Tight Rocks Research Articles

Fractal Characterization of Nanoscale Pores of Volcanic Reservoirs in the Dongling Area, Changling Fault Depression, Songliao Basin

Fractal theory is an efficient method to characterize quantitatively tight rocks. Volcanic rocks are very promising reservoirs, and their pore structures have considerable influence on the occurrence and percolation mechanisms of oil and gas. Therefore, the research topics of pore structure and fractal characteristics are important for sustainable volcanic resource development. The pore structure and fractal characteristics of microscopic pores of volcanic reservoirs in the Changling Fault Depression, Songliao Basin, were studied by combining fractal theory with mercury intrusion porosimetry and low-temperature nitrogen adsorption technique. After quantitative characterization of the nanoscale pore size distribution (PSD), four fractal dimensions were calculated. Subsequently, the relationships between fractal dimensions and pore structure parameters were evaluated. Three types of PSD models of volcanic reservoirs in the study area were established. The relationships between fractal dimensions and PSD models, as well as the clustering characteristics of the fractal dimensions, were investigated. The study revealed that the volcanic reservoirs developed a certain proportion of nanoscale pores with morphological characteristics dominated by wedge-shaped pores and slit pores. D4 is relatively strongly negatively correlated with pore size, illustrating that it can better reflect pore structure compared to the other fractal dimensions. Additionally, D4 can reflect pore surface roughness. This study shows that D1 and D2 can distinguish PSD models well, but D3 and D4 are more effective for the identification of the Type II PSD model. The fractal dimensions were divided into four clusters via hierarchical cluster analysis, each corresponding well to a certain PSD model or PSD model combination.

A pore geometry-based permeability model for tight rocks and new sight of impact of stress on permeability

The prediction of rock permeability is important in the extraction of oil/gas from tight reservoirs. Permeability is determined by connected pores and their distribution in rocks. The existence of pore can induce stress concentration around pore surface which affects pore strains. In common permeability models, volumetric pore strains are used to quantify the permeability evolution during gas production but pore strain solutions exclude the impact of stress concentration. In this study, the stress concentration around pore surface was considered and corresponding pore surface displacements were calculated. Different from solutions of volumetric pore strain, solutions of stress concentration and pore surface displacement have close relationship with pore geometry. Based on SEM images of tight rocks, the pore shape was assumed as ellipse. An analytical solution for the surface displacement of an ellipse pore was derived and substituted into the permeability definition. Different from common permeability models, this novel permeability model includes pore geometry property. This geometry-based permeability model was verified by experimental data. The comparison between the common model and this geometry-based model was also conducted. The sensitivity study was conducted to investigate impacts of pore geometry and stress variation on permeability evolution. It was illustrated that this geometry-based model is valid and its performance of permeability prediction for tight rocks is better than that of common model. This is because the important factors, such as pore geometry size and stress orientation, are incorporated explicitly. The advantage of this geometry-based model is that the impact of stress orientation (α) on permeability is involved so this geometry-based model is able to predict permeability of reservoirs after hydraulic fracturing where the stress orientation commonly changes.

Experimental and modelling approach to investigate the mechanisms of formation damage due to calcium carbonate precipitation in carbonate reservoirs

Calcium carbonate (CaCO3) precipitation, due to incompatibility between the injected water (IW) and formation water (FW), is known to be a major operational obstacle during water flooding projects. In this study, initially by using OLI Scale Chem and ScaleSoftPitzer software and static beaker tests, the potentiality of CaCO3 scaling was determined from the given ionic content of incompatible synthetic brines, under different conditions (temperature, pressure, and volume mixing ratio of incompatible brines). The results showed that the maximum amount of CaCO3 salt was formed at a volume mixing ratio of 0.8:0.2 (IW:FW). The simulation results showed that OLI software is more reliable than the ScaleSoftPitzer. In the second stage of this work, the 0.8:0.2 proportion of IW:FW was selected to examine the mechanisms under which the maximum formation damage of the tight carbonate cores occurred through the water injection experiments. In addition, the turbidity of the bulk solution was measured to confirm the core flooding outcomes. Various hydrodynamic parameters (low flow rate, scaling tendency, and the temperature) were evaluated in these experiments. Bulk induction time (tind) and scaling period (ts) were determined from the setup. Either heterogeneous nucleation (i.e. crystallization processes), or both heterogeneous nucleation and adhesion of pre-deposited crystals from the mixed incompatible brines to the pore wall of the cores, were attributed as the principal mechanisms of the formation damage of tight carbonate rocks owing to CaCO3 salt formation. Moreover, a semi-empirical model was established from this laboratory study, which predicts the scaling period (ts) as a function of interfacial energy, temperature, and scaling tendencies.

