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Penman, Andrew (Halliburton) | Wong, Siong Ming (Halliburton) | Cooper, Paul (Halliburton) | Fares, Wael (Halliburton) | Parker, Tim (Halliburton) | Goraya, Yassar (ADNOC OFFSHORE) | Alfelasi, Ali Saeed (ADNOC OFFSHORE) | Khemissa, Hocine (ADNOC OFFSHORE) | Al Dhafari, Bader Mohamed (ADNOC OFFSHORE) | Khaled, Islam (ADNOC OFFSHORE) | Ashraf, Muhammad (ADNOC OFFSHORE) | Al-Mutwali, Omar (ADNOC OFFSHORE) | Okuzawa, Takeru (ADNOC OFFSHORE)
Abstract A detailed visualization of borehole size and shape, both while drilling and prior to running casing, completions, or wireline logging equipment, is an essential requirement to minimize non-productive time (NPT) associated with poor borehole quality or wellbore stability issues. The required visualization is made possible using logging-while-drilling (LWD) high-resolution ultrasonic imaging technology, suitable for both water-based mud (WBM) and oil-based mud (OBM) systems. This paper provides borehole size and shape assessment from field deployments of a 4¾-in. ultrasonic calliper and imaging tool, illustrating the impact on borehole quality of various bottom-hole assembly (BHA) designs, including positive displacement mud motors (PDMs) and rotary steerable systems (RSS). The visualization of borehole quality enables features such as borehole spiralling and enlargement to be assessed and used as input into optimizing completions planning and formation-evaluation programs. In addition, the combination of high-resolution travel-time and reflection-amplitude images enables artefacts induced by drilling equipment, including RSS, to be identified and understood. High-resolution travel-time and reflection-amplitude images and 3D borehole profile plots are presented from multiple wells, showing how different drilling systems and logging parameters, including drillstring rotation and logging speeds, impact borehole quality. The relationship between the angular bend in the PDM and the impact it has on borehole spiralling is discussed. The LWD logs presented illustrate the factors that influence borehole quality and the methodology used to ensure that high-resolution images are available in both vertical and high-inclination wellbores, leading to the ability to reduce the NPT associated with wellbore stability issues. The observation and assessment of drilling artefacts and irregular borehole size and shape act as inputs into optimizing completion and logging programs, evaluating the optimal placement of packers and other completion equipment, and the design of the drill bit and BHA. The ability to collect high-resolution travel-time and reflection-amplitude ultrasonic images in both WBM and OBM, in wellbores ranging from 5¾ to 7¼-in., leads to significant improvements in the understanding of wellbore quality. Borehole size and shape can now be visualized in real time in either water or oil-based drilling fluids at a resolution capable of identifying all significant drilling-induced geometric artifacts. This allows the adjustment of drilling parameters to minimize NPT associated with common drilling hazards, the optimization of completion programs and wireline logging programs.
Shaver, Michael Alexander (ADNOC Offshore) | Segret, Gilles Pierre Michel (ADNOC Offshore) | Yudhia, Denya Pratama (ADNOC Offshore) | Al Ameri, Suhail Mohammed (ADNOC Offshore) | Couziqou, Erwan (ADNOC Offshore) | Al Marzouqi, Adel Rahman (ADNOC Offshore)
Abstract Thin layering and micro-fracturing of the thin laminated layers are some possible reasons for the wellbore stability problems of the Nahr Umr shale. If the drilling fluid density is too low, collapsing of the borehole is possible, and if the drilling fluid density is too high, invasion of the shale can occur, weakening the shale, making boreholes prone to instability. These effects can be semi-quantified and assessed through the development of a geomechanical model. The application of a geomechanical model of a reservoir and overlaying formations can be very useful for addressing ways to select a sweet spot and optimize the completion and development of a reservoir. The geomechanical model also provides a sound basis for addressing unforeseen drilling and borehole stability problems that are encountered during the life cycle of a reservoir. Key components of any geomechanical model are the principal stresses at depth: overburden, minimum horizontal principle stress, and maximum horizontal principle stress. These determine the existing tectonic fault regime: normal, strike-slip, and reverse. Additional components of a geomechanical model are pore pressure, unconfined compressive strength (UCS) rock strength, tilted anisotropy, and fracture and faults from image logs and seismic. Unfortunately, models used to make continuous well logging depth-based stress predictions involve some parameters that are derived from laboratory tests, fracture injection tests, and the actual fracturing of a well—all contributing to the uncertainty of the model predictions. This paper addresses ways to obtain these key parameter components of the geomechanical model from well logging data calibrated to ancillary data. It is shown how stress, UCS, and pore pressure prediction and interpretation can be improved by developing and applying models using wellbore acoustic, triple combo, and borehole image data calibrated to laboratory and field measurements. The nahr umr shale and other organic mudstone formations exhibit vertical transverse isotropic (VTI) anisotropy in the sense that rock properties are different in the vertical and horizontal directions (assuming non-tilted flatbed layering), the horizontal acoustic velocity is different from that of vertical velocity. This necessitates the building of anisotropic moduli and stress models. The anisotropic stress models require lateral strain, which as shown in the paper, can be obtained from micro-frac tests and/or borehole breakout data.
