Unconventional Rocks Research Articles

A novel anisotropy template for an improved interpretation of elastic anisotropy data

Tight unconventional rocks are characterized by the presence of laminations, preferentially oriented cracks, and an interconnected network of compliant minerals. Such anisotropic features can mechanically deform due to pressure depletion during production, leading to a human-induced change of elastic and fluid transport properties. Rock physics models allow us to better predict and assess stress- and direction-dependent elastic moduli of the rock, useful for horizontal stress estimates. However, elastic anisotropy can be challenging to measure and interpret. We have developed an anisotropy template that can be used to assess stress-dependent changes in elastic moduli and investigate rock textures. We present here the template construction using an effective medium model consisting of stiff and compliant layers and crack inclusions and evaluate the origin of stress-dependent stiffness changes in acoustic data from Berea, Bakken, Three Forks, and Mancos formations.

A fractal effective permeability model for dual-wet porous Media

Recent studies have shown that the pores of some unconventional rocks can be categorized into hydrophilic pores that boarded by inorganic minerals such as quartz and hydrophobic pores that within the organic matter. The rock which consists of both hydrophilic and hydrophobic pores shows a dual-wettability behavior. The previously-proposed imbibition transient analysis technique has been applied in characterizing the pore size distribution of the dual-wet rocks by analyzing comparative oil and water imbibition data. On the basis of the determined pore size distribution, a fractal model for estimating effective permeability of the dual-wet rock was proposed. The proposed model, together with the imbibition transient analysis technique, is able to estimate effective permeability of the dual-wet rocks by using imbibition data. The proposed model can also estimate the effective permeability of hydrophilic pores and hydrophobic pores. The proposed model takes injection pressure, wettability behavior and pore size distribution of the dual-wet rock into the consideration. Our sensitivity analyses show that injection pressure affects effective permeability and hydrophobic permeability by controlling the water saturation within hydrophobic pores. The rock with higher volumetric fraction of hydrophilic pores tends to have higher hydrophilic permeability and lower hydrophobic permeability. By keeping the porosity constant, effective permeability decreases as the volumetric fraction of small pores increases. Cited as: Shi, Y., Guo, Y., Dehghanpour, H., Song, H. A fractal effective permeability model for dual-wet porous media. Advances in Geo-Energy Research, 2023, 8(2): 100-111. https://doi.org/10.46690/ager.2023.05.04

STUDY OF THE DYNAMİCS OF THE İMPACT OF DRİLLİNG FLUİD SLURRY ON THE WELL BOTTOM

Currently, the study of the effect of drilling fluid slurry on the well bottom during the drilling of oil and gas wells remains one of the urgent problems in the center of attention. The main purpose of research on the dynamics of drilling fluid (or drilling mud) during the drilling process is to gather information about the effect of drilling fluid on the drilling process. As a result of this research, more detailed information about the effect of drilling mud on the well bottom will be determined, and based on that information, strategies will be drawn up for the selection and use of drilling mud to make the drilling process more effective, safe and successful. Drilling mud is a homogeneous mixture of two or more substances. system is understood. A solution is a mixture consisting of one or more soluble components and also solvents. In general, both dissolved components and solvents can be solid, liquid or gaseous. At this time, the dissolved substances are constantly distributed in the form of small particles in the solvent environment, causing the formation of a new dispersed system called a solution. At this time, dissolved substances create a dispersed phase, and solvents create a dispersed medium. The clay solutions in the drilling solution can be called the dispersed system, the dissolved clays can be called the dispersed phase, and the water, which is the solvent, can be called the dispersed medium. When used for unconventional formations, selecting a drilling fluid based on data from conventional reservoirs may be the wrong choice. During exposure to the drilling fluid, the drilling fluid has a chemical-mechanical effect on the formation rock; this interaction may be sharp or subtle, depending on the minerals that make up the rock structure and their chemical sensitivity to the fluid composition. Improper selection of drilling fluid can lead to strong rock-fluid interactions, resulting in wellbore instability. This paper presents a comprehensive experimental study investigating the effect of different drilling fluids on the mechanical properties of conventional and unconventional rock samples. Studying the dynamics of the impact of the drilling fluid solution on the bottom of the well is an important aspect of the drilling process. This study aims to better understand how the drilling fluid affects the bottom of the well and the surrounding formation. The results of this study can provide valuable information to optimize the use of drilling fluid solution, improve drilling efficiency and reduce the risk of well damage. Keywords: drilling fluid, drilling bit, layer, rock, well, wellbore, pressure.

