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The objective of this research is to develop and test a new concept for predicting permeability from routine rock properties. First, we develop a model predicting permeability as a function of capillary pressure. Our model, which is based on the work by Purcell, Burdine and Wyllie and Gardner models, is given by: (Equation 1 - See PDF) Combining the previous equation and the Brooks and Corey model for capillary pressure, we obtain: (Equation 2 - See PDF) The correlation given by this equation could yield permeability from capillary pressure (and vice-versa). This model also has potential extensions to relative permeability (i.e., the Brooks and Corey relative permeability functions) - which should make correlations based on porosity, permeability, and irreducible saturation general tools for reservoir engineering problems where relative permeability data are not available. Our study is validated with a large range/variety of core samples in order to provide a representative data sample over several orders of magnitude in permeability. Rock permeabilities in our data set range from 0.04 to 8700 md, while porosities range from 0.3 to 34 percent. Our correlation appears to be valid for both sandstone and carbonate lithologies.

This work presents the validation and enhancement of existing correlations for estimating and predicting the permeability in low permeability gas sands. The "original" problem of predicting the corrected or "liquid equivalent" permeability has been under investigation since the early 1940s — in particular, using the application of "gas slippage" theory to petrophysics by Klinkenberg. In the first part of this work, the viability of the Jones-Owens and Sampath-Keighin correlations for estimating the Klinkenberg-corrected (absolute) permeability from single-point, steady-state measurements were investigated. We also provide an update to these correlations using modern petrophysical data. In the second part of this work we proposed and validated a new "microflow" model for the evaluation of an equivalent liquid permeability from gas flow measurements. This work was based on a more detailed application of similar concepts employed by Klinkenberg. In fact, we obtained the Klinkenberg result as an approximate form of this result. A theoretical "microflow" result was given as a rational polynomial (i.e., a polynomial divided by a polynomial) in terms of the Knudsen number (ratio of the mean free path of the gas molecules to the characteristic flow length (typically the radius of the capillary)), and this result can be applied as an explicit correlation device, or as an implicit prediction model (presuming the model is tuned to a particular data set). The following contributions are derived from this work: ● Validation and extension of the correlations proposed by Jones-Owens and Sampath-Keighin for low permeability samples. ● Development and validation of a new "microflow" model which correctly represents the flow of gases in low permeability core samples. This model is also applied as a correlation for prediction of the equivalent liquid permeability in much the same fashion as the Klinkenberg model, although the new model is substantially more theoretical (and robust) as compared to the Klinkenberg correction model.

In many carbonate reservoirs, much of the porosity is in the form of micropores (with diameter 1-10 microns). This porosity lies far below the resolution of any conventional wireline logging tools and can only be observed through the analysis of extracted core. To investigate the spatial distribution of the microporosity over a large range of length scales requires accurate depth matching of extracted core to wireline data. With such a correlation up- and down-scaling relationships can be developed between porosity relationships observed at different length scales. The scaling relationships can then be used to infer the distribution of microporosity in regions of the borehole without extracted core. This thesis presents a new, general method for the accurate correlation of extracted core to wireline logs using their statistical properties. The method was developed using an X-ray computed tomography (CT) scan of a section of extracted carbonate core and well log data from the so-called Fullbore MicroImager (FMI) resistivity tool. Using geological marker features the extracted core was constrained to correspond to a 2ft (609mm) section of FMI data. Using a combination of statistics (mean, variance and the range from variograms of porosity), combined in a likelihood function, the correlation was reduced to an uncertainty of 0.72" (18.29mm). When applied to a second section of core, the technique reduced the uncertainty from 2ft (609mm) down to 0.3ft (91mm). With accurate correlation between core and wireline logs, the scaling relationships required to transfer porosity information between scales could be investigated. Using variogram scaling relationships, developed for the mining industry, variograms from the CT scan were up-scaled and compared with those calculated from associated FMI data. To simulate core samples in regions of the borehole without extracted core, two statistical simulation techniques were developed. The techniques both capture twopoint spatial statistics from binarised, horizontal slices of FMI data. These statistics iv are combined to obtain multi-point statistics, using either neighbourhood averaging or least squares estimation weighted by variance. The multi-point statistics were then used to simulate 2-D slices of 'virtual' core. Comparisons between the two techniques, using a variety of features, revealed that the neighbourhood averaging produced the most reliable results. This thesis thus enables, for the first time, core-to-log depth matching to the resolution of the logging tools employed. Spatial statistics extracted from the core and up-scaled can then be compared with similar statistics from the precisely-located log data sampling the volume of rock around the borehole wall. Finally simulations of 'virtual' core can be created using the statistical properties of the logs in regions where no core is available.

Magister Scientiae - MSc / The Bredasdorp basin is a sub-basin of the greater Outeniqua basin. It is located off the south coast, Southeast of Cape Town, South Africa. This basin is one of the largest hydrocarbon (mainly gas) producing basins within Southern Africa. The petrophysical characteristic of the E-block sandstone units within the Bredasdorp basin has been studied to evaluate their hydrocarbon potential. The data sets used in this research were wireline logs (Las format), core data, and geological well completion reports. The three studied wells are E-AH1, E- BW1 and E-L1. The evaluated interval ranges from 2000.33m to 3303.96m in depth with reference to Kelly bushing within the wells. The sandstone reservoirs of the Bredarsdorp basin are characterized by a range of stacked and amalgamated channels. They originated from materials eroded from pre-existing high stand shelf sandstone and transported into the central Bredarsdorp basin by turbidity current. These sandstones are generally in both synrift and drift section. The basin is thought to have developed from fan deltas and stream overwhelmed to water dominated delta. River dominated deltaic system progresses southward over the Northern edge of the central Bredasdorp basin. The Interactive Petrophysics (IP) software has been used extensively throughout the evaluation and development of interpretation model. The lithofacies of the rock units were grouped according to textural and structural features and grain sizes of well (E-AH1, E-BW1 and E-L1). Four different facies (A, B, C and D) were identified from the cored intervals of each well. Facies A was classified as a reservoir and facies B, C and D as a non-reservoir. Detailed petrophysical analyses were carried out on the selected sandstone interval of the studied wells. The cut-off parameters were applied on the seven studied sandstone interval to distinguish between pay and non-pay sand and all intervals were proved to be producing hydrocarbon. Volume of clay, porosity, water saturation and permeability were calculated within the pay sand interval. The average volume of clay ranged from 23.4% to 25.4%. The estimated average effective porosity ranged from 9.47% to 14.3%. The average water saturation ranged from 44.4% to 55.6%. Permeability ranged from 0.14mD to 79mD. The storage and flow capacity ranged from 183.2scf to 3852scf and 2.758mD-ft to 3081mD-ft respectively. The geological well completion reports classify these wells as a gas producing wells. E-L1 is estimated to have a potential recoverable gas volume of 549.06 cubic feet, E-BW1 is estimated to have 912.49 cubic feet and E-AH1 is estimated to have 279.69 cubic feet.

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The 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. / text