Abstract Classifying rock facies and estimating permeability is particularly challenging in Microporous dominated carbonate rocks. Reservoir rock types with a very small porosity range could have up to two orders of magnitude permeability difference resulting in high uncertainty in facies and permeability assignment in static and dynamic models. While seismic and conventional porosity logs can guide the mapping of large scale features to define resource density, estimating permeability requires the integration of advanced logs, core measurements, production data and a general understanding of the geologic depositional setting. Core based primary drainage capillary pressure measurements, including porous plate and mercury injection, offer a valuable insight into the relation between rock quality (i.e., permeability, pore throat size) and water saturation at various capillary pressure levels. Capillary pressure data was incorporated into a petrophysical workflow that compares current (Archie) water saturation at a particular height above free water level (i.e., capillary pressure) to the expected water saturation from core based capillary pressure measurements of various rock facies. This was then used to assign rock facies, and ultimately, estimate permeability along the entire wellbore, differentiating low quality microporous rocks from high quality grainstones with similar porosity values. The workflow first requires normalizing log based water saturations relative to structural position and proximity to the free water level to ensure that the only variable impacting current day water saturation is reservoir quality. This paper presents a case study where this workflow was used to detect the presence of grainstone facies in a giant Middle Eastern Carbonate Field. Log based algorithms were used to compare Archie water saturation with primary drainage core based saturation height functions of different rock facies to detect the presence of grainstones and estimate their permeability. Grainstones were then mapped spatially over the field and overlaid with field wide oil production and water injection data to confirm a positive correlation between predicted reservoir quality and productivity/injectivity of the reservoir facies. Core based permeability measurements were also used to confirm predicted permeability trends along wellbores where core was acquired. This workflow presents a novel approach in integrating core, log and dynamic production data to map high quality reservoir facies guiding future field development strategy, workover decisions, and selection of future well locations.

AbstractTo effectively simulate the performance of unconventional wells, it is essential to incorporate sufficient geological complexity to allow for realistic variability in the petrophysical and mechanical properties controlling the productivity of the effective stimulated rock volume. The heterogeneous and strongly layered nature of unconventional reservoirs requires appropriate representation of the high intra-bed contrast in anisotropic deformation and flow behavior, and the representation of pre-existing mechanical discontinuities (faults, bedding planes and natural fractures) in terms of mechanical and hydraulic coupling. These fundamental requirements cannot be achieved unless a high-vertical resolution petrophysical and geomechanical model is developed.As demonstrated in this paper, without integration of high (cm-scale) vertical resolution data such as borehole images and core X-ray computed tomography (CT) images, standard meter-scale petrophysical and geomechanical outputs typically used for Hydraulic Fracture (HF) and flow modeling are, at best, standard scalar log (~m-scale) average compositional volume-weighted representations of subsurface reality, that can be highly misleading when considering that mechanical and flow properties are actually ultimately controlled by fine-scale contrasts and extremes, rather than by arithmetic composition weighted averages.This paper presents an integrated workflow to model mechanical properties at sufficiently high resolution (cm-scale) to accurately honor rock fabric and its effects on HF (height and complexity) and therefore on production. The workflow relies on (1) a novel experimental geomechanics technique and associated analytical solutions to derive poroelastic anisotropy (Young's modulus, Poisson's ratio and Biot's coefficient in the bed-normal and bed-parallel directions) and (2) a joint, high vertical resolution, multi-physics petrophysical model relying itself on (2.1) a standard vertical (m-scale) resolution multi-physics log-based petrophysical output (average composition) automatically redistributed into a high vertical resolution well framework by using (2.2) local constraints from high-resolution data (borehole resistivity image and core dual energy X-ray CT images) coupled with neuronal-network derived core empirical relationships. Core-scale poroelastic predictors defined in (1) are then propagated into (2) to get high vertical resolution geomechanical properties and sub-surface stresses.Beyond providing appropriate inputs to HF modeling, this high vertical resolution well framework enables (i) detailed well-scale calibration and recognition of facies and stacking patterns; (ii) accurate and core-calibrated geochemical, petrophysical and geomechanical characterization of individual beds, and (iii) identification and characterization of discontinuities, in general, and interfaces between beds, in particular. Once upscaled, outputs of this workflow enable a more realistic borehole-view of reservoir quality, fluid flow units and geomechanical stratigraphy – all key information to a more optimal asset development.

