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2014 Fall WorkshopDevelopments in Core Analysis The Denver Well Logging Society invites you to attend our 2014 Fall workshop being held Tuesday, October 14th, 2014 at the Colorado School of Mines. Overview: In continuation of the DWLS' workshop tradition, this fall's workshop, Developments in Core Analysis, will be held from 8:00 am to 4:00 pm on Tuesday, October 14th at the Colorado School of Mines. Join us for an all-day workshop focusing on new techniques and technology regarding core and core analysis. Eight different speakers from both the service industry and operators come together to cover topics from NMR, fluid sensitivity, mineralogy and core chemistry. Instructors:
The goal is to learn more about core, about the rocks themselves, and what new information we can get from them that can help in continuing to improve our industry. Please sign up and tell your coworkers to do the same! When: Tuesday, October 14th, 2014 Where: Student Center (1600 Maple St) Registration: Reservations for non-DWLS members is $300, and can be made by clicking here:
DWLS members in good standing as of July 1st and students are eligible for a discount - you should have received a special email or flyer with this discount information. To pay by check contact Kim Mosberger at Reservations@dwls.spwla.org or call 303-770-4235. Payment must be received no later than Monday, September 22nd 2014; after that date, we will release your space reservation. Reservations must be made in advance, walk-ins will not be admitted! If paying by check, make it out to the DWLS, and mail it to (checks must be received by September 22nd): Dominic Holmes Cancellations: Cancellations with a full refund can be made up until the September 22nd deadline by contacting Kim. After that date, no refunds will be made, however, you may send someone else as your replacement (please notify us beforehand). Abstracts: Steady state permeability measurements for tight rocksShreerang S. ChhatreLow porosity and permeability liquid hydrocarbon reservoirs that require hydraulic fracturing, commonly known as "Tight Liquid Reservoirs", have recently received significant attention as a resource for producing oil due to the success of new horizontal well drilling and completion practices, as well as recent market economics. Characterization of these resources, particularly with respect to matrix permeability, is an important factor in determining the producibility and profitability of these resources. Current industry practices to measure permeability on these oil bearing rock samples are similar to those used on gas shale samples, which involves crushing the rocks and conducting measurements on the crushed samples. Such crushed-rock methods have been investigated for gas shales, and a number of publications have indicated the limitations of such methods in characterizing reservoir rocks. In this paper, we present results using a steady-state method to measure liquid permeability on intact tight oil samples under reservoir net confining stress. Our experiments indicate that factors such as stress creep, overburden stress, and type of fluid utilized for permeability measurements could have a significant impact on the measured permeability. Knowledge of these effects enables the development of best practices for tight oil permeability measurements, leading to results that are more representative of the reservoir and enabling more accurate business decisions. Our results indicate that stress creep is significant and slow. Large permeability declines occur during the first several days after stress is applied, and further declines continue for a month or more. Results also show that permeability is highly stress-sensitive, with a strong hysteresis effect. Large permeability declines are observed when the applied stress is increased, and little recovery occurs as the stress is relieved. Mineral-chemistry quantification and petrophysical calibration for multi-mineral evaluationsDouglas K. McCartyThe mineralogical complexity of many reservoirs, especially unconventional self-sourcing types, has led to the increased usage of multi-mineral optimizing of petrophysical evaluations for calculating porosity, water and hydrocarbon volumes. One of the key uncertainties in a petrophysical mineral model is the log response parameter assigned for each tool equation related to each volumetric component being solved for. Default parameter values supplied with vendor software are commonly used and often the petrophysicist needs to modify one or more values using either subjective local knowledge or intuition in order to achieve a result that is considered acceptable. Methods developed by Chevron for calibration of mineral log response parameters using core data include non-linear optimization of whole rock mineralogy and chemistry to obtain mineral structural formulae. Tool response parameters are controlled by the major and trace element chemistry of individual minerals in formation rock matrix along with the pore fluids. Accurate quantitative phase analysis by X-ray diffraction (QXRD) and rigorous sample preparation are especially critical steps in the process. QXRD in combination with aliquot whole rock elemental analyses can be processed using Chevron’s BestRock optimization software to provide refined quantities of the mineral species present in the formation and their structural formula, along with the predicted wireline logging responses of the individual mineral species. Calibrated petrophysical models are built from the information obtained from the QXRD and BestRock results. Application and Quality Control of Core Data for the Development and Validation of Elemental Spectroscopy Log InterpretationSusan HerronCore or