With the increasing demand for hydrocarbons, unconventional reservoirs are gaining prominence and account for a large percentage of oil and gas production. However, these unconventional reservoirs inevitably include challenges that must be carefully managed while planning an extraction strategy to yield maximum recovery. This paper demonstrates the advantages of an integrated and automated well placement workflow to improve geosteering in complex unconventional reservoirs with maximum hydrocarbon recovery.
Automated well placement technique is controlled by three primary components: (1) an integrated asset model; (2) availability of uninterrupted, real-time log data; and (3) appropriately selected well planning methods. Initially, a dynamically updatable model of subsurface geology is created that combines surface topography, and an initial well trajectory is planned. As the well progresses, new log data are added to the asset model, and an interpretation is made in real time. Incorporating real-time data helps to dynamically update the model and enable a comparison of planned vs. actual deviation surveys for course corrections. This procedure guides the geosteerer to update well plans, run feasibility analyses, and predict subsurface uncertainties ahead of drilling, thus, increasing the reservoir penetration and overall well productivity.
Automated well placement while drilling is a relatively new concept and requires collaboration across various disciplines. Currently, such techniques are gaining importance among operators of unconventional resources as it enhances accuracy in well positioning and provides better production while reducing costs, drilling risks, and uncertainties. In addition, when targeting very thin, geologically complex reservoir layers, it provides a holistic view of the dynamically changing asset. The use of this approach will enable oil and gas operators to make collaborative, cross-domain decisions and streamline existing unconventional workflows.
Fiber optic technology has been used in several wells at an oilfield to measure strain to monitor overburden deformation. The application of this technology involved a series of bench tests and field tests to gather some key learnings to enhance well design, well construction, and fiber optic operation. Prior to installation of the fiber optic, a series of bench tests were conducted to evaluate the coupling of fiber with the capillary lines to determine its impact on the measurement of strain. The testing demonstrated that anchoring the fiber at the top and bottom of the capillary line was sufficient to hold the fiber in place and enabled the effective measurement of strain along the length of the well, which was proven when applied to field conditions. To enhance well design for strain measurement, several wells had fiber optic capillary lines installed on the inside and outside of casing to investigate the potential dampening effect due to fiber being located inside a string of casing. This was used to determine the optimal casing string to install fiber optic to measure strain in the overburden. Additionally, a novel concept was utilized in the well design that involved using the fiber optic capillary clamps as borehole centralizers, which resulted in equipment and rig cost savings. The details of the bench tests, well design, operational experience, and their associated lessons learned are presented.
Obtaining high-resolution borehole images in oil-based mud (OBM) from logging-while-drilling (LWD) tools has been made possible through the recent development of ultrasonic imaging technologies. High-resolution acoustic impedance images enable reservoir evaluation through the identification of faults and fractures, bedding and laminations, and assessment of rock fabric. This paper presents examples of high-resolution images from a 4¾-in. ultrasonic imaging tool in OBM applications and discusses their value in assessing reservoir quality.
This paper provides details of field trials of an LWD ultrasonic imaging tool for use in boreholes ranging from 5¾ to 6¾ in. High-resolution images detailing both borehole caliper and acoustic impedance in both vertical and horizontal wellbores are shown, illustrating the high level of formation evaluation now available when OBM is used. The methodology used to address the impact of tool motion on the impedance images will also be covered. The value of real-time data on borehole stability assessment will be discussed, along with additional applications made possible from the real-time data, such as wellbore placement enhancement.
Both real-time and recorded data from field trials show the potential applications for the ultrasonic imaging tool. High-resolution impedance images covering different formations and lithologies show bedding planes and laminations and enable the calculation of stratigraphic dip, while the identification and assessment of fractures show the potential to aid operators during the development of their hydraulic fracturing program. Borehole caliper and shape assessment in real time can be used to modify the drilling parameters and to adjust mud weight, while providing an input into geomechanics assessment.
The LWD logs presented illustrate the factors that influence data quality and the methodology used to ensure high-resolution images are available in both vertical and high-angle wellbores using OBM. A direct comparison between data acquired while drilling and while re-logging sections is shown, highlighting the repeatability of the measurement while also illustrating the impact of time-since-drilled on the borehole. A comparison with wireline measurements highlights the potential for using the high-resolution LWD images as an alternative to wireline, where cost and risk of deploying the wireline may be high.
