Creating sufficient and sustained fracture conductivity contributes directly to the success of acid-fracturing treatments. The permeability and mineralogy distributions of formation rocks play significant roles in creating nonuniformly etched surfaces that can withstand high closure stress. Previous studies showed that, depending on the properties of formation rock and acidizing conditions (acid selection, formation temperature, injection rate, and contact time), a wide range of etching patterns (roughness, uniform, channeling) could be created that can dictate the resultant fracture conductivity. Insoluble minerals and their distribution can completely change the outcomes of acid-fracturing treatments. However, most experimental studies use homogeneous rock samples such as Indiana limestone that do not represent the highly heterogeneous features of carbonate rocks. This work studies the effect of heterogeneity and, more importantly, the distribution of insoluble rock on acid-fracture conductivity.
In this research, we conducted acid-fracturing experiments using both homogeneous Indiana limestone samples and heterogeneous carbonate rock samples. The Indiana limestone tests served as a baseline. The highly heterogeneous carbonate rock samples contain several types of insoluble minerals such as quartz and various types of clays along sealed natural fractures. These minerals are distributed in the form of streaks correlated against the flow direction, or as smaller nodules. After acidizing the rock samples, these minerals acted as pillars that significantly reduced conductivity-decline rate at high closure stresses. Both X-ray diffraction (XRD) and X-ray fluorescence (XRF) tests were performed to pinpoint the type and location of different minerals on the fracture surfaces. A surface profilometer was also used to correlate conductivity as a function of mineralogy distribution by comparing the surface scans from after the acidizing test to the scans after the conductivity test. Theoretical models considering geostatistical correlation parameters were used to match and understand the experimental results.
Results of our study showed that insoluble minerals with higher-strength mechanical properties were not crushed at high-closure stress, resulting in a less-steep conductivity decline with an increasing closure stress. If the acid etching creates enough conductivity, the rock sample can sustain a higher closure stress with a much lower decline rate compared with Indiana limestone samples. Fracture surfaces with insoluble mineral streaks correlated against the flow direction offer the benefit of being able to maintain conductivity at high closure stress, but not necessarily high initial conductivity. Using a fracture-conductivity model with correlation length, we matched the fracture-conductivity behavior for the heterogeneous samples. Fracture surfaces with mineral streaks correlated with the flow direction could increase acid-fracturing conductivity significantly as compared to the case when the streak is correlated against the flow direction.
The results of the study show that fracture conductivity can be optimized by taking advantage of the distribution of insoluble minerals along the fracture surface and demonstrate important considerations to make the acid-fracturing treatment successful.
Nuclear magnetic resonance (NMR)
Han, Heyleem (University of Oklahoma) | Dang, Son (University of Oklahoma) | Acosta, Juan C. (University of Oklahoma) | Fu, Jing (University of Oklahoma) | Sondergeld, Carl (University of Oklahoma) | Rai, Chandra (University of Oklahoma)
Developing tight shale formations, presents additional challenges due to their vertical and horizontal heterogeneities. Many real-time field decisions, such as lateral placement, are made with the understanding of sequence stratigraphy and a well's petrophysical profile. Handheld X-Ray fluorescence (XRF) has been commonly used as a rapid scanning tool for elemental analysis. Complementary to XRF, handheld Laser Induced Breakdown Spectroscopy (LIBS) has recently been developed, and quickly recognized as a useful tool. It captures the light elements, which XRF cannot, such as sodium, magnesium and more importantly carbon (both organic and inorganic), which are essential elements in understanding rich organic sedimentary rocks. LIBS spectra generally have lower emission signal intensities for dark organic rich samples; therefore, it is important to select optimal integration-delay times to capture better signal intensities for all emission lines ranging from the ultraviolet (180-400nm), through visible light (400-780nm) to infrared (780-960nm). Using a partial least square regression (PLS) and signal normalization, an inversion method was developed for rock slab characterization. The trained dataset includes 150 samples from different tight shale formations, such as Meramec, Woodford, Eagle Ford, Barnett, Bakken, Vaca Muerta and Wolfcamp. The inversion provides quantitative elemental concentrations with reasonable uncertainty. The results were validated with another group of 70 samples from different shale plays. XRF was obtained for the same samples and results showed a good correlation between LIBS and XRF for major elements (Al, Fe, Si, Mg, Si, Ca, K). Total carbon measured through LECO® without acidizing was used to verify LIBS total carbon readings. Mineralogy was inverted from the XRF elemental abundances.; this provided carbonate mineral concentration, which was used to calculate inorganic carbon. Total organic carbon (TOC) was later estimated as the difference between total carbon and inorganic carbon. In this study, we demonstrated the complete elemental analysis on 370-ft of core sampled at a 2-inch depth resolution using XRF and 0.5ft depth resolution using LIBS. Trace elements were used to understand formation chemostratigraphy, while major elements were used to invert for mineralogy, TOC, and to compute a brittleness index profile.
