Browsing by Subject "Petrophysics"
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Item Comparative study for the interpretation of mineral concentrations, total porosity, and TOC in hydrocarbon-bearing shale from conventional well logs(2012-08) Adiguna, Haryanto; Torres-Verdín, Carlos; Balhoff, MatthewThe estimation of porosity, water saturation, kerogen concentration, and mineral composition is an integral part of unconventional shale reservoir formation evaluation. Porosity, water saturation, and kerogen content determine the amount of hydrocarbon-in-place while mineral composition affects hydro-fracture generation and propagation. Effective hydraulic fracturing is a basic requirement for economically viable flow of gas in very-low permeability shales. Brittle shales are favorable for initiation and propagation of hydraulic fracture because they require marginal or no plastic deformation. By contrast, ductile shales tend to oppose fracture propagation and can heal hydraulic fractures. Silica and carbonate-rich shales often exhibit brittle behavior while clay-rich shales tend to be ductile. Many operating companies have turned their attention to neutron capture gamma-ray spectroscopy (NCS) logs for assessing in-situ mineral composition. The NCS tool converts the energy spectrum of neutron-induced captured gamma-rays into relative elemental yields and subsequently transforms them to dry-weight elemental fractions. However, NCS logs are not usually included in a well-logging suite due to cost, tool availability, and borehole conditions. Conventional well logs are typically acquired as a minimum logging program because they provide geologists and petrophysicists with the basic elements for tops identification, stratigraphic correlation, and net-pay determination. Most petrophysical interpretation techniques commonly used to quantify mineral composition from conventional well logs are based on the assumption that lithology is dominated by one or two minerals. In organic shale formations, these techniques are ineffective because all well logs are affected by large variations of mineralogy and pore structure. Even though it is difficult to separate the contribution from each mineral and fluid component on well logs using conventional interpretation methods, well logs still bear essential petrophysical properties that can be estimated using an inversion method. This thesis introduces an inversion-based workflow to estimate mineral and fluid concentrations of shale gas formations using conventional well logs. The workflow starts with the construction and calibration of a mineral model based on core analysis of crushed samples and X-Ray Diffraction (XRD). We implement a mineral grouping approach that reduces the number of unknowns to be estimated by the inversion without loss of accuracy in the representation of the main minerals. The second step examines various methods that can provide good initial values for the inversion. For example, a reliable prediction of kerogen concentration can be obtained using the ΔlogR method (Passey et al., 1990) as well as an empirical correlation with gamma-ray or uranium logs. After the mineral model is constructed and a set of initial values are established, nonlinear joint inversion estimates mineral and fluid concentrations from conventional well logs. An iterative refinement of the mineral model can be necessary depending on formation complexity and data quality. The final step of the workflow is to perform rock classification to identify favorable production zones. These zones are selected based on their hydrocarbon potential inferred from inverted petrophysical properties. Two synthetic examples with known mineral compositions and petrophysical properties are described to illustrate the application of inversion. The impact of shoulder-bed effects on inverted properties is examined for the two inversion modes: depth-by-depth and layer-by-layer. This thesis also documents several case studies from Haynesville and Barnett shales where the proposed workflow was successfully implemented and is in good agreement with core measurements and NCS logs. The field examples confirm the accuracy and reliability of nonlinear inversion to estimate porosity, water saturation, kerogen concentration, and mineral composition.Item Fast forward modeling and inversion of borehole sonic measurements using spatial sensitivity functions(2015-05) Huang, Shan, Ph. D.; Torres-Verdin, Carlos; Sepehrnoori, Kamy; Olson, Jon E; Sharma, Mukul M; Spikes, Kyle TBorehole sonic measurements are widely used by petrophysicists to estimate in-situ dynamic elastic properties of rock formations. The estimated formation properties typically guide the interpretation of seismic amplitude measurements in the exploration and development of hydrocarbon reservoirs. Due to limitations in vertical resolution, borehole sonic measurements (sonic logs) provide spatially averaged values of formation properties in thinly bedded rocks. In addition, mud-filtrate invasion and