High-spatial-resolution nuclear-magnetic-resonance method for investigation of fluid distribution in whole cores

Low field Nuclear Magnetic Resonance (NMR) has been widely used in laboratories to investigate hydrocarbon and water in small core plugs to provide accurate petrophysical measurements and for calibration of downhole NMR logs. One fundamental limiting factor of current NMR technologies on large whole core is that the spatial resolution is limited by the length of the radio-frequency (r.f.) detection coil. In addition, the end effects of finite coil length can compromise the accuracy of NMR measurement when the core is longer than the coil. Herein a method is developed to overcome these problems to acquire high-spatial-resolution (HSR-) NMR data of the fluid in the long rock samples. The method is implemented by first conducting a series of NMR measurements in synchronization with a stepwise movement of the long sample through the NMR r.f. coil with the step increment equal to the desired spatial resolution. It then inverts the acquired data to obtain HSR-NMR results using a robust inversion algorithm. This new method provides a non-destructive measurement of fluid content with any desired spatial resolution and is especially useful for tight rock samples with short NMR relaxation times. The method is tested on 23 preserved whole cores from a source rock reservoir. The measured fluid distribution from the HSR-NMR method matches well with the fluid content from GRI method on the same sections of the preserved cores. In addition, the measured fluid distribution correlates well with the kerogen content along the cores with obvious lamination in the samples.

Modeling Near-Miscible Gas Foam Injection in Fractured Tight Rocks and Its Challenges

Unlocking oil from tight reservoirs remains a challenging task, as the existence of fractures and oil-wet rock surfaces tends to make the recovery uneconomic. Injecting a gas in the form of a foam is considered a feasible technique in such reservoirs for providing conformance control and reducing gas-oil interfacial tension (IFT) that allows the injected fluids to enter the rock matrix. This paper presents a modeling strategy that aims to understand the behavior of near-miscible foam injection and to find the optimal strategy to oil recovery depending on the reservoir pressure and gas availability. Corefloods with foam injection following gas injection into a fractured rock were simulated and history matched using a compositional commercial simulator. The simulation results agreed with the experimental data with respect to both oil recovery and pressure gradient during both injection schedules. Additional simulations were carried out by increasing the foam strength and changing the injected gas composition. It was found that increasing foam strength or the proportion of ethane could boost oil production rate significantly. When injected gas gets miscible or near miscible, the foam model would face serious challenges, as gas and oil phases could not be distinguished by the simulator, while they have essentially different effects on the presence and strength of foam in terms of modeling. We provide in-depth thoughts and discussions on potential ways to improve current foam models to account for miscible and near-miscible conditions.

