Background and Aim: Foot-and-mouth disease virus (FMDV) serotypes A, O and South African Territories (SAT2) are endemic in Egypt; each is presented by a number of partially related topotypes and lineages, depending on their geographical origin. Continuous mutations and the emergence of new topotypes that lead to occasional vaccination failures were frequently recorded, so this study aimed to genetically characterize the circulating FMD virus strains in Egypt during 2013 and 2014 outbreaks, focusing on amino acids variations in VP1 region. Materials and Methods: A total of 51 oral tissue samples were collected from cattle and buffaloes in 13 farms, and 38 individual cases showed clinical signs suspected to be FMD in six Egyptian Governorates (Cairo, Giza, Qaliubia, Fayoum, Sharquia, and Assiut). FMDV in collected samples was characterized by reverse transcription-polymerase chain reaction (RT-PCR) amplification of full VP1 region, sequencing, and phylogenetic analysis. Results: Out of 51 samples, 44 (86.27%) were positive by RT-PCR using universal primers. Serotype O was predominant and detected in 31 samples (70.45%), serotype A was detected in 9 samples (20.45%), and then serotype SAT2 was identified in 4 samples (9.10%). Sequencing and phylogenetic analysis of VP1 demonstrated clustering of serotype O, A, and SAT2 in EA-3 topotype, ASIA topotype, and topotype VII, respectively. Serotype O is closely related to O/SUD/8/2008 with 94.6% identity but showed 14.6% differences from vaccine strain (O/PanAsia-2) of ME-SA topotype. Furthermore, Serotype A and SAT2 were closely related to recent circulating Egyptian isolates and vaccine strains type A/EGY/1/2012 (Asia topotype, lineage Iran-05) with identity 96.4% and vaccine strain of SAT2/EGY/A/2012 (topotype VII, lineage SAT2/VII/ALX-12) with identity 95.3%, respectively. Conclusion: The present study recommended further studies of serotype O to determine the immunogenic relationship between the vaccine strain and the new strains to attain maximum protection against circulating viruses.

As the oil and gas industry expands into evermore challenging environments with more complicated processes and designs, minimizing well cost and ensuring the best use of resources has resulted in an increase in the engineering planning and field-execution requirements. Drilling optimization has changed from simply improving the rate of penetration (ROP) to analyzing all aspects of the drilling process by establishing an integrated workflow that enables different engineering departments to plan and execute the well. In this case history, the operator’s challenges included vibration in horizontal sections, hydraulics, and wellbore integrity concerns resulting from narrow mud weights available to minimize reservoir damage and to control pore pressure. Drilling optimization also includes measuring and improving operational efficiency and consistency. Many activities are required in a drilling operation, and the inefficiency of these activities increases well costs. This inefficiency can be described as invisible lost time (ILT), which has been shown to contribute to up to 15% of total well cost. It exposes open holes to longer elapsed times which causes hole problems, especially in reactive formations. This case study takes a holistic look at the drilling performance and efficiency improvements that can be made by planning, modeling, and introducing a collaborative drilling engineering team with a real-time field execution team to analyze drilling challenges and address those challenges for future developments.

No abstract

To meet the current oil and gas market challenges, there is an industry need to optimize cost by safely drilling longer horizontal wells to maximize well productivity. Drilling challenges include the highly deviated trajectory that starts from the surface sections and wellhead, the high DogLeg Sevirity (DLS) profile with collision risks, and the thin complex geological structures, especially in new unconventional fields where numerous geological and geomechanical uncertainties are present. To mitigate for those challenges, reviewing the existing drilling techniques and technologies is necessary. To compete in the current Hi-Tech and Automation era, the main challenges for directional drilling service providers are to reduce well time, place wells accurately, and improve reliability, reducing repair and maintenance costs and helping the customer reduce time and costs for the overall project. Offset wells analysis and risk assessments allowed identifying the main challenges and problems during directional drilling phases, which were highlighted and summarized. As a proposed solution, the new generation of intelligent fully rotating high dogleg push-the-bit rotary steerable system has been implemented in the UAE onshore oil and gas fields to improve the directional drilling control and the performance. This implementation reduced the Non-Productive time (NPT) related to the human errors as the fully automation capabilities were being utilized. The new rotary steerable system has the highest mechanical specs in the market including self-diagnosis and self-prognosis through digital electronics and sophisticated algorithms that monitor equipment health in real-time and allow for managing the tool remotely. As a result, the new intelligent RSS was implemented in all possible complex wellbore conditions, such as wells with high DLS profile, drilling vertical, curve, and lateral sections in a single trip with high mud weight and high solid contents. Automation cruise control gave the opportunity to eliminate any well profile issues and maintain the aggressive drilling parameters. Using the Precise Near-bit Inclination and Azimuth and the At-Bit Gamma real-time data and high-frequency tool face measurements in the landing intervals where required for precise positional control to enable entering the reservoir in the correct location and with the correct attitude helping the customer's Geology and Geophysics department to place wells accurately while maintaining a high on bottom ROP.