Machine Learning-Based Accelerated Approaches to Infer Breakdown Pressure of Several Unconventional Rock Types.

Unconventional oil and gas reservoirs are usually classified by extremely low porosity and permeability values. The most economical way to produce hydrocarbons from such reservoirs is by creating artificially induced channels. To effectively design hydraulic fracturing jobs, accurate values of rock breakdown pressure are needed. Conducting hydraulic fracturing experiments in the laboratory is a very expensive and time-consuming process. Therefore, in this study, different machine learning (ML) models were efficiently utilized to predict the breakdown pressure of tight rocks. In the first part of the study, to measure the breakdown pressures, a comprehensive hydraulic fracturing experimental study was conducted on various rock specimens. A total of 130 experiments were conducted on different rock types such as shales, sandstone, tight carbonates, and synthetic samples. Rock mechanical properties such as Young's modulus (E), Poisson's ratio (ν), unconfined compressive strength, and indirect tensile strength (σt) were measured before conducting hydraulic fracturing tests. ML models were used to correlate the breakdown pressure of the rock as a function of fracturing experimental conditions and rock properties. In the ML model, we considered experimental conditions, including the injection rate, overburden pressures, and fracturing fluid viscosity, and rock properties including Young's modulus (E), Poisson's ratio (ν), UCS, and indirect tensile strength (σt), porosity, permeability, and bulk density. ML models include artificial neural networks (ANNs), random forests, decision trees, and the K-nearest neighbor. During training of ML models, the model hyperparameters were optimized by the grid-search optimization approach. With the optimal setting of the ML models, the breakdown pressure of the unconventional formation was predicted with an accuracy of 95%. The accuracy of all ML techniques was quite similar; however, an explicit empirical correlation from the ANN technique is proposed. The empirical correlation is the function of all input features and can be used as a standalone package in any software. The proposed methodology to predict the breakdown pressure of unconventional rocks can minimize the laboratory experimental cost of measuring fracture parameters and can be used as a quick assessment tool to evaluate the development prospect of unconventional tight rocks.

Reservoir characterisation of unconventional rock units in the middle jurassic Sargelu Formation, atrush field, zagros folded belt

The heterogeneous lithological components of the Middle Jurassic Sargelu Formation in the Atrush field of the high folded zone were examined using rock samples, conventional wireline logs, mud logs and well test results throughout two wells. The Sargelu Formation is 45 m thick and has been divided into three units based on lithological characteristics and shale volume. The upper unit of the Sargelu Formation is composed of argillaceous limestone with intercalation of dolostone and anhydrite beds. The middle unit of the Sargelu Formation is composed of organic rich laminated shales, which contain residual bitumen, whilst the lower unit of the formation is dominated by argillaceous limestones. Lithological variation, mineralogy and organic matter contents are shown to be essential factors in controlling the reservoir matrix porosity and permeability. The maximum matrix porosity and permeability were observed within the dolomite plug samples (13.40%, 10.40 mD) and the lowest values were recorded in the anhydrite samples, both found in the upper unit of the Sargelu Formation. The fracture permeability is three orders of magnitude higher than the matrix permeability and the hydrocarbon production is predominately derived from the fractured intervals throughout the Sargelu Formation. The interconnected fracture pathways are influenced by the lithological variation and mineralogical components of the formation along with the tectonic position of the field. It was found that as the confining pressure increased the fracture permeability reduced. The different lithologies were also found to be sensitive to increases in the confining pressure. The clastic shale rich rocks are most sensitive to increases in confining pressure, whilst the more carbonate rich rocks showed the lowest variation as a function of confining pressure.

