Sazali, Wan Muhammad Luqman (Petronas Research Sdn. Bhd.) | Md Shah, Sahriza Salwani (Petronas Research Sdn. Bhd.) | Kashim, M. Zuhaili (Petronas Research Sdn. Bhd.) | Kantaatmadja, Budi Priyatna (Petronas Research Sdn. Bhd.) | Knuefing, Lydia (Australian National University) | Young, Benjamin (Thermo Fisher Scientific)
PETRONAS is interested in monetizing X Field, a high CO2 carbonate gas field located in East Malaysian waters. Because of its location (more than 200 km from shore) and the preferable geological formation of the field, reinjection of produced CO2 back into the field's aquifer has been considered as part of the field development plan. To ensure feasibility, the PETRONAS R&D team has conducted a set of laboratory analyses to observe the impact of CO2 on the carbonate formations, through combining the use of static CO2 batch reaction experiments with advanced helical digital core analysis techniques. The analysis of two representative samples, from the aquifer zone is presented here. The initial state of the samples was determined through the use of theoretically exact helical micro computed tomography (microCT) techniques. The images were processed digitally to determine the porosity and calibrated with RCA to ensure the reliability of digital core analysis results. After scanning, both plugs were saturated with synthetic brine with similar composition as the fields' formation brine and aged with supercritical CO2 at reservoir temperature and pressure for 45 days. After 45 days, the aged core plugs underwent post reaction analysis using micro-CT scan and image processing software. Based on macroscopic observation, the core plugs showed no changes after aging with supercritical CO2 at high pressure and high temperature (HPHT) as per reservoir condition. However, analysing the high resolution micro CT images, the team was able to determine the changes in porosity before and after CO2 aging, which are around 1%.
Sazali, Wan Muhammad Luqman (PETRONAS) | Md Shah, Sahriza Salwani (PETRONAS) | Kashim, M Zuhaili (PETRONAS) | Kantaatmadja, Budi Priyatna (PETRONAS) | Knuefing, Lydia (Australian National University) | Young, Benjamin (Thermo Fisher Scientific) | Goodwin, Carley (Ohio State University)
There are a number of additional challenges in the development of high CO2 content gas fields. To meet the requirements of the Kyoto Protocol and Paris Agreement, an efficient means to deal with the produced CO2 such as re-injection into the reservoir for sequestration is required. With the intention of developing such high CO2 gas fields, PETRONAS has identified a trial candidate (X field) offshore Sarawak Malaysia, which is a carbonate gas field with 70% CO2 content and good potential to re-inject the produced CO2 into the field's aquifer zone. To study the feasibility of CO2 reinjection, PETRONAS R&D team are studying the effects of re-injected CO2 on the mineralogical and petrophysical properties of the reservoir and decided to incorporate Digital Core Analysis (DCA) into the case study. Although porosity determination and other petrophysical property characterisation using micro-CT images has been widely used for a number of years, there is still discussion about its accuracy and reliability. Based on previous internal studies, porosity determination via digital core analysis can be limited by the quality and resolution of micro-CT images collected and thus the capability of the image analysis software. This case study investigates accuracy and reliability of the use of contrast enhanced imaging practices and the use of the helical micro CT for porosity determination via Digital Core Analysis (DCA). PETRONAS adopted and optimized a contrast enhanced imaging methodology for use on 1-inch core plugs during scanning via a helical micro-CT and applied this as a case study to X field with the help of a technology partner to evaluated digital core analysis. In the same year, a commercially available image analysis software was launched, with such a DCA workflow in mind. Using this optimized methodology and the newly launched imaging software, the porosity values from DCA of the 1-inch core plugs show good correlation to the values from Routine Core Analysis (RCA) done on the same samples, with less than 1.5 porosity unit difference. In this case study, PETRONAS managed to compare the porosity obtained from DCA directly with porosity measured by RCA. This methodology will be used for porosity determination for wells or other regions of interest where limited samples or different sample sizes are not suitable for RCA.
