Shale gas has become a significant resource play in the USA over the past few years, and oil companies are now evaluating the shale gas potential of many sedimentary basins. The successful development of these shale gas systems has led to a strong exploration campaign in Saudi Arabia to investigate its several onshore basins. These "shales" have complex and varying mineralogies and require intensive petrophysical analysis to determine even basic characteristics. The renewed focus on rock sequences has necessitated the development of workflows and methods for characterizing these shale rocks. With the deployment of new methods comes the need for interpretation frameworks to understand properties from diverse measurements. We investigated the use of two techniques, the dielectric dispersion technique and nuclear magnetic resonance (NMR), as potential tools for systematic shale characterization and examined their applicability to reservoir evaluation in shale plays.Dielectric properties were measured on a suite of shale gas rock samples selected from several wells across the Silurian source rock formation. The frequency range of 10 MHz to 1 GHz covers the different polarization types of the electric field within the rock samples. The dependence of minerals in the shale-gas rocks on the interpretation of the dielectric response was studied. The dual-range Fourier transform infrared (FTIR) technique was used to accurately quantify the mineralogical composition of the studied samples, including pyrite. Pyrite has an obvious effect on the dielectric responses, and an accurate estimation of its volume is crucial for an enhanced interpretation of the dielectric response. The dependence of the effective matrix permittivity to the shale-gas minerals was well investigated in this work. A workflow was developed to accurately estimate the effective permittivity of the rock matrix to enhance the estimate of water volume from the dielectric response. The high-resolution retort was also used for the quantification of water content, and the results were compared to the water saturations from dielectric dispersion. NMR T 2 was also measured on the selected shale gas rock samples using very short echo spacing to capture all the inorganic and organic porosity at the nanometer scale. An accurate estimation of total porosity from NMR and total water content from dielectric dispersion enhances the estimation of the total gas in place of the shale-gas rocks.

The characterization of the clastic Zubair reservoir is challenging because of the high lamination and the oil properties change making the conventional saturation technique uncertain. A new workflow has been recently established in the newly appraised wells which has involved advanced petrophysical measurements along with the fluid sampling. The new technique has led to identify new HC layers that were overlooked by the previous techniques, thus adding more reserves to the KOC asset. Because of the high lamination of clastic Zubair formation and the change of the oil properties, the dielectric dispersion measurement was integrated along with the diffusion-based NMR to identify new oil zones that has been initially masked by the resistivity-based approach. The new approach has also provided details on the oil movability and the characterization of its property. As the newly identified layers were identified for the 1st time across the field, the fluid sampling was conducted to confirm the new findings. The advent of a new logging technology from a multi-frequency dielectric technique deployed over the formation has independently pinned down the HC pays over the Zubair interval, including a new zone below the water column. The zone was initially identified as heavy Tar zone. The advanced diffusion-based NMR was thus conducted and integrated with Dielectrics which has demonstrated the movability of HC using the diffusion-based NMR approach over the newly identified zone. A fluid sampling was later performed which has confirmed the new finding. The new identified zone was initially overlooked by the previous interpretation and extensive modeling over the entire field. The seal mechanism was also explained by taking advantage of the high-resolution dielectric dispersion measurement (mainly the low frequency), which has been also supported by the Images interpretation. This new approach has added an incremental oil storage over the field.

Tight unconventional reservoirs have become an increasingly common target for hydrocarbon production in Oman. Exploitation of these resources requires a comprehensive reservoir description and a characterization program to estimate reserves, identify properties that control production, and account for fracturability. It is becoming evident, however, that any single technology by itself is unable to address all the key challenges, and the integration of technologies is crucial to answer all the questions to reduce key subsurface uncertainties. This paper discusses in detail a case study in which the integration of advanced petrophysical logs has enabled successful downhole sampling and provided a comprehensive reservoir and fluid characterization despite the very challenging lithologies and very tight formation. The comprehensive logging suite included advanced measurements of dielectric dispersion, nuclear magnetic resonance (NMR), and spectroscopy. The reservoir fluids and dynamic properties were also characterized by a series of formation testing measurements. Dielectric dispersion logs clearly identified the hydrocarbon-bearing zones despite the characterless resistivity profile, taking advantage of its resistivity-independent saturation approach. The accuracy of the measurement was key to estimating water- filled porosity down to 0.5 p.u. regardless of the formation water salinity and changes in the rock electrical parameters. The integration of dielectric and NMR measurements, reflecting the pore structure, has played a major role in identifying the "best" reservoir intervals and indicating the type of fluid (hydrocarbon or water) filling the free pore space. The NMR unimodal and bimodal T2 distributions revealed the pore structure along with polarization effects on light hydrocarbons, helping to gain insight on the reservoir quality. The NMR was also combined with the microimaging measurements to indicate pore connectivity and formation heterogeneity. This integrated approach was applied to a deep tight-gas exploration well and has contributed to achieving successful formation sampling that provided an in-situ fluid characterization despite the tightness of the rocks, with only 4 p.u. average porosity. Integrated logging measurements along with fluid sampling resulted in both enhanced formation and fluid characterization in this exploratory well, shedding light on the hydrocarbon potential over the region.

