Downhole sampling and laboratory analysis are key complementary techniques offering a step change in fluid characterization. It is generally accepted that fluids in the reservoir are in chemical equilibrium. However this assertion, although convenient, is often invalid, for several reasons from source variations, due to in-reservoir reaction, degradation or precipitation. In a large majority of cases many of these phenomena are difficult to appreciate, because the techniques used for fluid sampling often lack the pin-point acquisition accuracy (geographical, depth and time) required to provide the information at a level of accuracy sufficient to detect subtle variations. Instead only a mixture of different oil is captured providing "averaged" oil composition and characteristics, whereas the reality in the reservoir may be markedly different. The vertical compositional gradient in oil column has been documented in many large oil column reservoirs. The geographical variation has been much less documented. In this paper we will demonstrate how variation at the scale of individual sand bodies in the reservoir, sometimes only tens of feet apart, can be very large (as observed in two sand bodies in the same well) and have a dramatic impact on oil property understanding and modeling. In turn understanding of these property variations and their impact on mobility, is a key factor for understanding fluid flow and for the choice of the correct secondary recovery mechanism for an improved recovery. The example of the Wara channelized sand, within the Greater Burgan complex, will illustrate the paper, where downhole fluid analysis is presented as a necessary complementary tool to improve the selection and construction of an accurate set of samples to ensure the data collection is complete and exhaustive before the well is completed.

Several challenges are associated with the characterization of organic rich unconventional plays, most significantly with the identification of sweet spots for optimum placement of horizontal wells, estimation of producible hydrocarbons and subsequent stimulation design. This paper presents the petrophysics and geomechanics integration approach from the X Formation and the important factors for the identification of sweet spots. The case study concentrates on the X Formation that consists of a succession of argillaceous limestone, mostly fine grained packstones and wackestones together with subordinate calcareous shales in the lower part. The complex carbonate lithology and fabric combined with low porosity and the requirement to evaluate total organic carbon presents a challenge to conventional logs and evaluation of them. Amid all the rock properties, the low permeability and productivity dictate the requirement to stimulate the wells effectively. Detailed integration of advanced and conventional log data, core data, mud logs and geomechanical analysis plays a critical role in the evaluation and development of these organic rich unconventional reservoirs. Extensive data gathering was done with wireline logging suite, which covered Resistivitiy/Density/Neutron/Spectral GR- Acoustic logs – Resistivity & Acoustic Images – Dielectric- NMR - Advanced Elemental Spectroscopy technologies and microfrac tests to characterize the hydrocarbon potential, sweet spots and in-situ stress contrast within the organic rich X Formation. The azimuthal and transverse acoustic anisotropies were obtained from X-dipole data to fully characterize the elastic properties of the formation. The static elastic properties were obtained using empirical core correlations as triaxial core tests were not available at the time of the study. The stress profile was calibrated against straddle packer microfrac tests to identify intervals with stress contrast for proper hydraulic fracturing interval selection. The integration of conventional and advanced logs enabled the accurate evaluation of total organic carbon (TOC), petrophysical volumes, and sweet spot selection. The advanced elemental spectroscopy data provided the mineralogy, amount of carbon presence in the rock, and consequently the associated organic carbon within the X Formation. The NMR reservoir characterization provided lithology independent total porosity. The difference between the NMR and density porosities provides additional information about organic matter. NMR data was utilized in this case study to identify and differentiate the organic matter and hydrocarbon presence within the X Formation. Acoustic and image logs provided the geomechanical properties that enable selection of the best intervals for microfrac stress measurement and proper fracture containment modeling. Geomechanical workflow allowed identification of intervals with a good stress contrast in X formation. The core data and stress measurements are recommended for the accurate calibration of the stress profiles and hydraulic fracture propagation modeling. The extensive data integration work presented in this single-well study within X Fomation, is a key factor for any organic rich unconventional reservoir characterization that integrated geology, petrophysics, mineralogy, and geomechanics for sweet spot identification within tight oil carbonate reservoirs.