ADNOC's limestone reservoirs suffer from the phenomena of injection water traveling preferentially at the top of the reservoir placing injection water above oil held there by capillary forces. Horizontal wells placed below areas of water override, cause the water above to slump unpredictably, increasing water cut and eventually killing the horizontal. Ultra Deep Directional Electromagnetic (EM) Logging While Drilling (LWD) tools provide the measurements to identify and map these water zones, improving reservoir management and design optimal well placement. 1D & 2D EM inversion modeling was conducted on two of ADNOC's largest oil producing reservoirs to evaluate the ability of an Ultra Deep Directional EM LWD Resistivity tool to identify water slumping in the presence of formation bed resistivity contrasts and predict depths of reliable detection (DOD) under various well trajectory scenarios. The inversion was run using depth of inversions up to 150 ft, the maximum expected vertical distance of tool to injection water. Modeling provided an optimized tool configuration (frequency, transmitter-receiver spacing's) to meet objectives. The inversion results further provided guidance for Geosteering, Geomapping and Geostopping decisions. The inversion results in these reservoirs indicated that the Ultra Deep resistivity tool has a DOD of 50-150 ft to pick reservoir tops and water slumping or non-uniform waterfront boundaries. The real-time inversion will optimize landing and drilling long horizontal section to increase net pay for production and even through sub-seismic faults, measuring changes in the reservoir fluid distribution, reduce drilling risk and exceed well production life. This information will aid in updating static model with water flood areas, reservoir tops, faults and structure, designing better infill well spacing and trajectories within bypass oil regions, designing proactive and not reactive smart well completions to delay or reduce water production and ultimately extended plateau and improve ultimate recovery factor. Furthermore, it will aid resistivity mapping of underlying or overlying reservoirs for future development plans. The encouraging results of this study confirmed to move forward with a field trial in these challenging reservoirs for better reservoir and fluid characterization and its management.

The future of hydrocarbon production has shifted toward the significant production potential of unconventional reservoirs. As the recovery of oil and gas becomes more complex, drilling through unconventional reservoirs pushes engineering boundaries to new limits to meet world demand in a safe and environmentally acceptable manner.ADCO decided to drill Well XY-123 in ЉXYЉ field in Abu Dhabi. ADCO leveraged extensive experience gained from numerous unconventional reservoir projects throughout the world in addition to the experience obtained from drilling over 1,000 wells in XY field.The main objective of the well was to acquire as much data as possible to create a database of knowledge for accurate study of the hydrocarbon potential in these reservoirs. Various formation evaluation data (density, neutron, resistivity, gamma ray, and sonic) were acquired from both loggingwhile-drilling (LWD) and logging using TLC. In addition, formation pressure sampling stations were also extracted from the reservoir. Conventional cores were successfully cut, with a 100% core recovery rate. Full data acquisition across the reservoir was obtained by the ADCO for the first time.Drilling such wells requires using the latest innovations in drilling engineering principles. These wells are more interrelated and sensitive to small changes than conventional wells. An integrated approach for both planning and execution is crucial because of the potential for risks, including high H 2 S percentages and drilling across high-pressure high-temperature (HP/HT) reservoirs, and all uncertainties must be properly assessed using solid engineering planning from many disciplines. This paper describes solutions to numerous challenges in terms of both planning and execution of a high-profile well, in addition to the experience gained. With the shared experience from the lessons learned drilling the well and the offset wells worldwide, this paper proposes a way forward view of the future of drilling unconventional reservoir wells in Abu Dhabi. Well ObjectiveThe well in question here was to be drilled in XY field, located in the onshore area of Abu Dhabi Emirates, about 150 Km to south west of Abu Dhabi city. This field is the largest mature asset in and the largest