This paper presents a field application of an advanced slim Pulsed Neutron Logging tool (PNL) for improved determination of hydrocarbon saturation as a key basis to evaluate the reliability of an ongoing enhanced oil recovery (EOR) cyclic steam stimulation (CSS) process in an unconsolidated heavy oil sand in Kuwait. The new PNL tool was used to evaluate changes in oil saturation and to track steam movement as part of the ongoing EOR CSS project in the field. This improved determination of hydrocarbon saturation is performed as a baseline prior to CSS and then used for future time-lapse evaluation of effectiveness of recovery during and after CSS using both PNL sigma and inelastic/capture or carbon/oxygen measurements. Its features enhanced capture and inelastic spectroscopy performance, particularly at high temperatures in places where CSS is ongoing due to its 175°C rating compared to 150°C from legacy tools. Gas, Sigma and Hydrogen Index (GSH), Thermal Decay Porosity (TPHI), lithology, Inelastic Capture (IC) mode was ran at 200 feet per hour (fph); twice the speed legacy PNL tool. Its 3 passes provided better performance than the 5 passes of legacy tool deployed under the same conditions, illustrating its better measurement accuracy. Inelastic spectroscopy logs from near, far detectors provided data for fluid analysis, which demonstrated the benefits from its elevated specifications. Its spectral yields’ results showed better accuracy and improved repeatability between different passes under the same well conditions in spite of logging at twice the speed. Compared to legacy tool, the new PNL technology provided enhanced detectors, new pulsed neutron generator (PNG) and pulsing scheme designed to optimize the gas/steam, sigma and neutron porosity measurements in terms of accuracy. Its faster logging and less exposure time makes it a better fit. Its PNG source and detectors minimize the spectrum degradation caused by high temperatures, hence better signals. The hydrocarbon saturation from its Carbon/Oxygen ratio and Total Organic Carbon (TOC) derived methods demonstrated consistency and cross validation over the logged interval. The advanced PNL tool fits better compared to the legacy PNL with improved repeatability and excellent precision. It now provides the basis for a reliable determination of hydrocarbon saturation, which will improve the evaluation of EOR CSS ongoing project.

In Umm Niqa field, Lower Fars (LF) is a shallow, unconsolidated, sour heavy oil and low-pressure sand reservoir. During the current appraisal and exploratory phases, oil production forecasts based on reservoir simulation models were observed to be significantly higher than actual production. Furthermore, unexpected early water breakthrough and the rapid increase in the water cut added more complexity to the reservoir production. This paper will focus on how these challenges were addressed with a unique workflow. If the reservoir is producing more than one phase, then relative permeability determination becomes essential for the production forecast as well as production optimization to delay the water breakthrough. Due to the unconsolidated nature of LF reservoir, it was challenging to perform coring operation in this environment. In the few cases where cores were obtained, it was almost impossible to perform the relative permeability analysis on the core plugs. Therefore, there was a need to obtain this information by exploring other technique or methodology. Hence in-situ relative permeability technique was implemented in three different wells. To address the relative permeability determination challenge, an innovative approach was implemented in three different wells. This approach determines the relative permeability at downhole conditions by utilizing the fluids clean-up and sampling data during the wireline downhole formation testing as well as some advanced petrophysical measurements such as the array resistivity, the nuclear magnetic resonance (NMR), and the dielectric dispersion. The data obtained were used as inputs for a multi-physics integrated workflow, which inverts for the relative permeability curves based on the modified Brooks-Corey model. In this paper, it will be demonstrated how the relative permeability results obtained from this technique in these three wells were applied to update the reservoir simulation models. The production forecasts were found to be significantly improved and close to the actual production figures. The early water breakthrough is better anticipated; therefore, the production rate can be adjusted to delay it and maximize the oil recovery. This method provides an alternative and efficient way to derive the relative permeability curves when it is challenging to obtain from the conventional core analysis techniques. This helped to better understand the number of wells required to be drilled to achieve the planned production target. This paper adds to the literature unique case studies where relative permeability determination is required, however, not possible to be obtained through conventional industry techniques such as core analysis due to a highly unconsolidated formation. Hence, an innovative workflow was adopted to measure the relative permeability at downhole conditions.