of the Cross-Well Communication (CWC) strain measurements provide information about possible fracture numbers and locations, as well as the fracture propagating rate based on known well distance. Changes in the strain measurements are coupled with microseismic events that can be simultaneously monitored using the same interrogator unit and fiber optic cable.
Here we present various diagnostic tools for DAS that help to better understand the completions program. A variety of physical effects, such as temperature, strain and micro seismicity are measured and correlated with the treatment program to aid in the analysis. Two of the offset wells were zipper-fractured first, then the fiber installed well was zipper-fractured with the third offset well. By monitoring CWC strain measurements we show that DAS can assess the treatment and performance of neighboring wells that are not instrumented with fiber optic cable. Low frequency strain events from neighboring wells provide direct measurements of the fracture density and possible fracture network post fiber well completion. CWC measurements can provide strain levels that can be analyzed in the context of the various completion parameters including stage length, clusters, and well spacing, etc. We also discuss the fluid and proppant allocations measurements that can be performed on the well with fiber installation. We show how DAS can be used as a tool for investigating cluster efficiency, diverter effectiveness, and for determining completions problems like screen-outs and stage communication.
The analysis of the DAS data demonstrates that current fiber-optic technology can provide enough sensitivity to detect a significant number of frac events that can be used for an improved reservoir description and as an assessment of the completions program.
The objective of the project is to reconcile and quantify the impact of geological and completion variables that cause significant EUR differences in two recent wells drilled and completed in the Uteland Butte member of the Green River formation in Uinta Basin, Utah. While the geology and reservoir conditions are similar for both wells, the completion design and parameters are different (Ball-and-Sleeve vs. Plug-and-Perf, job size, treatment rates, well length, etc.).
The Asset Team uses a structured workflow consisting of several modeling tools: Rate-Transient-Analysis (RTA), Frac Modeling (FM) and Reservoir Simulation (RS) to address and quantify the impact of each variable: Job size, Treatment Rate, Frac count per Stage, Well Length and the effect of clays.
The workflow began with a performance evaluation of the high EUR well (Plug-and-Perf, large job) with RTA and Frac modeling; followed by history-match and prediction of the EUR with the RS model. In the subsequent workflow, a single variable is changed in each modeling step, while others are held constant -- as such, the EUR impact for each variable can be quantified. The result from each step is calibrated with the actual performance observed in the field.
This model-based approach successfully quantified the production impact of each variable. Subsequently, the key drivers can be determined which explains the estimated EUR difference between the two wells. This work drives us to conclude that due to varying pressure, PVT and lithology across the field, different completion designs shall be utilized. The team has gained valuable insight on how to implement different completion techniques with varying job size and design for the basin. Currently, these results are used to drive the well designs and approval; with the long-term objective of optimizing the Field Development Plan.
Poor reproducibility of published findings is a problem that is plaguing most scientific fields. Low statistical power, insufficient sample size, and poor experimental design are often cited as contributing factors to irreproducibility. The majority of scientific research in the oil and gas industry is not designed to readily validate the hypothesis being generated. In a typical study, data is collected without an explicit expectation and the results are analyzed. In these cases, the outcome becomes known and hypotheses are derived afterwards with the benefit of hindsight. Though this process is valuable in scientific induction and hypothesis generation, it leaves most published “conclusions” without true validation. Additionally, due to the well-documented effects of “hindsight bias”, it is difficult to accurately gauge the success of a hypothesis when the results are already known. To truly demonstrate the veracity of the hypothesis, then, it is necessary to predict future behavior and validate these blind predictions with an adequate sample set. This study provides an example of blind validation using a multi-variate regression in the Midland Basin.
Using wells with known outcomes of oil performance, a hypothesis was generated to explain cumulative oil production in the form of a multiple linear equation. This hypothesis was then tested by generating blind predictions of well performance for the next 100+ wells - before they were drilled. Now, with the collection of significant production history on this well set, the accuracy of the blind predictions has been evaluated.
The findings suggest that 1) a relatively large sample set is required for validation 2) it is possible to blindly predict well performance more accurately than chance or stationarity and 3) withholding data during the model tuning process overestimates the success of the model when compared to blind, forward predictions.