The ability to collect high-resolution images in OBM in wellbores ranging from 5¾ to 6¾ in. ensures that increased reservoir characterization is possible, leading to significant improvements in determining the viability of unconventional and other challenging reservoirs. The high-resolution amplitude images are comparable with those available on wireline technologies, and the real-time application of borehole size and shape for input into wellbore stability and geomechanics analysis ensures that common drilling hazards can be avoided.
Cudjoe, Sherifa (University of Kansas) | Barati, Reza (University of Kansas) | Goldstein, Robert (University of Kansas) | Tsau, Jyun-Syung (University of Kansas) | Nicoud, Brian (Chesapeake Energy) | Bradford, Kyle (Chesapeake Energy) | Baldwin, Amanda (Chesapeake Energy) | Mohrbacher, David (Chesapeake Energy)
Huff-n-puff gas injection has proven to be effective for recovering more liquid hydrocarbons from hydraulically fractured and horizontally drilled wells in ultra-tight unconventional shales. The complexity of shales, however, inherent in the variation of mineral microstructure and heterogeneous pore space, makes accurate simulation of the huff-n-puff process for optimum recovery challenging. Therefore, this study deals with the visualization and quantification of the microstructure of Lower Eagle Ford (LEF) shale samples before and after hydrocarbon gas huff-n-puff recovery. This is used to produce reliable estimations of petrophysical (porosity, permeability) and intrinsic rock properties (tortuosity). The petrophysical and intrinsic property estimations measured provide accurate inputs for reservoir simulation for the huff-n-puff process.
The integrated workflow for pore-scale characterization includes scanning electron microscopy/backscattered electron microscopy (SEM/BSE), energy-dispersive X-ray spectroscopy (EDS), and focused ion beam-scanning electron microscopy (FIB-SEM). It includes mineral and maceral identification through elemental analysis, pore size and pore throat distribution, in addition to pore network development. A high pressure, high temperature (HPHT) system is used to expose the samples to hydrocarbon gas for 3 days before repeating the SEM measurements.
The 2-D SEM/BSE images are particularly useful at the micrometer scale, and show sediment particles, wispy seams of kerogen, discrete particles of depositional kerogen, and migrated organic matter embedded in a fine-grained matrix of clays, quartz, coccoliths, foraminifera, organic matter, and unidentifiable particles. Together, the SEM/BSE and FIB-SEM images show nano-scale pores in organic matter, as well as micro-scale intraparticle, interparticle, intercrystalline, breccia and fracture pores of varying sizes and geometries. Much of the pore space is impregnated with variously arranged porous organic matter which comes in later in the paragenesis. FIB-SEM images were utilized in the generation of pore network models. The EDS combined with SEM/BSE reveals spatially distributed diagenetic textures indicating calcite precipitation before pyrite, kaolinite precipitation, compactional fracturing and late migration of organic matter into open pore space. Significant findings include the differentiation of depositional kerogen from migrated organic matter (bitumen or solid bitumen/pyrobitumen). Most porosity is in the migrated organic matter, which has spongy or bubble pores, rather than in depositional kerogen. The pore-scale tortuosity in organic pores averages 1.56, 1.94, and 1.73 for the Lower Eagle Ford (LEF) samples A, B, and C, respectively. The tortuosity of the inorganic pore network is estimated at 1.60. Furthermore, the equivalent pore diameters from pore network models of both the organic and inorganic pores range from 13 nm – 580 nm and 20 nm – 4 μm, respectively. This is important because organic pores developed in both migrated solid bitumen (most common) and depositional kerogen (less common). These organic pore networks create permeability and provide diffusion pathways for gas molecules during the huff-n-puff process. After the hydrocarbon gas injection experiments, the gas exposure was observed to have displaced some of the migrated organic matter. In-situ interaction of injected hydrocarbon gas with bitumen/solid bitumen enhances our understanding of the recovery process.
Butler, Shane (University of North Dakota Energy & Environmental Research Center) | Azenkeng, Alexander (University of North Dakota Energy & Environmental Research Center) | Mibeck, Blaise (University of North Dakota Energy & Environmental Research Center) | Kurz, Bethany (University of North Dakota Energy & Environmental Research Center) | Eylands, Kurt (University of North Dakota Energy & Environmental Research Center)
Advanced characterization of the Bakken Formation, an unconventional oil and gas play of the Williston Basin, was performed via newly developed analytical tools of microscopic investigation in concert with standard laboratory methods. Characterization of an unconventional formation to understand the composition and distribution of framework grains, organic matter (OM), clay minerals, and porosity is difficult because of the extremely lithified nature of the lithofacies within the formation and the small grain and particle sizes. In this study, corroborative methods aimed to define micro- and nanoscale fabrics that impact parameters such as maturity, recovery, clay content, micropore networks, and CO2 interactions for either storage or enhanced oil recovery (EOR). Lateral and vertical variations in the rock fabric across multiple wellsites were observed on a micro- to nanometer scale with innovative analytical technologies.