NMR-Based Wettability Index for Unconventional Rocks

Standardized and benchmarked wettability characterization and quantification workflows are lacking in unconventional reservoir development. Quantification of in-situ wettability and changes due to wettability alteration efforts can assist with completions decisions, and economic oil production. This manuscript summarizes the establishment and validation of an NMR wettability index (NWI) for unconventional rocks. The method builds upon Looyestijn’s NMR wettability analysis methods for conventional rocks and has been tested on core plug samples from a variety of major producing unconventional reservoirs. It will be of interest to readers to note the marked range of wettability values quantified among the aforementioned tight formations. Our NWI model is well suited for data sets featuring complex oil and water T2 spectra with multiple peaks, common features of unconventional rock spectra. The results were subjected to comprehensive experimental and analytical validation, including complementary 3D NMR imaging and replication of the experiments with D2O. The validation procedure and advantages of the approach over other NMR wettability models are discussed in this review. Finally, best practices are detailed so that the SCAL methodology can be deployed on a larger scale.

NMR T1-T2 Logging in Unconventional Reservoirs: Pore-Size Distribution, Permeability, and Reservoir Quality

The rock-pore textural properties in unconventional fine-grained reservoirs are much more complicated than in conventional reservoirs. In fine-grained rocks, this complexity derives from very small component grain assemblages (clay and silt fractions) and very small pores (nano- to microsizes) overprinted by diagenesis. It is further compounded by the pores being developed in intergranular, grain dissolution, and organic-associated-intragranular voids. Additionally, because locally sourced hydrocarbons in unconventional reservoirs, in contrast to migrated hydrocarbons that are present in conventional reservoirs, exist within similar pore sizes as the original saturating water phase, they create geometrically complex fluid distributions. These imply that, in the context of nuclear magnetic resonance (NMR) logging and petrophysical interpretation of tight oil unconventional reservoirs, pore size can no longer be considered a proxy for fluid type and vice versa. This means using T2 or T1 cutoffs may give inaccurate predictions. Current industry applications of NMR T1-T2 logging have demonstrated reliable interpretation of fluid types and water saturation. However, because petrophysical controls of advanced relaxation effects (such as surface and bulk fluid relaxation properties, pore-size distribution, and wettability) are not properly understood, these applications have been limited to estimating fluid saturations and have not been applied to estimating pore sizes. We extend the application of NMR T1-T2 measurements in tight oil unconventional reservoirs to model pore-size distributions by using apparent surface relaxivities and bulk relaxation times that have been jointly estimated from poro-fluid relaxations. To test these predictions, modeled pore-size distributions are compared to rock-pore textural properties from petrographic images of core samples. Such comparison allows us to derive insights into controls of mudstone reservoir quality (RQ) in conjunction with the impact of rock fabric endmembers (e.g., matrix-supported clays, grain-supported framework, diagenetic cements, and solid organic matter) on pore-size distributions. With these assumptions in mind, it follows, based on the Kozeny-Carman formulation, that unconventional rock permeability is reliably predicted from the NMR-based pore-size distributions. Furthermore, we deduce the impact of mineral assemblages in the Herron permeability model to infer influence on rock textural properties and ultimately predict permeability in limited data environments. This paper introduces a novel approach to estimate pore-size distributions per fluid type (water and hydrocarbons) from NMR T1-T2 measurements in unconventional reservoirs. Additionally, petrophysical controls of RQ, storage, and transport properties are derived from NMR-based pore-size distributions and mineral assemblages. This enables more reliable RQ and permeability assessment than typical T2- or T1-cutoff methods.

Flow capacity characterization of unconventional natural gas bearing rocks using digital rock physics: A comparison between advection and diffusion

Experimental flow capacity characterization of unconventional rocks is a nontrivial task, and the relative contribution of advective vs. diffusive flow mechanisms remains illusive. Herein we apply a digital rock physics workflow to systematically compare the advection and diffusion behavior of supercritical methane in two 3D reconstructed unconventional shale and coal core samples. Nitrogen sorption experiments and scanning electron microscope observations are combined to inform the construction of representative pore network models. For advection modeling, we consider the nanometer-scale confinement effect and pore shape effect, while for diffusion modeling the contributions of Fick diffusion, transitional diffusion, and Knudsen diffusion are considered separately based on the Knudsen number. The effect of pore size, shape, pressure, and temperature on methane flow capacity in a single nanopore is first studied. Then the apparent permeability and effective diffusivity of the two reconstructed nanoporous media are calculated and compared. We demonstrate that at reservoir pressure and temperature conditions, diffusion contributes to mass flux (above 10%) only in micropores and small mesopores (< 10 nm). For most realistic unconventional rocks, the contribution of bulk diffusion can be neglected when estimating the flow capacity.

