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Logging while drilling (LWD) refers to the addition of wireline-quality formation measurements to the directional data of a Measurement While Drilling (MWD) service. Although attempts to deliver LWD serices date back to the 1920's, the first viable tools were by J.J. Arps in the 1960's, but these did not become a commercial service. The growth of MWD in the late 1970's and early 1980's delivered the first commercial LWD services by the major service providers. The initial tools were natural gamma and resistivity, and these made geosteering possible, as horizontal drilling grew. Information is returned to the surface using the same methods as MWD telemetry options.
Nuclear magnetic resonance (NMR) imaging has long been applied in the laboratory, and over the past few decades, downhole NMR tools have been developed. The latest entries into NMR logging are logging while drilling (LWD) tools. The development of LWD-NMR is ongoing and significant changes in hardware design, as well as significant changes and improvements in data acquisition and processing, can be expected in the next few years. The general benefits of LWD have been discussed elsewhere--in particular, NMR-LWD offers a nonradioactive alternative for porosity measurement, an NMR alternative to wireline in high-risk and high-cost wells, and enables high-resolution fluid analysis in thin beds and laminated reservoirs. By definition, logging tools operating in the drilling environment are built into drill collars and are, therefore, mandrel devices.
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.
No other technology used in petroleum-well construction has evolved more rapidly than measurement while drilling (MWD) and logging while drilling (LWD). Early in the history of the oil field, drillers and geologists often debated conditions at the drillbit. With advances in electronic components, materials science, and battery technology, it became technically feasible to make measurements at the bit, and transmit them to the surface so that the questions could be answered. Directional measurements were the first measurements to have commercial application, with almost all use in offshore, directionally drilled wells. As long as MWD achieved certain minimum-reliability targets, it was less costly than single shots, and it gained popularity accordingly.
Saleh, Khaled (Kuwait Oil Company) | Al-Khudari, Abdulaziz Bader (Kuwait Oil Company) | Al-Najdi, Amer (Kuwait Oil Company) | Al-Azmi, Mejbel Saad (Kuwait Oil Company) | Al-Otaibi, Fahad Barrak (Kuwait Oil Company) | Joshi, Girija Kumar (Kuwait Oil Company) | Abdulkarim, Anar (Halliburton) | Farhi, Nadir (Halliburton) | Nouh, Walid (Halliburton) | Clarion, Benjamin (Halliburton)
Abstract Traditionally, 12.25-in. hole sections in the Jurassic formations were planned to be drilled with mud weight (MW) of 20 ppg and solids content of 45%. The planned drilling would use a rotary assembly from the Hith formation, crossing several zones in which mud losses or gains were likely. The casing would then be set in the thin shale base of the Gotnia formation. A minor inaccuracy in casing setting depth could often lead to well-control issues. Pore pressure drops severely below the shale base and requires a MW of 15 ppg. Passing this shale base can lead to severe losses and potential abandonment of the well. An anhydrite marker is located approximately 50 ft above the shale base. To reduce risk, the operator would normally drill to this marker at a rate of penetration (ROP) of 20-30 ft/hr, then decrease the ROP to 2 ft/hr. While slowly drilling the last part of the section, penetration would be stopped every few feet to circulate bottoms-up to receive samples confirming the shale base; this process requires an additional 24 hours of rig time. After reaching the casing point, the operator would pull out of the hole to pick up logging-while-drilling (LWD) tools to perform a wiping run. This logging, however, is frequently cancelled because of wellbore stability issues, resulting in the loss of important formation-evaluation data across this interval. A new solution has been developed, comprising drilling with a rotary assembly to the final anhydrite marker, then pulling the string out of hole to pick up LWD triple-combo and sonic tools, with a conventional gamma ray sensor placed only 6 ft from the bit. The remaining part of the section would then be drilled at 7-10 ft/hr until the gamma-ray tool detected the shale base, thereby determining the casing depth. In addition, it was planned to re-log the previously drilled interval. This solution prevented the well from potential abandonment and reduced drilling time. It also secured critical formation evaluation data for exploration and future field development. The engineered drilling solution was tried for the first time in these formation sequences within a harsh drilling and logging environment. The option of rotary steerable services with an at-bit GR sensor was not considered because of the high cost.
Wang, Haifeng (Schlumberger) | Thiel, Michael (Schlumberger) | Denichou, Jean-Michel (Schlumberger) | Salim, Diogo (Schlumberger) | Leveque, Soazig (Schlumberger) | Wibowo, Vera Krissetiawati (Schlumberger) | Woods, Chris (Woodside Energy Ltd.) | Baker, Darren (Woodside Energy Ltd.)