near-wellbore formation damage can bias the elastic properties estimated from sonic logs. The interpretation of sonic logs in high angle (HA) and horizontal (HZ) wells is even more challenging because of three-dimensional geometrical effects and anisotropy. A reliable approach to account for geometrical effects in the interpretation of sonic logs is the implementation of forward modeling and inversion techniques. However, the computation time required to model the direct problem, namely wave propagation in the borehole environment, severely constraints the usage of inversion approaches in sonic-log interpretation. This dissertation develops new methods for the rapid simulation of sonic logs using the concept of spatial sensitivity functions. Sonic spatial sensitivity functions are equivalent to the Green’s function of a particular sonic measurement; they also serve as weighting matrices to map formation elastic properties into the respective measurement space. Application of sensitivity functions to challenging synthetic examples verifies that the maximum relative error in the modeled sonic logs is lower than 3% for flexural, Stoneley, and compressional (P-) and shear (S-) modes. Compared to rigorous numerical simulations, the new fast sonic modeling method reduces computation time by 98%. Using the fast sonic simulation algorithm, we develop an inversion method that combines multi-frequency flexural dispersion and P- and S- mode slowness logs to estimate layer-by-layer compressional and shear slownesses of rock formations. Synthetic verification examples as well as interpretation of field cases indicate that the estimated formation compressional and shear slownesses are within 3% of true model properties, exhibiting a maximum uncertainty of 6%. When compared to conventional sonic-log interpretation, the new inversion-based method effectively reduces shoulder-bed effects and relative errors in estimated properties by 15%, while the vertical resolution of sonic logs is improved from 1.83 m to 0.5 m. Finally, we show that multi-mode wave interference in HA/HZ wells makes it difficult to identify the low-frequency slowness asymptote of the flexural mode. We extend the sensitivity method to three dimensions to approach this latter problem and to model high-frequency dispersion logs. Because the calculated P-mode slowness log exhibits strong dependence to processing parameters, conventional waveform semblance-based processing becomes inadequate in HA wells. We introduce a new P-arrival slowness log to circumvent wave mode interference and to avoid semblance calculations. Additionally, we also develop a one-dimensional integration method to rapidly model P-arrival slowness logs when HA/HZ wells penetrate anisotropic thin beds. The fast modeling algorithm generates synthetic logs that match sonic logs simulated with rigorous modeling procedures within 5% while providing a 99% reduction in computation time.Item Integrated geological and petrophysical investigation on carbonate rocks of the middle early to late early Canyon high frequency sequence in the Northern Platform area of the SACROC Unit(2013-12) Isdiken, Batur; Fisher, W. L. (William Lawrence), 1932-; Torres-Verdín, CarlosThe SACROC unit is an isolated carbonate platform style of reservoir that typifies a peak icehouse system. Icehouse carbonate platforms are one of the least well understood and documented carbonate reservoir styles due to the reservoir heterogeneities they embody. The current study is an attempt to recognize carbonate rock types defined based on rock fabrics by integrating log and core based petrophysical analysis in high-frequency cycle (HFC) scale sequence stratigraphic framework and to improve our ability to understand static and dynamic petrophysical properties of these reservoir rock types, and there by, improve our understanding of heterogeneity in the middle early to late early Canyon (Canyon 2) high frequency sequence (HFS) in the Northern Platform of the SACROC Unit. Based on core descriptions, four different sub-tidal depositional facies were defined in the Canyon 2 HFS. Identified depositional facies were grouped into three different reservoir rock types in respect to their rock fabrics in order for the HFC scale petrophysical reservoir rock type characteristic analysis. Composed of succession of the identified reservoir rocks, twenty different HFCs were determined within the HFC scale sequence stratigraphic framework. The overall trend in the HFCs demonstrate systematic coarsening upward cycles with high reservoir quality at the cycle tops and low reservoir quality at the cycle bottoms. It was observed in terms of systems tracts described within the cycle scale frame work that the overall stacking pattern for high stand systems tracts (HST) and transgressive systems tracts (TST) is aggradational. And, the reservoir rocks representing the HST are more porous and permeable than those of TST. In addition to that, it was detected that the diagenetic overprint on the HST reservoir rocks is