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Use of magnetic-resonance-image (MRI) logging is growing as a logging while drilling (LWD) tool. The use of chemical nuclear sources downhole has been a logistical and management headache. MRI, by measuring in real time the free-fluid, capillary-bound-water, and clay-based-water volumes, offers an alternative, lithology-independent porosity measurement in complex lithologies. It can be used for geosteering and geostopping when sufficient productive formation has been exposed to the wellbore. Like most measurements, at an initial phase there are specialist applications that are more susceptible to realizing the value of magnetic-resonance logging.
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 Flow assurance is a vital challenge that affects the viability of an asset in all oil producing environments. A proper understanding of asphaltene precipitation leading to deposition lends itself to reliable completions planning and timely remediation efforts. This ultimately dictates the production life of the reservoir. The Wireline Formation Tester (WFT) has traditionally aided the understanding of asphaltene composition in reservoir fluids through the collection of pressurized fluid samples. Moreover, the use of Downhole Fluid Analysis (DFA) during a fluid pumpout has augmented the understanding of soluble asphaltenes under in-situ flowing conditions. However, an accurate and representative measurement of Asphaltene Onset Pressure (AOP) has eluded the industry. Traditionally, this measurement has been determined post-acquisition through different laboratory techniques performed on a restored fluid sample. Although sound, there are inherent challenges that affect the quality of the results. These challenges primarily include the need to restore samples to reservoir conditions, maintaining samples at equilibrium composition, and the destruction of fluid samples through inadvertent asphaltene precipitation during transporting and handling. Hence, there is a need for WFT operations to deliver a source of reliable analysis, particularly in high-pressure/high-temperature (HP/HT) reservoirs, to avoid costly miscalculations. A premiere industry method to determine AOP under in-situ producible conditions is presented. Demonstrated in a Gulf of Mexico (GOM) reservoir, this novel technique mimics the gravimetric and light scattering methods, where a fluid sample is isothermally depressurized from initial reservoir pressure; simultaneously, DFA monitors asphaltene precipitation from solution and a high-precision pressure gauge records the onset of asphaltene precipitation. This measurement is provided continuously and in real time. An added advantage is that experiments are performed individually after obtaining a pressurized sample in distinct oil zones. Therefore, the execution of this downhole AOP experiment is independent of an already captured fluid sample and does not impact the quality of any later laboratory-based analysis. Once the measurements are obtained, these can be utilized in flow assurance modeling methods to describe asphaltene precipitation kinetics, and continuity of complex reservoirs. For the first time in literature, this study applies these modeling methods in combination with the AOP data acquired from a downhole WFT This approach has the potential to create a step change in reservoir analysis by providing AOP at the sand-face, along with insight that describe performance from asphaltene precipitation. The results of which have tremendous economic implications on production planning.
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.
Wu, Junchen (School of Geosciences China University of Petroleum (East China)) | Fan, Yiren (School of Geosciences China University of Petroleum (East China)) | Deng, Shaogui (School of Geosciences China University of Petroleum (East China)) | Huang, Ruokun (Research Institute of Petroleum Exploration and Development, PetroChina Tarim Oilfield Company) | Wu, Fei (Suzhou Niumag Analytical Instrument Corporation) | Wang, Zhongtao (China Petroleum Logging Co. Ltd.)
Abstract Mud filtrate invasion is a complex and time-dependent process. During the process, a zone of finite size around the wellbore (invasion zone) in which a portion of the initial pore fluids have been displaced by the mud filtrate is gradually generated. As a result, the petrophysical and fluid properties of the formation in this zone will be inevitably altered, and sometimes tend to be quite different from their initial values. Petrophysicists and logging analysts have long considered mud filtrate invasion as a nuisance due to its troublesome effect on formation properties and logging measurements, especially on resistivity logging measurements. Note that even deep reading resistivity logging may not see deep enough (beyond the invasion zone), and need to be corrected. Therefore, simulation of mud filtrate invasion under near reservoir conditions is crucial for an in-depth understanding of its physics and effects on logging measurements, and hence for logging interpretation and formation evaluation. Otherwise, this will produce substantial errors in determining initial formation properties, and estimating hydrocarbon reserves and well productivity. To date, most researchers have done a number of works on mud filtrate invasion on the basis of physical simulation at core plug scale. However, conducting invasion experiment on core plug has intrinsic limitations. Firstly, the cylindrical shape of core plug determines that the seepage form of mud filtrate within it (horizontal linear flow) is completely different from that (plane radial flow) in the actual downhole environment, thereby causing a poor representation of the filtration law observed in the experiment. Secondly, due to the small size of core plug, it is almost impossible to monitor the radial resistivity variation for reflecting the dimension and geometry of the invasion zone. To overcome the limitations, a large-sized formation module (sectorial block structure, 55.9 cm in radial depth, and 10 cm in thickness) made by sandstone outcrop was introduced in this paper. Compared with core plug, as a novel type of experimental equivalent, the formation module is larger in size, greater in saturation capacity, and much more similar to the in-situ formation. Its structure can ensure the seepage form of mud filtrate within it is exactly the same as that in the actual downhole environment. Its large size is able to provide enough space and radial distance to follow the entire invasion process from beginning to dynamic equilibrium. The dynamic processes of long-term water-based mud filtrate (WBMF) invasions were duplicated realistically in laboratory. During the whole experimental period, the dynamic invasion data (including radial formation resistivity profile and filtration rate) can be uninterruptedly real-time acquired, thereby investigating and comparing the phenomenon of WBMF invasion in the formation modules with different physical properties. Finally, by combining physical and numerical simulation, the invasion characteristics of WBMF in high-permeability and tight sandstone reservoirs under in-situ formation conditions were quantified. The results obtained in this paper provide an experimental basis and theoretical support for enlightening novel simulation methodologies of mud filtrate invasion, revealing invasion mechanisms, and establishing invasion correction model for electric logging, etc.
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.