Abstract Recently the drilling industry has seen many advances in the application of deep directional electromagnetic (EM) measurements for mapping deeper into the reservoir, with the latest one capable of seeing over 250 ft above and below the wellbore providing unprecedented understanding of the reservoir. This measurement technology is now being used to look ahead of bit while drilling, for exploration wells to reduce drilling risks associated with unexpectedly penetrating certain formation. With the increasing complexity of the reservoirs that the industry is targeting, there is more and more quest for expanding the reservoir mapping capability, not just a 1D approach that can only map resistive boundaries on the vertical axis or near vertical axis and assume infinite extend in all other directions, but to enable geoscientists to better steer the well and better understand the reservoir structure and fluid contact in a full three-dimensional context around the wellbore. In this communication, the authors introduce a new solution to this quest for full three-dimensional real-time reservoir mapping. The solution is composed of three parts: a set of new measurements acquired downhole and transmitted to surface in real-time, a new inversion algorithm that is model independent and therefore fit for any reservoir complexity, and a new computing paradigm that make it possible to provide answers in real-time while drilling. The new set of measurements almost doubles the number of well logs that were acquired before and greatly enriches formations evaluation around the wellbore. The new algorithm, different from all previous algorithms, is not confined to any specific forms of models, making it suitable for exploring and finding solutions in complex reservoir settings. Finally, taking advantage of the latest advances in the Cloud computing, turnaround time of the new inversion is improved by over hundred times, thanks to the scalability of the algorithm design and Cloud computing infrastructure. Combining all these together allows to achieve three-dimensional reservoir map, without having to tradeoff between high resolution and depth of investigation. The 3D reservoir map that is generated from multiple transverse 2D inversion slices in real-time, enables timely update of reservoir model as drilling progress for the operator to make informed decisions. This new technology is currently deployed in several locations around the world and in different environments. In this paper, the authors review deployment results, to illustrate the technology, from preparation to real-time execution, and finally to post-job model update. With the ability of mapping in all directions while drilling, this technology opens the door to many applications and will enable the operators to target more complex reservoirs and achieving better geosteering results where 3D mapping and steering are required. In addition to its benefits for real-time operations, the technology also enables the geoscientists to update and calibrate their reservoir models with fine and accurate details, which can further benefit multiple disciplines including drilling, completion, production and reservoir management.
Clegg, Nigel (Halliburton) | Duriez, Alban (Halliburton) | Kiselev, Vladimir (Halliburton) | Sinha, Supriya (Halliburton) | Parker, Tim (Halliburton) | Jakobsen, Fredrik (Aker BP) | Jakobsen, Erik (Aker BP) | Marchant, David (Computational Geosciences Inc.) | Schwarzbach, Christoph (Computational Geosciences Inc.)
Abstract Mature fields contain wells drilled over decades, resulting in a complex distribution of cased hole from active producers, injectors, and abandoned wells. Continued field development requires access to bypassed pay and the drilling of new wells that must be threaded between the existing subterranean infrastructure. It is therefore important to know the position of any offset wells relative to a well being drilled so collision can be avoided. A well’s position is determined by directional survey points, for which the measurement error accumulates along the length of the well, increasing the uncertainty associated with the well position. The positional uncertainty is greater in wells drilled with older generations of surveying tools. Thus, a new well may be required to enter the ellipse of uncertainty representing the potential position of an older well, risking collision, to be able to reach desired targets in more distal parts of the reservoir. A potential solution to reduce collision risks is ultra-deep electromagnetic (EM) logging-while-drilling (LWD) tools, whose measurements are strongly influenced by proximity to metal casing and liners. This paper presents 3D inversion results of ultra-deep EM data from a development well in a mature field, which were used to identify a nearby cased well. Due to the large effect of casing on the measured EM field, it is important to validate the 3D results; this has been achieved using a synthetic modelling approach and assessment of azimuthal EM measurements. Models were created with casing positioned within resistive media with similar properties to those seen in the studied cases. Inverting these models allows testing of the inversion algorithm to show that it is providing a good representation of the cased well’s position relative to the newly drilled well. Further analysis of recorded and synthetic data showed that the raw EM field is strongly influenced as the casing is approached. The casing can be seen to clearly affect the EM field measurements when it is in the region of 10 to 15 m ahead of the EM transmitter, with the effect increasing in magnitude as this distance diminishes. Modelling shows that the EM field measurements behave in a predictable manner. As the ultra-deep EM tool approaches a cased well, it is possible to determine whether the casing is above, below, or critically, directly in line with the planned trajectory of the new well. Existing subterranean infrastructure can pose a major hazard to the drilling of new wells. Being able to identify an old well ahead of the bit using ultra-deep EM measurements would allow a new well to be steered away from the hazard or drilling stopped, preventing a collision. In addition, this may also allow the drilling of well paths that would otherwise be impossible to drill, due to the limitations imposed by positional uncertainty of the new and offset wells. This use of ultra-deep resistivity technology takes it beyond its more traditional benefits in well placement and formation evaluation, making it useful for improving well drilling safety.
Abstract The objective of this paper is to provide a context for strategic use of fluid sampling while drilling (FSWD) in the deep-water environment. Our work is based on data collected from Gulf of Mexico wells over the last 7 years and we incorporate both operator and service company experience. In this paper we review the current FSWD technology and the quality of the fluid samples. We provide practical guidelines for executing the FSWD operation and review types of wells where FSWD has been most effective. We also discuss the role FSWD plays in the business of efficient well construction (drilling, evaluating, and completing). Strategic use of FSWD can provide time savings and operational risk mitigation. FSWD has proven to provide high quality data and fluid samples, however, an awareness of the differences between conventional fluid sampling (wireline) and sampling while-drilling is important for maximizing benefits. Additionally, long term strategic commitment to FSWD is likely to provide the largest benefits to operators. FSWD has been around for about 10 years, but how, and where, to apply the technology has not been clear to many operators. The broader industry can benefit by learning from experiences accumulated through consistent and extensive FSWD use in deep-water wells showing how the technology has progressed, and how it is used to achieve business benefits.
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.
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.