Martini, Brigette (Corescan Inc.) | Bellian, Jerome (Whiting Petroleum Corporation) | Katz, David (Encana Corporation) | Fonteneau, Lionel (Corescan Pty Ltd) | Carey, Ronell (Corescan Pty Ltd) | Guisinger, Mary (Whiting Petroleum Corporation) | Nordeng, Stephan H. (University of North Dakota)
Hyperspectral core imaging studies of the Bakken-Three Forks formations over the past four years has revealed non-destructive, high resolution, spatially relevant insight into mineralogy, both primary and diagenetically altered that can be applied to reservoir characterization. While ‘big’ data like co-acquired hyperspectral imagery, digital photography and laser profiles can be challenging to analyze, synthesize, scale, visualize and store, their value in providing mineralogical information, structural variables and visual context at scales that lie between (and ultimately link) nano and reservoir-scale measurements of the Bakken-Three Forks system, is unique.
Simultaneous, co-acquired hyperspectral core imaging data (at 500 μm spatial resolution), digital color photography (at 50 μm spatial resolution) and laser profiles (at 20 μm spatial and 7 μm vertical resolution), were acquired over 24 wells for a total of 2,870 ft. of core, seven wells of which targeted the Bakken-Three Forks formations. These Bakken-Three Forks data (~5.5 TB) represent roughly 175,000,000 pixels of spatially referenced mineralogical data. Measurements were performed at a mobile Corescan HCI-3 laboratory based in Denver, CO, while spectral and spatial analysis of the data was completed using proprietary in-house spectral software, offsite in Perth, WA, Australia. Synthesis of the spectral-based mineral maps and laser-based structural data, with ancillary data (including Qemscan, XRD and various downhole geophysical surveys) were completed in several software and modelling platforms.
The resulting spatial context of this hyperspectral imaging-based mineralogy and assemblages are particularly compelling, both in small scale micro-distribution as well as borehole scale mineralogical distributions related to both primary lithology and secondary alteration. These studies also present some of the first successful measurement and derivation of lithology from hyperspectral data. Relationships between hyperspectral-derived mineralogy and oil concentrations are presented as are separately derived structural variables. The relationship between hyperspectral-based mineralogy to micro-scale reservoir characteristics (including those derived from Qemscan) were studied, as were relationships to larger-scale downhole geophysical data (resulting in compelling correlations between variables of resistivity and hyperspectral-mineralogy). Finally, basic Net-to-Gross calculations were completed using the hyperspectral imaging data, thereby extending the use of such data from geological characterizations through to resource estimations.
The high-fidelity mineralogical maps afforded by hyperspectral core imaging have not only provided new geological insight into the Bakken-Three Forks formations, but ultimately provide improved well completion designs in those formations, as well as a framework for applying the technology to other important unconventional reservoir formations in exploration and development. The semi-automated nature of the technology also ushers in the ability to consistently and accurately log mineralogy from multiple wells and fields globally, allowing for advanced comparative analysis.