Zhang, Yulai (University of New South Wales) | Mostaghimi, Peyman (University of New South Wales) | Fogdon, Andrew (FEI) | Arena, Alessio (FEI) | Sheppard, Adrian (Australian National University) | Middleton, Jill (Australian National University) | Armstrong, Ryan T. (University of New South Wales)
Molecular diffusion is an important mass transport mechanism for gas production from shale reservoirs. Characterization of matrix diffusivity is fundamental to understand the recovery from shale gas plays. By micro-computed tomography (micro-CT) imaging of X-ray dense and transparent liquids mixing in a saturated shale sample, 4D dynamic and spatially-resolved monitoring of diffusion experiments has been successfully achieved. This work extends the previously presented method by applying a new mathematical procedure to measure the local, directional Fickian diffusion coefficients matching the observed concentration fields. Small centimeter-sized vertically-cored plugs of shales from the Eagle Ford formation and Permian Basin are imaged over the course of diffusion experiments. The time lapse step and overall duration are designed to minimize artifacts and uncertainties in the local diffusive flux and concentration gradient obtained from image analysis. For the Eagle Ford sample, local diffusion coefficients of the horizontal direction are in the range of 10-14-10-12 m2/s, with an average of 8.4×10-13 m2/s; while for the vertical direction, they are in the range of 10-15-10-13 m2/s, with an average of 2.2×10-14 m2/s. The diffusion process is heavily influenced by fractures. For the Permian Basin sample, the diffusion is dominated by the matrix due to fewer fractures. The horizontal direction local diffusion coefficients are in the range of 10-14-10-12 m2/s, with an average of 3.2×10-13 m2/s. For the vertical direction, they are in the range of 10-15-10-13 m2/s, with an average of 4×10-14 m2/s. Both of the samples exhibit an intermediate level of heterogeneity in terms of the measured Dykstra-Parsons coefficients. The matrix diffusion coefficients are extremely anisotropic with up to 3 orders of magnitude change from parallel to perpendicular to bedding. Combined dynamic micro-CT imaging and local directional diffusion coefficient measurements is a powerful tool to characterize mass transport in shales and provides a benchmark for comparison to flow simulations on static images. New understandings on mass transport properties will be helpful for prediction and optimization of shale gas production.
Sommacal, Silvano (FEI Oil and Gas) | Fogden, Andrew (FEI Oil and Gas) | Young, Benjamin (FEI Oil and Gas) | Noel, William (FEI Oil and Gas) | Arena, Alessio (FEI Oil and Gas) | Salazar, Leonardo (FEI Oil and Gas) | Gerwig, Tobias (FEI Oil and Gas) | Cheng, Qianhao (Australian National University) | Kingston, Andrew (Australian National University) | Marchal, Denis (Petrobras Argentina S.A.) | Perez Mazas, Ana Maria (Petrobras Argentina S.A.) | Naides, Claudio Hugo (Petrobras Argentina S.A.) | Kohler, Guillermina (Petrobras Argentina S.A.) | Cagnolatti, Marcelo (Petrobras Argentina S.A.)
Current understanding of hydrocarbon storage and flow in the matrix and fractures of shales is insufficient to predict recovery. Multiscale imaging of shale pore networks is foundational to multiscale modeling of transport for comparison to experimental measurements. The current study illustrates a workflow for integrated 3D imaging, analysis and property prediction using shale subsamples from the Vaca Muerta formation, Neuquén Basin, Argentina.
From a sample piece rich in organic matter (OM), three small horizontal plugs of 4 or 5 mm diameter were cored. Each of these sister plugs was micro-CT scanned in a sequence of prepared states, after which the tomograms were spatially registered into alignment. In particular, the plugs were scanned after solvent cleaning and drying, followed by a second scan after full saturation of their connected pore space with the X-ray dense liquid diiodomethane (CH2I2). The tomogram difference yielded a 3D volumetric map of total effective porosity at each voxel, despite the fact that the vast majority of pores lie below tomogram resolution. Each plug was then exposed to free iodine (I2), which stains OM to selectively increase its X-ray attenuation. The third scan in this iodine-stained state thus provided a registered 3D volumetric map of the OM distribution. Following these non-destructive steps, the plugs were sectioned and ion milled for high resolution BSEM imaging and SEM-EDS mineral mapping. These 2D mosaic images were registered into their corresponding cross-section through the plug tomograms.
To supplement this workflow, one of the plugs was first imaged in its uncleaned state in which the in-place oil was selectively X-ray contrasted to reveal its plug-scale 3D distribution, prior to cleaning. Another of the plugs, after micro-CT scanning of its CH2I2-saturated state, was drained in air by centrifugation and re-scanned, to yield the distribution of drained pores down to throat sizes of 20 nm. These analyses showed that the larger throats were most frequently hosted by OM, in the form of expulsion cracks, and that the majority of the oil resided in the OM.