The novelty of this study is in the collection of a blind sample set of newly drilled wells after the predictions were generated. This allows for the quantification of the model's predictivity loss when used in a truly forward sense. The significance of this observation is that the error found in a forward sense is not the same as is found when simply withholding a portion of the data for testing. The application of this learning is far-reaching. The majority of published models are validated in a backwards sense, using existing observations. However, most of these studies are aimed at predicting and manipulating future behavior, for example, improving well performance through completions design. Without taking the next step to prove that this future expectation was achieved with a significant sample set, it cannot necessarily be expected that a model will be useful for its intended application.
Martini, Brigette (Corescan Inc.) | Bellian, Jerome (Whiting Petroleum Corporation) | Katz, David (Encana Corporation) | Fonteneau, Lionel (Corescan Pty Ltd) | Carey, Ronell (Corescan Pty Ltd) | Guisinger, Mary (Whiting Petroleum Corporation) | Nordeng, Stephan H. (University of North Dakota)
Hyperspectral core imaging studies of the Bakken-Three Forks formations over the past four years has revealed non-destructive, high resolution, spatially relevant insight into mineralogy, both primary and diagenetically altered that can be applied to reservoir characterization. While ‘big’ data like co-acquired hyperspectral imagery, digital photography and laser profiles can be challenging to analyze, synthesize, scale, visualize and store, their value in providing mineralogical information, structural variables and visual context at scales that lie between (and ultimately link) nano and reservoir-scale measurements of the Bakken-Three Forks system, is unique.
Simultaneous, co-acquired hyperspectral core imaging data (at 500 μm spatial resolution), digital color photography (at 50 μm spatial resolution) and laser profiles (at 20 μm spatial and 7 μm vertical resolution), were acquired over 24 wells for a total of 2,870 ft. of core, seven wells of which targeted the Bakken-Three Forks formations. These Bakken-Three Forks data (~5.5 TB) represent roughly 175,000,000 pixels of spatially referenced mineralogical data. Measurements were performed at a mobile Corescan HCI-3 laboratory based in Denver, CO, while spectral and spatial analysis of the data was completed using proprietary in-house spectral software, offsite in Perth, WA, Australia. Synthesis of the spectral-based mineral maps and laser-based structural data, with ancillary data (including Qemscan, XRD and various downhole geophysical surveys) were completed in several software and modelling platforms.
The resulting spatial context of this hyperspectral imaging-based mineralogy and assemblages are particularly compelling, both in small scale micro-distribution as well as borehole scale mineralogical distributions related to both primary lithology and secondary alteration. These studies also present some of the first successful measurement and derivation of lithology from hyperspectral data. Relationships between hyperspectral-derived mineralogy and oil concentrations are presented as are separately derived structural variables. The relationship between hyperspectral-based mineralogy to micro-scale reservoir characteristics (including those derived from Qemscan) were studied, as were relationships to larger-scale downhole geophysical data (resulting in compelling correlations between variables of resistivity and hyperspectral-mineralogy). Finally, basic Net-to-Gross calculations were completed using the hyperspectral imaging data, thereby extending the use of such data from geological characterizations through to resource estimations.
The high-fidelity mineralogical maps afforded by hyperspectral core imaging have not only provided new geological insight into the Bakken-Three Forks formations, but ultimately provide improved well completion designs in those formations, as well as a framework for applying the technology to other important unconventional reservoir formations in exploration and development. The semi-automated nature of the technology also ushers in the ability to consistently and accurately log mineralogy from multiple wells and fields globally, allowing for advanced comparative analysis.
Petroleum produced from low permeability shales is different to the dispersed in-situ fluids from which it is derived. Whereas in-situ fluids consist of hydrocarbons, resins and asphaltenes in proportions governed by organic matter type, maturity and retention behaviour, the produced fluids are highly enriched in hydrocarbons and low polarity non-hydrocarbons, and show an enhanced GOR. Here, we study the effects of fractionation during production from Permian and Cretaceous shales using laboratory experiments, PVT-modeling and a regional PVT database. Our goal was to develop methodologies for predicting yields and compositions of produced fluids ahead of drilling.
