There are number of small oil fields located in western onshore India, undergoing a fast track development campaign, wherein wells have witnessed NPT due to various drilling challenges such as tight hole, stuck pipe etc. Bad borehole condition has affected the data quality being recorded for formation evaluation and poor cement quality. Most of these drilling problems are reported in shallow shale formations like Tarapur, Post-Kand and Babaguru. Target reservoirs like Kalol and Cambay shale are relatively silty with porosity in range of 8%-15% which requires hydro-fracturing jobs to enhance production. This paper summarizes these challenges and provides current learning based on results of a geomechanical workflow implemented in the field. Far field and near wellbore advanced acoustic measurements have been recorded in recent wells to estimate direct horizontal stress profile and map regional variation of tectonics across two fields. 1D Mechanical Earth Models (MEMs) have been constructed for different wells in the area to develop a geomechanical understanding of the reservoir as well as in the overburden and underlying layers. Anisotropic stress profile provides better understanding on rock fabric-based tectonics effects to check feasibility of optimized hydro-fracturing operations. History match of predicted failures using 1D MEM with caliper and drilling events suggest that shales and coals are relatively weaker than sands in both fields with 10%-15% variation of stress gradient magnitude laterally. Triaxial test results provided UCS calibration for better wellbore stability analysis (WBS) and stable mud weight window prediction in new wells. In the first field targeting Kalol formation, presence of weak coal layers near target sandstone layers make perforation and hydro-fracturing design more challenging. Stress barriers are located around 30m-40m away from target zones with frac height expected in the range of 50m-80m depending on frac job volume and geological variations. There is a stress contrast of 200psi-500psi between target Kalol layer with potential shale barrier layers using anisotropic rock properties and stress profile. Closure pressure ranges 3700psi-4200psi in target zones with good petrophysical properties. Perforations were carried out away from coal layers towards bottom of reservoir with thickness of 6m-11m. In another field with Cambay formation as target, the well was perforated using integrated petrophysical and geomechanical findings in different well profiles. Frac half-length obtained after net pressure match is around 40m-50m as confirmed with temperature log which suggests that the frac job was effective. Height barriers match very well with micro seismic events conducted afterwards. Production rate has improved by 150%-200% in two fields with new integrated strategy of reservoir quality and completion quality in deviated wells. Implementation of stable mud weight window concept helped to improve hole condition significantly in new wells and increase in effective rate of penetration (ROP) by 15%-20% with no major drilling events.
The present oil industry is more challenged than ever to develop novel methods for oil exploration and production, while reducing costs at the same time. This necessity changes the need of logging tools for reservoir characterization. Saturation height modeling (SHM) is an important aspect of determining the production capability of an oilfield. This is often performed by taking core samples, which is pivotal for such analysis, but expensive and challenging. Further, cores are usually taken in the zones of interests in the well. This calls for an alternate analysis, which is not only available for the entire interval of the well but is also less expensive than the traditional coring techniques. Nuclear Magnetic Resonance (NMR) applications have proved promising over the years to perform SHM, without using cores. NMR, however, has a shallow depth of investigation and using wireline measurements is even more challenging due to longer time after bit and increased mud filtrate invasion. Consequently, its use is restricted to quantifying porosity. This makes it imperative to remove the effect of any filtrate or hydrocarbons from NMR logs to be able to use them for any advance analysis. A novel methodology is presented in this paper to perform SHM analysis in carbonates. It uses NMR data along with modern processing techniques like factor analysis (Jain et al. 2013) and fluid substitution (Minh et al. 2016) and integrated workflow to define hydrocarbon uncontaminated pseudo capillary pressure curves and saturation height functions for different rock facies observed in the formation. The results are validated on five wells in the same field, and further confirmation is also done with testing results.
Considering the modern oil price environment, oil companies are more pressured than ever to reduce costs. This need affects tools used for reservoir characterization. Coring is important but expensive and is usually not available for the entire length of the well. A novel methodology is presented to perform reservoir characterization from wireline nuclear magnetic resonance (NMR) data, in the absence of any core, in offshore gas-bearing wells. This includes computing T2 cutoff, hydrocarbon saturation, permeability, and poro-fluid sand facies determination. NMR is a shallow measurement and using wireline NMR measurements is even more challenging due to higher time after bit and increased mud filtrate invasion. Consequently, its use is restricted to quantifying porosity, and even the basic assessment of bound/free fluid require correct T2 cutoff to be determined from cores. Traditional formation evaluation methods use various equations like Archie’s, dual water, Waxman Smits, etc. to determine hydrocarbon saturation, all of which have many variables which, again, must be determined from cores. This makes it imperative to have core measurements to get precise results. In this paper, we present the results of successful implementation of the proposed methodology, which functions without core data. It employs NMR data along with modern processing techniques like factor analysis and fluid substitution, and integrates density data to evaluate reservoir by 1) minimizing the mud signal, 2) using the virgin zone data to extract dominant peaks and repeated patterns on T2 distribution to divide the entire reservoir section into different poro-fluid types, 3) obtaining the T2 cutoffs for various poro-fluids facies, 4) calculating density magnetic resonance porosity (DMRP) and adopting it to drive fluid substitution, 5) obtaining original water equivalent porosity which is divided by DMRP to get water saturation, 6) employing the fluid substituted (water-only equivalent) T2 distribution along with the T2 cutoff determined by factor analysis to calculate permeability using the Timur-Coates equation.
Owing to the depleting reserves in the conventional reservoirs over the last few years, unconventional reservoirs have gained significant importance in the exploration of oil and gas. Basement rocks, though non-sedimentary in origin, is looked upto as one of the important unconventional reservoirs. Deccan volcanics in Kutch-Saurashtra is one such example from India. This study shows and validates a methodology of how acoustic log data can be integrated with borehole images to understand reservoir properties that governs flow. It has been noticed that presence of open fractures is not the single biggest driver contributing to production. Insitu stress plays a critical role in guiding fracture mobility. To understand and determine which fractures would contribute to flow, a geomechanical study of performing the fracture stability analysis has been carried out. This generates a Mohr circle plot that defines the Mohr-Colomb shear failure criteria using the stress and critical fracture angles. Combining these three-way approaches of acoustic, image log and geomechanics, a workflow has been established for this field to identify fractures and quantify the permeable zones. This workflow has been used for two nearby wells in this field and subsequent result emphasises the utility of this method to find out sweet spots of fluid flow in fractured basement.
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