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Abstract A new 2 1/8-in. outer-diameter photorealistic imager for oil-based muds (OBM) has recently started field testing in unconventional formations in North America. To obtain the best interpretation of its measurements, a twostep quantitative inversion workflow has been developed with a performance similar to the existing inversion workflows for the regular high-definition OBM imagers. The new inversion workflow provides borehole resistivity images, borehole rugosity images, and borehole dielectric permittivity images as well as multiple quality curves. The modeling of the new borehole imager is performed with a 2D axisymmetric finite element code. An efficient forward model is developed by fitting the tool response tables into fourth-order polynomials in terms of the sensor standoff, formation, and mud impedivities for broad ranges of model parameters. The fast forward model based on the polynomial fitting is calibrated against the actual tool measurements in a laboratory setup and applied in the inversion algorithms. The inversion workflow is tested with synthetic data and the inverted model parameters are compared with their true values to study and analyze their corresponding measurement sensitivity and optimize the inversion input parameters. It is used to invert several field test datasets in unconventional wells. The results show that the inversion results provide critical added value for formation evaluation, showing geological features that would otherwise be missed, such as fracture properties. Projection-based formation impedivity images, as available for the regular high-definition OBM imagers, are ideal for conductive formations but suffer from a rollover effect in resistive formations. In comparison, the image formed from the inverted formation resistivity does not roll over and is more consistent for resistive formations. The image formed by the inverted standoff reflects surface conditions of the borehole and can be used to interpret whether the fractures and the faults are open, closed, or damaged in the drilling process. Multiple image examples are given from unconventional wells to demonstrate that the inverted standoff image can reveal fractures when there is insufficient or even no contrast in medium properties. The inverted standoff image also serves as a diagnostic tool for interpreting borehole and tool conditions during the measurements. The inverted permittivity may have a larger dynamic range than the resistivity especially for unconventional formations, thus providing an alternative and potentially clearer borehole image.
Bloemenkamp, Richard (Schlumberger) | Zhang, Tianhua (Schlumberger) | Comparon, Laetitia (Schlumberger) | Laronga, Robert (Schlumberger) | Yang, Shiduo (Schlumberger) | Marpaung, Sihar (Schlumberger) | Guinois, Elodie Marquina (Schlumberger) | Valley, Glenn (Schlumberger) | Vessereau, Patrick (Schlumberger) | Shalaby, Ehab (Schlumberger) | Li, Bingjian (Schlumberger) | Kumar, Anish (Schlumberger) | Kear, Rick (Schlumberger) | Yang, Yu (Schlumberger)
While they provide a recognized technical advance for wells drilled with oil-based mud (OBM), OBM-adapted microresistivity images of the last 13 years remain far from the geologic interpretability provided by imagers that operate in a water-based mud (WBM) environment. Recently the use of a high-definition WBM imager has been demonstrated in wells drilled with OBM, but its application has been principally limited to high-resistivity formations with excellent hole conditions or to cases where the drilling fluid has been engineered to favor acquisition.
To fill this gap, a new wireline microelectrical imager has been introduced, engineered from the ground up to acquire high-definition, full-coverage images in any well drilled with OBM. The all-new physics architecture includes a strategy to minimize and eventually eliminate the inevitable contribution of the nonconductive fluid and to optimize the mode of operation in accordance with formation parameters. New tool-specific processing steps complement the standard borehole image processing workflow to render highly representative images of the formation.
Examining the measurement response in detail, via both modeling and real-world examples, demonstrates several favorable characteristics, for example, sensitivity to vertical as well as horizontal features, reduction of shoulder-bed effects, and reduced sensitivity to desiccation cracks.
The novel mechanical architecture includes a new sonde design with significant operational advantages. It conveys a sensor array composed of 192 microelectrodes providing 98% circumferential coverage in an 8-in. borehole. The individual microelectrodes are smaller than those of industry-standard imagers for WBM, each with a surface area of only 10.8 mm2, which provides excellent spatial resolution.
