Exploration Of Unconventional Reservoirs Research Articles

Elastic and anisotropic properties of organic‐rich lacustrine shales: An experimental study

AbstractExperimental investigation of the elastic behaviours of lacustrine shales remains sparse, although they play an essential role in source rock evaluation, unconventional reservoir exploration and development, and the seal integrity evaluation for geological storage of CO2 and nuclear waste disposal. We make the ultrasonic velocity measurement of 63 organic‐rich shale samples (Chang 7, Qingshankou and Lucaogou formation) from three typical lacustrine basins in China. It is found that the P‐ and S‐wave velocity of Chang 7 and Qingshankou shale corresponding to the fresh‐brackish lacustrine depositional environment is mainly impacted by the clay and organic matter content, whereas their elastic anisotropic magnitude is mostly influenced by clay content. The P‐ and S‐wave velocities of Lucaogou shale corresponding to the saline lacustrine depositional environment are mainly affected by the total organic carbon and porosity and exhibit weak anisotropy linked to organic matter enrichment. Exponential law well captures the relationship between anisotropic magnitude and velocity perpendicular to bedding for both saline and fresh‐brackish water lacustrine shales, although there exists notable discrepancy, particularly at low velocities. The disparity in elasticity between laminations has a profound impact on the magnitude of elastic anisotropy and shapes the trend of velocity variations.

Unconventional Reservoir Characterization and Formation Evaluation: A Case Study of a Tight Sandstone Reservoir in West Africa

Unconventional reservoirs, including gas shales and tight gas sands, have gained prominence in the energy sector due to technological advancements and escalating energy demands. The oil industry is eagerly refining techniques to decipher these reservoirs, aiming to reduce data collection costs and uncertainties in reserve estimations. Characteristically, tight reservoirs exhibit low matrix porosity and ultra-low permeability, necessitating artificial stimulation for enhanced production. The efficacy of the stimulation hinges on the organic material distribution, the rock’s mechanical attributes, and the prevailing stress field. Comprehensive petrophysical analysis, integrating standard and specialized logs, core analyses, and dynamic data, is pivotal for a nuanced understanding of these reservoirs. This ensures a reduction in prediction uncertainties, with parameters like shale volume, porosity, and permeability being vital. This article delves into an intricate petrophysical evaluation of the Nene field, a West African unconventional reservoir. It underscores the geological intricacies of the field, the pivotal role of data acquisition, and introduces avant-garde methodologies for depth matching, rock typing, and the estimation of permeability. This research highlights the significance of unconventional reservoir exploration in today’s energy milieu, offering a granular understanding of the Nene field’s geological challenges and proffering a blueprint for analogous future endeavours in unconventional reservoirs.

Heterogeneity indexes of unconventional reservoir shales: Quantitatively characterizing mechanical properties and failure behaviors

Heterogeneity is an inherent feature of subsurface rocks. Unconventional reservoir shales, a group of typically fined-grained sedimentary rocks, usually exhibit strong heterogeneities due to the diversity of their constituents, including stiff silicate and carbonate minerals, ductile clay minerals, and organic matter. Understanding the influence of heterogeneities on the mechanical response as well as the failure behavior of reservoir shales plays a crucial role in numerous fields of Earth and Energy sciences, such as unconventional reservoir exploration, sealing of CO2 sequestration, nuclear waste disposal, and hydrogen storage. In this study, we propose two heterogeneity indexes, intending to quantitatively characterize the heterogeneity of mineralogical compositions in unconventional reservoir shales. The first index takes into account the heterogeneity of mineral content, and the other one comprehensively considers the mineralogical heterogeneity and its corresponding mechanical properties. We apply these heterogeneities indexes to two experimental datasets of marine and lacustrine shales. The results show that the heterogeneity index significantly influences the mechanical properties and deformation behaviors of reservoir shales. As the increment of heterogeneous indexes, the ultimate strength and static Young's modulus show a general decreasing trend. However, the effect of the heterogeneity index on the static Poisson's ratio is weak. The numerical simulation results also confirm our experimental analysis, where the ultimate strength and Young's modulus of rock have a negative correlation with the heterogeneity indexes. The proposed heterogeneity indexes provide insights into understanding the mechanical behaviors and fracability assessment of reservoir shales.

