A new workflow was implemented for the first time in three UAE onshore wells with the primary objective being to increase drilling efficiency while managing the associated risks. The workflow combines proven technologies, software and wellbore surveillance services to deliver risk-free wells ahead of authority for expenditure (AFE) targeting the reduction of nonproductive time (NPT) and invisible lost time (ILT), together with risk management. The workflow begins with a preliminary field analysis to identify the main challenges and areas that needed improvement. The observations are consolidated on a comprehensive drilling road map by well section that are used to outline prevention and mitigation measures, expected rate of penetration (ROP) and recommended drilling parameters. The study also allowed for identifying performance benchmarks such as average and on bottom ROP and connection time. Key performance indicators (KPI) were developed to monitor progress and track the well with respect to well improvements versus the benchmarks identified. The selection of the monitoring tools and modules required during the execution phase was developed based on the risks and KPIs identified during the field study and were further tailored to target specific challenges such as stuck pipe prevention, hole cleaning, shock and vibration, and connection time. The workflow enabled the flawless execution of three onshore wells ahead of AFE with zero NPT. The closed loop monitoring enabled real time interventions preventing risks such as stuck pipe, ensuring shoe-to-shoe drilling, and avoiding potentially lost-in-hole (LIH) costs. This monitoring process also enabled significant ILT reduction, saving approximately USD 500k for the three wells. This case study demonstrates the use of a novel approach to increase well construction efficiency by eliminating lost time while enhancing risk control. The main basis for success of this workflow is using existing and cost-effective technology while capitalizing on the renewed synergy between different departments such as drilling, mud logging, and well operations analysis. The workflow can be customized based on the different needs by combining specific modules for monitoring, analysis, and wellbore surveillance services to increase the efficiency of any well construction.

Rotary Steerable System (RSS) has been used for quite some time in the industry and in UAE onshore fields. But as the wells become increasingly more complex operators are forced to look into upgraded technologies to expand the envelope beyond the known limits, often implying more complex and costly bottom hole assembly (BHA). At the same time the current oil price situation make it extremely difficult for operators to justify any increment of Authority for Expenditure (AFE) or to take the risk of experimenting new solutions that could potentially increase non-productive-time (NPT), even if for just limited period until the learning curve is established. This case study demonstrates that adopting both fit for purpose technology and invisible lost time (ILT) reduction strategy can yield tremendous performance improvement delivering wells ahead of AFE. A preliminary field analysis carried as first thing to understand the field drilling challenges and performance limiters highlighted that both on bottom (rate of penetration, ROP) and off bottom time (connection time, wiper trips, circulation time, tripping time, etc.) presented areas for improvement. Throughout the life cycle phases of field development more complex reservoirs have been targeted for example thinner layers, multi-structural drain sections, extended laterals, etc. The demand of an RSS being able to drill smoother wellbore minimizing tortuosity and enabling longer sections and trouble-free tripping had gradually changed from being a "nice to have" feature to be a necessity not only to eliminate time waste but also to prevent costly stuck pipe events. The new high performance RSS (HP-RSS) and its enhanced software for trajectory control enabled a faster on bottom ROP by minimizing the need of directional driller intervention to correct the trajectory hence maximizing on bottom time. The enhanced directional control translated into smoother wellbores resulting in reduced friction factors and torque and drag which eliminated the need of wiper trips and decreased tripping and connection times. In parallel with this also drilling and connection procedure were revised, utilizing torque and drag real time monitoring to optimize connection time. The expanded envelope of HP-RSS also enabled further improvement of hydraulics for effective hole cleaning while drilling minimizing the hole conditioning time on connection. The advantage of having superior quality wellbore extended also to post drilling phases, for example it enabled a faster and trouble-free running of complex smart completion reducing HSE risks and further impacting AFE. In summary, the HP-RSS enabled superior performance saving $287.5K for an invidual well. The total amount of saving projected over a year in this field is estimated to be around $ 2.9M. Efficiency and reliability are keys to lower costs and increase profitability in oil and gas operations. This paper introduces a novel approach that aim to expand technical confidence to drilling and reservoir management to target more challenging drains sections with higher productivity.

