This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s).
In this study, experiments were done on samples from the Marcellus, Woodford, and Eagle Ford shales. The experiments showed that samples from these formations were grossly water-wet, mixed-wet and oil-wet, respectively. The correlation of average wettability index with total organic carbon (TOC) showed that 5 wt% is the critical TOC content required to achieve connectivity and generate oil-wet pathways. Similarly, correlation of average wettability index with clay content showed that <10 wt% clay, samples are oil-wet and >65 wt%, they are predominantly water-wet, and between 10 and 65 wt% clay content, samples exhibited mixed wettability. The threshold values of 5 wt% TOC and 10 wt% clays represent the same volumetric fraction (~10%) of the rock. The figure of 10% can be thought of as percolation threshold for connectivity in shale rocks.
Scanning electron microscope (SEM) imaging done on representative samples (one per formation) was used to quantitatively assess the fraction of different pore types. The fractions of different pore types were in agreement with the observations from the macroscopic imbibition experiments. For instance, oil-wet Eagle Ford samples had a higher fraction of organic pores (22.5%) while water-wet Marcellus samples had a higher fraction of inorganic pores (40%). The samples from all the three shales had a high fraction of mixed-wet pores (Marcellus 57%, Eagle Ford 69%, and Woodford 68%). This knowledge of fractions of different pore types can be instrumental in modeling connectivity pathways.
Robert Freedman, Consultant; David Rose, Schlumberger; and Boqin Sun, Ronald L. Brown, and Thomas Malizia, Chevron Summary We introduce a novel well-logging method for determining more-accurate total porosities, fluid volumes, and kerogen volumes in shale-gas and shale-tight-oil wells. Improved accuracy is achieved by self-consistently accounting for the effects of light hydrocarbons and kerogen on the log responses. The logging measurements needed to practice this method are bulk densities, nuclear-magneticresonance (NMR) total porosities, and total-organic-carbon (TOC) weight fractions. The TOC weight fractions and the matrix densities, which are used to interpret the bulk density measurements, are both derived from geochemical-tool measurements. Most unconventional shale-gas and shale-tight-oil reservoirs contain some nonproducible immobile hydrocarbons. When immobile hydrocarbons are present, our method requires prior knowledge of in-situ total water volumes. The water volumes can be estimated from dielectric-tool measurements. In special cases (e.g., in some mature shale-gas reservoirs) where no immobile hydrocarbons are present, a dielectric tool is not needed. In such cases total water volumes are outputs of the method. We discuss the response functions in shale reservoirs for measurements of bulk densities, NMR porosities, and TOC weight fractions and derive exact self-consistent solutions to the response equations. The algebraic solutions are used to compute shale total porosities, fluid volumes, and kerogen volumes. The predicted shale total porosities and fluid volumes are corrected for light-hydrocarbon effects on the measured bulk densities and NMR porosities and for kerogen effects on the bulk densities. It is shown that significant errors can be made in log-derived shale total porosities if NMR porosities or density-log porosities are assumed to represent true-shale porosities without applying proper corrections. We discuss the application of the method to the analysis of logging data acquired in a mature shale-gas well drilled in the Marcellus Shale in the northeastern United States and to data acquired in a shale-tight-oil well drilled in the Permian Basin in west Texas. A multifrequency dielectric tool is used to determine in-situ total water volumes in the tight oil well. The mature shale-gas reservoir does not contain immobile hydrocarbons, and, therefore, dielectric-logging measurements were not needed in this well. The results in both wells are shown to compare favorably with core data. Introduction The steady decline of oil and gas production in North America during the latter part of the 20th century was markedly and unexpectedly reversed by the shale-oil and shale-gas revolution that coincidentally started at the beginning of the new millennium. This revolution has no doubt changed the worldwide energy balance in the 21st century.
Pore connectivity controls fluid flow in porous media. Well-established methods such as permeability measurements or mercury-injection porosimetry are used to evaluate pore connectivity. However, these methods have limits in unconventional shale formation mainly because of the presence of different-wettability pores with large capillary pressures associated with them. In the present study, we have used the sequential spontaneous imbibition of brine and dodecane to study pore connectivity in shales. The present study shows the presence of water-wet pores, hydrocarbon-wet pores, and mixed-wettability pores. The water-wet pores are the continuous phase, and are controlled by the amount and distribution of inorganic water-wet minerals. The hydrocarbon-wet pores are essentially contained within the organic matter and require a minimum amount of total organic carbon (TOC), ≈3 wt%, to form a connected network of hydrocarbon wet pores. The ≈3 wt% of TOC is a necessary, but not sufficient, condition for developing connectivity throughout organic bodies. The mixed-wettability pores appear to enhance the systems connectivity.