cuttings samples are often analyzed for chemical and mineral composition to provide ground truth for developing petrophysical or geological applications or for validating log interpretations of elemental concentrations, mineralogy, and matrix properties. Unfortunately, some core data are inaccurate, but they are rarely subjected to quality control measures and can therefore lead to erroneous conclusions regarding the validity of the log data. For core data, elemental concentrations are generally measured by X-ray fluorescence (XRF) or inductively coupled plasma (ICP) techniques. The best way to validate results from these techniques is to test certified reference materials that are composed of sedimentary minerals similar in composition to samples of interest. Core mineralogy is most commonly analyzed by X-ray diffraction (XRD) or Fourier transform infrared spectroscopy (FTIR). Laboratory results can be evaluated by analyzing known mixtures of certified minerals. Once it has been established that sources of accurate core elemental concentrations and mineralogy are available, it is advisable to implement routine quality control monitoring. An example of a quality control measure is a technique that requires independent analyses for elemental and mineral concentrations. The technique assumes that the minerals have fixed elemental compositions. Measured mineralogy is used to compute elemental concentrations of the major elements, including Si, Al, K, Fe, S, Ca, Mg, and Na. Derived elemental concentrations are compared with the measured elemental concentrations. Deviations between the derived and measured concentrations are used to evaluate the quality of the input data. Examples of both good and poor inputs for elemental and mineral data are shown. Once the quality of the data is proved to be good, it is possible to use the data to validate the accuracy of interpretations developed for elemental spectroscopy logs, such as the closure model to convert concentrations to yields and models to interpret mineralogy. Application of Hydrous Pyrolysis in Petrophysical and Geochemical Studies of Source Rocks at Various Thermal MaturitiesMichael D. LewanUnderstanding changes in petrophysical and geochemical parameters during source rock thermal maturation is a critical component in evaluating source-rock petroleum accumulations. Natural core data are preferred, but obtaining cores that represent the same facies of a source rock at different thermal maturities is seldom possible. An alternative approach is to induce thermal maturity changes by laboratory pyrolysis on aliquots of a source-rock sample of a given facies of interest. Hydrous pyrolysis is an effective way to induce thermal maturity on source-rock cores and provide expelled oils that are similar in composition to natural crude oils. However, net-volume increases during bitumen and oil generation result in expanded cores due to opening of bedding-plane partings. Although meaningful geochemical measurements on expanded, recovered cores are possible, the utility of the core for measuring petrophysical properties relevant to natural subsurface cores is not suitable. This problem created during hydrous pyrolysis is alleviated by using a stainless steel uniaxial confinement clamp on rock cores cut perpendicular to bedding fabric. The clamp prevents expansion just as overburden does during natural petroleum formation in the subsurface. As a result, intact cores can be recovered at various thermal maturities for the measurement of petrophysical properties as well as for geochemical analyses. This approach has been applied to 1.7-inch diameter cores taken perpendicular to the bedding fabric of a 2.3- to 2.4-inch thick slab of Mahogany oil shale from the Eocene Green River Formation. Cores were subjected to hydrous pyrolysis at 360 °C for 72 h, which represents near maximum oil generation. One core was heated unconfined and the other was heated in the uniaxial confinement clamp. The unconfined core developed open tensile fractures parallel to the bedding fabric that result in a 38 % vertical expansion of the core. These open fractures did not occur in the confined core, but short, discontinuous vertical fractures on the core periphery occurred as a result of lateral expansion. Digital Rock What?!*?!* What do you really do with it?AJ KumarRapid, non-destructive screening using high-frequency imaging techniques over a broad size resolution range now provides a possible solution to rock and pore properties estimation. The presentation includes many typical applications of macro-CT scanning from simple visualization to more quantitative petrophysical applications. Image-segmentation, a quantitative visualization technique, provides plenty of applications including quantifying fractures, vug volumes, wormhole development, net-to-gross applications, gas-oil relative permeability visualization etc. Dual-energy x-ray scan-interpreted bulk density, photoelectric effect, effective atomic number, porosity, and lithological interpretation techniques will be explained. Some of these properties can be compared to log response to adjust core to log depths. The high-resolution lithological interpretation helps better selection of sampling points before core is out of aluminum sleeves and detailed description of reservoirs. The use of micro-CT scanner to characterize pore size distribution, estimate permeability and high resolution SEM to characterize pore networks for physical properties prediction will also be reviewed. Multiscale Imaging of Tight Reservoir Core MaterialMark KnackstedtReliable laboratory measurements of static and dynamic properties on tight oil and gas samples are essential for assessment of hydrocarbons in place, recoverable reserves, and productivity estimates. Although