Rock fracturing, followed by proppant injection, has been used for years to improve oil and gas production rates in low permeability reservoirs and is now a routine part of producing from low-permeability resources such as a shales and tight sands. While field data makes clear the effectiveness of this technique, there is still much room to improve on the science, including how the proppant-filled fracture system responds to changes in loading stress and the corresponding impact on the proppant structure and fracture width, which affect permeability and conductivity. Here, we use high-resolution x-ray computed tomography (XCT) to image two unsaturated rock/fracture/proppant systems: one with shale, one with Berea sandstone. Both systems were imaged under a series of stress levels typical of producing reservoirs. The resulting XCT images were segmented, analyzed for structural and porosity changes, and then used for image-based flow modeling of Stokes flow using both finite element (FEM) and Lattice Boltzmann (LBM) methods. The images and quantitative grain analysis showed expected changes as stress increased: rearrangement of the packing structure, corresponding reduction in porosity, and some embedding at rock walls to a depth of less than 0.5 times the proppant diameter. The shale system exhibited more embedding than the Berea system. At the highest stress in the Berea system (20kpsi or 138MPa), individual proppant particles failed and the broken particles caused significant loss of permeability. For the shale system, the embedding had a significant effect on the simulated permeability/fracture conductivity. Simulation results for each of the loadings showed that permeability is less sensitive to loading than experimental (vendor-reported) permeability values, but also show reasonable agreement at 8kpsi (55MPa) for both systems. Another somewhat surprising result is that fracture permeability for the single-layer proppants confined between shale is similar to what would be predicted from bulk proppant results, despite the significantly different flow geometry in the monolayer fracture.

Abstract Unconventional resources (tight gas, shale gas, and tight liquids) have become a transformative energy source in North America largely through trial and error field experimentation. Low gas prices in North America and the expansion of unconventional developments internationally are driving a need for more rapid and lower cost assessments of potential. Operational efficiency will always be the critical success factor in unconventional resource development, but a holistic understanding of the system from plates to plays to pores can enhance that efficiency, achieved by integrating results from a variety of advanced laboratory analytical techniques with stratigraphic models that enable mapping of key play parameters. Geochemical analysis of core and cuttings is used to determine organic matter type, richness, and thermal maturity, from which hydrocarbon yields and fluid properties can be predicted. With unconventional resources, the hydrocarbon source rock is often also the reservoir. To understand storage capacity, the new generation of scanning electron microscopes enables nanometer-scale imaging of pores in the mineral matrix and organic matter, and generation of three dimensional volumes of the pore network that provide insight into hydrocarbon habitat and shale permeability. Finally, geomechanical experiments are performed to measure compressive strength and elastic properties, which are used to calibrate log-scale measurements to understand the variation of these rock properties across a play. Proppant embedment tests are used to understand the mechanical interaction between rocks, proppants and stimulation fluids at simulated downhole pressure conditions. Putting the results of these laboratory analyses and experiments into a play-scale stratigraphic framework provides an understanding of the geologic factors driving past successes and failures in a range of unconventional resource types. This has enabled assessment of basin potential in new plays before investment, and rapid evaluation of play-scale sweet spots.

A database of core-derived mechanical properties measurements has been used to develop new empirical correlations relating rock strength and compressibility to associated petrographic and petrophysical data. Automated fitting procedures translate these empirical observations into predictive algorithms for estimating mechanical properties from geophysical wireline logs. The database comprises similar to 600 triaxial compressive strength tests of sandstone-to-shale lithotypes and similar to 275 uniaxial and hydrostatic compaction tests of siliciclastic reservoir rocks (unconsolidated sands to tight gas sandstones). New predictive algorithms derive: shear strength from lithotype (arenite, wacke or shale) porosity and normal stress magnitude; Mohr-Coulomb cohesion and internal friction angle from porosity and total clay weight fraction; pore volume compressibility at initial reservoir stress conditions from elastic moduli. Observed trends in material properties defining the Cam clay elastoplastic constitutive model offer some constraints for approximating the onset of pore collapse and the evolution of rock compressibility with fluid pressure reduction under uniaxial strain boundary conditions.