Fogden, Andrew (FEI Oil &Gas) | Arena, Alessio (FEI Oil & Gas) | Zhang, Christopher (FEI Oil &Gas) | Carnerup, Anna (FEI Oil & Gas) | Goergen, Eric (FEI Oil& Gas) | Olson, Terri (FEI Oil & Gas) | Cheng, Qianhao (Australian National University) | Middleton, Jill (Australian National University) | Kingston, Andrew (Australian National University) | Zhang, Yulai (University of New South Wales) | Armstrong, Ryan (University of New South Wales)
Optimization of production from shale reservoirs requires understanding of rock properties over a range of scales. Multiple imaging techniques can be combined to determine the nature, connectivity, and wettability of nano-scale pore systems as well as the underlying mineralogy and organic textures that control reservoir behavior and the propensity of the matrix to fail and to contain expulsion cracks. The current study demonstrates new capabilities in integrated multiscale and time-resolved imaging and analysis workflows for three organic-rich shale samples from two formations.
The spatial distributions of connected porosity, organic matter, and microfractures within vertical sub-plugs were quantified from micro-CT imaging, using X-ray contrast enhancement strategies to detect their volume contributions from sub-resolution features, together with tomogram alignment and segmentation. These registered 3D volume distributions comprising billions of voxels showed that most of the porosity in these three samples was hosted by organic matter and most of the coring-induced fractures ran through laminations of locally higher organic content. Dynamic micro-CT imaging was also performed to directly visualize the progress of liquid-liquid diffusion through the pore space. The imaged concentration profiles were fitted to models to estimate the average in-plane diffusivity coefficient.
This tomographic analysis was validated and complemented by automated high-resolution 2D back-scattered SEM (BSEM) and SEM-EDS imaging and mapping of pores, organic matter and mineralogy over ion-milled sub-plug sections, and registration of these image mosaics into the corresponding tomogram cross-section. In this way, information on the fine scale of individual features could be combined with statistics over the more representative tomogram volumes. The distribution of organic matter was characterized from this 2D BSEM together with 3D FIBSEM imaging. The majority of organic-hosted connected pores detected by contrast-enhanced micro-CT lay below BSEM and FIBSEM resolution. Secondary electron SEM images (using FESEM) of raw broken surfaces revealed the relatively homogeneous texture of the sub-10 nm pore network permeating the fused aggregates of bitumen nano-granules. Further, the same contrast technique used to highlight bitumen in the tomograms was also applied to ion-milled sections to extend the automated BSEM imaging coupled with SEM-EDS mapping to distinguish bitumen from kerogen at high resolution.
Fogden, Andrew (Australian National University) | Latham, Shane (Australian National University) | McKay, Thomas (Australian National University) | Marathe, Rohini (Australian National University) | Turner, Michael (Australian National University) | Kingston, Andrew (Australian National University) | Senden, Tim (Australian National University)
The utility of high-resolution micro-CT for characterising the structure of unconventionals on length scales from millimetres down to microns was advanced by implementation of a sample preparation and scanning workflow to selectively increase the X-ray attenuation of pores or organic matter (OM) and thus enhance their contrast and resolution in tomographic images. Subsamples (of 2-3 mm diameter) of a siliceous and a calcareous shale, both organic-rich, were scanned in the following four states: 1) initial, 2) infiltrated with diiodomethane, 3) post-dry, and 4) stained with iodine. All four tomograms were spatially registered to align perfectly, from which their differences highlighted either the pore space (with diiodomethane) or the OM (with iodine). These 3D digitised maps provided unprecedented insight into the forms of the resolvable pore and OM features and their distribution in relation to the background of sub-resolution porosity and OM. Segmentation of the pore and OM phases yielded total contents in reasonable quantitative agreement with helium porosity and TOC measurements on neighbouring material. Further statistical methods were applied to quantify the co-location of porosity and OM within the tomograms, as a basis for classifying their main feature types and the frequency of their occurrence.