Nonlinear Acoustics Applications for Near-Wellbore Formation Evaluation

We present experimental and modeling results and a downhole logging tool concept resulting from a research collaboration between Chevron Energy Technology Company and Los Alamos National Laboratory investigating using nonlinear acoustics applications for natural fracture characterization and assessing near-wellbore mechanical integrity or drilling-induced damage. The generation of a scattered wave by noncollinear mixing of two acoustic plane waves in an acoustically nonlinear medium was first documented several decades ago. If the frequency ratio and convergence angle of the two waves and the compressional-to-shear velocity ratio of the medium where they intersect meet certain conditions, their interaction creates a scattered third wave, propagating in a predictable direction, with a frequency equal to the sum or difference between the two primary wave frequencies and an amplitude dependent on the nonlinearity at the intersection location. The conditions resulting in this scattering and the properties of the scattered wave are thus governed by the physics of the interaction, resulting in a set of “selection rules” that are the key to the measurement principle introduced here. If the two transmitted plane waves are oriented such that the third wave returns to the borehole, the phenomenon may be used as the basis for a logging tool measuring acoustic nonlinearity around the wellbore circumference, with a secondary measurement of the compressional-to-shear velocity ratio. Laboratory measurements supported by finite-difference and analytical modeling confirmed that the mixing of two plane compressional waves generated a shear wave as predicted by the selection rules in a large Berea sandstone block, confirming the potential for a downhole tool with a depth of investigation in the range 15 to 20 cm. Historical data show that nonlinearity in core samples is primarily caused by a lack of mechanical integrity. In the oil field, this may be microfractures in tight rock unconventional reservoirs or incipient near-wellbore failure while drilling. This prompts applications to fracture characterization and calibration of mechanical earth models. The main practical challenge for a downhole logging tool is injecting powerful directional acoustic energy into the formation. We envisage an openhole tool making sequential station measurements using transmitters built into hydraulically controlled pads contacting the borehole wall. Noncollinear mixing may be activated by maintaining the frequency of one transmitter constant while sweeping the other through the range of frequency ratios predicted by the selection rules, resulting in a received sum or difference frequency signal that rises to a peak and then falls. Alternatively, the frequency ratio may be maintained while steering one of the acoustic beams. The peak signal amplitude indicates the coefficient of nonlinearity, which is sensitive to lack of mechanical integrity caused by natural fractures or mechanical disaggregation. The frequency ratio at which it occurs is an indicator of the shear-to-compressional velocity at the location where the two beams cross. In this manner, a record of nonlinearity along or around the borehole can be envisaged. The physics of acoustic nonlinearity is well established, and our laboratory measurements have determined that the phenomenon of interest should occur and be measurable in the subsurface. Overcoming the engineering challenges would bring new formation evaluation insights unique to this measurement principle.

Tectonostratigraphic evolution, palaeogeography and main petroleum plays of the Nuussuaq Basin: An outcrop analogue for the Cretaceous–Palaeogene rift basins offshore West Greenland