Predicting Shear Wave Velocity Using a Convolutional Neural Network and Dual-Constraint Calculation for Anisotropic Parameters Incorporating Compressional and Shear Wave Velocities

As the exploration of unconventional reservoirs progresses, characterizing challenging formations like tight sandstone becomes increasingly complex. Anisotropic parameters play a vital role in accurately characterizing these unconventional reservoirs. In light of this, this paper introduces an approach that uses a dual-constraint anisotropic rock physics model based on compressional and shear wave velocities. The proposed method aims to enhance the precision of anisotropic parameter calculations, thus improving the overall accuracy of reservoir characterization. The paper begins by applying a convolutional neural network (CNN) to predict shear wave velocity, effectively resolving the issue of incomplete shear wave logging data. Subsequently, an anisotropic rock physics model is developed specifically for tight sandstone. A comprehensive analysis is conducted to examine the influence of quartz, clay porosity aspect ratio, and fracture density on compressional and shear wave velocities. Trial calculations using the anisotropic model data demonstrated that the accuracy of calculating anisotropic parameters significantly improved when both compressional and transverse wave velocity constraints were taken into account, as opposed to relying solely on the compressional wave velocity constraint. Furthermore, the rationality of predicting anisotropic parameters using both the shear wave velocity predicted by the convolutional neural network and the measured compressional wave velocity was confirmed using the example of deep tight sandstone in the Junggar Basin.

Fabrication and mechanism of microspheres with tunable and control-released hydrophobicity: Ultra-low-density proppants

Ultra-low-density proppants with tunable and control-released hydrophobicity can meet different requirements of different fracture environments, thus playing an important role in unconventional reservoir exploration. In this study, for the first time, we designed and synthesized proppants with a molecular structure of γ-methacryloxypropyltrimethoxysilane (KH570)-styrene (St)-divinyl benzene (DVB) (FR-SDB) through suspension polymerization. FR-SDB was examined by Fourier-transform infrared spectroscopy, atomic force microscopy, scanning electron microscopy, and X-ray diffraction to understand the mechanism of tunable and control-released hydrophobicity. The results revealed that the hydrophobicity is related to the hydration reaction of chemically bonded KH570 and the difference in the reaction activities under different aqueous environments at different temperatures. The wettability of FR-SDB was evaluated according to the static water contact angle (θw) on its surface. The contact angle θw on the surface of FR-SDB can be tailored from the initial angle of approximately 50° to 80°–125° in a wide time range of 10 min to 144 h. FR-SDB exhibited ultra-low apparent density of approximately 1.028 g/cm3, high compressive strength, and a crushing ratio of ∼ 1.81% at closure pressure of 69 MPa.

Key Technology of Volumetric Fracturing in Vertical Wells of Hugely Thick Shale Oil Reservoirs in the Fengcheng Formation of the Mahu Sag

Shale oil reservoirs in the Fengcheng Formation of the Mahu Sag are characterized by a large buried depth of sandbodies, huge thickness, overall oil-bearing properties, dense matrix, and enrichment in metal ions. As a result, fracturing is prone to be insufficient in vertical extension and unable to cover the reservoir, with low fracture complexity, high sanding risks, and an incompatibility of conventional guar gum fracturing fluid. Based on a detailed description of reservoir mechanical properties and an evaluation of the main controlling factors of fracture networks, a calculation model of fracability index was built to fully exploit the exploration potential of the shale oil in this area. In light of the vertical fracture propagation, the perforation clusters and cluster spacing were determined to develop a fine vertical layered approach. In accordance with the development of natural fractures, the optimized volumetric fracturing technology was upgraded, and the net pressure in fracture was increased by construction with high pumping rate. Multi-scale filling was realized with the combination of proppants of different sizes, and a gradual pumping rate increase was employed to ensure safe sand adding. Further, a series of temperature-resistant and salt-resistant polymer fracturing fluids were developed. As a result, the key technology was developed for volumetric fracturing in vertical wells of hugely thick shale oil reservoirs in the Fengcheng Formation of the Mahu Sag. This technology has been successfully applied in Well MY1 in the shale oil reservoirs of the Fengcheng Formation, with a high-yield oil flow of 50 m3 per day after stimulation treatment. This started a new and promising prospect of unconventional reservoir exploration in the Mahu Sag, which is of great significance in guiding the subsequent shale oil development in this area.

