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Wellbore instability has been experienced in areas of the Marcellus Shale and can become particularly troublesome in the superlaterals that are becoming more prevalent in that play. Often the instability while drilling these very long lateral wells is minimal; problems are more likely to occur while tripping out after reaching TD. The most common instability events when pulling out of the hole appear to be tight hole, pack-off and stuck pipe. These problems often worsen with time, indicating there is some time-dependence to the failure mechanism.
In order to develop effective mitigation strategies to combat the instability, it is imperative that the failure mechanism be correctly identified. Previous publications (Kowan and Ong, 2016; Addis et al. 2016; Riley et al. 2012) have suggested that bedding planes may play a role in some of the drilling problems experienced in the Marcellus Shale. In this paper, we will present a case study from the Marcellus that shows conclusive proof of weak bedding plane failure along a lateral well, where thousands of feet of anisotropic failure were captured with a LWD image log.
This image provided confirmation of the presence and failure of weak bedding planes in the Marcellus Shale. The image was also used to validate an existing geomechanical model for the area and gave the operator more confidence in the mitigation strategies developed from that geomechanical model, which had been based on the assumption that weak bedding was contributing to difficulty experienced on multiple lateral wells when tripping out of the hole.
This case study will begin with an overview of the geomechanical model, including the drilling history, stress/pore pressure model and rock properties. Next, some highlights from the image log, showing anisotropic bedding plane failure, will be featured as well as a comparison of the image to the geomechanical model. This case study will conclude with a review of proposed mitigation strategies that could be implemented by the operator to limit the risks posed by weak beds and minimize instability, when drilling laterals in this area, or similarly complex areas, of the Marcellus Shale.
This work compares traditional petrophysical workflows to machine learning methods to compute porosity and permeability in the Inyan Kara Formation of the Dakota Group in the Williston Basin. Quality of dataset (variability, size and robustness), basic theoretical approach, method, results, applicability in the geological area and predictive power are the fundamental basis of this comparison.
Produced water disposal into a shallow Dakota Group presents challenges to nearby development drilling, potentially generating high-pressure zones in the overburden. Accurate pressure prediction for the Dakota is very valuable for drilling design and development timing decisions. Along with disposal volumes, porosity is the critical variable which determines the formation pressure. The Dakota does not contain hydrocarbons resulting in limited porosity log data. However, there are abundant resistivity and gamma ray logs through this interval. Therefore, a data analytics model is used to compute porosity based on location and available resistivity and gamma ray logs. Also, a modified Archie’s equation is used to compute porosity from resistivity and gamma ray data. Data analytics-based porosity and resistivity-based porosity are compared with available neutron-density log derived porosities.
The team working this project comprised a Petrophysicist, Reservoir Engineer and Geologist who compiled, analyzed and built a geo- and reservoir model based on this work to predict formation pressure in the Dakota Sands.
The Williston Basin, North Dakota, has become one of the largest oil producers in the United States. Large volumes of water are being produced along with oil, most of which is disposed in Inyan Kara formation of the Dakota Group. The Dakota Group is situated between the surface and the zones targeted for oil and gas development drilling. Water disposal into this shallower formation presents risks to nearby development drilling, potentially causing high pressure zones in the overburden. Accurate pore pressure predictions for the Dakota Group is very valuable for drilling design decisions. Along with disposal volumes, porosity is the critical variable which determines the formation pressure.
Wang, Lin (Chengdu University of Technology / Guangdong University of Petrochemical Technology) | He, Yong Ming (Chengdu University of Technology) | Xiao, Yi Hang (Chengdu University of Technology) | Wang, Hong Hui (Chengdu University of Technology) | Ma, Fei Ying (Guangdong University of Petrochemical Technology)
The classic Lucas-Washburn imbibition equation is applicable only to homogeneous hydrophilic pores, not to hydrophobic and mixed-wet pores. Shale and coalbed rocks contain water-wet pores, oil-wet pores and mixed-wet pores. To describe water imbibition into these pores, functional relations between flow velocity of gas-water interface, interfacial tension, size of pore, contact angle, viscosity and area fraction of wall have been derived by the Lucas-Washburn equation method of mixed-wet cylindrical capillary. The result of research shows that contact angles and the surface-area fraction of wall combine to determine direction of flow during spontaneous gas-water imbibition in mixed-wet pore. The level-set numerical simulation method was used to verify the result of the Lucas-Washburn equation method, and results of the both methods are roughly consistent. The imbibition equation of mixed-wet pores can be used to determine whether fracturing-fluid imbibition occurs in rocks, and it can also provide a basis for adding wettability alteration additive in fracturing fluid.