Target wells with known fluid properties were used for calibration. Shales from neighbouring wells of slightly lower maturity were mildly matured to that of the calibration well using MSSV pyrolysis, and a PhaseSnapShot of the resultant fluid made using PVTsim.
The first example, from the late oil window Eagle Ford, demonstrates that both kerogen and bitumen are important petroleum precursors, and that in-situ compositions are largely determined by the most recently generated charge, rather than by cumulative addition during maturation. The PVT model, calibrated to the engineering report of the target well and its environs, reveals that a high proportion of the in-place C7+ fluids remain in the rock matrix relative to gas during production. The second example, taken from a gas and condensate fairway in the Permian Basin, shows that the predicted bulk composition of recently generated petroleum is facies dependent. PVT fluid calibrations have low Psat and low cricondentherms. These characteristics are reproduced by experiment, but only for those zones containing low contents of high molecular weight liquids. Any contributions to produced fluids from other zones is associated with massive retention of high molecular weight organics. The third example concerns volatile oil production from wells in the Permian Basin. The MSSV products generated by adjacent lower maturity shales exhibited phase envelopes with higher cricondentherms than that of the calibration, this being attributable to a molecular weight difference in heavy components. Adjusting the MW from 249 (measured) to 222 (produced oil PVT value) in the PVTsim model aligned the cricondentherms. This tuning step corresponds to the preferential retention of heavy polar compounds in the rock matrix during production. In a second step, 20% of the tuned MSSV-generated liquids are considered to be retained in the rock, thereby raising Psat. The result is an excellent match between the doubly tuned predicted phase envelope and that of the produced fluid. The preferential retention of polar compounds is also in line with this tuning step.
In summary, fractionation is part and parcel of production from shales. Up to 80% liquids retention relative to gas has been demonstrated. Production efficiency assessments are readily inferred from these data.
The extent to which fractionation occurs varies a lot, and has here been assessed by combining experimental rock geochemistry with PVT modeling (PhaseSnapShots), and using PVT reports on produced fluids for calibration.
Recent studies have indicated that Huff-n-Puff (HNP) gas injection has the potential to recover an additional 30-70% oil from multi-fractured horizontal wells in shale reservoirs. Nonetheless, this technique is very sensitive to production constraints and is impacted by uncertainty related to measurement quality (particularly frequency and resolution), and lack of constraining data. In this paper, a Bayesian workflow is provided to optimize the HNP process under uncertainty using a Duvernay shale well as an example.
Compositional simulations are conducted which incorporate a tuned PVT model and a set of measured cyclic injection/compaction pressure-sensitive permeability data. Markov chain Monte Carlo (McMC) is used to estimate the posterior distributions of the model uncertain variables by matching the primary production data. The McMC process is accelerated by employing an accurate proxy model (kriging) which is updated using a highly adaptive sampling algorithm. Gaussian Processes are then used to optimize the HNP control variables by maximizing the lower confidence interval (μ-σ) of cumulative oil production (after 10 years) across a fixed ensemble of uncertain variables sampled from posterior distributions.
The uncertain variable space includes several parameters representing reservoir and fracture properties. The posterior distributions for some parameters, such as primary fracture permeability and effective half-length, are narrower, while wider distributions are obtained for other parameters. The results indicate that the impact of uncertain variables on HNP performance is nonlinear. Some uncertain variables (such as molecular diffusion) that do not show strong sensitivity during the primary production strongly impact gas injection HNP performance. The results of optimization under uncertainty confirm that the lower confidence interval of cumulative oil production can be maximized by an injection time of around 1.5 months, a production time of around 2.5 months, and very short soaking times. In addition, a maximum injection rate and a flowing bottomhole pressure around the bubble point are required to ensure maximum incremental recovery. Analysis of the objective function surface highlights some other sets of production constraints with competitive results. Finally, the optimal set of production constraints, in combination with an ensemble of uncertain variables, results in a median HNP cumulative oil production that is 30% greater than that for primary production.