Gravity data as a faulting assessment tool for unconventional reservoirs regional exploration: The Sergipe–Alagoas Basin example

This paper introduces a gravity regional interpretation workflow for mapping the natural fracture system, a challenge in unconventional reservoir exploration. The workflow comprises coupling two gravity data attributes, the tilt angle and the multiscale edge detection (worming), to build a high-resolution image structural framework of a given basin’s basement. That includes a description of the fault directions and fault density, consolidated in a fault distribution map. The proposed workflow was applied to available gravity data of a representative passive-margin basin, the Sergipe-Alagoas Basin, Brazil. The source rocks of Sergipe-Alagoas are organic-rich shale deposited in the principal depocenters during the rift phase of the basin’s evolution. These shaly units are the unconventional reservoirs in the basin. These organic-rich shales are acknowledged as syn-rift unconventional reservoir analogs of all Brazilian continental margin basins and many other passive-margin basins worldwide. The workflow recognized two fault trends in the studied area. A principal NE–SW and a minor NW–SE. 3D seismic interpretation validated the proposed workflow by successfully associating the gravity faults with traditional fault attributes. One advantage of this workflow is that it can be implemented over broad regions at a minimum expense. The proposed method can be used to rank opportunities in unconventional exploration.

A Novel Approach for Evaluating Gas Saturation Effects on the Phase Reversal Characteristics of Seismic AVO Responses From Strongly Attenuating Reservoirs

Phase reversal is an important feather that can often be observed in seismic amplitude variation versus offset (AVO) analysis. A proper description of phase shift behaviors from a reservoir with multiple pore-fluids, nevertheless, should consider influences of attenuation and velocity dispersion. We propose a novel method here for estimating phase reversals in cases where frequency-dependent attenuation and dispersion are present. Numerical results from the proposed method illustrate that there exist significant variations in terms of magnitude and phase of seismic reflections, between the elastic and anelastic cases. In particular, we observe a gradually continuous phase shift with the angle in place of a phase jump in the elastic model. Numerical results analysis of a frequency-dependent rock physics model indicates a change in gas saturation and fluid patch scale causes apparent impacts on the phase variations from waveform data using the Hilbert transform. The recognition of such phenomena from seismic AVO responses thus offers an obvious potential to strengthen our abilities of detecting hydrocarbon reservoirs. In addition, the proposed method may be of great importance to unconventional reservoir exploration and CO <sub xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">2</sub> changes monitoring in brine-filled reservoirs.

Machine learning for geophysical characterization of brittleness: Tuscaloosa Marine Shale case study

Brittleness is one of the most important reservoir properties for unconventional reservoir exploration and production. Better knowledge about the brittleness distribution can help to optimize the hydraulic fracturing operation and lower costs. However, there are very few reliable and effective physical models to predict the spatial distribution of brittleness. We have developed a machine learning-based method to predict subsurface brittleness by using multidiscipline data sets, such as seismic attributes, rock physics, and petrophysics information, which allows us to implement the prediction without using a physical model. The method is applied on a data set from Tuscaloosa Marine Shale, and the predicted rock physics template is close to the calculated value from conventional inverted elastic parameters. Therefore, the proposed method helps determine areas of the reservoir that have optimal geomechanical properties for successful hydraulic fracturing.

Modeling of Biot’s coefficient for a clay-bearing sandstone reservoir

The exploration of unconventional reservoirs has been vigorously developed with the application of hydraulic fracturing technology in horizontal wells. The success of fracturing depends on the accuracy of the effective stress, which could be considerably influenced by Biot’s coefficient. Biot’s coefficient is mainly influenced by the clay content, porosity, and fluid saturation. Previous studies regarding the calculation of Biot’s coefficient considered only the porosity or porosity structure and are irrational for sandstones with a high clay content and low permeability. A method was conducted to estimate Biot’s coefficient from wave velocities based on the Biot and Squirt (BISQ) poroelasticity theory. It is suggested that the clay content surrounding the skeleton, rather than that in the skeleton, affects the Biot’s coefficient significantly. A clay content coefficient and fluid saturation are considered in the BISQ model. Experiments with samples from four oil fields show that the Biot’s coefficient calculated using our method matches well with those obtained from in situ experiments. It is suggested that the new method for determining Biot’s coefficient is much more suitable for sandstones with low permeability, low porosity, and high clay content, compared to the methods put forward by other studies. In addition, it is proposed to calculate Biot’s coefficient by using seismic or acoustic logging data.

