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Abstract Broadband relative dielectric dispersion measurements are considered interesting options for assessment of water-filled pore volume. Conventional models such as Complex Refractive Index Model (CRIM) and Maxwell Garnett (MG), often overlook or oversimplify the complexity of pore structure, geometrical distribution of the constituting fluids, and spatial distribution of minerals. This yields to significant errors in assessment of water saturation especially in rocks with complex pore structure. Therefore, it becomes important to quantify the impacts of pore structure and spatial distribution of minerals on broadband relative dielectric dispersion measurements to be able to make decisions about reliability of water saturation estimates from these measurements in a given formation. The objectives of this paper are (a) to quantify the impacts of pore structure and spatial distribution of minerals on relative dielectric permittivity measurements in a wide range of frequencies, (b) to propose a new simple and physically meaningful workflow, which honors pore geometry and spatial distribution of minerals to enhance fluid saturation assessment using relative dielectric permittivity measurements, (c) to verify the reliability of the introduced model in the pore-scale domain. First, we perform numerical simulations of relative dielectric dispersion measurements in the frequency range of 20 MHz to 1 GHz in the pore-scale domain. The input to the numerical simulator includes pore-scale images of actual complex carbonate rock samples. We use a physically meaningful model which honors spatial distribution of the rock constituents for the multi-frequency interpretation of relative dielectric response. To verify the reliability of the model in multiple frequencies, we apply the model to the results of relative dielectric simulations in the pore-scale domain on 3D computed tomography scan (CT-scan) images of carbonate rock samples, which are synthetically saturated to obtain a wide range of water saturation. We successfully verified the reliability of the introduced model in the pore-scale domain using carbonate rock samples with multi-modal pore-size distribution. Estimated water saturations from the results of simulations at 1 GHz resulted in an average relative error of less than 4%. We observed measurable improvements in fluid saturation estimates compared to the cases which CRIM or MG models are used. Results demonstrated that application of conventional models to estimate water saturation from relative dielectric response is not reliable in frequencies below 1 GHz.
In January 2004, the Mangala Field discovery well was drilled in the Barmer Basin of Rajasthan, in northwestern India. The petrophysical data acquired in this and subsequent wells allow a very precise estimation of field stock tank oil initially in place (STOIIP). This paper documents the techniques that allowed the estimate of STOIIP to be more precisely defined and to be revised upward by 12%, a substantial increase when dealing with a billion barrel field. Conventional log evaluation of the initial data indicated a sequence of clean, quartzose sandstones with porosity greater than 25%. This, with resistivity in the oil column over 2,000ohm-m, suggested that water saturations (Sw) were ~15% or even less. Based on initial data and conventional techniques, the initial STOIIP estimate was made and an extensive core analysis programme was begun in six appraisal wells. The objective was to better define the actual reservoir STOIIP. An appraisal well was cored with synthetic oil based mud containing a tracer, and Dean- Stark Sw analyses were done. In addition to routine core analyses and the Dean-Stark Sw data, a sizeable set of other special core analyses is also now available. This includes extensive capillary pressure data, laboratory NMR, and core electrical properties measurements. The current petrophysical dataset verifies the existence of Sw's that are typically less than 5%PV, and often near 1%PV, in a very high-permeability and highporosity reservoir containing little clay. The reservoir contains a medium gravity, highly paraffinic oil, and is moderately oil-wet. The various laboratory datasets challenged some of the traditional assumptions concerning the use of Archie constants in such reservoirs for Sw calculations. The upward revision of STOIIP is significant, and can be principally attributed to the more accurate estimation of reservoir fluid saturations. As this work demonstrates that very low Sw values exist in the Barmer Basin, the Mangala field can provide a model for the proper economic evaluation of similar reservoirs. The laboratory results challenge some of the traditional thinking about the petrophysical properties of reservoirs such as this one. One should not be surprised that high quality reservoirs can have initial water saturations lower than 5% of pore volume on average, and with many zones at less than 1%. Present electric log tools and analysis methods will not reveal these low levels without integration with core data and appropriately designed core analysis programmes. Also, and perhaps more importantly, this work clearly demonstrates the economic worth of extensive laboratory measurements and analyses on a highvolume, high-value reservoir such as Mangala.