more than that of the TST. According to the overall petrophysical observations, the grain-dominated packstone deposited during HST was interpreted as the best reservoir rock. Upon well log analysis on the identified reservoir rocks, some specific log responses were attributed to the identified reservoir rocks as their characteristic log signatures.Item Inversion-based petrophysical interpretation of logging-while-drilling nuclear and resistivity measurements(2013-08) Ijasan, Olabode; Torres-Verdín, CarlosUndulating well trajectories are often drilled to improve length exposure to rock formations, target desirable hydrocarbon-saturated zones, and enhance resolution of borehole measurements. Despite these merits, undulating wells can introduce adverse conditions to the interpretation of borehole measurements which are seldom observed in vertical wells penetrating horizontal layers. Common examples are polarization horns observed across formation bed boundaries in borehole resistivity measurements acquired in highly-deviated wells. Consequently, conventional interpretation practices developed for vertical wells can yield inaccurate results in HA/HZ wells. A reliable approach to account for well trajectory and bed-boundary effects in the petrophysical interpretation of well logs is the application of forward and inverse modeling techniques because of their explicit use of measurement response functions. The main objective of this dissertation is to develop inversion-based petrophysical interpretation methods that quantitatively integrate logging-while-drilling (LWD) multi-sector nuclear (i.e., density, neutron porosity, photoelectric factor, natural gamma ray) and multi-array propagation resistivity measurements. Under the assumption of a multi-layer formation model, the inversion approach estimates formation properties specific to a given measurement domain by numerically reproducing the available measurements. Subsequently, compositional multi-mineral analysis of inverted layer-by-layer properties is implemented for volumetric estimation of rock and fluid constituents. The most important prerequisite for efficient petrophysical inversion is fast and accurate forward models that incorporate specific measurement response functions for numerical simulation of LWD measurements. In the nuclear measurement domain, first-order perturbation theory and flux sensitivity functions (FSFs) are reliable and accurate for rapid numerical simulation. Albeit efficient, these first-order approximations can be inaccurate when modeling neutron porosity logs, especially in the presence of borehole environmental effects (tool standoff or/and invasion) and across highly contrasting beds and complex formation geometries. Accordingly, a secondary thrust of this dissertation is the introduction of two new methods for improving the accuracy of rapid numerical simulation of LWD neutron porosity measurements. The two methods include: (1) a neutron-density petrophysical parameterization approach for describing formation macroscopic cross section, and (2) a one-group neutron diffusion flux-difference method for estimating perturbed spatial neutron porosity fluxes. Both methods are validated with full Monte Carlo (MC) calculations of spatial neutron detector FSFs and subsequent simulations of neutron porosity logs in the presence of LWD azimuthal standoff, invasion, and highly dipping beds. Analysis of field and synthetic verification examples with the combined resistivity-nuclear inversion method confirms that inversion-based estimation of hydrocarbon pore volume in HA/HZ wells is more accurate than conventional well-log analysis. Estimated hydrocarbon pore volume from conventional analysis can give rise to errors as high as 15% in undulating HA/HZ intervals.Item Mixing laws and fluid substitution for interpretation of magnetic resonance measurements(2016-12) Ravi, Vivek R; Torres-Verdin, CarlosNuclear magnetic resonance (NMR) relaxation time measurements are affected by pore structure and saturating fluids. Interpretation of NMR distributions as pore-size distributions and estimation of permeability from NMR logs using methods such as the Schlumberger Doll Research (SDR) model assume a homogeneous surface relaxivity and remain reliable only for measurements obtained from homogeneous single-fluid saturated rocks. However, heterogeneous rock formations commonly consist of laminations, vugs, and a mixed solid composition, which result in non-uniform values of surface relaxivity. Furthermore, most rock formations penetrated by wells contain multiple fluids and are commonly affected by mud-filtrate invasion. Therefore, presence of spatial heterogeneity and multiple fluids in rock formations render the petrophysical interpretation and analysis of longitudinal relaxation time T1 and transverse relaxation time T2 measurements challenging. Thus, it is necessary to correct for spatial heterogeneity by decomposing the NMR response of the heterogeneous formation into that of its homogeneous components. Presence