Abstract Sonic imaging has been traditionally provided using wireline acoustic logging tools in vertical or deviated pilot wells, and, in horizontal wells, using tractors and drillpipe conveyance, to provide information such as lithological changes and natural fractures extending tens of meters from the borehole. Providing a sonic imaging capability on other conveyance methods, particularly closer to drill time, has been a long-held ambition to reduce rig time and provide more timely information during the well construction process. Particularly where conventional wireline operations are not advisable or not possible, the slim-dipole logging technology offers greater flexibility and reduces operational risk. The small-diameter logging tool can be conveyed through the drillstring using a mud pump flow to deliver the tool out through a specialized 2 ½-in. portal in the bit to the open borehole. Sonic logging conveyed through the drillstring was primarily intended for estimating formation slownesses along extended reach wells providing essential information for designing completions and optimizing perforation performance along the reservoir interval. Providing a sonic imaging capability for this conveyance platform involved a tool firmware modification to extend the waveform listening times for both the monopole and dipole sources and optimizing on-board memory for data storage. New workflows were developed to reduce the interference of the direct borehole modes that typically obscure the underlying reflected arrival events, which account for the differences in the signal response, as compared to a traditional larger diameter wireline tool. Using finite difference modeling, we quantify the effects of the tool’s smaller diameter on the azimuth precision of the sonic imaging measurements and confirm the capabilities for providing useful sonic imaging results. Automated sonic imaging and migration workflows were used to convert these reflected arrival events into a 3D formation model and corresponding log of true dip and azimuth useful for formation evaluation and completions design in a timely manner. We present data from the study area introducing far-field imaging on slim dipole technology. Monopole and dipole sonic imaging waveform measurements were acquired along a highly deviated well through a complex fractured carbonate formation. Horizontally polarized shear (SH) reflections from major horizons through the formation were identified in the filtered dipole waveforms to provide structural insight for layers not crossing the wellbore. In addition, the automated workflows identified mode-converted refracted arrivals and P reflections from fractures along the lateral, and thus complemented the borehole image analysis.
Abstract A new, through-the-bit, ultra-slim wireline borehole-imaging tool for use in oil-based mud provides photorealistic images. The imager is designed to be conveyed through drill-pipe. At the desired well section, it exits the drill pipe through a portal drill bit and starts the logging. Field test measurements in several horizontal, unconventional wells in North America show images of fine detail with a large amount of geological information and high value for well development. A relatively new solution for conveying tools to the deepest point of a high angle or horizontal wells uses a drill bit with a portal hole at the bit face. As soon as the bit reaches the total depth, a string of logging tools is pumped down through the drill pipe. The tools exit the bit through the portal hole, arriving in the open hole and are ready for the up log. The tools operate on battery and store the log data in memory so that no cable is interfering as the drill pipe is tripped out of the well while the tools are acquiring data. The quality of wireline electrical borehole images in wells drilled with oil-based mud has significantly improved in recent years. Modern microresistivity imagers operate in the megahertz-frequency range, radiating the electromagnetic signal through the non-conductive mud column. A composite processing scheme produces high-resolution impedivity images. The new, ultra-slim borehole-imager tool uses these measurement principles and processing methods. Innovating beyond the existing tool designs the tool is now re-engineered to dimensions sufficiently slim to fit through drill pipes and to use through-the-bit logging techniques. The new, ultra-slim tool geometry proves highly reliable and, due to the deployment technique, highly effective in challenging hole conditions. The tool did not suffer any damage and showed only minute wear over more than twenty field test wells. The tool’s twelve-pad geometry provides 75% coverage in a six-inch diameter borehole and its image quality compares very well with existing larger tools. The field test of this borehole imaging tool covers all scenarios from vertical to deviated and to long-reach, horizontal wells. Geological structures, sedimentary heterogeneities, faults and fractures are imaged with detail matching benchmark wireline images. The interpretation answers allow operators of unconventional reservoirs to employ intelligent stimulation strategies based on geological reality and effective well development. A new high-frequency borehole imager for wells drilled with oil-based mud is introduced. Deployed through the drill pipe and its portal bit, the imager carries photorealistic microresistivity images into wells where conventional wireline conveyance techniques reach their limits in both practicality and viability.