Structural Formation, Evolution, and Genetic Mechanisms of Fault in Controlling Hydrocarbon Migration of Unconventional Rocks: A Case Study of Zhuangnan Fault

Zhuangnan fault zone was affiliated with Gubei subsag of the Zhanhua sag in Jiyang Depression, Bohai gulf basin. Zhuangnan fault zone has two functions as the main east-west strike-slip accommodation structure. That is, on the one hand, Zhuangnan fault zone inherited the rules of development of regional tectonic. On the other hand, the present structure framework of Zhanhua sag was reconstructed by Zhuangnan fault zone. In the study, there are four main seismic reflectors: T0, T1, T2, and T6. They are the basis for researching the planar and vertical features of Zhuangnan fault zone. The structural formation, evolution, and genetic mechanisms of Zhuangnan fault zone are studied from three aspects of geometry, kinematics, and dynamics. In geometry, by the closure interpretation of 43 south-north interpretation sections and 24 east-west interpretation sections, the result indicates that Zhuangnan fault zone has its special regularity and characteristic which has three-piece planar characterization (eastern part, middle part, and western part). Three types of plane combination forms are determined: arched, linear, and “S” curved type. The plane combination structure styles of the Zhuangnan fault zone mainly include feather row, horsetail, grid, diagonal, and parallel style. These planar structural features play an important role in indicating the fault zoning of Zhuangnan fault zone. Based on the plane and section structural styles of Zhuangnan fault zone and the analysis of dynamic evolution, it is found that Zhuangnan fault zone has a succession relationship between deep and shallow fault systems. From tectonic evolution and regional dynamic point of view, this paper discusses the activity law of the Zhuangnan fault zone and the boundary faults on the east and west sides of Jiyang Depression, which are Changdi fault, Wuhaozhuang fault, and Chengnan fault, respectively. This study provides a new and more reasonable explanation for the unique structural characteristics of Zhuangnan fault zone and further confirms the important role and regulation mechanism of Zhuangnan fault zone.

Unconventional CO2 Storage: CO2 Mineral Trapping Predicted in Characterized Shales, Sandstones, and Coal Seam Interburden

Summary Carbon dioxide (CO2) capture from industrial sources including coal combustion, gas processing, cement or steel production, blue hydrogen, or direct air capture, and subsequent geological storage is part of the transition to reduce greenhouse gas emissions. Unconventional and conventional reservoirs provide opportunities for beneficial use such as enhanced recovery, supercritical CO2 (ScCO2) fracturing, and storage of gases such as CO2 and ancillary gases, or potentially hydrogen. The purpose of this study is to use Australian unconventional rock packages to understand the controls on CO2 reactivity and mineral trapping (the most secure form of storage) and compare the potential for CO2 storage. Characterization of core from the Surat, Eromanga, and Cooper basins, Australia, is used to populate CO2 and production water-rock reactivity models. Sensitivity to production water composition and temperature was also tested. Coal seam gas (CSG) reservoir interburden ranged from clay-rich mudstones to interlaminated sandstone and mudstone, and calcite cemented sandstones. The coal seam interburden samples contained high plagioclase and chlorite content. They were predicted to alter to carbonates calcite, ankerite, siderite, and dawsonite mineral trapping CO2. After 30 years, net mineral trapping varied from −0.1 to +0.3 kg CO2/m3, and pH was 4.6–4.9. Net mineral trapping after 1,000 years varied from 5.7 to 16.3 kg CO2/m3 and was 17.1 kg CO2/m3 with higher salinity water. The mineral content had the main control with different lithologies decreasing mineral trapping by 41 or 35% compared with a base case. Overlying plagioclase-rich sandstone trapped 17.1 kg CO2/m3 as calcite, ankerite, dawsonite, and siderite after 1,000 years with the pH increasing to 6. For the quartz-rich oil reservoir sandstone, however, only 0.3 kg CO2/m3 was trapped after 1,000 years. Gas shale and marine black oil shales contained high mica, chlorite, and feldspar content that could be converted to carbonate minerals, mineral trapping CO2. A marine black oil shale mineral trapped 8.3 and 13.9 kg CO2/m3 after 30 and 1,000 years, respectively, as siderite and ankerite. Unconventional reservoirs have a strong potential for mineral trapping during CO2 storage.