From a field test comprising more than 40 operations in various OBM fluids, high-definition images were acquired in a variety of environments, from high-resistivity carbonates to shales and low-resistivity clastics, demonstrating the robustness and widespread applicability of the new tool. The examples include challenging environmental conditions and they explore the limits of accurate measurement. Comparison with legacy images demonstrates that the new physics of measurement coupled with the high-resolution, high-coverage sensor array has achieved much more than a microimaging step change. The new images faithfully reproduce formation geology with photorealistic clarity and promise to revolutionize the geologic interpretation of wells drilled with OBM.
Li, Bingjian (Schlumberger Oil Field Services) | Chen, Yong-Hua (Southwestern Energy, Woodland, USA) | Gawankar, Kiran (Schlumberger-Doll Research) | Miller, Camron K. (Schlumberger Oil Field Services) | Xu, Weixin (Schlumberger Oil Field Services) | Laronga, Rob J. (Schlumberger Oil Field Services) | Omeragic, Dzevat (Southwestern Energy, Woodland, USA)
Abstract Distinguishing open natural fractures from healed fractures has been a significant challenge in shale formations drilled with oil-based mud. Ultrasonic imaging tools can locate open fractures, but such data is seldom acquired due to concerns related to the effects of heavy mud and, in high-angle wells, operational efficiency and tool eccentralization. Until now, the microelectrical image tools in the market were not capable of differentiating open fractures from healed fractures in oil-based mud. A new, high-definition oil-based mud microelectrical imager has been deployed that operates at high frequencies and provides images with high borehole coverage. This new tool can identify natural fractures, sub-seismic faults, and other geological features in the reservoirs. In addition to high-resolution images of formation resistivity, an advanced inversion processing can be applied to generate resolution-matched images of the quantified standoff between each sensor in the array and the borehole wall. Such standoff images are of special value for differentiating open fractures from healed fractures. The use of these standoff images are presented in several recent case studies from U.S. shale plays. In the first case study from a pilot shale well in the northeast, natural fractures are identified on the new microelectrical imager and then further interpreted as open, partially open or healed fractures based on the inverted standoff images. Such open fracture interpretation has been validated by ultrasonic image data from the same well. In the second case study from an Eagle Ford Shale lateral in south Texas, both natural fractures and sub-seismic faults were detected. Interestingly, one of the interpreted open faults based on standoff images was even evident on dynamic pressure data in a monitoring well nearby during the stimulation process. Natural fractures can impact the shale reservoir quality, completion quality, or both, depending on the fracture types and intensity. Therefore, it is beneficial to have a reliable dataset to sort fractures by their type: open, partially open and healed.
Haddad, E.. (Schlumberger) | Wells, P.. (Schlumberger) | Fredette, M.. (Schlumberger) | Toniolo, J.. (Schlumberger) | Mallick, A.. (Schlumberger) | Nguyen, H.. (Schlumberger) | Bammi, S.. (Schlumberger) | Laronga, R. J. (Schlumberger) | Kherroubi, J.. (Schlumberger) | He, A.. (Schlumberger) | Gelman, A.. (Schlumberger) | Jarrot, A.. (Schlumberger) | Fratarcangeli, D.. (Tapstone Energy) | Alcorn, T.. (Tapstone Energy) | Tipton, T.. (Tapstone Energy)
Abstract Microelectrical imaging is a well-known and highly versatile geological and reservoir characterization technique that produces representative and photorealistic images of the formations intersected by a wellbore to form the basis of a thorough and reliable geological interpretation. These images are used to characterize geological structures, natural fractures, faults and interpret sedimentary features and rock facies. This paper introduces the world's first through-the-bit microelectrical imaging tool, also the world's smallest tool in the genre, at 2-1/8 in diameter and 140 lbs. The new tool provides the lowest-cost, lowest-risk method to obtain high-quality images in lateral wells for applications such as fracture characterization of unconventional reservoirs. We present the electrical and mechanical design innovations that enabled repackaging the performance of the industry- standard microelectrical imaging tool into a ‘nano’ format tough enough to withstand the rigors of through-the-bit conveyance, often in laterals that exceed two miles' length. The basic physics of the industry-standard are maintained with some obvious changes to the geometry. A simple and elegant twelve-arm bowspring design maximizes coverage of the borehole wall, while being robust enough to prevent pads from being ripped off downhole, a