The Mangala Field was discovered in January 2004 (Yashwant, et al, 2006) by the drilling of the Mangala-1 well which targeted a simple, tilted fault-block trap formed within the rifted, Tertiary Barmer Basin (Figure-1) .
Fig. 1 Location map of Barmer Basin, northwest India. (available in full paper)
This well encountered a gross oil column of 156m within the Fatehgarh Sandstones of Late Palaeocene age. The Fatehgarh Sandstone consists of interbedded sands and shales, and has been sub-divided into the Lower Fatehgarh Sandstone dominated by well-connected sheetflood and braided channel sands, and the Upper Fatehgarh Sandstone dominated by sinuous, meandering, fluvial channel sands.
Seleznev, Nikita (Schlumberger) | Habashy, Tarek M. (Schlumberger) | Claverie, Michel (Schlumberger) | Wang, Hanming (Chevron U.S.A. Inc.) | Wang, Haijing (Chevron U.S.A. Inc.) | Hermes, Amir (Schlumberger) | Gendur, Jason (Schlumberger) | Feng, Ling (Schlumberger) | Loan, Mary Ellen (Schlumberger)
ABSTRACT Tight oil reservoirs present a unique opportunity for dielectric dispersion logging. Dielectric logging is sensitive to the water content and provides water-filled porosity without having to know Archie’s empirical parameters or water salinities, as is required with resistivity log interpretation. Moreover, because of the extremely low permeability of the shale reservoirs, there is effectively no invasion of the borehole fluids into the formation. Thus, in these reservoirs, dielectric dispersion logging directly provides the water-filled porosity of the undisturbed zone. In this paper, we investigate the interpretation of the dielectric dispersion measurements in tight oil formations. A representative core collection was obtained from two intervals in a field. The core material was characterized in terms of lithology and total organic carbon (TOC) content. The cores were cleaned and saturated with brines that match the formation water salinities. Next, the dielectric dispersion measurements on cores were obtained under controlled laboratory conditions of pressure, temperature, and brine salinity. On the basis of the analysis we conducted on these data, we have developed a new method for the interpretation of multifrequency dielectric logs in tight oil reservoirs. The new method has a significant advantage over the existing approaches because it does not require an input for either matrix or hydrocarbon permittivities, including kerogen permittivity, to derive water-filled porosity as is the case with the existing approaches. The new method enables the elimination of all associated uncertainties with formation mineral models in complex lithologies, unknown mineral permittivity endpoints, and, most importantly, the poorly defined permittivity of kerogen. The new method requires only the relatively well-known input of formation temperature. Thus, the new method provides a more robust, streamlined, and consistent interpretation of the dielectric dispersion logs in tight oil and reduces the uncertainty on the estimate of hydrocarbon in place. INTRODUCTION Currently the Permian Basin produces ∼4.8 million barrels of oil per day, constituting more than a third of total US production of ∼13 million barrels of oil per day (US EIA 2020). The Wolfcamp and Spraberry formations are the main producing intervals in the Permian Basin. Despite the economic significance of these reservoirs, challenges in their formation evaluation remain to be addressed.
Abstract Subsurface characterization of fluid volumes is typically constrained and validated by core analytical fluid saturation measurement techniques (example Dean-Stark or Open Retort methodology). As production in resource plays has progressed over time, it has been noted that many of these methods have a large error when compared to production data. A large source of the error seems to be that water saturations in tight rocks have been consistently underestimated in the traditional laboratory measurement techniques. Operators need improved fluid saturation measurements to better constrain their log-based oil-in-place estimates and forward-looking production trends. The overall goal of this study is to test a new laboratory workflow for fluid saturation quantification. Recent advancements have led to an innovative methodology where a closed retort laboratory technique is applied to samples from lithological rock types in the Williston, Uinta and Denever-Julesburg (DJ) basins. This new technique is specifically designed to better quantify and validate water measurements throughout the tight rock analysis process, as well as improved oil recovery and built-in prediction. A comparison of standard crushed rock analysis employing Dean-Stark saturation methods is compared to the closed retort results and observations discussed. Results will also be compared against additional laboratory methods that validate the results such as geochemistry and nuclear magnetic resonance. Finally, open-hole wireline logs will be utilized to quantify the impact on total water saturation and the oil-in place estimates based on the improved accuracy of the closed retort technique.