Quality Control of Nuclear Magnetic Resonance Measurements Using Pseudo-T2 Distributions

Summary Nuclear magnetic resonance (NMR) measurements are extremely valuable in the assessment of fluid-flow properties of rocks. However, inverted NMR transverse-relaxation time (T2) distributions are often biased by positivity constraints and the implementation of regularization (stabilization) methods. In some cases, it is difficult to determine whether the estimated pore-size distributions are reliable or byproducts of the inversion. On-site quality control of NMR inversion results is thus essential to avoid erroneous analyses based on nonphysical interpretations across conventional or unconventional rocks. It is also important to adjust the measurement acquisition process in real time in response to variable signal/noise conditions in the borehole environment. We introduce and compare three quality-control approaches; two of them are based on two different signal processing practices, namely the semilogarithmic derivative and the Hilbert transform, while the third is based on a nonlinear optimization technique. Validation of the inverted T2 distribution is performed by applying either method to the echo train decay of proton magnetization to estimate a pseudo-T2 distribution that is not affected by inversion artifacts. These three methods are data-driven processes for on-site, continuous quality control of borehole NMR measurements. In the first method, a pseudo-T2 distribution is constructed by taking the derivative of the echo train decay with respect to the natural logarithm of the relaxation time. For the second method, the Hilbert transform is applied to the raw proton magnetization decay to approximate the T2 distribution. The latter method consists of an approximation of the derivative of the time decay of magnetization using least-squares minimization. NMR laboratory measurements were performed on a wide variety of rocks, the associated T2 distributions were estimated using linear inversion, and the three quality-control methods were applied for comparison. The reliability of our quality-control procedures was verified by benchmarking them against the inverted T2 distributions. Furthermore, these quality-control methods, when applied continuously to borehole NMR measurements, enable the optimization of the measurements in real time to mitigate the effects of biasing noise. By verifying the location of the dominant mode of the T2 distribution during NMR measurement acquisition, the operator can determine whether (a) more stacking of proton magnetization decays is needed, or (b) longer- or shorter-time sampling is needed to attain a high-quality estimation of the pore-size distribution before performing the T2 inversion. Our work provides the basis of effective quality-control methods for NMR measurements for the petrophysical interpretation of rocks with complex pore-size distributions, especially in unconventional rocks, where noise present in the measurements (notably at early acquisition times), can mask the useful signal originating from pore-size distributions and fluids. The fast and reliable quality control of estimated T2 distributions is not affected by inversion artifacts, relying only on unfiltered, raw data.

Computing elastic properties of organic-rich source rocks using digital images

Digital rocks are 3D image-based representations of pore-scale geometries that reside in virtual laboratories. High-resolution 3D images that capture microstructural details of the real rock are used to build a digital rock. The digital rock, which is a data-driven model, is used to simulate physical processes such as fluid flow, heat flow, electricity, and elastic deformation through basic laws of physics and numerical simulations. Unconventional reservoirs are chemically heterogeneous where the rock matrix is composed of inorganic minerals, and hydrocarbons are held in the pores of thermally matured organic matter, all of which vary spatially at the nanoscale. This nanoscale heterogeneity poses challenges in measuring the petrophysical properties of source rocks and interpreting the data with reference to the changing rock structure. Focused ion beam scanning electron microscopy is a powerful 3D imaging technique used to study source rock structure where significant micro- and nanoscale heterogeneity exists. Compared to conventional rocks, the imaging resolution required to image source rocks is much higher due to the nanoscale pores, while the field of view becomes smaller. Moreover, pore connectivity and resulting permeability are extremely low, making flow property computations much more challenging than in conventional rocks. Elastic properties of source rocks are significantly more anisotropic than those of conventional reservoirs. However, one advantage of unconventional rocks is that the soft organic matter can be captured at the same imaging resolution as the stiff inorganic matrix, making digital elasticity computations feasible. Physical measurement of kerogen elastic properties is difficult because of the tiny sample size. Digital rock physics provides a unique and powerful tool in the elastic characterization of kerogen.