Cronkwright, David (University of Calgary) | Ghanizadeh, Amin (University of Calgary) | DeBuhr, Chris (University of Calgary) | Song, Chengyao (University of Calgary) | Deglint, Hanford (University of Calgary) | Clarkson, Chris (University of Calgary) | Ardakani, Omid (Geological Survey of Canada)
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Denver, Colorado, USA, 22-24 July 2019. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited. Abstract Fluid distribution and fluid-rock interactions within the nano-/macro-porous pore network of tight oil reservoirs will affect both primary and enhanced oil recovery (EOR) processes. Focusing on selected samples obtained from the liquids-rich reservoirs within the Montney Formation (Canada), the primary objective of this work is to evaluate the impact of mineralogical composition on micro-scale fluid distribution at different saturation states: 1) "partially-preserved" and 2) after a series of core-flooding experiments using reservoir fluids (oil, brine) under "in-situ" stress conditions. Small rock chips (cm-sized), sub-sampled from "partially-preserved" (using dry ice) core plugs, were cryogenically frozen and analyzed using an environmental field emission scanning electron microscope (E-FESEM) equipped with X-ray mapping capability (EDS).
Hammon, Helen (Premier Oilfield Group) | Prather, Timothy (Premier Oilfield Group) | Rowe, Harry (Premier Oilfield Group) | Mainali, Pukar (Premier Oilfield Group) | Matheny, Mei (Premier Oilfield Group) | Krumm, Robert (Premier Oilfield Group)
The Latest Pennsylvanian and Early Permian (Wolfcamp, Dean, and Spraberry) interval of the Midland Basin, West Texas, represents a thick (often >1000 ft), mixed succession of shale, carbonate, and siltstone/sandstone lithologies that accumulated in a deep-water marine environment under variable hydrographic restriction. Because the succession is highly heterolithic, it is critical to understand and predict the stratigraphic and lateral variability in lithologic change and assess its impacts on reservoir properties. A highly-resolved (2-inch vertical) x-ray fluorescence-based chemostratigraphic study was undertaken on the Sun Oil D.E. Richards #1 drill core, recovered from Martin Co., TX. The core, while not continuous, contains “windows” of continuous sections of the upper Wolfcamp shale/siltstone through the lowermost Clearfork equivalent strata (Upper Leonard). XRF analysis for major and trace elements was conducted on the slabbed core face for 2567 sample intervals which were calibrated using a set of reference materials from a broad range of mudrock lithologies. In conjunction with XRF sampling, a subset of depth-matched sample powders (n = 229) was collected from the back of the core for mineralogical (XRD) and organic carbon analysis (LECO). A data refinement approach that incorporates elemental results from XRF and mineralogical results from XRD powders is developed to highlight element-mineral linkages and to establish a stoichiometry-derived mineralogy model from the 2-inch XRF data. The XRF-modeled mineralogy can be utilized to resolve sub-log-scale lithological variability and its impacts on rock strength, which are important characteristics to consider for completion optimization and overall drilling strategies in unconventional reservoirs.
Integration of XRD data with the 2-inch XRF data reveals that large-scale changes in elemental concentrations (%Al, Si/Al, %Ca, %Mg) can be interpreted as changes in mineralogical abundances of clays, quartz/clay, calcite, and dolomite, respectively. Furthermore, TOC values can be used to understand the organic variability present in each chemofacies found in this study. A discussion of the chemostratigraphy in the context of mineralogical changes, rock strength changes, and the selection of more detailed analyses (e.g., NMR, rock mechanics) will be undertaken.
Whidden, Katherine (U.S. Geological Survey) | Birdwell, Justin (U.S. Geological Survey) | Dumoulin, Julie (U.S. Geological Survey) | Fonteneau, Lionel (Corescan Pty Ltd) | Martini, Brigette (Corescan Pty Ltd)
The Middle – Upper Triassic Shublik Formation is an organic-rich heterogeneous carbonate-siliciclastic-phosphatic unit that generated much of the oil in the Prudhoe Bay field and other hydrocarbon accumulations in northern Alaska. A large dataset, including total organic carbon (TOC), X-ray diffraction (XRD), X-ray fluorescence (XRF) and inductively coupled plasma – mass spectrometry (ICP-MS) measurements, has been built from core and outcrop samples of the Shublik, with a focus on the organic-rich intervals. In addition, two core intervals from the Shublik were analyzed using a hyperspectral imaging system in the visible, near-infrared and shortwave-infrared range. Integration of the hyperspectral results with core descriptions, microfacies interpretations, and analytical data is being used to decipher mudstone depositional and diagenetic processes.