Detailed morphologies and chemical compositions of ion-milled samples were obtained with field emission scanning electron microscopy (FESEM) coupled with energy-dispersive spectroscopy (EDS). Furthermore, a new software suite, Advanced Mineral Identification and Characterization System (AMICS), was used to classify and quantify mineralogy, OM, and porosity from the FESEM images. For validation purposes, x-ray diffraction was used to obtain bulk mineral and clay mineral data and x-ray fluorescence to obtain bulk chemical compositions of the samples. Advanced image analysis was performed on high-resolution FESEM images as another corroborative approach to characterize key features of interest within the lithofacies. Each sample consisted of high-resolution FESEM backscattered electron (BSE) images taken at multiple magnifications to maximize particle morphology in the fine-grained rock of the unconventional reservoir.
The data highlighted trends related to factors that impact CO2 transport and sorption in unconventional reservoirs. Segmented BSE images from the FESEM using program parameters that included texture, gray scale, and other morphological properties made it possible to estimate OM, clays, and porosity for each sample. The compositional analysis, including matrix porosity, OM porosity, and mineralogical composition maps, provided context for the potential of organic-rich and tight rock formations as CO2- based EOR targets or CO2 storage targets.
Advanced image analysis techniques were applied to better understand and quantify factors that could affect CO2 storage in the Bakken Formation, with an ultimate goal of improved method development to estimate CO2 storage potential of unconventional reservoirs. Discernible differences in fabric, mineral, and elemental content in comparable lithofacies across wellsites provided insight into the nature of the Bakken Formation, which could serve as a proxy for other tight rock, organic-rich reservoirs that could be potential targets for both CO2-based EOR and CO2 storage.
Mejia, Lucas (The University of Texas at Austin) | Mehmani, Ayaz (The University of Texas at Austin) | Balhoff, Matthew (The University of Texas at Austin) | Torres-Verdin, Carlos (The University of Texas at Austin)
We employ microfluidics to capture the impact of several diagenetic processes, including the formation of vugs and fractures, cementation, and grain dissolution, on waterflooding sweep efficiency in diagenetically altered media. Heterogeneous porous media are constructed with glass micromodels using micro-CT images of sandstones in order to mimic chemical and mechanical diagenetic processes typically encountered in subsurface rocks. Cementation was emulated by placing micrograins in intergranular pores, dissolution was introduced by replacing stress-bearing grains with arrays of micrograins, a vug was incorporated into the pore system by removing grains from a circular area in the middle of the matrix domain, and a high-permeability channel was added to study the effect of a natural fracture on flow efficiency.
From the five cases studied, we find porosity-forming processes such as those giving rise to vugs, natural fractures, and grain dissolution, result in the largest increases in recovery efficiency. Secondary pores enhance the merging of fingering dendrites, which results in higher recovery. In addition, the increase in local hydraulic conductivity due to porosity-forming diagenesis directs the fingering dendrites to traverse the middle of the matrix in addition to its boundaries. Modifying the geometry of micromodels according to probable burial stages (paragenesis), allows us to investigate the effect that subsurface conditions have on microscopic sweep and enables a quantitative interdisciplinary method for reducing reservoir development uncertainties.
Pore-scale investigations can reveal dominant underlying fluid flow mechanisms for predicting the sweep efficiency of waterflooding in porous media. In pore-scale numerical modeling, the rock pore space is discretized via meshing or represented by an approximate pore-network depending on the domain size and available computational resources. Core-flood experiments are conducted by imposing a flow rate (or pressure gradient) on the porous medium and measuring the fluid volumes at the outlet. To evaluate microscopic sweep in core floods, pore-scale images of floods performed in small cores can be acquired using fast synchrotron imaging. However, both numerical modeling and core flooding become intractable in tight rocks1 due to resolution limitations for capturing the pore space in representative domain sizes (Bultreys et al., 2016). Microfluidics experiments have the unique ability to provide controlled environments for displacement experiments, including displacement of oil by waterflooding, in short time spans (minutes to hours). In addition, microfluidics devices allow direct visualization of flow and transport at the pore scale, which provides insight for engineering more effective recovery methods for subsequent experiments.