Chemomechanical effects of oxidizer‐CO2 systems upon hydraulically fractured unconventional source rock

AbstractCarbon dioxide (CO2) as supercritical (scCO2) or foamed (CO2‐Foam) fluid has been tested many times as a fracturing fluid, though it has not yet proven viable. Many challenges have been identified with scCO2 as a fracturing fluid, including poor additive solubility, low viscosity, and limited accessibility. However, CO2 is known to adsorb to organic matter (OM) and displace methane (i.e., enhanced coal bed methane [ECBM] operations), or to mobilize oil as in tertiary enhanced oil recovery. In this study we augment the efficacy of the kerogen control fluid (KCF) for stimulating unconventional rock formations by alternating aqueous oxidizing fracturing fluid with CO2 injection or by combining oxidizers directly with CO2 as a new additive. To this end, KCF‐CO2 tests were designed to treat OM and extend the depth of permeability enhancement. We report the first attempt to combine oxidizer with CO2 in the presence of source shale rocks at elevated temperature and pressure. Scanning electron microscopy imaging of the treated shale sample surfaces demonstrate potential porosity and permeability enhancement, though some mineral and organic deposits are also observed, which may prove to be detrimental. Meanwhile, alternating water‐based KCF with CO2 provides a potential improvement to the KCF as predicted by early lab results on OM. The KCF‐CO2 concept has no equivalent to date in unconventional hydraulic fracturing operations. This technology will contribute to reducing the footprint of anthropogenic CO2 and enhancing its permanent sequestration in unconventional stimulated reservoirs, compliant with our global clean energy initiative of carbon capture, utilization, and storage.

Statistical thermal damage constitutive model of rocks based on Weibull distribution

On the basis of Lemaitre’s strain equivalence theory, the effects of high temperatures on the mechanical parameters of rock are taken into account, and a thermal damage variable DT is introduced. A statistical thermal damage constitutive model is developed by adopting the modified Mohr-Coulomb criterion with the hypothesis that the mesoscopic unit strength of rock subjected to thermal treatment obeys a Weibull random distribution. The values of the model parameters are determined by the extreme value method according to the concept of yielding. The rationality of the model is verified by comparing the calculated results with experimental results from uniaxial and conventional triaxial experiments of granite, marble, and sandstone specimens that were subjected to different high-temperature treatments. The results indicate that the model can simulate the whole process of stress-strain relations of different lithological rocks under different confined pressure and temperature conditions; the model can also reflect the characteristics of strain softening. The model does not contain any unconventional rock mechanics parameters and is lithology independent, which is highly convenient for engineering applications. This research can provide a theoretical basis for the development and protection of high-temperature rock projects.

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 critical review of common models in hydraulic-fracturing simulation: A practical guide for practitioners