Petrographic analysis of Upper Triassic organic-rich intervals within the Shublik suggests that the main microfacies is a laminated bioclastic wackestone/packstone that was episodically disrupted by energetic events of variable intensity. These energetic events produced transitional and sparry calcite bioclastic packstone to grainstone intervals, depending on the depth of sediment column disturbance. By using hyperspectral imaging data from the Ikpikpuk core, individual distribution maps for minerals of interest have been generated and corroborate the microfacies interpretations. These maps also illustrate small-scale vertical changes in mineralogy. The laminated bioclastic wackestone/packstone intervals contain less calcite than the adjacent sparry bioclastic packstone to grainstone intervals. The calcite in these laminated intervals is more iron rich. This interpretation suggests that lower iron concentrations should be expected in the disrupted intervals than in nearby laminated intervals. Textural features are also enhanced in the hyperspectral images relative to visual description of the cores by combining the extraction of the average reflectance in the visible part of the electromagnetic spectrum and the depth of the main carbonate-related feature belonging to calcite. Examples noted in the enhanced imagery include low-angle features, calcite grain-size, and the size, shape and orientation of phosphatic nodules. This enhancement is being used to differentiate laminated from sparry bioclastic packstone to grainstone-rich intervals and provides a more comprehensive assessment of the microfacies than is practical by thin-section analysis.
Production from organic-rich shale petroleum systems is extremely challenging due to the complex rock and flow characteristics. An accurate characterization of shale reservoir rock properties would positively impact hydrocarbon exploration and production planning. We integrate large-scale geologic components with small-scale petrophysical rock properties to categorize distinct rock types in low porosity and low permeability shales. We then use this workflow to distinguish three rock types in the reservoir interval of the Niobrara shale in the Denver Basin of the United States: The Upper Chalks (A, B, and C Chalk), the Marls (A, B, and C Marl), and the Lower Chalks (D Chalk and Fort Hays Limestone). In our study area, we find that the Upper Chalk has better reservoir-rock quality, moderate source-rock potential, stiffer rocks, and a higher fraction of compliant micro- and nanopores. On the other hand, the Marls have moderate reservoir-rock quality, and a higher source rock potential. Both the Upper Chalks and the Marls should have major economic potentials. The Lower Chalk has higher porosity and a higher fraction of micro-and nanopores; however, it exhibits poor source rock potential. The measured core data indicates large mineralogy, organic-richness, and porosity heterogeneities throughout the Niobrara interval at all scale.
Unconventional petroleum systems are highly complex hydrocarbon resource plays both at the reservoir scale and at the pore scale (Aplin and Macquaker, 2011; Loucks et al., 2012; Hart et al., 2013; Hackley and Cardott, 2016). These organic-rich sedimentary plays, generally described as shale reservoirs, are composed of very fine silt-and clay-sized particles with grain sizes < 62.5 μm (Loucks et al., 2009; Nichols, 2009; Passey et al., 2010; Kuila et al., 2014; Saidian et al., 2014). They undergo extensive post-depositional diagenesis that transforms rock composition and texture, hydrocarbon storage and productivity, and reservoir flow features (Rushing et al., 2008; McCarthy et al., 2011; Jarvie, 2012; Milliken et al., 2012). Although some shale rock facies can retain depositional attributes during diagenesis, many critical reservoir properties, such as, mineralogy, pore structure, organic richness and present-day organic potential, etc., are significantly perturbed (Hackley and Cardott, 2016).