of multiple fluids is corrected by replacing the hydrocarbon NMR response in the original logs with the corresponding water response in order to obtain NMR distributions of the 100% water saturated formation. Subsequently, the petrophysical quantities of interest such as permeability and pore-size distribution are determined. NMR mixing laws define the physics of how NMR data from different homogeneous components combine. It was observed that a linear mixing law best describes a laminated formation and a non-linear mixing law best describes a dispersed formation. In this work, NMR mixing laws are derived and applied to give a better interpretation of NMR logs obtained from highly heterogeneous formations by extracting the NMR distributions of each homogeneous component. A physics-based NMR fluid substitution method is also developed, which takes into account capillary-pressure effects and pore-size distributions and does not require knowledge of permeability and surface relaxivity. The method consists of two steps. First, the hydrocarbon NMR response is removed from the initially water-hydrocarbon saturated NMR data. Next, the NMR distribution of the resulting hydrocarbon-depleted system is transformed to that of a completely water-saturated system. Several laboratory measurements and field cases are used to successfully verify the mixing laws and the fluid substitution method.Item Relationship between pore geometry, measured by petrographic image analysis, and pore-throat geometry, calculated from capillary pressure, as a means to predict reservoir performance in secondary recovery programs for carbonate reservoirs.(2009-05-15) Dicus, Christina MarieThe purpose of this study was first to develop a method by which a detailed porosity classification system could be utilized to understand the relationship between pore/pore-throat geometry, genetic porosity type, and facies. Additionally, this study investigated the relationships between pore/pore-throat geometry, petrophysical parameters, and reservoir performance characteristics. This study focused on the Jurassic Smackover reservoir rocks of Grayson field, Columbia County, Arkansas. This three part study developed an adapted genetic carbonate pore type classification system, through which the Grayson reservoir rocks were uniquely categorized by a percent-factor, describing the effect of diagenetic events on the preservation of original depositional texture, and a second factor describing if the most significant diagenetic event resulted in porosity enhancement or reduction. The second part used petrographic image analysis and mercury-injection capillary pressure tests to calculate pore/pore-throat sizes. From these data sets pore/pore-throat sizes were compared to facies, pore type, and each other showing that pore-throat size is controlled by pore type and that pore size is controlled primarily by facies. When compared with each other, a pore size range can be estimated if the pore type and the median pore-throat aperture are known. Capillary pressure data was also used to understand the behavior of the dependent rock properties (porosity, permeability, and wettability), and it was determined that size-reduced samples, regardless of facies, tend to show similar dependent rock property behavior, but size-enhanced samples show dispersion. Finally, capillary pressure data was used to understand fluid flow behavior of pore types and facies. Oncolitic grainstone samples show unpredictable fluid flow behavior compared to oolitic grainstone samples, yet oncolitic grainstone samples will move a higher percentage of fluid. Size-enhanced samples showed heterogeneous fluid flow behavior while the size-reduced samples could be grouped by the number of modes of pore-throat sizes. Finally, this study utilized petrographic image analysis to determine if 2- dimensional porosity values could be calculated and compared to porosity values from 3-dimensional porosity techniques. The complex, heterogeneous pore network found in the Grayson reservoir rocks prevents the use of petrographic image analysis as a porosity calculation technique.Item Rock Classification in Organic Shale Based on Petrophysical and Elastic Rock Properties Calculated from Well Logs(2015-01-05) Aranibar Fernandez, Alvaro AThis thesis introduces a rock classification technique for organic-rich shale that takes into account well-log-based estimates of compositional, petrophysical, and elastic properties. Well logs and laboratory core measurements were used to calculate depth-by-depth petrophysical and compositional properties of three wells in two organic-rich formations. Then, either acoustic well logs or effective medium theories helped estimate formation elastic properties. Estimates of total porosity, Total Organic Content (TOC), fluid saturation, volumetric concentrations of mineral constituents, and elastic properties facilitated identification of different rock classes, using an unsupervised artificial neural network. A good rock classification