This study introduces a novel outlook on a shale-pore system and on the potential effect of pore compressibility on the production performance. We divide porosity of the system into accessible and inaccessible pores, and incorporate inaccessible pores with grains into the part of the rock that is not accessible. In general, accessible pores contribute to flow directly, whereas inaccessible pores do not.
We present a mathematical model that uses mercury-injection capillary pressure (MICP) data to determine the accessible-pore and inaccessible part of the rock (IRP) compressibility as a function of pressure. During MICP testing in a typical shale sample, the rock sample experiences conformance, compression, and intrusion as effective pressure increases. We characterize the compressibility value dependent on MICP data as a function of pressure. The calculated compressibility values for accessible pores generally appear to be much greater (two to three orders of magnitude) than those of IRP.
Next, we evaluate how calculated accessible-pore-compressibility values affect gas recovery in several shale-gas plays. Our results suggest that substitution of total pore compressibility with accessible-pore compressibility can significantly change the reservoir-behavior prediction. The fundamental rock property used in many reservoir-engineering calculations including reserves estimates, reservoir performance, and production forecasting is the total pore-volume (PV) compressibility, which has an approximate value typically within the range of 1×10-6 to 1×10-4 psi-1 (Mahomad 2014). By recognizing the part of the pore system that actually contributes to production and identifying its compressibility, we can substitute total pore compressibility with accessible-pore compressibility. The result changes the value by nearly two orders of magnitude.
The outcome of the paper changes the industry’s take on prediction of reservoir performance, especially the rock-compaction mechanism. This study finds that production caused by rock compaction is in fact much greater than what has often been regarded, which will change the performance evaluation on a great number of reservoirs in terms of economic feasibility.
Matskova, N. (Universite de Poitiers) | Pret, D. (Universite de Poitiers) | Gaboreau, S. (BRGM) | Cosenza, P. (Universite de Poitiers) | Brechon, R. (Universite de Poitiers) | Gener, I. (Universite de Poitiers) | Fialips, C. I. (Total E&P) | Dubes, G. (Total E&P) | Gelin, F. (Total E&P)
Non-conventional shale reservoirs are characterized by multi-scaled pore systems closely associated with a variable spatial distribution of mineral grains and organic matter. Therefore, only an integrated multi-technique approach can provide a quantitative balance in pore size distribution. Such a balance is not achievable when each of the different methods is applied on different samples that are randomly selected within the formation being studied. In this multi-technique study, the initial cores were first scanned by μ-tomography with an achieved resolution of 78.8 μm to visualize potential spatial heterogeneities at the core scale. This approach identified similar and homogenous areas of interest for localized bulk measurements. In particular, the sub-sample positions were selected, in the 3D views, in areas presenting (i) similar non-clay grain amounts, (ii) similar X-ray linear attenuation coefficients, and (iii) no cracks or macro-heterogeneities.
This approach was applied to seven core samples (dimensions of ~7x7 cm) from the Vaca Muerta formation (Argentina), taken from three different exploration wells in zones with various hydrocarbon types (condensate gas, dry gas, and oil). These samples were chosen on the basis of well log data and their petrophysical interpretations. Lithofacies with similar mineral distribution but contrasting physical properties (resistivity, porosity, and density) and organic matter content were selected.
Conventional bulk methods were used to characterize the pore network of the selected sub-samples: mercury intrusion porosimetry, gas adsorption, nuclear magnetic resonance spectroscopy and helium pycnometry. Some of these methods are generally applied to non-localized crushed powder samples, which is inappropriate for evaluating preserved microstructure from the micro- to the macro-porosity range. For this reason, most of the acquisitions were performed on preserved core blocks, including nitrogen gas adsorption experiments, which were performed with kinetic control of adsorption equilibrium. This innovative approach has provided, for the first time ever, a full set of truly comparable data, localized on 3D views, displaying quantitative balances of pore size distribution in shale reservoirs.
Li, Jing (China University of Petroleum at Beijing) | Jia, Pin (China University of Petroleum at Beijing) | Wu, Keliu (China University of Petroleum at Beijing) | Wang, Xiangzeng (Shaanxi Yanchang Petroleum Group Corp. Ltd.) | Qu, Shiyuan (China University of Petroleum at Beijing) | Shi, Juntai (China University of Petroleum at Beijing) | Jiang, Tianhao (CNOOC EnerTech-Drilling & Production Co.) | Dong, Yifu (CNOOC EnerTech-Drilling & Production Co.)