Rowe, Harry (Data Analytics Consultant / Premier Oilfield Group) | Mainali, Pukar (Premier Oilfield Group) | Nieto, Michael (Premier Oilfield Group) | Grillo, John (Premier Oilfield Group) | Rowe, Harry B. (Data Analytics Consultant)
The interpretation of large geochemical data sets (103 to 105 sample points) and their derivatives are developed, checked for veracity and relevance, optimized, and integrated with associated data sets to address questions regarding lithological heterogeneity, depositional continuity, depositional conditions, diagenesis, and brittleness. A 110-well Delaware Basin XRF-based geochemical data set, largely consisting of 10-feet-resolution cuttings samples that span much of the Wolfcamp through Delaware Mountain Group, are used as an example. Data workflows employing a suite of unsupervised learning techniques (e.g., PCA, HCA) are evaluated to determine the strengths/limitations of each technique, and their collective/comparative utility. Elemental results are used as inputs to stoichiometry-constrained element-to-mineral (E-M) models that yield useful inferences. The strengths of an E-M model rest on the accuracy of the ED-XRF calibration, sample quality, analytical prowess of the ED-XRF analyst, the overall rigorousness of the XRD technique and analyst employed, and the specific approach of the E-M model. Further to this point, derivatives of the XRF-based modeled mineralogy, such as a mineral brittleness index (mBI) and derived chemofacies, are only as good as the analytical underpinnings of the inputs. Modern core- and cuttings-based stratigraphic studies frequently incorporate an inorganic geochemical component, often acquired with portable energy-dispersive x-ray fluorescence (ED-XRF). Despite the analytical limitations of the ED-XRF approach, the use of this technique yields large, quantitative data sets collected at the length-scale of inches (cores) to feet (cuttings). In their raw elemental form, these data sets provide additional correlation and lithological control at scales just above (core), to just below (cuttings) the scale of most downhole log suites. The significance of this approach is that it can be used to 1) refine rock signatures in well logs, and 2) resolve questions regarding stratigraphic succession and correlation. While the initial focus of the study is to reconstruct the spatial distribution of lithologies at the scale of cuttings sample collection (10 feet), the overarching goal of the project is to optimize the interpretation of log signatures through the addition of data generated from the rock. This approach has cross-disciplinary implications, including refinement of petrophysical, geomechanical, and regional geological models. The modeled mineralogy from the chemostratigraphy results has direct implications for modeling fluid-rock compatibility and the overall completions process, including a more strategic selection of stage lengths.
Elastic properties of unconventional rock, including gas/oil shale and tight gas sand (TGS), are crucial in hydraulic fracture modeling. The two most important rock elastic properties are Young's modulus and Poisson's ratio. These properties can be determined from sonic well logs, but the required logs (compressional and shear velocity) are not always available. These properties can be measured from plug samples using a triaxial load frame, but these tests are slow, expensive, and require an intact cylindrical sample.
An alternative is to use rock physics modeling applied to mineralogy and porosity computed from ion-milled scanning electron microscope (SEM) images to compute elastic constants from small rock fragments. This method can also be applied to data from whole core computed tomography (CT) scans. This approach was used to develop a digital rock workflow to compute elastic properties from rotary sidewalls cores, drill cuttings, and core CT data.
The new approach combines quantitative information obtained from 2D ion-milled SEM images with rock physics effective-medium models, the latter used to relate volume properties to elastic properties. These models can be obtained from wireline and/or laboratory measurements of bulk rock volumetrics together with elastic rock properties. This process of finding a rock physics model is called rock physics diagnostics.
The SEM images provide porosity, organic matter volume, and pore structure. The mineralogy of the sample obtained through quantitative X-ray diffraction (XRD) is added to those inputs. Well log data relevant to the local area are then used to establish a rock physics model linking the elastic properties to porosity, organic matter content, and mineralogy. These models are established for each basin and formation, based on available wireline log data. High quality wireline data is key to successful rock physics diagnostics (RPD).
In this study, wireline logs and core samples were obtained from a well in Culberson Co, TX. The zone of interest in this case was the Wolfcamp A formation. After establishing the appropriate rock physics effective medium models, the elastic properties were computed, including Young's modulus, Poisson's ratio, compressional wave velocity, and shear wave velocity from SEM images and XRD mineral data. The computed, upscaled elastic properties closely matched the log variability.
This method can be used to obtain the required elastic properties from wells that lack compressional and dipole shear wave data. This mechanical properties data can be used to compute horizontal stress, unconfined compressive strength, and other critical properties that control hydraulic fracture growth. In many cases, drill cuttings can be used for the SEM analysis. This new approach does not require cores, and so can be especially valuable in quantifying elastic and mechanical properties along the lateral wellbore where wireline logs are seldom available.