Abstract In the modern oilfield, borehole images can be considered as the minimally representative element of any well-planned geological model/interpretation. In the same borehole it is common to acquire multiple images using different physics and/or resolutions. The challenge for any petro-technical expert is to extract detailed information from several images simultaneously without losing the petrophysical information of the formation. This work shows an innovative approach to combine several borehole images into one new multi-dimensional fused and high-resolution image that allows, at a glance, a petrophysical and geological qualitative interpretation while maintaining quantitative measurement properties. The new image is created by applying color mathematics and advanced image fusion techniques: At the first stage low resolution LWD nuclear images are merged into one multichannel or multiphysics image that integrates all petrophysical measurement’s information of each single input image. A specific transfer function was developed, it normalizes the input measurements into color intensity that, combined into an RGB (red-green-blue) color space, is visualized as a full-color image. The strong and bilateral connection between measurements and colors enables processing that can be used to produce ad-hoc secondary images. In a second stage the multiphysics image resolution is increased by applying a specific type of image fusion: Pansharpening. The goal is to inject details and texture present in a high-resolution image into the low resolution multiphysics image without compromising the petrophysical measurements. The pansharpening algorithm was especially developed for the borehole images application and compared with other established sharpening methods. The resulting high-resolution multiphysics image integrates all input measurements in the form of RGB colors and the texture from the high-resolution image. The image fusion workflow has been tested using LWD GR, density, photo-electric factor images and a high-resolution resistivity image. Image fusion is an innovative method that extends beyond physical constraints of single sensors: the result is a unique image dataset that contains simultaneously geological and petrophysical information at the highest resolution. This work will also give examples of applications of the new fused image.
Abstract Conventional formation evaluation provides fast and accurate estimations of petrophysical properties in conventional formations through conventional well logs and routine core analysis (RCA) data. However, as the complexity of the evaluated formations increases conventional formation evaluation fails to provide accurate estimates of petrophysical properties. This inaccuracy is mainly caused by rapid variation in rock fabric (i.e., spatial distribution of rock components) not properly captured by conventional well logging tools and interpretation methods. Acquisition of high-resolution whole-core computed tomography (CT) scanning images can help to identify rock-fabric-related parameters that can enhance formation evaluation. In a recent publication, we introduced a permeability-based cost function for rock classification, optimization of the number of rock classes, and estimation of permeability. Incorporation of additional petrophysical properties into the proposed cost function can improved the reliability of the detected rock classes and ultimately improve the estimation of class-based petrophysical properties. The objectives of this paper are (a) to introduce a robust optimization method for rock classification and estimation of petrophysical properties, (b), to automatically employ whole-core two-dimensional (2D) CT-scan images and slabbed whole-core photos for enhanced estimates of petrophysical properties, (c) to integrate whole-core CT-scan images and slabbed whole-core photos with well logs and RCA data for automatic rock classification, (d) to derive class-based rock physics models for improved estimates of petrophysical properties. First, we conducted formation evaluation using well logs and RCA data for estimation of petrophysical properties. Then, we derived quantitative features from 2D CT-scan images and slabbed whole-core photos. We employed image-based features, RCA data and CT-scan-based bulk density for optimization of the number rock classes. Optimization of rock classes was accomplished using a physics-based cost function (i.e., a function of petrophysical properties of the rock) that compares class-based estimates of petrophysical properties (e.g., permeability and porosity) with core-measured properties for increasing number of image-based rock classes. The cost function is computed until convergence is achieved. Finally, we used class-based rock physics models for improved estimates of porosity and permeability. We demonstrated the reliability of the proposed method using whole-core CT-scan images and core photos from two siliciclastic depth intervals with measurable variation in rock fabric. We used well logs, RCA data, and CT-scan-based bulk-density. The advantages of using whole-core CT-scan data are two-fold. First, it provides high-resolution quantitative features that capture rapid spatial variation in rock fabric allowing accurate rock classification. Second, the use of CT-scan-based bulk density improved the accuracy of class-based porosity-bulk density models. The optimum number of rock classes was consistent for all the evaluated cost functions. Class-based rock physics models improved the estimates of porosity and permeability values. A unique contribution of the introduced workflow when compared to previously documented image-based rock classification workflows is that it simultaneously improves estimates of both porosity and permeability, and it can capture rock class that might not be identifiable using conventional rock classification techniques.