Binder, Gary (Colorado School of Mines) | Titov, Aleksei (Colorado School of Mines) | Tamayo, Diana (Colorado School of Mines) | Simmons, James (Colorado School of Mines) | Tura, Ali (Colorado School of Mines) | Byerley, Grant (Apache Corporation) | Monk, David (Apache Corporation)
In 2017, distributed acoustic sensing (DAS) technology was deployed in a horizontal well to conduct a time-lapse vertical seismic profiling (VSP) survey before and after each of 78 hydraulic fracturing stages. The goal of the survey was to more continuously monitor the evolution of stimulated rock throughout the treatment of the well. From two vibroseis source locations at the surface, time shifts of P-waves were observed along the well that decayed almost completely by the end of the treatment. A shadowing effect in the time shifts was observed that enables the height of the stimulated rock volume to be estimated. Using full wavefield modeling, the distribution of time shifts is well described by an equivalent medium model of vertical fractures that close as pressure declines due to fluid leak-off. Converted P to S waves were also observed to scatter off stimulated rock near some stages as confirmed with full wavefield modeling. The signal-to-noise ratio is a limitation of the current dataset, but recent improvements in DAS technology can enable stage-by-stage monitoring of the stimulated rock height, fracture compliance, and decay time as a well is completed.
Distributed Acoustic Sensing (DAS) has opened new possibilities for seismic monitoring of unconventional reservoirs. Using a laser interrogator to launch light pulses down a fiber optic cable, dynamic strain changes can be sampled along the cable from the phase shift of light backscattered to the interrogator (Hartog, 2017). Since the fiber optic cable can be permanently cemented outside the casing in a borehole, highly repeatable vertical seismic profiling (VSP) surveys can be acquired frequently without costly wireline geophone deployments that interfere with well treatment activities (Mateeva et al., 2017; Meek et al., 2017).
As described by Byerley et al., 2018, a unique interstage DAS VSP survey was conducted in 2017 during the stimulation of a horizontal well targeting the Wolfcamp formation in the Midland Basin, Texas. Using two vibroseis source locations offset about 1 mile from the heel and toe of the well, DAS data was acquired in the treatment well before and after each of 78 hydraulic fracturing stages. At the expense of fewer source locations, this type of acquisition allows the evolution of the stimulated rock volume (SRV) to be monitored on a stage-by-stage basis as the well is treated.
Objectives - Image-Based Rock Physics (IBRP) simulation of petrophysical properties based on sub-micron to micron-scale images of very fine-grain rocks is constrained by the resolution and range of various imaging techniques used. Unlike some conventional sandstone and carbonate reservoir rock where a single Micro-Computed X-ray Tomography (μCT) volume images nearly all of the significant pores and pore throats, many low-permeability rock types contain phase regions with micro-pores and pore throats, including intergranular microcrack pores, that are not accurately resolved at the required μCT scale needed for a representative elementary volume (REV) for the whole rock. Properties for these regions are obtained at a finer-scale or using a different measurement method and these properties then assigned to the phase regions at the larger REV scale. This study explores the methodology involved in obtaining and assigning microcrack properties in μCT rock images and demonstrates a workflow to handle uncertainty in the location and properties of microcracks using two representative low-permeability sandstones.
Methods/Procedures/Process - The workflow combines μCT images of a mini-plug sample (~50mm3), which represents the rock REV, with Focused Ion Beam - Scanning Electron Microscopy (FIB-SEM) images (~200μm3) of regions of various types of observed microporosity (including intergranular microcrack pores) which occur within the REV sample. Different representative types of microporosity regions were imaged and properties calculated from the higher-resolution FIB-SEM image volumes. For some fraction of μCT microporosity regions, such as micro-fractures, their locations in the REV μCT sample was known but the micro-fracture properties were not known. A sub-resolution micro-fracture model was numerically constructed, honoring the mineral facies morphology and microporosity types assigned based on their respective distributions as observed in high resolution SEM images. Resultant porosity, capillary pressure and flow properties on the larger REV volume were cross-validated with independent core analysis measurements.
Results/Observations/Conclusions - This study illustrates a workflow for assigning properties, obtained at finer scales or using other measurement methods, to regions in the REV at larger scale but lower resolution. The resulting rock model produces the same porosity, permeability, and capillary pressure as core analysis measurements, and has the potential to predict relative permeability.