Hydraulic fracturing techniques use a variety of chemicals which alter the formation properties in the optimization of fracture initiation and growth. Acids are primarily used to clean perforations to provide an easy flow path into the formation for the fracturing fluid. Additionally, clay stabilizers may be pumped to prevent clay swelling and/or fines migration. These chemicals interact with shale to change its mechanical properties; however, mechanical testing of shale source rocks, especially fissile shale, is extremely difficult because of the limited availability of suitably sized samples and their inherent anisotropy. Nanoindentation provides an alternative technique to measure Young’s modulus and hardness of these rocks and to examine their dependency on chemical exposure. Acids weaken the shale frame and Young’s modulus was found to decrease by 13 to 80% after exposure. The results from acid exposure are evaluated with respect to mineralogy, porosity, microstructure, and other petrophysical properties. Microstructural changes caused by the exposure to acids were observed using a scanning electron microscope (SEM). The significant alterations in Young’s modulus from commonly used additives in fracturing fluids have a potentially large impact on formation damage and fracture performance. Lower values of Young’s modulus could lead to significant reduction in fracture conductivity due to enhanced proppant embedment or damage leading to rock failure. Nanoindentation hardness values decreased by as much as 82% after acid exposure. Knowing the potential formation damage induced by treatment fluids allows an optimal selection of treatment fluids. Better proppant performance can be predicted from the composition of formation, acid exposure, Young’s modulus and hardness responses.
For the spontaneous imbibition, where the driving force is the capillary pressure only, multiple analytical models were developed to analyze the spontaneous uptake of a wetting phase by a porous medium saturated with a nonwetting phase. These models would not accurately represent the fluid loss during hydraulic fracturing because of the impact of the injection pressure. This study, is an attempt to estimate the water relative permeability and capillary pressure curves during the simultaneous effect of the spontaneous imbibition and injection pressure, and compare the results to the spontaneous imbibition case. Therefore, the impact of the pumping pressure on the imbibition capillary pressure and water relative permeability curves would be possible.
Brineflooding experiments were conducted for outcrop samples from the Eagle Ford shale to determine the performance of the upstream pressure over time. The imbibition relative permeability curves were calculated by integrating the upstream pressure versus time relationship using the trapezoidal integration method. Moreover, matching of the Corey equation to the relative permeability was considered to estimate the equivalent Corey water exponent. The calculated brine Corey exponent was two while it was four for the case of spontaneous imbibition. Therefore, the injection pressure enhances the water relative permeability.
The imbibition capillary pressure curve was calculated by simulating the flooding experiments using the ECLIPSE commercial simulator and matching the predicted results to the experimental pressure-time relationship. The injection pressure resulted in positive values for the capillary pressure; moreover, it has no effect on the spontaneous-imbibition capillary pressure.
Predicting well deliverability loss due to condensate banking requires imbibition gas/oil relative permeability as a function of capillary number. These measurements can be difficult to conduct and are often unavailable. It would be of benefit if reasonable estimates of the imbibition relative permeability can be obtained from commonly available drainage data. We use a multiphase lattice Boltzmann method to compute drainage and imbibition gas/oil relative permeability for a Berea Sandstone core. The computations are done on a 3D digital pore space of the core constructed for micro-CT-scan images. The imbibition calculations are for both displacement and dropout processes, and for a range of capillary numbers. These results are then compared to experimental measurements reported in literature as a function of krg/kro and capillary number Nc, and they showed agreement with experimental results for different sandstones.
Stokes, M. Rebecca (Chevron Energy Technology Company) | Yang, Z. Elton (Chevron Energy Technology Company) | Ezebuiro, Prince (Chevron Energy Technology Company) | Fischer, Timothy (Chevron Energy Technology Company)
Measuring the cation exchange capacity (CEC) of clay-bearing rocks is a useful tool to estimate smectite content, or amount of swelling clay in the rock, and is referenced in many aspects of oil and gas exploration. Measuring the CEC of a rock, however, is laborious and depending on the method used requires saturation and extraction steps, the use of multiple chemicals, titration, and spectroscopic analysis. This study builds on the established petrophysical link between clays and relative permittivity (ɛ’r) and outlines a workflow and set of equations that allow for bulk rock CEC to be calculated from permittivity measurements of crushed rock using a handheld dielectric probe. A series of quartz-smectite mineral mixtures were prepared and high-frequency (80 MHz to 1.4 GHz) dielectric measurements collected at six relative humidity (RH) conditions ranging from 8 to 75%. For each RH data set, a strong linear relationship (R2 ≥ 0.98) exists between permittivity values at 120 MHz and the laboratory-measured CEC of the mineral mixtures. The equations from these calibration curves were used to derive three RH-dependent equations and were the basis for developing a relationship between RH, ɛ’r, and CEC. The method was validated on a variety of crushed sedimentary rocks and differences between the calculated values from this study and the laboratory-measured CEC values range ± 6 meq/100g. These results demonstrate that dielectric permittivity measurements on crushed rock can be used as a CEC-proxy and is a fast and flexible alternative to laboratory-based CEC analysis.