Abstract Significant rock strength anisotropy associated with weak bedding laminations in shale can lead to wellbore instability challenges especially when drilling Extended Reach Drilling (ERD) wells that require low angles of attack relative to the formation bedding planes. Past drilling experience with water-based muds in offshore Abu Dhabi showed a high frequency of hole-cleaning and stuck-pipe events for wells deviated above approximately 40° from vertical. This was attributed to shale instability due to the invasion of the drilling fluids into micro-fractures along bedding planes as longer exposure lengths and times increased with the angle of deviation. Recently the decision to further develop a giant field with wells drilled from artificial islands has created the need for large numbers of ERD wells that will cross the shale formations at angles in the range of 40° to 85°. Pilot holes have been successfully drilled across shales at angles up to 80° by using non-aqueous drilling fluid (NADF) with mud weights predicted with an ExxonMobil proprietary model that uses previous experience and limited log data. Nevertheless, it was considered advantageous, if not essential, to better understand the mechanisms for shale instability as a function of both the angle of inclination and azimuth of the section, since it is critical to reliable prediction of the mud weight and chemistry required to avoid well-bore instability. An extensive program of tri-axial compression testing of orientated preserved core plugs was conducted in order to quantify the degree of strength anisotropy associated with both a reservoir cap, Layer A shale and intra-reservoir shales encountered while drilling offshore Abu Dhabi. This work showed that Layer A shale's compressive strength can be reduced by approximately 70 to 75% and the intra-reservoir shares by approximately 45 to 50%, when the shear plane of failure aligns with the weak laminations, compared to loading parallel, or perpendicular to the bedding planes. The inclusion of the measured strength anisotropy functions into a wellbore stability model is shown to accurately predict the observed mud weights associated with induced wellbore breakout. The non-aqueous (NADF) mud weight required for wellbore stability was incorporated in an Integrated Hole Quality and Quantitative Risk Assessment (IHQ/QRA) study to evaluate the drillability of various ERD well designs. Actual field drilling performance with NADF has also been used to validate the model. Increased understanding of this wellbore failure mechanism has the potential to reduce drilling risk and significantly increase current extended reach drilling limits for ZADCO's long term field development plan offshore Abu Dhabi.

The cone penetration test (CPT) has been widely used in Louisiana to classify soils, measure undrained shear strength (S-u), and identify bearing stratum for driven piles. This paper compares the values of S-u based on CPT measurement with S of the unconfined compression test. A total of 752 CPT soundings were collected and archived using ArcGIS software in which 503 were matched with adjacent boreholes and 249 did not have adjacent borehole data available. The dataset was analyzed for general as well as specific trends in order to identify appropriate parameters to be included in the investigation. The calibration of the CPT expression for S-u was conducted using the first order reliability method (FORM) and accounting for all sources of uncertainty. Optimum CPT coefficient. (N-kt) values to calculate S-u were computed for various target reliability values. It was determined that the soil classification is the only parameter showing clear trends that affect CPT estimates of the undrained shear strength. Values of N-kt for each soil type based on the Robertson (1990) classification and the Zhang and Tumay (1999) classification were determined for three target reliability levels. It is obvious that the N-kt coefficient for soils with higher clay content is lower than those with less clay content. A single N-kt value that is valid for all soil types is unwarranted as will lead to acceptable results for some soil conditions and unacceptable results for others, which can be unconservative.

The objective of the “geomechanics from logs” (GML) research project is to develop model-driven predictive software for determining rock mechanical properties (specifically rock strength, compressibility and fracability) from other, more easily measured, rock properties (e.g. lithology, porosity, clay volume, velocity) routinely derived from nuclear, resistivity and acoustic logging tools. To this end, geomechanics from logs seeks to increase fundamental understanding of the primary geologic controls on rock mechanical properties and to translate this new insight into novel predictive tools.

The Cone Penetration Test (CPT) is widely used in Louisiana to classify soils, measure undrained shear strength (Su), and identify bearing stratum for driven piles. This paper compares the values of Su based on CPT measurement with Su of the unconfined compression test. A total of 752 CPT soundings were collected and archived using ArcGIS software in which 503 were matched with adjacent boreholes and 249 did not have adjacent borehole data available. From these CPT locations, 862 unique Su strength data points were obtained at various depths. The dataset was analyzed for general as well as specific trends in order to identify appropriate parameters to be included in the study. Soil classification was clearly the most plausible parameter based on which the CPT undrained shear strength estimates should be calibrated. The calibration of the CPT expression for Su was conducted using the First Order Reliability Method (FORM) and accounting for all sources of uncertainty. Optimum CPT coefficient values to calculated Su were computed for various target reliability values.