In laminated, anisotropic unconventional rocks (ultra-tight shale, tight gas, coal seam, and so forth), the true hydraulic-fracturing mode is a complex, mixed-mode process. The fracture-modeling practitioner often encounters a wide range of fracture models. The selection of an appropriate fracture model has become a daunting task with significant implications for the hydraulic-fracturing pre-treatment design or post-treatment diagnostic evaluation. Therefore, it is crucial to properly identify the assumptions and limitations of each model, and how they affect the modeling output as well as the treatment design. This study provides a critical review of the assumptions, advantages, and disadvantages of the more-common fracture models in hydraulic-fracturing simulation. The models covered range from the simplified 2D, pseudo 3D (P3D), and lumped parameter (LP) models to 3D planar-fracture models (elastically coupled and shear-decoupled models), and to more complex 3D models including the displacement discontinuity model (DDM), discrete fracture network (DFN) model, distinct element model (DEM), bonded particle model (BPM), synthetic rock mass (SRM) using BPM and smooth joint model (SJM), lattice model (including the dual-lattice implementation of SRM), continuum and extended-continuum models, and the meshless models. The advantages and disadvantages of the more advanced 3D models are analyzed in the context of simulating special cases, including alternate fracturing and hydraulic fracturing in naturally fractured reservoirs. In the context of these special cases, the capabilities and limitations of these models in incorporating the complex interactions between the hydraulic fractures, and between hydraulic and pre-existing fractures and joints are discussed. This study outlines how a fracture model should be carefully selected, considering the geological and geomechanical conditions, availability of data, and the scope of investigation.

Two Approaches Provide Quality Control for NMR Measurement of Unconventional Rock

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201358, “Quality Control of NMR Measurements in Unconventional Rocks Using Hilbert Transforms and Semilogarithmic Derivatives,” by Pierre Aérens, SPE, David Medellin, and Carlos Torres-Verdin, SPE, The University of Texas at Austin, prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, 5-7 October. The paper has not been peer reviewed. Nuclear magnetic resonance (NMR) measurements are extremely valuable in the assessment of fluid-flow properties of rocks. However, inverted transverse-relaxation time (T2) distributions are often biased. The authors of the complete paper introduce and compare two quality-control approaches based on two different signal-processing practices: the semilogarithmic derivative and the Hilbert transform. This work provides the basis of effective quality-control methods for NMR measurements for the petrophysical interpretation of rocks with complex pore-size distributions. The fast and reliable quality control of estimated T2 distributions is not affected by inversion artifacts, relying only on unfiltered, raw data. Introduction Borehole NMR measurements are commonly riddled with excessive noise that precludes high-resolution assessments of rock and fluid properties, especially in unconventional rock. Inverted T2 distributions can be biased by positivity constraints and the regularization method used in the inversion, making it difficult to determine whether the estimated pore-size distributions are reliable or byproducts of the inversion or regularization. Quality control of inversion results is essential for the robust quantitative interpretation of proton magnetization decays. The complete paper presents a mathematical analysis for the two data-quality assessment methods and the work flow to estimate pseudo-T2 distributions on the basis of time-decay proton magnetizations. The estimation and assessment methods are then applied to both synthetic and experimental data sets to verify their validity and reliability. The laboratory examples are detailed in the complete paper. Validation With Synthetic Cases The authors apply the derivative and Hilbert methods to two synthetic examples for a total of three cases. Both synthetic examples comprise three exponential magnetization decays, with amplitudes equal to A1=0.5, A2 =0.2, and A3=0.3. The first example is referred to as ideal because it is not contaminated with noise and because the authors chose the T2 peak times separated by three orders of magnitude at 1 µs, 1 ms, and 1000 ms, respectively. The second example showcases a more-realistic choice of T2 peak values, namely 0.1, 10, and 200 ms, respectively.

Technology Focus: Well Testing (February 2021)