well-known fault of existing imaging tools in lateral wells. In-pad front-end signal processing of twelve buttons ensures strong signal-to-noise while demanding further innovation in miniaturization. Notwithstanding its diminutive size, the new tool delivers images of 5mm nominal resolution and 76% circumferential coverage in six inch boreholes drilled with water-base fluids. We discuss implications of the new design for the image data processing chain, as development of significant new and tool- specific processing methods was necessary. For example, the irregularity of tool movement in long laterals, the lack of wireline cable depth measurement during logging, and the multiple pad levels necessitated the application of new depth correction techniques that smartly combine physics-based and image-based approaches. On another point, considering the lack of real-time QC during memory acquisition, the data acquisition strategy was designed to provide comprehensive auxiliary data to give the processor maximum flexibility to quality control and correct the signal processing. We review the results of seventy-five jobs conducted in North American unconventional wells, and examine the details of specific case studies. In many specific plays, a growing number of operators recognize the geology—in particular the distribution of natural fractures and faults along the lateral, as the key factor in completion performance. We find that the new and efficiently acquired images are a powerful tool to identify and characterize these features, underlining a strategy to eliminate negative surprises and improve lateral completion performance.
ABSTRACT Natural fractures maintain a significant role in many hydrocarbon plays, in both conventional and unconventional reservoirs. In exploration and development scenarios, specific fracture properties, such as orientation and density, are important. However, more critical is their internal architecture: are the fractures open to fluid flow or filled with minerals? Borehole microresistivity imaging tools are widely used to determine these fracture characteristics. In wells drilled with water-based muds, open fractures are filled with conductive borehole fluid that enables distinguishing open, water-filled fractures from resistive, mineral-filled fractures and the surrounding rock. However, many wells today are drilled with oil-based muds. In this case, mineral-filled fractures and oil-based-mud-filled fractures are equally highly resistive and cannot be directly distinguished using resistivity images only. The latest-generation wireline oil-based-mud microresistivity imagers operate in the megahertz frequency range, radiating the electrical current capacitively through the nonconductive mud column and delivering photorealistic borehole images. Both electrical conductivity and dielectric permittivity components constitute the measured signal. The quantitative interpretation uses a sequence of model-based parametric inversion runs to first estimate the mud properties of the log and subsequently invert for the standoff of the microelectrode buttons to the rock surface and the formation resistivity and dielectric permittivity within the volume of investigation. Our example case shows highly resistive, high-angle fractures from the resistivity images with their orientation and density. The standoff image determines if the mud column penetrates the fracture plane, showing an apparently high standoff compared with the surrounding rock. If the standoff appears high in the fracture plane, the fracture is classified open to fluid flow. However, are these fractures indeed fully dilated and open or are they filled with different materials—are they partially mineralized with calcite and partially open, filled with mud? To further determine the fracture fill and susceptibility to fluid flow, a new workflow employs the material dependency of the relative dielectric permittivity. The relative permittivity is estimated as function of resistivity and frequency pixel by pixel on the resistivity image. The estimate formula is empirically derived from several hundred laboratory measurements on core plugs with different fluid saturations and salinities. The resulting borehole image enables distinguishing materials in the volume of investigation. The new image shows that drilling-induced fractures have low values, which correspond to the oil in open fractures controlled by the mud. The image also shows some fractures with slightly elevated values, corresponding to rock-forming minerals (calcite) and partially low values, which are interpreted as mud, saturated with oil. As result, these types of fractures are classified as partially open with vuggy mineral fill, consistent with the core description. Higher values on the image are attributed to shales and other rocks with raised clay content. Simulation results confirm the sensitivity of such estimated relative permittivity with respect to rock parameters such as rock-matrix permittivity and water-phase tortuosity.