The onshore Nuussuaq Basin in central West Greenland comprises a complete Albian–Paleocene succession and as such represents the only complete rift succession outcrop analogue for the Cretaceous–Palaeogene offshore frontier basins in West Greenland. The basin fill reflects five tectonostratigraphic phases: 1) Pre-rift, 2) Albian – Early Cenomanian Early Rift, 3) Early Cenomanian – Early Campanian Thermal Subsidence, 4) Early Campanian – Early Paleocene Late Rift, and 5) Early Paleocene – Late Eocene Break-up and Drift. In addition, the succession is divided into nine tectonostratigraphic sequences (TSSs), each representing a specific configuration of depositional elements resulting mainly from tectonic events, which caused major palaeogeographic reconstruction of the basin and therefore critical to the petroleum systems. The sequences are bounded by unconformities or, in one case, by a major flooding phase. The Early Rift Phase in the Nuussuaq Basin was initiated in the Albian with development of half-grabens along N–S directed extensional faults. This phase was characterised by continued growth along extensional faults and embraces three TSSs (TSS1–3). They are characterised by alluvial fan, fan-delta and lacustrine sedimentation, wave- and tidal-dominated deltaic deposition, followed by a major fall in relative sea level and canyon incision. Oil seeps indicate presence of a lacustrine/brackish-water source rock at depth. During the following Late Cenomanian – Early Campanian Thermal Subsidence Phase a regional marine drowning of the basin took place with deposition of organic-rich mudstones, followed by re-establishment of deltaic deposition in the Coniacian–Santonian (TSS4). The Early Campanian – Early Paleocene Late Rift Phase was associated with a change in stress regime, formation of NW–SE directed extensional faults, uplift of highs and a major change in depositional environments from deltaic deposition to deposition from gravity flows in a confined system of slope channels and canyons. During the initial phase, structurally-controlled turbidite channels were established in a NW–SE trending graben-like structure that acted as conduits for sediment transport into the offshore areas (TSS5). This was followed by several phases of major uplift resulting from the rise of the Proto-Icelandic Mantle Plume prior to continental break-up eventually leading to the deposition of two structurally controlled TSSs (TSS6–7) characterised by the formation of submarine and subaerial canyons that acted as conduits for huge amounts of sediments transported into the offshore areas. The Nuussuaq Basin experienced significant subsidence during the initial phase of break-up volcanism with deposition of organic-rich Lower Paleocene marine mudstones blanketing the basin followed by a thick succession of Paleocene–Eocene volcanic rocks referred to as the West Greenland Basalt Province (TSS8–9). Volcanism gradually spread eastwards eventually blocking the connection to the sea stemming up a large lake between the prograding volcanic front and the cratonic mainland to the east. Finally, when the volcanic rocks covered the entire basin, rivers were redirected, and sediments were deposited in the offshore Sisimiut Basin to the south and the Melville Bay Basin to the north. During this latest rifting and break-up phase, the Nuussuaq Basin was aborted and terminated as a failed rift basin.Four main plays have been defined based on the tectonostratigraphic subdivision: An Early Rift Play, a Thermal Subsidence Play, a Late Rift Play and a Break-up and Drift Play. The Early Rift Play has alluvial and estuarine sandstones as reservoir, Albian lacustrine/brackish-water mudstones as source rock and Cenomanian–Turonian mudstones as seal. The Thermal Subsidence Play has deltaic and shallow marine sandstones as reservoirs, Cenomanian–Turonian mudstones as source and Campanian mudstones as seal. The Late Rift Play has incised valley, submarine canyon and turbidite sandstones as reservoirs, and Campanian and Paleocene mudstones as seal and source. The Break-up and Drift Play is subdivided into three sub-plays, including: a Lacustrine Sub-play, an Intra-basaltic Siliciclastic Sub-play and a Fractured Volcanic Sub-play. The Lacustrine Sub-play has fluvio-deltaic sandstones as reservoir and intra-formational lacustrine and delta-plain mudstones as seal. The Intra-basaltic Siliciclastic Sub-play comprise fluvial and lacustrine sandstones as reservoir and volcaniclastic or siliciclastic mudstones as seal. The Fractured Volcanic Sub-play comprises fractured, porous volcanic rocks as reservoir and intra-basaltic mudstones or tight fine-grained volcanic rocks as seal. All three sub-plays require vertical or long-distance migration of hydrocarbons from deeper-seated Cretaceous – Lower Paleocene kitchens. Because the tectonostratigraphic phases recognised in the Nuussuaq Basin can also be applied to the regional seismic mapping offshore Greenland the implications of the Nuussuaq Basin plays can be applied to the frontier offshore basins.

Rapid multiscale pore network modeling for drainage in tight sandstone

Tight sandstone possesses multiscale pores. Capturing and modeling the important pore properties into a pore network for drainage is challenging and computationally expensive. We present a method for modeling of a multiscale pore network, which enables us to handle huge rock micro computed tomography (μCT) images with high computational efficiency and minimal experimental input data. This method uses micro-links to represent the upscaled transport properties of micropores unresolved by the image and connects pore clusters that have topological relationships in the image to extract a connected pore network from it. The size distribution of micro-links is optimized and determined by experimental permeability. The effects of the number distribution of micro-links on flow properties are investigated to obtain the robust parameter. The presented method is validated on a digital core and the published experimental data. This method is successfully applied to rapidly evaluate the influence of mineral components on drainage behavior in two tight sandstone rocks, which involves a large number of computations. The two μCT images both contain more than 109 voxels and are handled by a personal computer, proving the potential in rapidly, accurately, and conveniently handling huge tight sandstone μCT image for evaluating the drainage characteristics.

Experimental Investigation of Gas Dynamic Effects Using Nanoporous Synthetic Materials as Tight Rock Analogues