Quick, Easy, and Economic Mineralogical Studies of Flooded Chalk for EOR Experiments Using Raman Spectroscopy

Understanding the chalk-fluid interactions and the associated mineralogical and mechanical alterations on a sub-micron scale are major goals in Enhanced Oil Recovery. Mechanical strength, porosity, and permeability of chalk are linked to mineral dissolution that occurs during brine injections, and affect the reservoir potential. This paper presents a novel “single grain” methodology to recognize the varieties of carbonates in rocks and loose sediments: Raman spectroscopy is a non-destructive, quick, and user-friendly technique representing a powerful tool to identify minerals down to 1 µm. An innovative working technique for oil exploration is proposed, as the mineralogy of micron-sized crystals grown in two flooded chalk samples (Liége, Belgium) was successfully investigated by Raman spectroscopy. The drilled chalk cores were flooded with MgCl2 for ca. 1.5 (Long Term Test) and 3 years (Ultra Long Term Test) under North Sea reservoir conditions (Long Term Test: 130 °C, 1 PV/day, 9.3 MPa effective stress; Ultra Long Term Test: 130 °C, varying between 1–3 PV/day, 10.4 MPa effective stress). Raman spectroscopy was able to identify the presence of recrystallized magnesite along the core of the Long Term Test up to 4 cm from the injection surface, down to the crystal size of 1–2 µm. In the Ultra Long Term Test core, the growth of MgCO3 affected nearly the entire core (7 cm). In both samples, no dolomite or high-magnesium calcite secondary growth could be detected when analysing 557 and 90 Raman spectra on the Long and Ultra Long Term Test, respectively. This study can offer Raman spectroscopy as a breakthrough tool in petroleum exploration of unconventional reservoirs, due to its quickness, spatial resolution, and non-destructive acquisition of data. These characteristics would encourage its use coupled with electron microscopes and energy dispersive systems or even electron microprobe studies.

Characterization of carbonate mudrocks of the Jurassic Tuwaiq Mountain Formation, Jafurah basin, Saudi Arabia: Implications for unconventional reservoir potential evaluation

Organically rich mud rocks are currently targeted for unconventional oil and gas exploration and development in many places around the world, including Saudi Arabia. The Jurassic Tuwaiq Mountain Formation in the Jafurah basin, located east of the giant Ghawar oil field is the primary focus of this paper. The formation has been divided into 3 Tiers possessing varying reservoir qualities. Of these Tiers, the bottom Tier 1 possesses the most excellent shale gas characteristics such as high total organic content (TOC), low clay content and high hydrocarbon saturation. The formation of interest is also in the proper maturity window for hydrocarbon generation and relatively shallow, making it attractive for an economic unconventional shale gas play. To expedite shale gas development in Saudi Arabia, a phased de-risking strategy has been implemented. The strategy consists of four phases; exploration, appraisal, pilot and development. Three wells, representing the first unconventional reservoir exploration wells drilled in the Jafurah basin have been selected for this study. The wells were drilled vertically, cored and logged. Wells were then sidetracked with 5000 ft horizontal laterals and stimulated through multistage hydraulic fracturing. All stimulated wells flowed gas and condensate to surface. This paper summarizes, with examples, a workflow for characterizing the Tuwaiq Mountain Formation as a potential unconventional liquid rich gas play. Crucial to this, is the development of a reservoir quality predictive model for acreage grading, sweet spot identification and fracturing stage selection. This methodical approach is applicable to the evaluation of any emerging unconventional play.

Seismic attributes and kinematic azimuthal analysis for fracture and stress detection in complex geologic settings

Fractured rocks can exhibit good reservoir properties and provide high-permeability passages for hydrocarbons. Understanding fracture and stress systems is a key element in successful horizontal drilling and fracking for unconventional reservoir exploration. As a result, there is growing interest in methods that can estimate fracture orientation, density, and style. However, fracture detection using surface seismic data is challenging, and the results are usually ambiguous. Each method has its own strengths and weaknesses and responds to fractures and compressional stress in different ways. A major uncertainty in fracture analysis based on azimuthally variant seismic velocities is caused by interference from structural effects, localized small-scale velocity anomalies, and directional stress. They can induce azimuthal variation in velocity, which can mask the influence on traveltimes caused by the fractures. To overcome these challenges, we focused on a fracture and compressional stress detection methodology using 3D scanning of azimuthally dependent residual moveout volumes constrained by fracture-sensitive seismic attributes. Our workflow was successfully applied to wide-azimuth, highfold land seismic data acquired over a fractured formation in the northern part of Saudi Arabia, where we were able to map 3D zones with a high probability of fractures and differentiate them from areas with higher compressional stress.