New methods used to accurately determine water and hydrocarbon saturation profile, hydrocarbon typing & reservoir extent (connectivity) in real time by using acquired insitu water salinity measurement downhole and measured hydrocarbon optical density from formation testers. The uncertainties present from water salinity (Rw) values from nearby wells (due to vertical & aerial variations) may compute inaccurate hydrocarbon saturations when input in Archie's based fluid saturation model, which affects the hydrocarbon in place calculations. Also, relying only on pressure measurement for connectivity assessment & reservoir extent using Vertical Interference Testing (VIT) may sometimes be misleading & inconclusive due to supercharging in low permeability & low pressure contrast in high permeability which affects the field development plans. Therefore, the new methodology is introduced to overcome these challenges. Firstly, the downhole water salinity is measured in a water zone at the bottom of the reservoir while pumping out using formation tester after achieving clean-out (negligible contamination). The values were input into the initial petrophysical model to recompute the new fluid saturation which was confirmed by pump-out fluid fractions from other zones. Secondly, the optical density measurement from the spectroscopy was used to confirm the vertical connectivity though Reservoir Fluid Geodynamics & indicating a compositional gradient in real time in an oil column. This was done by constructing Flory-Huggins-Zuo (FHZ) Equation of State model and identifying asphaltene molecular size from optical density gradient. These two methods will bring accurate & reliable results compared to conventional methods which has some uncertainties impacting evaluation & reservoir understanding. Secondly, will help in optimizing sampling & downhole fluid analysis programs which eventually saves cost & time & CO2 emissions. Thirdly, Optical Density gradient analysis can be also used for flow assurance prediction.

Traditional approach relys on reservoir pressures to assess reservoir connectivity in low permeability formations. This paper will present a new approach of applying Reservoir Fluid Geodynamics (RFG) through Flory Huggins-Zuo (FHZ) equation of state (EOS) for asphaltene distributions to determine reservoir connectivity and fluid typing in undrilled locations. FHZ-EOS asphaltene gradient was constructed with data from downhole fluid samples in different wells covering two zones (A and B). The downhole fluid analysis (DFA) results were validated with laboratory analysis. The structural continuity of both zones across the study area in the field was validated using a wide range of geological data including conventional open-hole logs. The resulting FHZ-EOS model formed the basis for fluid typing, correlation and connectivity across layers. The DFA data was used in real time at different stages of formation fluid sampling cleanup to correlate the samples quality with the existing model. The DFA data used in real time in conjunction with the pre-built FHZ-EOS model, improved the sampling quality check process and confidence in the sample quality, especially in the presence of low gas oil ratio (GOR) fluids. This improvement in real time data quality helped to optimize the pumping time and reduce the number of samples in each reservoir since the confidence in the sample quality was high. The constructed asphaltene gradient from the FHZ-EOS model also confirm the hydrocarbon continuity both vertically and laterally in undrilled locations with the study area of the field. For each of the zones, the data analysis shows a clear and distinct asphaltene gradient with different asphaltene molecule sizes. This supports the presence of heavy oil / tar towards the deeper sections of the area of interest within the field. It also predicted the depths / location of the heavy oil / tar, which will assist in the field development plan and flow assurance.