accurate plug measurements are important in all rock types, this accuracy becomes critical in the low porosity and permeability range associated with unconventional reservoirs. The low porosity and permeability of these reservoirs creates substantial challenges for existing core measurements methods and has contributed significantly to increased interest in the use of digital rock technology (integrated 3D multi-scale imaging and modeling methods). Imaging technologies can reveal important submicron scale pore structures which enable improved classification and aids quantitative flow modeling in tight reservoir core. Here we discuss the development and testing of a multiple scale imaging and analysis workflow for predicting the petrophysical and multiphase flow properties of tight reservoir core (10 mD < k < 1.0 mD). We illustrate that the methods can assist in developing an understanding of key controls on petrophysical and multiphase flow properties in tight gas reservoir samples. We discuss the opportunities to couple this insight with analogue databases to offer tool to make rapid assessments of reservoir properties in tight reservoir core. Fluid Sensitivity Analyses - When Rocks Behave BadlyMargaret LessengerReservoir rocks can be highly sensitive to fluids introduced through either hydraulic fracturing, water disposal or waterflood injection. Rock fluid sensitivity can lead to reduced permeability and permanent formation damage resulting in reduced productivity or injectivity. It is generally assumed that the clays are the primary culprit in formation damage, either due to swelling, water shock or denigration. In this paper we present results from a two-year effort to understand the fluid sensitivity of tight sand reservoirs in the Greater Monument Butte Field in the Uinta Basin. Newfield drills and completes approximately 200 wells per year in the field and the field is currently under waterflood. Before this study, these wells were completed with fresh water. Initially, we assumed that potential fluid sensitivity was caused by mixed-layer illite-smectite (I/S) when XRD results indicated that some of the reservoir rocks contained pore-bridging I/S. We designed initial core-flood regained permeability experiments combined with core NMR in our primary reservoir rocks to identify and quantify the clay reactions. The completions and field development teams initiated pilot studies in parallel with the core experiments. The results of these initial tests indicated that the reservoirs were sensitive to the completions fluid, but that we did not understand the underlying mechanism. Based on the results, the completions team went to full-field application of 7% KCl fluids for well completions while we tried a new approach involving pore-scale imaging to identify the fluid sensitivity mechanism. SEM combined with EDX imaging of minerals in pores before and after fluid placement helped identify the fluid sensitivity mechanism and was the key to designing new core flood experiments with much improved and understandable results. These new core flood experiments led to optimized completions fluids for the field. The results of this work challenge a number of the commonly-held assumptions of rock-fluid sensitivity and have implications on how to design effective core fluid sensitivity studies. This work involved collaboration between petrophysicists, geologists, engineers, and facilities to design and implement a completions fluid that does not damage multiple reservoirs while remaining cost-effective and reducing well scaling problems. This work demonstrates the value of focused science that challenges commonly-held assumptions within the context of cost constraints and field operations. High Frequency NMR for Tight Rock CoresHarry XieNuclear magnetic resonance (NMR), particularly at low-field, is a powerful tool for both well-logging and rock core analysis in the petroleum industry providing important petrophysical information in reservoir evaluation. In conventional reservoirs, the fundamental physics behind the low-field NMR is that large quantities of hydrogen rich fluids reside in large sized pores enabling simple quantification of relaxation time cut-offs. This is clearly not appropriate for unconventional reservoirs such as shale gas and shale oil where the fast-relaxing fluids of interest reside in the so called bound fluid region. Furthermore, most unconventional rocks exhibit nanometer sized pores, low porosity and permeability. These petrophysical characteristics will in turn lead to much shorter T2’s and low signal intensities, and push the low-field NMR technology to its limit. New techniques and alternative analysis methods have to be explored and deployed to assist in understanding NMR responses from all fluids and solids that may contain hydrogen in tight rocks. Those components include water, hydrocarbons, organic matter, kerogen, etc. In this talk, we will address the technical challenges and difficulties of low-field NMR in analyzing tight rocks and introduce high frequency NMR to the unconventional reservoirs. The reasons and advantages of utilizing high frequency NMR techniques for core analysis will be discussed as additional means to assist in evaluation of total porosity, pore size distribution, fluid content and types. Examples of T1 and T2 data from high frequency NMR will be presented along with T1-T2 maps allowing for more realistic evaluation of tight rocks previously unavailable from conventional NMR testing. The enhanced sensitivity, accuracy and reliability of the high frequency NMR analysis also enable us to develop a novel and rapid screening method to determine water and oil saturations in fresh, tight rocks. |
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