Recent events and studies show that wellbore stability and geopressure events continue to plague the oil industry with issues that affect the safety of people and the environment. In addition, events such as kicks and lost circulation also create significant loss of time and productivity, commonly referred to as non-productive time (NPT). Deepwater studies have shown NPT related to kicks, and lost circulation can amount to 4.5% of the total well construction time. Consequently, early kick and lost circulation detection is crucial to eliminating detrimental effects on human and environmental safety, in addition to minimizing NPT.Kicks frequently happen during connections, and flowback fingerprint monitoring has been used for more than a decade across the industry to aid in kick detection. However, setting alarm thresholds and identifying abnormal flowbacks has been a manual process that relies heavily on the experience and intuition of the engineer who performs this critical safety monitoring. This manual process frequently misses early signs of influx, and thus greatly increases the well remediation time .This publication focuses on the development and deployment of an automated flowback monitoring technology. The new solution aids drillers and drilling engineers by generating intelligent alarms relevant to current well conditions for early kick and loss detection, which can result in detecting kicks up to one connection earlier than the existing manual method. This paper demonstrates the benefits of Smart Flowback Fingerprinting over existing practices and how it can significantly reduce safety risks and NPT.

The JV operator was looking for a combination of technologies to optimize drilling in Canada's Mackenzie Delta region. The area is characterized by a permafrost section up to 2,000 ft (609 m) thick. This shallow permafrost section is dominated by unconsolidated silt with freshwater ice ranging from 60% volume to pure ice layers. Historically, mechanical heat input has melted the frozen layer, resulting in increased hydrates/shallow gas risks, extreme hole enlargement/cleaning problems, rig support issues, wellbore instability, stuck pipe, hydraulic isolation, and environmental impact issues. Optimizing drilling operations through the shallow section is critical to maximize the number of wells that can be drilled with the available rigs in this limited-access area. To move the rig requires approximately 3 ft (1 m) of ice cover, which significantly limits the operating season, increasing the need for rig efficiency and reduction of non-productive time (NPT). The industry has endorsed the importance of mud cooling through the shallow permafrost and the underlying hydrate-bearing formations to avoid borehole instability and to control hydrate dissolution. However, the industry has struggled to maintain sufficiently cold mud at the high pump/power rates required to effectively drill/clean the larger surface holes. To solve the challenges, the operator utilized a casing-while-drilling (CwD) and casing bit system with a unique-to-the-industry mud-chilling technology and a variety of controlled drilling parameters. The CwD and casing bit system allowed the operator to drill and set casing through the problematic zones in one operation with relatively low flow rates to avoid hole enlargement. The lower flow rates also enabled the use of smaller, lighter rig equipment that reduced the required ice thickness to move the rig and therefore increase the winter season operating period. Following the successful implementation of the CwD and casing bit system on the first well of a winter program, the second well was drilled safer with the elimination of a casing string, which further reduced drilling time and cost. Introduction Oil and gas operators have explored in the Arctic regions of northern Canada, Alaska, and Russia for more than 40 years. Early drilling campaigns encountered significant problems drilling through the shallow permafrost sections due to degradation of drilling conditions as a result of permafrost thaw. Experience from these earlier operations and experiments conducted by Kutasov et al (1988) has highlighted the need to maintain chilled drilling mud to minimize permafrost thaw during the well construction process. Production operations in the Canadian Arctic have not yet reached development stage. Industry experience in other Arctic regions, including Alaska—as well as Canadian National Energy Board (NEB) regulations—dictate a need to protect permafrost substrata through the entire life cycle of the well.

Nowadays, one of the greatest deepwater drilling challenges is maximizing drilling efficiency while mitigating vibration dysfunctions when drilling and underreaming through salt and sub-salt formations. Historically, vibration has been responsible for considarable non-productive time (NPT) related to bottom hole assembly (BHA) twist-offs, downhole tool failures and premature bit and underreamer wear. With the high operating costs associated with deepwater sub-salt wells, operators have increased their focus on improving drilling efficiency by mitigating harmful vibration. For years, bits and underreamers were designed and selected independently, not as part of a system. This tradition has contributed to drilling dysfunctions that cannot be controlled by drilling parameter management that can potentially lead to drilling failures. Through advances in technology and drilling practices over the past two years, operators and service companies have realized that optimum synchronization between bit and underreamer is critical and one very effective way to achieve operators drilling efficiency objectives. This paper focuses on significant performance improvements achieved while drilling inter-bedded formations, salt and sub-salt sections in a deepwater well in the Gulf of Mexico Green Canyon area. In this case study, the operator deployed a concentric underreamer coupled with a fit-for-purpose bit, designed for this type of application. The proper selection of bit and underreamer and the implementation of drilling best practices allowed the operator to drill smoothly, limiting harmful vibration levels, even through lithology transition zones, including the salt exit. The drilling mechanical specific energy (MSE) was greatly reduced and the rate of penetration was significantly increased when compared to offset wells previously drilled in the area. This paper will identify, describe and discuss the factors leading to the creation of a smooth drilling environment, reduction in MSE, higher rate of penetration (ROP) and lower costs on this well. Introduction As the economics of drilling and completing wells in the deepwater Gulf of Mexico environment become more challenging, operators are seeking ways to maximize their reservoir recovery rates while minimizing non-productive time. This is even more critical with daily drilling spread costs in excess of $1 million dollars. To reach the reservoir with the optimally sized production casing, as well as to address other drilling problems including equivalent circulating density (ECD) limitations and swelling shales, more operators' drilling programs recognize a growing need for reliable concentric expandable devices. These reamers allow users to enlarge the hole below the last casing shoe so that tighter tolerance casing strings can be run. A key to reducing cost is being able to concurrently drill and expand the hole section in a single run. This paper describes the deployment of a newly introduced concentric underreamer coupled with a fit-for-purpose bit in the fourth of a series of exploration and appraisal wells in the Green Canyon area of the Gulf of Mexico with water depths over 4,000 feet. Drilling performance on this well is then compared to the previous two wells and clearly shows significant improvement in ROP, reduced MSE and lower vibration levels using this new concentric reamer and properly matched PDC pilot bit.

Operators have been drilling deepwater prospects in the Gulf of Mexico (GOM) since the late 1980s. However, technology has evolved tremendously enabling deepwater operators to explore deeper frontiers. Many of the recent promising GOM deepwater prospects are targeting the lower tertiary sedimentary dispersal system that is regionally continuous from the coastal zone to the deepwater basin. Many of these wells seek ultradeep targets with total vertical depth (TVD) ranging from 28,000 - 35,000 ft (8534-10668 m). To reach these deep lower tertiary reservoirs in the middle Paleocene to early Eocene age (Wilcox Group), operators must overcome many drilling challenges, including wellbore integrity, borehole stability, pressure management, destructive vibrations and suboptimum drill bit and under-reamer performance when drilling at these greater depths. Due to the nature of the well construction and completion programs of these deepwater ultra-deep wells, which very often require over six casing strings, concentric expandable under-reamers are regularly used to maximize the wellbore final section size. As these lower tertiary sandstones can be highly abrasive and hard, especially under extremely high confining pressures, bit and under-reamer durability has become a huge challenge. This paper will focus on the deepest successful 12 ¼ -in underreamer run in the world (31,400 ft or 9571 m TVD), achieved when drilling the deepest oil or gas well ever drilled., with emphasis on the selected under-reamer characteristics, bit selection and best drilling practices used.