There is a considerable volume of hydrocarbon located in challenging carbonate reservoirs around the world. These reservoirs can be difficult to evaluate with conventional logging measurements and therefore the hydrocarbon reserves can be underestimated. On the other hand, as the recent development has focused more on low to ultra-low carbonate permeability zones, the testing program becomes very difficult, and getting fluid samples to determine the properties becomes a challenge. A thin Lower Cretaceous carbonate reservoir with relatively low permeability is undergoing development by drilling maximum reservoir contact wells. Reservoir characterization on three recently drilled wells in this carbonate reservoir reveals a gas cap, and a long oil-water transitional zone complicated by capillary pressure effect, which made it difficult to determine fluid contacts by using pressure gradient. To overcome these issues, a new approach has been used in these three wells, by utilizing a new wireline formation testing tool, scanning across transition zone for direct mobile fluid identification, along with a full suite of petrophysical evaluation data, which resulted in considerable time saving and provided a better estimate of an oil-water contact (OWC). This leads to a big improvement in the estimation of hydrocarbon volumes, and efficient completion design. The preference of new technology measurements over conventional and standard logging facilitated in better determination of the hydrocarbon properties in situ, which goes a long way in understanding the present condition of the reservoir, thereby helping in the planning process of the development of the same. In this paper, cases will be presented to demonstrate how the modern logging techniques helped in extending the hydrocarbon zone; therefore, more hydrocarbon can be claimed, while providing a unique solution of testing these formations as well as predicting the possible production capability Introduction This work was a part of a study to identify fluid contacts in a carbonate reservoir. This field is characterized by good porosity, moderate to low permeability and long transition zones. The reservoir is heterogeneous in lithology due to the development of rudist banks, syn-depositional faulting and later digenetic overprinting. Sequences within the buildup are difficult to map, probably because of growth faulting, depositional topography, rapid facies changes and stacking and shingling of rudist banks. The producing formation in the field was developed for oil and gas, and a facies map and a reservoir model were generated. Subsequently, the descriptive framework was done by using logs and available pressure and sampling data. By integrating this framework with a geological model, better planning and geosteering of horizontal wells could be accomplished. This case study will help in characterizing the field, and therefore lead to better simulation models.

A methodology to determine water contamination levels prior sampling to guarantee the capture of representative water samples, as its highly crucial for understanding saturation profile, reservoir reserves & field development planning. The presence of low salinity mud while trying to sample low salinity water adds further challenges in acquiring a clean sample. Especially, that the resistivity measurement sometimes won't have a resistivity contrast. Nevertheless, the conventional optical density measurement won't be able to differentiate the two water types. Applying power law model and utilization of resistivity/conductivity and density measurements to quantify contamination levels as the fluid property in miscible filtrate & formation water will match such transition profile. Since both water base mud filtrate (WBMf) & formation water exhibit the same optical spectroscopy response, it will be quite challenging to differentiate between them. Hence, the above method is used to quantify accurate contamination. The pH measurement was also used to monitor rate of change & stabilization across pump out station whenever there's no contrast in salinities between WBMf & formation water. The contamination calculations process can be divided into four steps: Firstly, exponent selection for the power law which depends on the inlet selection, either radial probe or single probe. Secondly, determination of filtrate properties (initial end point). Third, flow regime identification diagnostics after power law fitting. Fourth, end point extrapolation. The resistivity/conductivity, density and pH measurements were utilized during down hole fluid analysis of water stations to evaluate the contamination levels using the power law model in a shallow carbonate environment. The model was tried for multiple inlets radial probe & single probe using different power law exponents. The results were consistent and determined the right timings to sample clean water bottles with minimum contamination levels to be analyzed at the lab. Hence, providing accurate geochemical analysis for the reservoir's field development planning and optimizing station time and avoiding unnecessary pump out in real time which saves time and cost.

In exploration areas formation water salinity is often unknown. Several log-based techniques can be used to estimate the water resistivity, which can be used to calculate the equivalent formation water salinity, such as the Pickett's plot technique or spontaneous potential (SP log) but remain subjected to some uncertainties. Although captured down hole samples can accurately determine salinity, it can take a long time to receive the laboratory analysis results, delaying the Field Development Plan (FDP) studies and affecting current logging operations decisions. In this paper, we tested two methodologies. First, we utilized a novel dry weight chlorine (DWCL) measurement from an advanced spectroscopy tool to estimate the formation salinity at the depth of investigation of the device. This newly introduced methodology can be used in areas where formation salinity is unknown. The second methodology uses a new downhole induction resistivity cell in the formation tester tool. This cell gives a calibrated direct measurement of the water resistivity in the flowline, which can be converted into an equivalent water salinity if temperature is provided, and cross-checked with the DWCL values from the spectroscopy tool. The new chlorine measurement, along with the flowline induction resistivity measurement, provides a robust workflow to estimate the formation water salinity, enhancing the quality of the saturation evaluation for quick decision-making during logging operations, and accelerating the evaluation studies rather than waiting on laboratory results.