The application of a Bayesian framework for optimizing the HNP performance in a real shale reservoir is introduced for the first time. This work provides practical guidelines for the efficient application of advanced machine learning techniques for optimization under uncertainty, resulting in better decision making.
Hamdi, H. (University of Calgary) | Clarkson, C. R. (University of Calgary) | Ghanizadeh, A. (University of Calgary) | Ghaderi, S. M. (University of Calgary) | Vahedian, A. (University of Calgary) | Riazi, N. (University of Calgary) | Esmail, A. (Encana Corporation)
Hydraulic fracturing in tight and shale reservoirs is a revolutionary technology enabling economically-viable production. Nevertheless, oil recovery factors achieved from primary production are still very low, typically 5-10% of original oil in place (OOIP). Recent laboratory and certain pilot results have demonstrated the technical success of enhanced oil recovery (EOR) techniques to increase oil recovery from unconventional reservoirs. In this paper, the potential of cyclic gas injection (i.e. huff-n-puff; HNP) in the Duvernay shale in Alberta, Canada is evaluated.
A compositional numerical model was used to simulate the multi-contact extraction HNP process using lean and rich gas injection. A fluid model was constructed using collected fluid samples, and was tuned to several laboratory experiments. Pressure-dependent permeability (PDP) data, used to constrain the simulation, were compiled from a series of laboratory experiments. From the laboratory experiments, the impact of confining stress, during loading and unloading cycles, on the permeability of intact and artificially-fractured (propped and unpropped) core plug samples was quantified. The fluid model, laboratory measurements, and additional petrophysical data, were used as input to the simulation model which was calibrated (history-matched) against historical production data (primary recovery). The calibrated model was subsequently used to optimize the operational conditions for HNP.
To assess the value of the measured PDP data, a history-matching trial, with PDP curves allowed to be a free-floating (adjustable) parameter, was performed. Importantly, the PDP curves providing the best history-match closely resembled the experimentally-measured depletion PDP curves. This step provided important validation of the laboratory-derived data, and the confidence to use PDP curves generated for the injection case.
Optimized HNP simulation results, obtained using the calibrated numerical model, indicate that a 1.5-2 times increase in recovery can be obtained in a 20-year time span. The highest recoveries for the studied well are the result of higher injection rates, shorter injection, soaking, and production times, and higher flowing pressures during the production cycle.
This study provides a comprehensive workflow with practical guidelines for integrating laboratory measurements and field observations for the successful calibration of a reservoir model used to history-match a Duvernay shale well. The calibrated model was employed to investigate the feasibility of HNP operations in the Duvernay shale, with a variety of injection fluids. The history-matching and HNP optimization processes were conducted using novel algorithms to minimize the number of simulation runs and achieve a balance between computation time and the quality of the history-match.
Ghanizadeh, A. (University of Calgary) | Clarkson, C. R. (University of Calgary) | Song, C. (University of Calgary) | Vahedian, A. (University of Calgary) | DeBuhr, C. (University of Calgary) | Deglint, H. J. (University of Calgary) | Wood, J. M. (Encana Corporation)
Quantification of absolute permeability to liquid hydrocarbons is critical for the evaluation of production potential of tight oil and liquid-rich gas reservoirs. However, due in part to the nanometer-sized pore throats in these low-permeability (tight) unconventional reservoirs, laboratory-based characterization of oil permeability is particularly challenging. Focusing on the Montney and Bakken formations in western Canada, the primary objectives of this work are therefore to 1) compare absolute (formation oil) and slip-corrected gas (N2) permeability values for selected core plug samples under similar experimental conditions, 2) compare steady-state and non-steady-state (i.e. pulse-decay) flow techniques for measuring absolute (oil) permeability and 3) examine controls (e.g. effective stress, porosity) on liquid hydrocarbon permeability in these tight rock samples.