At first glance, well testing may not come across as high-tech. At a time of rampant digitalization, with catchy phrasing such as “machine learning” and “Internet of things,” how can we compete with “slip joints” and “Bourdet derivatives” from the ’80s? Further down Memory Lane, bubble buckets and semilog graph paper look even more as if they are from a bygone era. Yet the former are still relied upon in specific onshore applications (I used one 2 years ago), and petroleum engineering students continue to learn the fundamentals of pressure transient analysis with the latter. Most of today’s equipment and interpretation methods are indeed not new. After all, well testing has been around for nearly a century, resulting in a legacy that may not always look cutting-edge, but these tried-and-true tools (both hardware and analytical) were so technologically remarkable that they became staples. Call it pragmatism; others may retort that “if it ain’t broke, don’t fix it.” These tools enable operators to test exploration and appraisal wells before any production facilities are installed, flowing hydrocarbons to a drilling rig in a controlled and safe manner, sometimes for the first time since these molecules were trapped millions of years ago. Service companies developed equipment that can be operated under a variety of conditions, enhancing the operator’s flexibility to tailor to virtually any circumstances, while layering in safety features and contingencies. Disturbances stemming from flowing the well are recorded by gauges that can resolve minuscule pressure changes. Far beyond permeability thickness at the well, the resulting pressure transients yield insights into reservoir architecture, thereby illuminating the operator’s subsurface understanding to inform field development and a lifetime of reservoir management. A nonexhaustive list of recent improvements and additions to our toolbox includes: Acoustic telemetry for wireless equipment actuation in temporary completions Wet-mate connectors for formation-face instrumentation in permanent completions Fiber optics for distributed temperature and acoustics with no moving parts Multiwell deconvolution for application to producing fields A business tenet contends that a compromise must be sought between quality, cost, and time. You may have heard it as “good, cheap, or fast - pick two.” While this is a simplistic vision that omits other key dimensions, technology has undeniably improved the value proposition of well testing. This month’s papers exemplify the vibrancy of technology in our discipline. Well tests are the linchpin of a carbonate’s appraisal campaign and unlock dynamic insights into nonmatrix behavior otherwise inaccessible from static logs. Heterogeneity in unconventional rocks is recognized with a fully integrated reservoir/fracture/wellbore simulator that can model different layers of varying thickness, stiffness, hardness, and stress, to name but a few. A convolutional neural network offers a brilliant engineering control to complement the traditional flare watchers and proactively monitor suboptimal combustion, furthering our industry’s environmental commitment. In the suggestions for additional reading, peruse the elegant Bayesian take on uncertainty analysis and the intriguing combination of geomechanics and well testing.

Evaluation of calculated connate water saturation values in case of unconventional rock samples

The present study represents possibilities of calculating the connate water saturation - CWS - values of samples from unconventional reservoirs and how to evaluate the obtained result. CWS is an extremely important property of the reservoir rocks. It basically determines the value of the resource and can also predict production technology difficulties. For the samples included in the measurement program, significant or extremely high CWS values were determined. Analysis of the corrected pore size distribution proved to be the most appropriate method for interpreting CWS values, although, it also shows some correlation with the most frequent pore radius - MFPR - and porosity.

A novel NMR surface relaxivity measurements on rock cuttings for conventional and unconventional reservoirs

Surface relaxivity (ρ) is an intrinsic rock property that makes low-field NMR a valuable tool for determining pore size distribution of geological formations. Its value can vary considerably in different rocks depending on the type and distribution of the rock minerals, rock surface wettability and petrophysical properties. Therefore, laboratory measurement of ρ is required on a case by case basis. However, existing NMR methods are expensive, complex, and most often require supplementary and expensive non-NMR measurements. Rock samples are also required to be well consolidated and cylindrical so that experiments can be run at high pressures – a barrier for measurements of unconsolidated and thinly laminated unconventional rocks. This study proposes a new NMR method termed ‘NMR grain sizing method’, that uses different grain sizes of a given rock to generate pores of corresponding sizes. Using a geometric constant, grain specific surfaces are transformed to pore surfaces, and the governing NMR equation is rearranged so that we have a method that measures ρ from only NMR measurements on rock cuttings. This approach is simple, inexpensive, and does not require supplementary measurements. It offers an added advantage for characterizing thinly laminated formations. A proof of concept is demonstrated for three unconventional rocks (Qusaiba shale, Jafurah carbonate mudrock and Eagle Ford) and two conventional rocks (Berea sandstone and Indiana limestone). The ranges of surface relaxivity are 96.9–134.5 μm/s (Qusaiba shale); 62.07–106 μm/s (Jafurah carbonate mudrock); 55.9–68.72 μm/s (Eagle Ford); 35.51–43.2 μm/s (Berea sandstone); and 33.2–40.54 μm/s (Indiana limestone). All ρ measurements are reproducible with 95% confidence interval. The measured values for Indiana limestone and Berea sandstones were validated with micro CT based pore network models and also compare well with literature data. Measurement of Qusaiba shale and Jafurah carbonate source rocks are apparently reported for the first time here.