Serry, Amr M. (ADNOC Offshore) | Al-Hassani, Sultan D. (ADNOC Offshore) | Ahmed, Shafiq N. (ADNOC Offshore) | Khan, Owais A. (ADNOC Offshore) | Aboujmeih, Hassan F. (ADNOC Offshore) | Zakaria, Hasan (ADNOC Offshore) | Pippi, Olivier P. (ADNOC Offshore) | Salim, Israa A. (Schlumberger) | Abdel-Halim, Amro (Schlumberger) | Donald, Adam (Schlumberger)
Abstract Faulting is one type of structural trap for hydrocarbon reservoirs. With more and more fields moving toward the brownfield or mature operations stage of life, the opportunity to target bypassed or attic oil in the vicinity of bounding fault(s) is becoming more and more attractive to operators. However, without an effective logging-while-drilling (LWD) tool to locate and map a fault parallel to the well trajectory, it has been challenging and potentially high risk to optimally place a well to drain oil reserves near the fault. Operators often plan these horizontal wells at a significant distance away from the mapped fault position to avoid impacts to the well construction and production of the well. Often, the interpreted fault position, based on seismic data, can have significant lateral uncertainty, and uncertainties attached to standard well survey measurements make it challenging to place the well near the fault. This often results in the wells being placed much farther from the fault than expected, which is not optimal for maximizing recovery. In other cases, due to uncertainty in the location of the fault, the wells would accidentally penetrate the side faults and cause drilling and other issues. Conventional remote boundary detection LWD tools do not assist with locating the fault position, as they only detect formation boundaries above or below the trajectory and not to the side. In this paper, the authors propose a novel approach for mapping features like a fault parallel to the well trajectory, which was previously impossible to map accurately. This new approach utilizes a new class of deep directional resistivity measurements acquired by a reservoir mapping-while-drilling tool. The deep directional resistivity measurements are input to a newly devised inversion algorithm, resulting in high-resolution reservoir mapping on the transverse plane, which is perpendicular to the well path. These new measurements have a strong sensitivity to resistivity in contrast to the sides of the wellbore, making them suitable for side fault detection. The new inversion in the transverse plane is not limited to detecting a side fault; it can also map any feature on the transverse plane to the well path, which further broadens the application of this technology. Using the deep directional resistivity data acquired from a horizontal ultra-ERD well recently drilled in the Wandoo Field offshore Western Australia, the authors tested this approach against the well results and existing control wells. Excellent mapping of the main side fault up to 30 m to the side of the well was achieved with the new approach. Furthermore, the inversion reveals other interesting features like lateral formation thickness variations and the casing of a nearby well. In addition, the methodology of utilizing this new approach for guiding geosteering parallel to side fault in real time is elaborated, and the future applications are discussed.
Orban, Nicolas (TOTAL) | Garg, Shashank (TOTAL) | Shaldaev, Mikhail (TOTAL) | Shrivastava, Chandramani (Schlumberger) | Cuadros, Guillermo (Schlumberger) | Marquinez, Victor (Schlumberger) | A, Adrian (Schlumberger) | Wibowo, Vera (Schlumberger) | Domingos, Ricardo (Schlumberger)
Abstract The pre-salt carbonates of Brazil pose drilling and characterization challenges associated with inherent reservoir heterogeneity; and borehole imaging while drilling often provides insights helpful for both, operational and subsequent decisions. The findings and learnings from a 3-well campaign, offshore Brazil are presented to assess and validate a recently deployed high-definition borehole imaging technology that provides industry’s first real-time ultrasonic amplitude images and time-to-depth corrections for best possible images maintaining the geological features integrity. High-definition ultrasonic measurements were acquired at two central frequencies with 0.2-in resolution and provided amplitude and transit time images for geological characterization and petrophysical evaluation in addition to azimuthal ultrasonic calipers. The lossy nature of amplitude data makes it difficult to transmit in real-time; therefore, a unique data compression technology was used to achieve industry’s first high quality amplitude images streaming while drilling. In deepwater operations acquisition of high-definition logging while drilling (LWD) images can be severely degraded if time-to-depth offset due to heave is not compensated. Recently developed heave-filtering workflows ensured the integrity of subsurface features. The time-indexed data was processed with this application in real-time, providing good results and confidence in the capability of this technology. Image-logs of the first well were helpful in interpretation and added value to the reservoir understanding; however, many intervals suffered from lack of confidence in image features. Simulations were performed to improve the images acquisition parameters based on learnings from this experience. New optimized operational parameters were applied in next two wells, resulting in image logs of excellent quality. Data from second well suffered from high heave while drilling, which required implementation of the heave-filtering memory data workflow. For the third well, an additional requirement for real-time image quality-control was defined, requiring data to be processed after every drill-stand. Real-time data quality provided confidence in optimal quality of memory data, thereby eliminating the need of post-drilling wireline operations in open-hole. The images acquired in memory helped characterize intervals of stromatolites with various morphology, and zones of vugs distribution, providing excellent alternative for wireline logging, de-risking the operations in pre-salt carbonate logging in Brazil offshore operations.