Drilling wells with long departure for extended reach applications is indeed a difficult task. Adding dual lateral sections involves increased risks, thus feasibility studies for wells design and execution purposes are critical. However, the success of this challenging campaign has enabled a new way of cost saving for wells construction. This case study demonstrates the solutions during drilling and completion by using a single surface slot with two strings for deep water and gas injection wells in shallow coastal water field in UAE. Dual laterals with long departure involve risks associated with drilling and completion, especially for long sections at high inclinations. The process involves optimization of the well trajectory to minimize the inclination at whipstock setting depth in order to reduce the drilling footage in the dense formations. Optimizing the Bottom Hole Assembly and drilling parameters to improve the rate of penetration (ROP), always targeting shoe to shoe runs; optimizing the retrievable whipstock type selection together with retrieving procedure; improving the completion design in high inclination at nipple depth to be able to set the packer and test the tubing successfully. Drilling one for two is the most beneficial point that this well construction practice has offered. Exiting from a congested surface location expose to the highest risk of Anti Collision, now reducing to 50% the exposure minimizing HSE risks. Saving surface facility while delivering two reservoir drains for better productivity is the key element for cost reduction. Most importantly, the concept is feasible and proven. Surface location has become increasingly more congested in this field thus much higher collision risk, drilling and completion technical constraints are being pushed beyond their limit to target deeper and further reach reservoirs. Lessons learnt and recommendations have been captured to establish the basis for continuous performance improvement. This paper presents a novel approach to well construction with increasing efficiency, integrity from all involved parties, reducing operational risks while significantly reducing cost, and ultimately increasing productivity and profitability.

Drilling fluid losses while drilling a mature cretaceous limestone reservoir unit (Formation A) has been worsening over years with reservoir depletion and lack of pressure support. New drilling methods were needed to eliminate or reduce total losses and the associated non-productive time with them. Nitrified Managed Pressure Drilling proposed to help in mitigating losses and reducing non-productive-time. This paper explains the challenge, details the solution that was proposed to tackle, and discusses the results of the application. Nitrified Managed Pressure Drilling (MPD) decreases the Equivalent Circulation Density (ECD) below the lowest possible static mud weight (water) and at the same time deals safely with any unintended hydrocarbon influxes while drilling the reservoir 6″ hole section. The well data was analysed and modelled with different Nitrogen pumping rates and Surface Back Pressure (SBP) to determine the best rates that a mitigates losses but at the same time prevent hydrocarbon influxes. A closed-Loop drilling system proposed utilizing rotating control device, a separation package, and locally produced membrane Nitrogen allowed to manage the annular hydraulic pressure profile accordingly and mitigate the total losses scenario eliminating the wait on water time Rigorous planning and disciplined execution have led to safe and successful conclusion with no QHSE issues encountered. The designed Nitrified Managed Pressure Drilling solution succeeded in preventing the drilling fluid losses in the reservoir section by reducing the overbalance pressure of the drilling mud from 700 psi to 250 psi, which resulted in the elimination of 3 days of the rig's non-productive-time related to waiting on water. The closed-loop system coupled with a precise data acquisition and monitoring system has helped in maintaining a slight overbalance condition over the reservoir preventing any unintended hydrocarbon influxes to the surface. The lessons learned captured from this operation have contributed to the optimization of the Nitrified MPD in (Formation A) and to the overall MPD implementation in ADNOC fields. This paper displays the first application of nitrified managed pressure drilling in the United Arab Emirates. The equipment design and planning have accounted for many different scenarios, as this type of drilling technology enables more precise wellbore pressure management with less interruptions to drilling ahead

Pad Drilling Concept was developed to increase and sustain the production rate one of the UAE Brownfield Onshore Oilfield (BO) from four different reservoirs. The surface facilities of the field will accommodate total of 80Mbd and technical rate of 96Mbd. The project scope was redefined in 2016 to enhance the overall project's cost and further study on newly developed reservoir (Reservoir "A"). The project came into execution since January 2018 and so far, 100 plus wells drilled successfully. Therefore, to accommodate the required number of wells based on the company production target ahead of time, the planning stage represented as per 2018-2022 business plan is maintained with first oil in Q1 2020. The Full Field Development Plan (FFDP) is to deliver a total of 210 wells to sustain the production rate beyond 2024. Thus, the selected scheme for the FFDP which is planned to be artificially lifted is based on water injection and water alternating gas injection (WAG). The Key aspects of the project are:Partial development of Reservoir "A"Sensitive environmental areaBrownfield development in Simultaneous Operations (SIMOPS) conditions.Directional Drilling trajectory and anticollision constrains. Critical success factors for this project are:Integrated Project Management Team with dedicated full time resourcesAppointment and selection of competent Engineering contractor to develop the facilities within the target time.Timely approval and implementation of project's milestone. Thus, the benefits from the project for this Field are:Optimized Field Development Plan;Prevent congestions & access constraints;Standardization of HSE & Operations;Economical Surface Facilities Management.Rig days and cost saving.Sweep Efficiency of the reservoir.Early completion / production of project.