Applications/Significance/Novelty - It is expected that the majority of low-permeability rocks require an upscaling methodology similar to that developed in this study for IBRP computations and integration with core analysis. Using this methodology IBRP offers deeper understanding of building blocks of the upscaled-properties measured by core analysis. IBRP also offers the ability to measure/compute relative permeabilities that are nearly physically impossible to measure on core and the ability to construct digital rocks that allow evaluation of complete suites of rocks and their properties.
Robust links between unconventional pore-scale properties, organic matter, and production trends remain unclear, despite numerous pore-scale characterization studies from various petro-technical disciplines. Specifically, a clear and/or widely agreed upon understanding of kerogen-bitumen-porosity relationships is currently lacking. This work explores an interdisciplinary petrographic methodology to link organic pore-associations and habit to geochemistry and, ultimately, petrophysics. The method directly collocates (overlays) high resolution mosaic scanning electron microscopy (SEM) images with reflected white and UV/fluorescent light images (organic matter petrography analysis), enabling the identification of various kerogen maceral types and bitumen within the monochromatic SEM images. Mosaic SEM images are leveraged to help ensure the statistical representativeness of the characterized area. The consistent application of this integrated imaging workflow across various rock types, maturity, and basins has enabled foundational insights into specific organic-matter porosity associations and trends.
Understanding unconventional reservoirs requires examining the porosity and permeability hosted within the mudrock-based (clay and silt-sized grains; includes claystones, mudstones, chalks, siltstones, shales, etc.) stratigraphy of the petroleum system, typically characterized by low porosity and low permeability. Organic porosity, specifically, has been studied for less than a decade, and there is currently a lack of clear understanding of organic porosity development in unconventional mudstone reservoirs (Katz and Arango, 2018). Due to the small nature of the pore sizes, scanning electron microscopy (SEM) is one method used to characterize nanoporosity hosted in the mineral matrices and/or organic matter (Loucks and Reed, 2014). However, SEM is limited in the ability to differentiate between different organic macerals, or individual organic matter constituents, found in the examined organic-rich shale/mudstone. Traditional methods for definitive organic matter determination include organic petrographic analyses using standard incident white light and UV microscopy under oil immersion. Organic petrography is limited to lower magnifications, approximately 50x magnification, compared to the high-magnification possible with SEM, allowing for resolutions up to approximately 2.5 nm/pixel and, correspondingly, pore features of around 5-10 nm.
The definition of unconventional reservoirs continues to evolve over time as advances in technology make it more viable to extract hydrocarbons. The need for reservoir characterization in such reservoirs, however, will continue to increase to optimize wellbore placement and enhance production. For high-angle or horizontal wellbores common in unconventional drilling, obtaining information from wireline technologies may be either too expensive or risky, although obtaining a wellbore stability assessment while drilling provides a key input into the real-time geomechanical model. This paper presents field test results of a new 4¾-in. ultrasonic imaging logging-while-drilling (LWD) tool that provides a real-time assessment of borehole shape and high-resolution caliper and acoustic impedance images in both water-based mud (WBM) and oil-based mud (OBM) applications.
Images from measurements, such as gamma ray, resistivity, or density, are common in LWD applications. However, high-resolution images have historically been limited to WBM applications. This paper describes the sensor physics and tool configuration that enable the acquisition of borehole caliper and acoustic impedance images in all mud types, with examples of logs obtained while drilling in boreholes using OBM. Details of the comparison with wireline data sets are also given.
Vertical and horizontal wellbores covering different lithologies are described, showing that high-resolution images are now available in slimhole OBM applications. Caliper images illustrate small changes in borehole shape, and impedance images can be used to evaluate geological features and determine stratigraphic dip. The evaluation of caliper data with a wireline multifinger caliper illustrates the potential to eliminate a separate wireline run before completing the well. Comparison of while-drilling data with tripping out of hole data provides crucial insight into wellbore deterioration with time.
The technology described addresses key challenges encountered while drilling and evaluating unconventional reservoirs. Real-time wellbore stability assessment enables optimization of drilling parameters and mud weight in all unconventional reservoirs. Identification of faults and fractures provides valuable information to optimize the hydraulic fracturing program in shale gas applications. Inputs into the geomechanical model are valuable in the assessment of tight sand reservoirs with extremely low porosity and permeability. Limestone reservoirs with minor shale content may require OBM to minimize wellbore deterioration with time. Monitoring such deterioration is critical in optimizing the placement of packers and the hydraulic fracturing program design.
Providing the industry's highest-resolution images in all mud types, even under high logging speeds represents a unique method of assessing real-time wellbore stability and enhancing formation evaluation in slim wellbores in unconventional reservoirs.