Solling, Theis (Maersk Oil) | Marquez, Xiomara (Maersk Oil Qatar AS) | Finlay, Sharon Jane (Maersk Oil Qatar AS) | Bounoua, Noureddine (Qatar Petroleum) | Gagigi, Tarek (Qatar Petroleum) | McKay, Thomas (Australian National University) | Fogden, Andrew (Australian National University)
Carbonate reservoir rocks often possess highly complex pore spaces, exhibiting extreme heterogeneity in the size, shape and connectivity of their pores at multiple scales. These variable features strongly impact oil recovery and pose severe challenges to reliable measurement and simulation of flow properties. As a complement to parallel studies of the plugs by conventional petrographic and core analysis techniques, a set of samples from four wells in the Shuaiba reservoir of the Al Shaheen field was analysed by 2D mineral mapping (from QEMSCAN) of polished plug sections, and by 3D tomographic mapping (from micro-CT) of subsampled mini-plugs, as a complement to parallel studies of the plugs by conventional petrographic and core analysis techniques. QEMSCAN showed a high variability in measured porosity and pyrite content over all sampled length scales, from millimetres (across the polished plug faces) to feet (with depth in a given well) to kilometres (across the four wells). The porosity from QEMSCAN was generally found to be in good agreement with that measured on the conventional plugs. Two mini-plugs of 5 mm diameter were scanned using helical micro-CT, one of which was subsequently analysed to segment the macropores, microporosity, calcite and pyrite. Comparison with the QEMSCAN results from the section of the "parent?? plug showed consistency in estimated porosity and pyrite content between the two methods. Simulations of conductivity and absolute permeability were performed on subvolumes of the segmented tomogram, and displayed a strong variability with the location and size of the chosen subvolume, although the overall trends remained in good agreement with core analysis.
Over the past decade, the rapid developments in X-ray computed tomography (CT), micro-tomography (micro-CT) and sophisticated algorithms for processing tomographic datasets and performing modelling and simulation on them have given rise to the disciplines of digital core analysis and computational rock physics (Knackstedt et al. 2009; Dvorkin et al. 2011). Their aim is to acquire a sufficiently detailed 3D description of a rock sample, spanning the relevant length scales (Sok et al. 2010), to calculate its bulk, elastic or fluid and electrical transport properties. Such analyses give enhanced insight into how the chain of molecular-, pore- and plug-scale characteristics and responses give rise to the core-scale properties measured in laboratories. They may also represent the only alternative for samples on which physical core analysis is unreliable or infeasible. Most pertinently, digital core analysis of multi-phase flow (Oren and Bakke 2003) offers the promise of improved power to predict the recovery of hydrocarbon resources. This approach is especially promising for carbonate reservoir rocks, which often exhibit extreme heterogeneity in the size, shape and connectivity of their pores. Carbonate waterflooding can be strongly impacted by pore types as disparate and intermixed as microporosity, vugs and fractures, for which our vocabulary of geological/petrophysical classifications (Dunham 1962; Choquette and Pray 1970; Lucia 1995) is an insufficient basis for prediction of completeness or rates of oil recovery (Kamath et al. 2001; Graue and Bogno 1999).
Dodd, Nicole (Australian National University) | Marathe, Rohini (Australian National University) | Middleton, Jill (Australian National University) | Fogden, Andrew (Australian National University) | Carnerup, Anna (Lithicon Pty Ltd) | Knackstedt, Mark (Lithicon Pty Ltd) | Mogensen, Kristian (Maersk Oil Research & Technology Centre) | Marquez, Xiomara (Maersk Oil Research & Technology Centre) | Frank, Soren (Maersk Oil Research & Technology Centre) | Bounoua, Noureddine (Qatar Petroleum) | Noman, Rashed (Qatar Petroleum)
3D pore-scale imaging and analysis provides an understanding of microscopic displacement processes and potentially a new set of predictive modeling tools for estimating multiphase flow properties of core material. Reconciliation and integration of the data derived from these models requires accurate characterization of the pore-scale distribution of fluids and a more detailed understanding of the role of wettability in oil recovery.
The current study reports experimental imaging progress in these endeavors for a preserved-state carbonate core from a Middle Eastern waterflooded reservoir. Micro-CT methods were used in combination with novel fluid X-ray contrasting techniques and image registration to visualize the 3D pore-scale distribution of residual oil in mini-plugs. Segmentation of the registered tomograms and their differences facilitated estimation of the residual oil saturation. These predictions from digital analysis agreed reasonably well with laboratory measurements of oil saturation from extraction of sister mini-plugs and spectrophotometry. The tomogram segmentations provide additional information beyond this average value, such as the fractions of oil associated with macroporosity and microporosity.
After the tomogram acquisitions, one of the dried mini-plugs was cut and SEM imaged at this exposed face to provide 2D images of fine features below the micro-CT resolution limit, such as the characteristic dimpled texture of asphaltene films on calcite surfaces due to their local wettability alteration in the reservoir. A new registration procedure was developed to embed the SEM images from the cut plug into the tomogram of the original uncut plug at their correct locations, so that this high-resolution wettability information could be integrated into the 3D pore network description and correlated to the local distribution of residual oil.