To improve the understanding of gas transport processes in tight rocks (e.g., shales), systematic flow tests with different gases were conducted on artificial micro- to nanoporous analogue materials. Due to the rigidity of these systems, fluid-dynamic effects could be studied at elevated pressures without interference of poro-elastic effects. Flow tests with narrow capillaries did not reveal any viscosity anomaly in a confined space down to capillary diameters of 2 µm. Experiments with nanoporous ceramic disks (> 99% Al2O3) conducted at confining pressures from 10 to 50 MPa did not indicate any stress dependence of permeability coefficients. Analysis of the apparent permeability coefficients over a mean gas pressure range from 0.2 to 30.5 MPa showed essentially linear Klinkenberg trends with no indication of second-order slip flow. The Klinkenberg-corrected permeability coefficients measured with helium were consistently higher than those measured with all other gases under the same conditions. This “helium anomaly” was, however, less pronounced than the same effect observed in natural rocks, indicating that it is probably not related to fluid-dynamic effects but rather to gas–solid interactions (e.g., sorption). Permeability tests with CO2 on the nanoporous membrane show significant deviations from the linear Klinkenberg trend around the critical point. This is due to the drastic changes of the thermodynamic properties, in particular the isothermal compressibility, in this pressure and temperature range. Helium pycnometry, mercury intrusion porosimetry and low-pressure nitrogen sorption showed good agreement in terms of porosity (~ 28%) and the most prominent pore diameter (~ 68.5 nm).

Enhanced Recovery of Nanoconfined Oil in Tight Rocks Using Lean Gas (C2H6 and CO2) Injection

SummaryOrganic matters in source rocks store oil in significantly larger volume than that based on its pore volume (PV) due to so-called nanoconfinement effects. With pressure depletion and production, however, oil recovery is characteristically low because of the low compressibility of the fluid and amplified interaction with pore surface in the nanoporous material. For the additional recovery, CO2 injection has been widely adopted in shale gas and tight oil recovery over the last decades. But its supply and corrosion are often pointed out as drawbacks. In this study, we propose ethane injection as an alternative enhanced oil recovery (EOR) strategy for more productive oil production from tight unconventional reservoirs. Monte Carlo (MC) molecular simulation is used to reconstruct molecular configuration in pores under reservoir conditions. Further, molecular dynamics (MD) simulation provides the basis for understanding the recovery mechanism of in-situ fluids. These enable us to estimate thermodynamic recovery and the free energy associated with dissolution of injected gas. Primary oil recovery is typically below 15%, indicating that pressure depletion and fluid expansion are no longer effective recovery mechanisms. Ethane injection shows 5 to 20% higher recovery enhancement than CO2 injection. The superior performance is more pronounced, especially in nanopores, because oil in the smaller pores is richer in heavy components compared to the bulk fluids, and ethane molecules are more effective in displacing the heavy hydrocarbons. Analysis of the dissolution free energy confirms that introducing ethane into reservoirs is more favored and requires less energy for the enhanced recovery.

Fluid flow and permeability analysis of tight gas carbonate reservoir rocks using fractures and dynamic data

The porosity, permeability, rock material and fracture networks of the newly discovered tight carbonate reservoir rock, the Early Cretaceous Sarmord Formation in Zagros basin are examined. The methods used to investigate the formation are rock cores, micro-resistivity image logs, drill stem tests, drilling fluid data, petrophysical wireline data and drilled cutting samples.The analysed data show that the Sarmord Formation is characterized by extensive open and partially open macro-fractures formed by the local stress from fault and fold propagation. These fractures are sub-vertical with an average dip of 73°, fracture aperture of 0.44 mm and persistence (length) of 11.0 cm. The dominant strike of the fractures is NE-SW, parallel to the observed faults and perpendicular to the main Miran West structure.The vast majority of reservoir porosity was found to be in the rock matrix, with the fractures having very limited impact (average fracture porosity is 0.032%) on porosity. In contrast the fracture permeability averages 240 mD which is four orders of magnitude greater than the matrix permeability. As a result, the inter-connected fractures create effective fluid flow pathways and enhanced hydrocarbon migration perpendicular to the fold structure. Faulting associated with the field structure led to fault damaged zones which act as zones of inter-connected fractures with higher permeability and preferential fluid flow pathways. It is demonstrated that the fracture permeability is driven by the fracture aperture and spacing, whilst the fracture persistence has limited control on permeability.The findings of this study highlight that the importance of fractures and faults on reservoir's quality in tight gas bearing rocks. The network of inter-connected fractures, provide the fluid flow which control the permeability. In contrast the matrix controls the pore spaces and the hydrocarbon storage. This work emphasizes the importance of understanding the impact of structural geology in tight carbonate reservoirs.

