The accuracy of the phase envelope calculated for a black oil sample strongly depends upon the quality and type of information used to optimize the equation of state (EOS). Possible inputs for EOS tuning include (but is not limited to) composition from a chromatogram or optical absorbance, density, saturation pressure (bubble or dew point pressure), and the relative volumes of liquid and gas. In this manuscript, we describe a workflow using a system of microsensors that our group has previously published that accurately measures fluid properties from which the phase envelopes of several black oil samples are calculated and refined.

Relative permeability and capillary pressure are essential information for reservoir modeling, as they impact production optimization and reservoir management. Obtaining this data from special core analysis can take a significant amount of time. Furthermore, it can be challenging to guarantee that the core is restored to its original reservoir wettability state. Additional challenges include cost, scale, and the presence of contamination or alteration. Other emerging techniques, like digital rock, face similar issues. A new workflow has been designed to address those challenges and complement the traditional core analysis offering, by obtaining relative permeability and capillary pressure in-situ from wireline formation tester (WFT) and open hole logging measurements. In this workflow, a near-wellbore reservoir model is built to simulate the mud-filtrate invasion. This reservoir model, combined with an electromagnetic model, simulates resistivity logs, and subsequent pressure transient and mud-filtrate cleanup processes induced by WFT formation testing. Petrophysical log analysis, using array resistivity, nuclear magnetic resonance, and dielectric measurements, is performed to provide prior information for the model initialization. Vertical interference testing from WFT at the same depth provides permeability anisotropy. An optimization engine is employed to update the selected reservoir model parameters until the simulated resistivity logs, pressure transient, and water-cut data match their measured counterparts. Relative permeability and capillary pressure are estimated together with other parameters including mud-filtrate invasion volume and permeability. Both stochastic and deterministic methods are used for the inversion. The deterministic method is cost-effective if a good initial model can be obtained, while the stochastic method is able to find the minimization function's global minimum but needs high computational effort. This workflow was applied to one well in the Ahmadi field in Kuwait, targeting an inter-tidal deposit. In-situ relative permeability and capillary pressure curves were obtained by the deterministic and stochastic methods using formation testing data and petrophysical logs acquired over the interval. The results are consistent between the two methods and representat the effective formation properties in the surveyed interval. This case study demonstrates that it is possible to obtain in-situ relative permeability and capillary pressure data from commonly acquired wireline measurements. The delay in obtaining the relative permeability and capillary pressure data is significantly reduced compared to special core and digital core analysis techniques. Since the measurement is performed downhole, it doesn't suffer from the doubts that surround the core samples restoration process to original reservoir conditions. The formation volume investigated by this survey, in the order of several feet, represents the formation macroscopic properties, thus bridging the gap between core scale and reservoir scale.

The Greater Burgan field has been producing since 1946 from a series of highly permeable Cretaceous reservoirs. Recently, a series of more complex reservoirs has been reassessed using advanced logging and wireline formation tester (WFT) technologies. The techniques employed in the reassessment include fluid-quality (viscosity and presence of tar) mapping using nuclear magnetic resonance (NMR) log data and shallow invasion measurements using multifrequency, multispacing dielectric data. In addition, the dielectric logs provide a direct measurement of the Archie m exponent in water zones. Improvements in formation evaluation achieved by integrating these results with conventional logs included better differentiation of moveable from residual hydrocarbon, identification of variations in formation water salinity, and maps of oil-quality variation versus depth and across the field. These techniques were applied to three case studies. In the first case study, formation evaluation was conducted in an Upper Cretaceous carbonate formation of unknown water salinity. The combination of dielectric logs and NMR enabled identification of water-bearing and residual oil zones where formation water salinity could be determined. The analysis revealed increasing water salinity with depth. Dielectric logging also provided a direct evaluation of Archie's m exponent in the water zones, in the absence of special core analysis. The NMR highlights variations in oil quality from one well to another. In the second case study, a viscous oil layer located in the middle of a water zone in a Middle Cretaceous reservoir was evaluated. Moveable oil was identified by radial oil saturation variation close to the borehole detected by the dielectric log measurement. The interpretation was verified by the first oil sample ever recovered in this layer. In the final case study, in a Lower Cretaceous reservoir, dielectric measurements provided accurate estimates of residual oil saturation required for planning enhanced oil recovery projects. The results obtained from the application of the multifrequency dielectric dispersion and diffusion-NMR as confirmed with WFT sampling bring new insight to the evaluation of challenging formations within the Burgan field.

The biggest clastic reservoir based in Kuwait has been facing evaluation challenges over the thick intervals of highly laminated thin hydrocarbon layers. Conventional wireline tools have a limitation on resolution when it comes to addressing these thin beds. Therefore, the reserves are usually underestimated, and thin pays are often overlooked. This paper presents the integration of a variety of advanced Wireline tools in order to correctly evaluate and compute reserves from these thin pay zones. Acquisition of the triaxial induction tool enabled the study of resistivity anisotropy and the identification of thin pay zones through the distinct reading of the resistivity of the thin sand reservoir. The thin layers have also been further validated using high resolution advanced thin bed analysis from image logs. Advanced spectroscopy and NMR data were used to quantitively define the sand and shale fractions within the thin beds. These measurements were critical to input to improve the resistivity interpretation followed by a reliable estimate of the saturation. High resolution dielectric measurements provided resistivity-independent saturation information enhancing the NMR interpretation using water-filled porosity which was a key input into the identification of the heavy oil presence in Burgan. The newly identified thin pay zones have been further validated using the fluid sampling confirming presence of hydrocarbons with greater understanding of its properties and uniquely quantifying the mobile fluid fractions. The additional available reserves can only be properly determined by combining data from multiple sources to achieve a comprehensive evaluation. Resistivity anisotropy was observed based on the separation of vertical and horizontal resistivities and was therefore investigated to understand its root-cause over different zones. By integrating the results from the dielectric dispersion measurements, the diffusion-based NMR data, spectroscopy data, borehole image interpretation and high-resolution sand count delineation of different lithologic units at a finer scale, we were able to identify thin bedded sand-shale intervals in addition to pin-pointing the heavy oil intervals. Hydrocarbon saturations of individual sand layers showed improvement in hydrocarbon volumes, improvement in permeabilities across the studied zones and increased net pay estimations by 12%. Results from the fluid sampling performed across the newly identified thin pays have validated the advanced logging interpretation results and the presence of hydrocarbons. These intervals were overlooked by the standard basic evaluation and the reservoir potential has been revisited following the latest integrated advanced results. By combining the results of all these advanced wireline answer products, we were able to properly identify and quantify the additional available reserves and therefore change the classification of these reservoirs from poor to excellent with new development plan in place. The paper demonstrates the value solution of the high vertical resolutions taking advantage of the latest advanced technologies to enhance the characterization of laminated thin beds. The integrated advanced solution has enabled improved reservoir potential by the identification of new pay zones initially overlooked by the standard basic measurements.