Abstract Borehole Imaging technology is often key for reservoir characterization and becomes more relevant when images are acquired while drilling to capture reservoir geology and petrophysical property distributions around the borehole. Logging While Drilling (LWD) high-resolution electrical/acoustics images of the borehole can resolve formation layers and heterogeneity down to 5mm (0.2in) scale and can detect response from far smaller features. This allows both, improved operational efficiency and better-informed drilling as well as shortening of the geological interpretation turn-around time from wireline logging time (days after drilling) to semi-real time (drilling time or hours after drilling). LWD high resolution images often suffer from the lack of direct downhole velocity measurements against the sensors. Depth tracking is on surface, referenced to the surface block movement. The imaging sensor acquiring data can be thousands of feet away from this surface reference. Imaging sensors on the bottom-hole assembly (BHA) are located not too far away from the drill bit. They are also subject to complex drilling-time motion such as tool whirling, stick and slip, vibration, mode coupling etc. This can make the downhole sensor movement dis-synchronized with the surface pipe depth increment. The Time-Depth conversion may accordingly get dis-synchronized to generate LWD depth image with missing features and distorted feature-integrity in depth. In severe conditions distorted image impacts real time image feature interpretation and leads to increased interpretation uncertainties. In this paper we investigate two main dissynchronization problems using synthetic data: heave effect and BHA stick and slip effect. Pseudo velocity is computed from the surface measurement due to the lack of downhole sensor velocity direct measurement. In order to minimize heave effect, an advanced band-pass filter is proposed. The filter order is chosen in consistency with the sensor’s pseudo velocity behavior. Other properties of this advanced filter are also presented. In order to minimize the BHA stick and slip effect, pseudo velocity is analyzed as a delayed and minimized representative of the downhole sensor movement. A windowed-thresholding method is proposed to restore the compressed and stretched image features. Dip error analysis is performed by picking bed and fracture surface on the synthetic image data, before and after image distortion correction. The analysis results show a non-negligible effect on the accuracy of the true dip computed if the distortions are left un-corrected. Even in favorable logging conditions, the apparent dip error can contribute up to 50% of the total error. In this case, the image post-processing method proposed in this paper can not only improve the image quality but also reduce image interpretation uncertainties.
Abstract Assessment of effective mechanical properties such as elastic properties and brittleness can be challenging in the presence of complex rock composition, pore structure, and spatial distribution of minerals, especially in the absence of acoustic measurements. Conventional methods such as effective medium modeling, are not reliable for assessments of mechanical properties in complex formations such as carbonates, because solid skeleton of carbonates does not consist of granular minerals with ideal shapes. The effective medium models also overlook both the spatial distribution of petrophysical properties, and the coupled hydraulic and mechanical (HM) processes, which causes significant uncertainties in geomechanical evaluations. The objective of this paper is to develop a numerical method to enhance assessment of effective mechanical properties of anisotropic and heterogenous carbonate formations by modeling the variation of effective stress and the evolution of corresponding strain. The developed method takes into account the coupled HM processes, the realistic spatial distribution of rock inclusions (i.e., rock fabrics), dynamic fluid flow, pore pressure, and pore structure. To achieve this objective, we develop a pore-scale numerical simulator by satisfying conservation equations and considering the coupling among relevant HM phenomena. We adopt peridynamic theory to discretize the micro-scale medium. The inputs to our numerical modeling include pore-scale images of rock samples as well as mechanical and hydraulic properties of each rock inclusion. We perform image processing on micro-CT scan images of rock samples to obtain a realistic micro-scale structure of both rock matrix (i.e., concentration, spatial distribution, and shape of rock constituents) and pore space. We then assign realistic mechanical and hydraulic properties to each rock constituent within the pore-scale medium. The outcomes of numerical modeling include the variation of effective stress and the evolution of corresponding strain by honoring the variability in mechanical/hydraulic properties of rock inclusions caused by their spatial distribution, pore pressure, pore structure, natural fractures, and dynamic fluid flow at the micro-scale domain. We then compare the outcomes of numerical models with the mechanical properties estimated based on effective medium models.