Using a customized liquid permeameter designed and built in-house, permeability measurements are conducted with formation oil on selected intact core plugs from the Montney and Bakken formations using steady-state and pulse-decay flow techniques at varying stress conditions. The experiments are performed on the same core plugs used previously for pulse-decay gas (N2) permeability tests at similar experimental conditions - therefore, the impact of heterogeneity on liquid/gas permeability comparisons is mitigated. For the core plugs analyzed in this study, the absolute (oil) permeability values range between 2.610−4 and 3.510−2 md, depending on the lithology/formation (Bakken, Montney), methodology (steady-state, pulse-decay), effective stress (500-2300 psi) and mean pore pressure (283-815 psi) conditions. Experimental observations suggest that 1) absolute (oil) permeability values are consistently (up to 20%) lower than the slip-corrected gas (N2) permeability values measured under similar experimental conditions, 2) for one of the analyzed core plugs, the oil permeability value measured using the steady-state technique is approximately 30% larger than that measured using the pulse-decay technique, 3) the measured oil permeability values increase consistently with increasing helium porosity (5.5-13.1 %), and 4) oil permeability values decrease up to 30% with increasing effective stress (500-2300 psi). The observed discrepancies between permeability values obtained from steady-state and pulse-decay techniques can be attributed to 1) non-uniform propagation of pressure gradients and stress regimes inherent to steady-state and pulse-decay permeability methods and 2) experimental/numerical errors associated with permeability determination.
Absolute permeability, while an important control on oil/condensate flow in tight oil reservoirs, is difficult and timeconsuming to measure for low-permeability rocks in the laboratory. As a result, liquid hydrocarbon permeability data are not commonly reported in the literature - for unconventional reservoirs, these data have been primarily measured for comparatively high-permeability rocks (permeabilities within the millidarcy range). Through measurement of absolute (formation oil) permeability values on selected tight rock samples with varying lithology and porosity, the current study provides critical data and insights of importance to the evaluation of primary and enhanced oil potential in western Canadian tight reservoirs with permeabilities down to the nanodarcy range.
Ghanizadeh, A. (University of Calgary) | Clarkson, C. R. (University of Calgary) | Clarke, K. M. (University of Calgary) | Yang, Z. (University of Calgary) | Rashidi, B. (University of Calgary) | Vahedian, A. (University of Calgary) | Song, C. (University of Calgary) | DeBuhr, C. (University of Calgary) | Haghshenas, B. (University of Calgary) | Ardakani, O. H. (Geological Survey of Canada) | Sanei, H. (Aarhus University) | Royer, D. P. (Encana Corporation)
Hydrocarbon storage capacity of organic-rich shales depends upon porosity and surface area, whereas pore (throat) size distribution and pore (throat) network connectivity control permeability. The pores within organic matter (OM) of organic-rich shales develop during thermal maturation as different hydrocarbon phases are generated and expelled from the OM. Organic-rich shales can potentially retain a large proportion of the hydrocarbons generated during the diagenesis process. Commercial hydrocarbon production from liquid-rich shale reservoirs can be achieved using completion technologies such as multi-stage-fractured horizontal wells (MFHWs). However, the ability of industry to identify "sweet spots" along MFHWs is still hampered by insufficient understanding of the effect of type/content of entrained hydrocarbon/OM components on reservoir quality. The primary objective of the current study is therefore to investigate the impact of entrained hydrocarbon/OM on storage and transport properties of the organic-rich shales.
To accomplish this goal, a comprehensive suite of petrophysical analyses are performed on a diverse sample suite from the Duvernay Formation (a prolific Canadian shale oil reservoir) differing in organic matter content (2.8-5 wt.%; n = 5), before and after sequential pyrolysis by a revised Rock-Eval analysis (extended slow heating (ESH) Rock-Eval analysis;
Compared to the "as-received" state, porosity, permeability, modal pore size distribution and surface area increase with sequential pyrolysis stages, associated with expulsion and devolatilization of free light oil and fluid-like hydrocarbon residue (S2a; up to 380 °C). However, the change in petrophysical properties associated with the degradation of solid bitumen/residual carbon (S2b; up to 650 °C) is variable and unpredictable. The observed reduction in porosity/permeability values after the S2b stage are likely attributed to 1) occlusion of pore volume with solid bitumen/residual carbon degradation (i.e. coking) and/or 2) sample swelling due to water loss from lattice structure of clay minerals (i.e. illite) and 3) sample compaction as a result of OM removal from the rock matrix.
The present study is a continuation of previous works (