Characteristics of gas transport in nanopores are topics of great interest for evaluation of unconventional reservoirs. The apparent permeability model for single-phase gas flow has been extensively investigated. Few models, however, have been established for the gas transport in gas/water two-phase flow condition. Unfortunately, initial water always exists under reservoir condition. Although the initial water saturation is generally regarded as immobile state, its impact on gas flow capacity should not be simply neglected. In this work, firstly, the state of sub-irreducible water saturation in shale gas reservoirs have been carefully investigated, and the thickness of thin film bound on inorganic pore surface (e.g. clay or quartz) has been quantified. Subsequently, by considering the impact of the water film on the effective hydraulic diameter, gas diffusion-slip-flow model is established. Noting that the intermolecular interactions of gas phase at high pressure and temperature condition become remarkable, the real gas effect is also considered rather than regarding shale methane as ideal gas. Our proposed model has been directly verified by the laboratory tests, and the gas relative permeability in different cases with varying Knudsen numbers has been computed. To our surprise, the calculated relative permeability curves for gas transport in narrow pores demonstrate as convex shape, which indicates that the influence of water on gas flow weakens as the increase of irreducible water saturation. This phenomenon become obvious especially in large Knudsen number condition. In fact, as the increase of Knudsen number, the gas slippage becomes significant and the relative impact of pre-adsorbed water reduces. For a typical tight gas reservoir with initial water saturation of 30%, the effective permeability for gas transport will reduce about 15%~30%, which depends on the Knudsen number for gas transport. Therefore, neglecting the effect of two-phase interaction might overestimate the gas deliverability.
ABSTRACT: Geomechanical properties are important for reservoir characterization and optimal stimulation design in the oil and gas industry. The conventional techniques, such as laboratory core analysis and downhole acoustic/wireline logging can be expensive and sometimes uncertain to process for unconventional reservoirs. In this study, a convenient and cost-effective technology is presented that uses routinely available drilling data to calculate the geomechanical properties without the need for downhole logging operations. A wellbore friction model is used to estimate the coefficient of friction and effective downhole weight on bit (DWOB) from the routinely collected drilling data. The inverted rate of penetration (ROP) models use the estimated downhole weight on bit and formation lithology constants to calculate the geomechanical properties throughout the horizontal reservoir formations such as confined compressive strength (CCS), unconfined compressive strength (UCS), Young’s modulus, permeability, porosity and Poisson’s ratio. In this article, the field case study is presented for a sample North American well applied to the lower Eagle Ford formation. The calculated geomechanical property log is also verified with tests performed on cores in reservoir rock formations.
Continuous monitoring of rock mechanical and reservoir properties along the wellbore in unconventional horizontal wells demands convenient and efficient logging techniques. The conventional logging techniques involve laboratory core analysis and well logging using sonic and resistivity image logs which are not readily available for all unconventional wells (1 in 10 or 1 in 20) mainly due to associated cost, data uncertainity and time consuming to process. Moreover there are possible risks and concerns of trapping logging tools downhole in highly deviated and horizontal wells drilled in unconventional reservoirs. For many years, researchers and engineers have been investigating several models and techniques to obtain geomechanical property logs for the successful development of unconventional resrvoirs and stimulation design for maximum hydrocarbon production. The Artificial Intelligence and Data Mining (AI&DM) or data- driven models were developed to generate synthetic geomechanical information from the conventional logs in shale plays (Eshkalak et al., 2013). The conventional log data from a shale well was used for training and calibration during neural network model development to generate the synthelic logs for other wells. This model provides better performance for the wells in proximity of the training well with actual geomechanical properties. A convenient ROP model was developed to calculate rock mechanical properties such as, confined compressive strength (CCS), unconfined compressive strength (UCS) and Young’s modulus (E) at each drilled depth from the routinely collected drilling data such as rate of penetration (ROP), weight on bit (WOB) and RPM (Hareland and Nygaard, 2007). In horizontal drilling, the actual downhole weight on bit differs from the measured surface WOB (obtained from on and off bottom hook load difference readings) due to the friction caused by drill string movement, rotation within the wellbore and wellbore geometry. A previously developed 3D wellbore friction model (torque and drag (T&D) model) was used to estimate the coefficient of friction and effective downhole weight on bit (DWOB) from the surface measurements of WOB, hook load, surface applied RPM along with the wellbore survey measurement, standpipe pressure and drill string information (Fazalizadeh et al., 2010).