Machine-Learning-Assisted Segmentation of Focused Ion Beam-Scanning Electron Microscopy Images with Artifacts for Improved Void-Space Characterization of Tight Reservoir Rocks

SummaryThe modern focused ion beam-scanning electron microscopy (FIB-SEM) allows imaging of nanoporous tight reservoir-rock samples in 3D at a resolution up to 3 nm/voxel. Correct porosity determination from FIB-SEM images requires fast and robust segmentation. However, the quality and efficient segmentation of FIB-SEM images is still a complicated and challenging task. Typically, a trained operator spends days or weeks in subjective and semimanual labeling of a single FIB-SEM data set. The presence of FIB-SEM artifacts, such as porebacks, requires developing a new methodology for efficient image segmentation. We have developed a method for simplification of multimodal segmentation of FIB-SEM data sets using machine-learning (ML)-based techniques.We study a collection of rock samples formed according to the petrophysical interpretation of well logs from a complex tight gas reservoir rock of the Berezov Formation (West Siberia, Russia). The core samples were passed through a multiscale imaging workflow for pore-space-structure upscaling from nanometer to log scale. FIB-SEM imaging resolved the finest scale using a dual-beam analytical system. Image segmentation used an architecture derived from a convolutional neural network (CNN) in the DeepUNet (Ronneberger et al. 2015) configuration. We implemented the solution in the Pytorch® (Facebook, Inc., Menlo Park, California, USA) framework in a Linux environment. Computation exploited a high-performance computing system.The acquired data included three 3D FIB-SEM data sets with a physical size of approximately 20 × 15 × 25 µm with a voxel size of 5 nm. A professional geologist manually segmented (labeled) a fraction of slices. We split the labeled slices into training, validation, and test data. We then augmented the training data to increase its size. The developed CNN delivered promising results. The model performed automatic segmentation with the following average quality indicators according to test data: accuracy of 86.66%, precision of 54.93%, recall of 83.76%, and F1 score of 55.10%. We achieved a significant boost in segmentation speed of 14.5 megapixel (MP)/min. Compared with 0.18 to 1.45 MP/min for manual labeling, this yielded an efficiency increase of at least 10 times.The presented research work improves the quality of quantitative petrophysical characterization of complex reservoir rocks using digital rock imaging. The development allows the multiphase segmentation of 3D FIB-SEM data complicated with artifacts. It delivers correct and precise pore-space segmentation, resulting in little turn-around-time saving and increased porosity-data quality. Although image segmentation using CNNs is mainstream in the modern ML world, it is an emerging novel approach for reservoir-characterization tasks.

CH4 isotopic ordering records ultra-slow hydrocarbon biodegradation in the deep subsurface

Investigation of the biology and biochemistry of the deep subsurface provides invaluable information regarding the limit of life in extreme environments and its role in the global carbon cycle. It has been observed that subsurface microbial CH4 can form in apparent isotopic equilibrium, both with respect to methane clumped isotopic species and D/H fractionation with respect to coexisting water. This observation fostered the suggestion that methanogenic metabolisms in energy-starved environments can operate through slow and reversible enzymatic reactions. Here we present isotopic data including a vertical profile of clumped isotopic indices of methane from Paleozoic-aged pore waters in an aquiclude system from the Michigan Basin. We show evidence of both internal isotopic equilibrium of methane and intermolecular H-isotopic equilibrium between methane and co-occurring non-gaseous n-alkanes. Various mixing and microbial metabolic models were tested and allowed us to identify the possibility of the production of methane at thermodynamic equilibrium from the syntrophic degradation of sedimentary n-alkanes at ultra-slow rates. Significance StatementThe recent ability to measure the clumped isotopic composition of methane has fostered new ways of observing the deep subsurface biogeochemistry and has been proposed as a new independent geothermometer when methane is formed at or near isotopic equilibrium. In this manuscript, we present the first continuous Paleozoic sedimentary profile of clumped isotopes in pore methane (i.e. directly sampled from the pores of tight sedimentary rocks) from a paleo-bioreactor in the subsurface and show that a syntrophic metabolic network between fermentative bacteria and mainly acetotrophic methanogens can thrive in an energy limited environment.