technique improves (a) petrophysical evaluation of organic-rich shale reservoirs, (b) fluid flow characterization, (c) detection of productive zones for fracturing jobs, and (d) prediction of hydraulic fracturing and stimulation effectiveness. Then, a rock classification method was then applied to the field examples from the Haynesville shale and Woodford shales for rock classification. The estimates of porosity, TOC, bulk modulus, shear modulus, and volumetric concentrations of minerals were obtained and then validated by comparing them to laboratory measurements. These calculated properties and well logs served as inputs to an artificial neural network to identify the different rock classes in both formations. Finally, the rock classes enabled identification of good candidate zones for fracture stimulation.Item Tool design, physics and interpretation of neutron-gamma density(2016-05) Luycx, Mathilde Michèle; Torres-Verdín, Carlos; Schneider, ErichChemical radioactive sources pose health, safety, and environmental risks. Pulsed neutron generators have replaced Americium/Beryllium sources for the measurement of neutron porosity. However, Cesium 137 (Cs-137) is still mainly used to measure bulk density. Neutron-Gamma density is a new radioisotope-free measurement of density based on neutron-induced inelastic gamma rays. The first part of this report reviews relevant literature to the Neutron-Gamma density measurement and to the modeling of nuclear logging tools. The second part of this report investigates the nuclear physics behind Neutron-Gamma density and presents the development of a tool design optimized for the measurement. The third part of this report regards the development of a real-time interpretation algorithm. The objective of the algorithm is to correct for the changes in spatial distribution and source strength of the neutron-induced gamma ray source. These source variations are caused by fast neutron transport. Therefore, the interpretation algorithm has inputs of fast neutron and gamma ray counts. We achieve an accuracy of 0.019 g/cm3 in clean formation and 0.034 g/cm3 in shale and shaly formations. In the last part of this report, we study some of the measurement limitations regarding the density range and the influence of standoff. The algorithm does not accurately estimate higher densities (densities greater than 2.89 g/cm3) and standoff should be kept to a maximum of 0.25 inch for light mud. Finally, the depth of investigation of Neutron-Gamma Density is twice the depth of investigation of Gamma-Gamma Density. This work is presented as part of the PhD fast track option and will be extended to a PhD dissertation in the future.Item Using 3D printing for the instruction of petrophysical properties(2014-08) Dees, Elizabeth Ann; Prodanović, Maša; Allen, David T.With the recent increase in natural gas production, the demand for college educated petroleum engineers has increased. A greater number of high school graduates are now applying to petroleum engineering degree programs, however, the admission requirements to petroleum engineering schools are becoming increasingly stricter. Secondary educators have a greater challenge to better prepare students to compete for these positions and there is a need to introduce petrophysical concepts to students in the most effective manner. One petrophysical concept is porosity of rock. In this report, background information on rock formation and porosity of rocks is provided along with a brief summary on how 3D printers operate. But primarily, a lesson plan is presented to teach rock porosity in a novel way using 3D printed enlargements of porous rock from x-ray microtomography images of packed sand. The hypothesis was that students will gain greater understanding of petrophysical properties when using 3D prints of rocks. The porosity lesson with a lab using the 3D printed rocks was taught to a treatment group of 20 upcoming 6th graders. A porosity lesson without the use of 3D printed rocks was didactically taught to a control group of 14 additional 6th graders. Because of time limitations, not all of the students from the treatment group were able to experience all elements of the lab. However, every student in the control group received instruction and practice on how to calculate porosity of rock. The treatment group showed greater gain in learning the abstract concept about porosity that rocks of similar structure will have equivalent porosity regardless of grain size. However, the control group indicated greater gain learning the fundamental concepts of the definition of porosity, how to calculate porosity, and at being able to transfer their knowledge of percent porosity to a general problem about percentages. Despite the limited sample size and other sources of error, using 3D printed enlargements of rock was found to enhance students’ abilities to visualize abstract petrophysical properties. However, benefits from didactic instruction of fundamental concepts of petrophysical properties were found as well.