Li, Jing (China University of Petroleum) | Li, Xiangfang (China University of Petroleum) | Wu, Keliu (University of Calgary) | Chen, Zhangxin John (University of Calgary) | Wang, Kun (University of Calgary) | Zhong, Minglu (The University of Hong Kong) | Bai, Zhijun (Powerchina Zhongnan Engineering Corporation Limited)
Characteristics of gas transport in nanopores are topics of great interest for evaluation of unconventional reservoirs. The apparent permeability model for single-phase gas flow has been extensively investigated. Few models, however, have been established for the gas transport in gas/liquid two-phase flow condition. Unfortunately, initial water always exists under reservoir condition. Although it is regarded as immobile state, the impact of which on gas flow capacity should not be simply neglected.
In this work, firstly, the state of sub-irreducible water saturation in unconventional reservoirs have been carefully investigated, and the thickness of thin film bound on inorganic pore surface (e.g. clay or quartz) has been quantified. Subsequently, by considering the impact of the water film on the effective hydraulic diameter, gas slip-flow model is established. Noting that the gas phase in moist conditions is mainly composed of both methane and vapor rather than single-component methane. Thus, the methane-vapor binary gas state equation has been introduced to describe the real gas effect under high pressure and temperature condition. Our proposed model has been directly verified by the laboratory tests, and the gas relative permeability in different cases with varying Knudsen numbers has been computed.
To our surprise, the calculated relative permeability curves for gas transport in narrow pores demonstrate as convex shape, which indicates that the influence of water on gas flow weakens as the increase of irreducible water saturation. This phenomenon become obvious especially in large Knudsen number condition. In fact, as the increase of Knudsen number, the gas slippage becomes significant and the relative impact of pre-adsorbed water reduces. For a typical tight gas reservoir with initial water saturation of 30%, the effective permeability for gas transport will reduce about 15%~30%, which depends on the Knudsen number for gas transport. Therefore, neglecting the effect of two-phase interaction might overestimate the gas deliverability.
Development of source-rock resources relies on the rigorous knowledge of their petrophysical properties such as porosity, permeability, and hydrocarbon saturation. In parallel, a concise description of the wettability and pore structures is commended. This paper presents a detailed Nuclear Magnetic Resonance (NMR) T2 study of the wetting characteristics and pore structure in organic-rich source rocks from different locations including the Eagle Ford formation. Although these rocks are highly laminated and calcite dominated, our studies indicated that they have distinct different pore structure and connectivity, and differ in how TOC is dispersed within the rock fabric. We believe that the entailed findings could influence our thinking on how best to produce these shales, wellbore stability, drilling fluid selection and other asset development actions.
Source-rock samples with varied amount of total organic content (TOC) were drilled perpendicular or parallel to the laminations. The samples were cut into twin plugs which were sequentially saturated by spontaneous imbibition of 5% KCl brine and diesel (oil). The NMR T2 measurements were used to determine the fluid imbibition rate and amount, as well as the porosity associated with organic and inorganic components of the source rocks. The fracture apertures were obtained via an application of characteristic T2 cutoff times to the NMR T2 distributions. The mineral elements, phases and TOC of the rocks were measured using X-ray Fluorescence (XRF), X-ray Diffraction (XRD) and HAWK pyrolysis, respectively.
The prevalence of surface relaxation on the NMR dynamics was prominent as the transverse relaxation took place at time scales (T2 ≤ 100 ms) much shorter than their bulk values. The overall wettability of the samples showed a mixed character as the brine and the oil had been intimately imbibed. Nevertheless, the details of the wetting behavior of the Eagle ford samples and the other samples were different. For instance, Eagle Ford samples imbibed larger volumes of brine and faster than oil, on the contrary the other samples imbibed larger volumes of oil and faster than brine.
The apparent preference of oil on the other samples is attributed to their high TOC compared to the Eagle Ford samples. Upon imbibition in these samples, brine is observed to flow along the clay rich bedding planes. In fact, the interaction between brine and clay is identified to be the potential driver of the rock stability problems especially near the wellbore; however it is constrained by the type of residing clays. The discrepancies in the wetting traits are magnified by the presence of fractures which enhanced the network connectivity of both hydrophobic and hydrophilic pores or even across them. Furthermore, the fractures allowed the fluids to surpass the vertical bedding planes and thus accelerating the fluid distribution processes inside the pore space. The fracture apertures were found to range from 1 μm to 15 μm which are typical values for source rocks (