Halogens in Pore Water of Tight Rocks of the Bazhenov Formation in the Nizhnevartovsk Arch of Western Siberia, Russian Federation

The paper presents data on halogens content (Br−, Cl− and I−) in pore water of tight rocks of the Bazhenov Formation (BF) in the Nizhnevartovsk arch of Western Siberia, Russian Federation. We used an integrated approach to analyze 7 whole core samples with the maximum preserved natural water content from 2 different BF fields. Here for the first time, we show that the aqueous extract method can be used to estimate the iodine content in pore water of shale rocks. The target BF rock samples contain silicate minerals, clays, carbonates, pyrite, plagioclase, feldspar, have a high mass content of total organic carbon 5.99÷12.00 wt.%. The residual water content for all studied samples changes from 0.76 to 3.89 wt.%. We found that the Cl− content in pore water varies from 1.4 to 14.2 g/l, Br− from 1.58 to 36.99 mg/l and I− from 2.93 to 36.11 mg/l. I− and Br− concentration in BF pore water is much higher than in seawater. The content of halogens varies unevenly with the well depth due to heterogeneity of the mineral composition of BF rocks even within one well. We discovered that the organic matter of BF almost completely releases the iodine in the pore solution due to diagenesis and katogenesis processes. All target BF samples have iodine in pore water, and only three BF samples have iodine in organomineral complex of rocks (1-3% of the total iodine content). The obtained results have a great importance because allow expanding the available data on the composition of pore waters in shale rocks of the Bazhenov Formation.

Transient shape factors for dual-porosity simulation of tight rocks

The shape-factor concept provides an elegant and powerful upscaling method for fractured reservoir simulation. Many different shape-factors, among which the well-known Warren and Root, and Kazemi shape-factors have been proposed in the past. Since different shape-factors can lead to totally different reservoir behavior, selection of the appropriate shape-factor value is critical for accurate fractured reservoir modeling. Constant shape factor is commonly used for simulation of fractured reservoirs by assuming that pressure transient reaches to center of the matrix block within very small time. On the contrary, tight rocks exhibit longer duration of unsteady-state flow such that matrix – fracture transfer is not constant, but rather varies with time until reaching to a constant value. In this regard, dual-porosity simulation of tight rocks using constant shape factor does not capture actual physics of matrix to fracture flow and yields inaccurate performance prediction. In this study, analytical solutions of pressure diffusion and corresponding shape factors are presented for various matrix shapes. The results are compared to those obtained with simple empirical functions. Proposed functions significantly improve accuracy over existing approaches in the prediction of both mean matrix pressure and transfer function. Results of fine grid single-porosity model are compared with two different dual porosity models, one with constant shape factor and one with time dependent shape factor, to verify proposed approach.

Permeability Prediction in Tight Carbonate Rocks Using Gene Expression Programming (GEP)

Permeability Prediction in Tight Carbonate Rocks Using Gene Expression Programming (GEP)

Fast direct flow simulation in porous media by coupling with pore network and Laplace models

Permeability characterises flow in porous rocks/media for upscaling, while steady-state flow fields allow analysis of reactive transport, fines migration, and tight unconventional rocks. Fast calculation of permeability and flow fields obtained from Pore Network Models (PNM) and Laplace Semi-Analytical Solvers (SAS) deviate from computationally demanding simulation of Navier Stokes Equations (NSE) due to flow and geometry simplifications. Coupling PNM/SAS with direct simulation via Lattice Boltzmann Method (LBM) provides 5--150× speed-up without accuracy loss over 100 samples from 0.7mD to 3.5D. Permeability errors in PNM/SAS show 10-20% (up to 50-70%) error. PNM shows higher variance from geometric simplifications compared to SAS which only makes flow-based assumptions. PNM/SAS errors are eliminated by coupling with LBM at a fraction of LBM-only compute cost. Steady-state conditions with PNM/SAS-LBM are reached in <2,000 timesteps, compared to LBM-only which can require >105 timesteps in tight domains such as cemented sandstone, carbonate, coal, and shale.