Rücker, Maja (Imperial College London / Shell Global Solutions International B.V.) | Bartels, Willem-Bart (Utrecht University / Shell Global Solutions International B.V.) | Bultreys, Tom (Imperial College London / Ghent University) | Boone, Marijn (Tescan XRE) | Singh, Kamaljit (Heriot-Watt University / Imperial College London) | Garfi, Gaetano (Imperial College London) | Scanziani, Alessio (Imperial College London) | Spurin, Catherine (Imperial College London) | Yesufu-Rufai, Sherifat (Imperial College London) | Krevor, Samuel (Imperial College London) | Blunt, Martin J. (Imperial College London) | Wilson, Ove (Shell Global Solutions International B.V.) | Mahani, Hassan (Shell Global Solutions International B.V.) | Cnudde, Veerle (Utrecht University / Ghent University) | Luckham, Paul F. (Imperial College London) | Georgiadis, Apostolos (Imperial College London / Shell Global Solutions International B.V.) | Berg, Steffen (Imperial College London / Utrecht University)
Wettability is a key factor influencing multiphase flow in porous media. In addition to the average contact angle, the spatial distribution of contact angles throughout the porous medium is important, as it directly controls the connectivity of wetting and nonwetting phases. The controlling factors may not only relate to the surface chemistry of minerals but also to their texture, which implies that a length-scale range from nanometers to centimeters has to be considered. So far, an integrated workflow addressing wettability consistently through the different scales does not exist. In this study, we demonstrate that such a workflow is possible by combining microcomputed tomography (μCT) imaging with atomic-force microscopy (AFM). We find that in a carbonate rock, consisting of 99.9% calcite with a dual-porosity structure, wettability is ultimately controlled by the surface texture of the mineral. Roughness and texture variation within the rock control the capillary pressure required for initializing proper crude oil-rock contacts that allow aging and subsequent wettability alteration. AFM enables us to characterize such surface-fluid interactions and to investigate the surface texture. In this study, we use AFM to image nanoscale fluid-configurations in 3D at connate water saturation and compare the fluid configuration with simulations on the rock surface, assuming different capillary pressures.
Connolly, Paul R. J. (The University of Western Australia) | Sarout, Joël (CSIRO Energy) | Dautriat, Jérémie (CSIRO Energy) | May, Eric F. (The University of Western Australia) | Johns, Michael L. (The University of Western Australia)
Here, we report the design and performance of a novel NMR-compatible core holder system allowing for the measurement of both ultrasonic P-wave velocities and NMR relaxation parameters in rock cores at relatively high temperature and pressure conditions. To the authors’ knowledge, this new apparatus represents the first documented example of coupled low-field NMR and ultrasonic measurements of rock cores at reservoir pressure and variable saturation conditions, and allows for a new approach to study pore-scale saturation effects on elastic-wave propagation in rocks. Saturation-wave velocity models usually require some description of fluid saturation and/or distribution and NMR provides a unique ability to measure the local physical and chemical environment of pore fluids. Hence, there are several advantages over other routine core saturation measurements often coupled with ultrasonic measurements, such as resistivity, X-ray tomography or simple fluid volume accounting. Successful validation of our apparatus against a conventional benchtop ultrasonic measurement system was performed using a dry Berea sandstone core, while demonstration of sequential NMR and ultrasonic measurements was performed on a Bentheimer Sandstone core as a function of variable brine and supercritical CO2 saturation (coreflooding conditions).
The Gas Research Institute (GRI) method enabling permeability measurement on crushed samples or drill cuttings was proposed in the early 1990s. This paper presents a study done by Cydarex and Total to (1) analyze the validity of permeabilities determined with GRI methods applied in the industry, (2) collect information about these methods, and (3) explain the discrepancies between the results collected for similar rocks. Three materials were selected: one homogeneous outcrop rock and two reservoir rocks having absolute permeabilities ranging from 1 to 50 nD, and anisotropy ratios varying from 1 to 3. For each rock sample, the permeabilities delivered by three commercial laboratories having their own GRI methods were compared to the permeabilities we derived with our methods, the DarcyPress and the Step Decay dedicated to centimetric core plugs. The laboratories worked on packs of millimetric rock particles. We show that the dispersion in the permeability data increases when the sample characteristic length decreases. In order to better understand the observations, the results were analyzed using the recorded raw pressure data and information on the devices and procedures provided by the laboratories. Furthermore, their experimental pressure signals were compared to numerical signals simulated from our results and their parameters. We demonstrate that the huge discrepancies noticed between permeabilities of crushed samples and permeabilities of core plugs are essentially related to experimental problems. Notably, in the GRI tests performed by the laboratories, the pressure relaxation due to the gas flow in the sample pore network is partially or entirely hidden by the thermal relaxation occurring at the beginning of the test, leading to an erroneous permeability estimation. Lastly, we highlight that more reliable permeability values can be obtained from GRI tests if the method and the device are appropriate.