Although waterflooding has been used for decades to recover oil, the recovery mechanisms at the pore- and molecular-scales remain uncertain. Two poorly characterized and interrelated factors are thought to control multiphase flow in rocks. One is the pore-scale configuration of the fluids and their interfaces within the complex geometry and topology of the pore space. The other is the wettability, which is dictated by the crude oil/brine/rock interactions resulting from the molecular-scale surface chemistry (Salathiel 1973; Anderson 1986; Morrow 1990).
Developments in 3D imaging by X-ray computed micro-tomography (micro-CT) and image processing and analysis have been harnessed to visualize and quantify pore networks in rocks (Sheppard et al. 2005), and more recently to image their partial occupancy by two immiscible fluids. Wet-state imaging typically necessitates the doping of one of the two fluids to accentuate its X-ray attenuation, e.g., by dosing the oil with a heavy halogenated analog or the brine with a heavy salt. Such approaches have been used to map the pore-scale saturation in rocks prepared in a sequence of states (Seright et al. 2006), for which tomogram registration algorithms (Latham et al. 2008) are invaluable to monitor changes in individual pores (Kumar et al. 2009). Recent applications to flow (Blunt et al. 2012) and flooding (Wildenschild and Sheppard, 2013) have led to enhanced insight into pore-scale mechanisms and offer the opportunity to explain trends and uncertainties in laboratory measurements and to calibrate computational models of recovery.
The mechanical and transport properties of reservoir rocks depend on the morphology of microstructure, e.g. connectivity, size and shape of grains and of the pores. Such information can be gained from digital core analysis, which is increasingly used to understand the internal fabric of heterogeneous rocks or for the analysis of samples not amenable to standard laboratory analysis. At the same time, big advances are made on the imaging hardware side including the development of ultra-high resolution CCDs and recording techniques like helical scanning, leading to datasets of enormous dimensions and relatively large field of view. In this context it is highly desirable to develop automatic coarse scale classification methods to e.g. recognize the occurrence and spatial structure of digital rock types within such tomographic images - or existing morphological trends within a rock type, as this may lead to powerful characterization and data reduction techniques as well as upscaling methods.
We use regional Minkowski measures to define fine-sale rock types using a multi-variate Gaussian mixture model for classification. The discriminative power of the method is firstly demonstrated for an artificial sample which consists of a mixture of Poisson processes spatially separated using a Gaussian random field approach. Furthermore, we demonstrate how this method can be used to describe the fractions of two spatially overlapping non-stationary process generating a morphological trend - e.g. a fining up sequence. Finally, the method is applied to discriminate different morphological regimes of a thin- bedded sandstone. Importantly, for morphologies resulting from a Poisson process of grains, the classification result can directly be used to predict physical properties using effective grain shapes. For other processes such a relationship may be developed; in particular, using the classification result subsections of a tomogram can be selected for which such a relationship can be derived explicitly.
The microstructure of carbonate rocks experiences substantial changes under reactive processes, in particular chemical dissolution and deposition, including dissolution-released-fines migration occurring during acidizing. A better understanding of such changes at the pore scale and their influences on rock properties is of great value for the effective design and implementation of reactive processes in carbonate reservoirs. In this work, we demonstrate the use of X-ray microcomputed tomography (micro-CT) to quantitatively investigate the local porosity changes in a meso-/microporous carbonate core sample during chemical dissolution. A reactive flooding experiment in a core sample by a nonacidic solution is designed such that changes in pore space from before to after the reactant injection could be imaged in exactly the same locations with micro-CT at a resolution of less than 5 µm. A methodology with three-phase segmentation and 2D histograms of image intensity is used to quantify distributions of the evolution of each image voxel. This technique allows the incorporation of microporosity into the calculation of the evolution regions, including the migration of fines, to accurately quantify the evolution scenarios. The micro-CT images reveal a quasiuniform dissolution pattern and allow characterizing the accompanying migration of fines within the core sample. The 3D pore networks are derived from the image data, which quantify changes in network structure and the pore geometry. The 2D histograms of image intensity derived from the pre- and post dissolution images show quantitatively how macro- and micropores are enlarged by dissolution close to the inlet, whereas the deposition of fines mainly occurs in pores far from the inlet boundary. These results can explain why permeability of the sample initially decreases and then increases when injection time increases. Pore-surface area between each region is computed on the basis of the spatially resolved voxel evolution scenarios. This allows calculation of local distribution of reactive surface area, which, in turn, will assist in the prediction of local reaction rates in reactive flow simulators.