A New Experimental Approach for Hydraulic Fracturing Fluid Damage of Ultradeep Tight Gas Formation

The unconventional resources from an ultradeep tight gas reservoir have received significant attention in recent decades. Hydraulic fracturing is the main method for tight gas reservoir development because of its extremely low permeability and porosity. During hydraulic fracturing, high hydraulic fracturing fluid (HFF) that invaded the zone near the fracture face may reduce gas relative permeability significantly and impede gas production. The sources of this damage can be the high capillary pressure (HCP) and the presence of water-sensitive clays (PWC). For tight rock, it is usually infeasible to identify the primary damage mechanism using the traditional steady-state measurement method due to long measurement time and gauge accuracy. In this paper, we present a new experimental approach to identify the primary mechanism of the fracture face damage (FFD) through the application of the pressure transmission method and pressure decay method. Both rock matrix and naturally fractured tight samples (depth 18,000 ft, Tarim field, China) were tested. The experimental results showed that the average high capillary pressure damage indexes ( D HCP ) of rock matrix cores and naturally fractured cores are 94.9% and 92.4%, respectively, indicating severe damage caused by HCP. The average clay-swelling and mobilization (CSM) damage indexes ( D CSM ) of rock matrix cores and naturally fractured cores are 29.6% and 38.4%, respectively, indicating that the damage caused by CSM is lighter than that by HCP. HCP is the primary damage mechanism for the tight sandstone. And the damage degree of the rock matrix cores is higher than that of the naturally fractured core. The proposed procedures can be applied to identify the FFD mechanism of other tight and shale formation and provide insightful fundamental data for HFF optimization.

Quantitative visualization and characteristics of gas flow in 3D pore-fracture system of tight rock based on Lattice Boltzmann simulation

The geometric complexity of the 3D pore-fracture system of tight rock at the pore-scale is a primary challenge for the prediction of gas flow. In this paper, the 3D pore-fracture systems of tight rock are reconstructed based on the representation unit volume (REV) of the intact tight sandstone and fractal fracture. A 3D regularized lattice Boltzmann model that considered the gas slippage effect is employed to simulate gas flow in the 3D pore-fracture systems. Effects of the micro-fracture morphology and gas rarefaction effect on gas flow and permeability of the pore-fracture systems are examined and investigated. The simulation results indicate that the gas flow behaviors in the pore-fracture system are strongly related to the above two factors. Gas flow behaviors in the pore-fracture structure is more sensitive at the low-pressure condition and gas rarefaction effect are more sensitive to the pore-fracture system with the highly rough fracture or the low fracture connectivity.

Porosity and permeability variability across a chalk reservoir in the Danish North Sea: Quantitative impacts of depositional and diagenetic processes

Abstract The Upper Cretaceous to Lower Paleocene Chalk Group in the North Sea comprises important reservoir targets for hydrocarbon and energy storage. The quantitative impacts of mineralogy, chalk diagenesis and oil saturation on petrophysics are often based on general trends that cannot be directly applied to reservoir engineering. The present study aims at identifying quantitatively the individual effects of mineralogy, compaction and cementation, and oil saturation on porosity and permeability by means of detailed samplings and mineralogical and petrophysical analyses from base to top of the Kraka reservoir. Special attention is brought to the visual inspection of the rock fabric and its variations across the reservoir in order to better constrain interpretations and establish relationships within an otherwise scattered dataset. Porosity and permeability variations are categorised into two trends, a mineralogical and diagenetic trend, which can both form tight rock. For chalk containing >7% quartz and > 4% clay, porosity decreases linearly from 35% to 21% and permeability from 0.5 mD to 0.07 mD with increasing quartz content. The amount of quartz rather than clay appears as an effective tool to estimate the petrophysical properties of impure chalk. Below 7% quartz and 4% clay, compaction and cementation decrease porosity and permeability in two steps along transects from oil- to water-bearing intervals. A first step of predominantly mechanical compaction reducing porosity and permeability from >41% to 37% and from 3 to 3.5 mD to 1.5–2.5 mD, respectively, is followed by a phase of chemical compaction and cementation that further deteriorates petrophysical properties. In Ekofisk Fm., stylolitised chalk and deposits located adjacent to chert horizons display singular petrophysical properties that do not fit the observed trends. The outliers likely result from phases of local chemical compaction and early cementation associated with chert formation. Porosity-permeability functions and uncertainty analyses are also proposed for the different controlling factors and at different scales of observation. The proposed petrophysical relationships are instrumental in building more realistic reservoir models and can assist geoscientists in interpreting and upscaling the large amount of geological data collected in chalk fields.