In the 12 ¼-in. section of an Abu Dhabi offshore company's wells, complex directional well profiles and varied formation characteristics create a challenging drilling environment. Outcomes of the drilling efforts in this environment include non-productive time (NPT) as a result of tripping, as well as lower rates of penetration (ROP) as a result of vibration. Conventional positive displacement motors (PDM) were typically used in this offshore application. Polycrystalline diamond compact (PDC) bits were run with the PDMs because of their longer life and increased ROP through the varied formations; the particular designs used had provided good steerability in previous applications. The conventional PDM-PDC system, however, often creates high vibrations that reduce overall performance. In addition, the section has always required two runs so that the bent housing could be changed in the second run, which resulted in lost time for tripping. To address these issues, a new system was designed that provides significant advantages over conventional steerable assemblies. This system includes a specially designed long-gauge PDC bit run on a point-the-bit rotary steerable tool, both of which were designed and modeled together. The advantages observed using this system in the field includes improved hole quality and increased ROP, as well as reduced hole spiraling and tortuosity, reduced vibration, better steerability and hole cleaning, increased bit life, and reduced tripping time. This paper provides three case studies of the use of this system in which one of Abu Dhabi offshore operators achieved the objective of drilling the 12 ¼-in. interval, which averaged more than 2,500 ft, in a single run, and optimized the ROP without compromising hole quality or cleaning efficiency. A summary of results indicates the effectiveness of design improvements, with the new bits achieving the highest single run ROP in history for this particular operator and longest footage achieved in a single run. These benefits are expected to have considerable implications on future drilling operations. Introduction For our offshore client, saving drilling time and improving ROP without compromising the hole quality was always important. For this reason, after drilling the first two wells in their field, the client's drilling team conducted a workshop and invited all service providers to call for an overall improvement. Increased ROP was only part of the company's goal because increasing only the ROP can lead to issues related to wellbore stability and hole cleaning. In addition, the combination of increased ROP with formation characteristics can create severe vibrations, which increase the probability of malfunction of drilling tools. Concentrating on hole quality only without allowing optimum drilling parameters was not the ultimate goal; therefore, the balance of improving the ROP, drilling efficiency, and hole quality was set as the first goal to achieve. Two different drilling bottomhole assemblies (BHAs) were used to accomplish the drilling of the 12 ¼-in hole section, as requested. The first run was usually almost vertical and a new or used PDC bit was normally used. A bent housing was usually added for a slight build-up and to continue the tangent section for the remainder of the hole. As a result of using a normal PDC bit and conventional motors, the following issues were always encountered while completing the course of this section:Lower ROP resulting from the directional work and, in some intervals, from severe vibrationsFaster bit wear as a result of hole condition and spiralingDifficulties and extra NPT while running the casing as a result of hole quality

Planning complex well designs for multilateral and extended reach wells presents substantial challenges for optimizing well construction, drilling risks, and economics. The subject well of this case study is located in a prolific onshore field in Abu Dhabi; the field has been producing for many years, giving rise to pore pressure uncertainties between different reservoir sublayers. The primary challenges are associated with reducing drilling time for the future development program while delivering optimized drilling performance and cost effective openhole side tracks with rotary steerable system (RSS) bottomhole assemblies (BHA), eliminating extra trips, and enabling accurate formation evaluation and precise well placement. Goals included optimizing drilling parameters in accordance with rig capabilities, addressing anti-collision concerns, optimizing mud weights to mitigate differential sticking, maximizing reservoir exposure in thin reservoir sublayers, and minimizing the surface footprint. Close collaboration between the operator and the directional drilling/logging-while-drilling (LWD)/geosteering service provider was a key component of developing a fit-for-purpose solution. This solution consists of a comprehensive feasibility study using historical field data, a detailed pre-planning process that includes well and BHA design; anti-collision; and optimizing sidetrack points, LWD configuration, and tool downloads for longevity. The well plan incorporated a trilateral design with optimized trajectories for minimizing dogleg severity (DLS) and borehole tortuosity in the horizontal laterals while cutting the poor porosity layers that separate the targeted four thin reservoir sublayers. The mother bore trajectory also included humps (building the inclination from 89° to 91°, then returning to 89° within 50 ft with 4° DLS) to facilitate openhole sidetracks without the need to pull out of the hole (POOH). The BHA included a RSS with azimuthal density, neutron porosity, gamma ray, and propagation resistivity tools. The alternative BHA included azimuthal deep resistivity and acoustic LWD sensors to meet complex drilling, geosteering, and petrophysical data gathering requirements. A formation tester while-drilling sensor was also included to provide accurate pore pressure measurements to optimize mud weight in real time. Continuous (24/7) real-time operation support provided drilling performance monitoring and analysis, and facilitated geosteering services. Three horizontal laterals of 5,000 ft each were successfully drilled with openhole sidetracks without POOH for the first time in the United Arab Emirates. Mud weights were optimized by reductions from 78 to 70 pcf, and 100% reservoir exposure was attained in all three laterals. Finally, significant improvement in production and cost savings, as compared to traditional single lateral designs, prompted a review of the future development drilling program. This paper presents a step change from traditional field development drilling techniques in terms of well construction. Similar well designs are currently being implemented to benchmark drilling, well placement, and petrophysical data gathering requirements for future development drilling to maximize asset value.