Situated on the central North Slope of Alaska along the Coleville River, Umiat is one of the most frigid places on Earth. The target reservoir, the Lower Grandstand, lies at an average depth of just 470 ft below ground level and is one of the largest untapped oil fields in Alaska bearing light, sweet crude in a low-energy reservoir. Conventional drilling and completions would cripple the development economics and make too large of an environmental impact at the surface. Developing methods to drill horizontally in permafrost, a task never before achieved in Alaska, would enhance Umiat production compared to that from conventional well geometries. However, the subsurface drilling environment presented challenges since the majority of directional drilling would be in permafrost. With limited infrastructure in place for year-round access to the region, Linc Energy built over 100 miles of snow and ice roads to gain access during Alaska's coldest months. This limits access for drilling from January through the initiation of the cold breakup in late April. During well planning, the bottomhole assemblies for high dogleg and shallow horizontal landing were optimized by applying experience drilling wells in permafrost in other areas across the North Slope. A new mineral-oil-base reservoir drilling fluid was proposed to provide formation compatibility and low mud weight while reducing friction. Close communication with the rig and office teams was established to enable critical decisions to be taken using drilling dynamics measurements to monitor tripping loads and to geosteer the well. While drilling the well, the directional drilling response was better than expected landing the horizontal. The risk of stuck pipe was greater than anticipated. As anticipated in the modeling, additional weight was added on the top of the drillstring to avoid pipe buckle and to assist with weight transfer. The new reservoir drilling fluid achieved a density just a half-pound per gallon above the pore pressure and produced sufficient lubricity to reach well depth, thus validating the accuracy of the predrill modelling. The first horizontal well in Umiat was a success, achieving an extended reach drilling ratio of 3.23 with 800 BOPD production rates and 0% water cut. The well set two important records as the shallowest horizontal well drilled in Alaska and the first horizontal well drilled and landed entirely in permafrost in Alaska. The results of these methods and processes demonstrated that horizontal wells can be drilled in permafrost as this was the first such well in Alaska. The lessons learned on this well will be instrumental for future horizontal wells drilled in permafrost and will enable future permafrost reservoirs to be drilled and produced with horizontal geometry worldwide.

Shallow drilling losses are a significant problem in the Permian basin because of the presence of subsurface karst features. Karst weakens the soluble rock producing voids and caves systems that result in drilling losses. An operator drilling in Culberson County, Texas recently experienced total losses drilling four surface holes in a pair of neighboring pads located in bordering leases. Drilling into caves negatively affected operations by reducing the drilled footage per day, increasing fluid and cementing costs, and increasing the difficulty in performing satisfactory cementing jobs to cover the water table. This paper will describe the issues faced drilling with losses and explain how to manage the risk of losses by improving surface well placement with airborne gravity full tensor gradiometry (FTG) to map subsurface hazards. Airborne gravity FTG measures the directional components of the gravity field. Multiple simultaneously acquired tensor components allow identification of anomalies associated with subsurface voids. For this project, a Basler BT67 aircraft acquired data over the targeted expanse with line spacing of 328 ft. The aerial survey took place over 3 days in July 2017. Feasibility modeling using Castile formation cave systems reveals detectability of single caves larger than 10 m diameter with FTG, however networks of smaller caves are also detectable. Polygons created from analysis of negative vertical gravity tensor (Tzz) anomalies separate the cave systems into tiered risk areas. Initial analysis reveals risk at both pads where losses occurred. Extending the analysis to the entire survey, the drilling events in the drilled offset wells match with the risk interpreted for karst. FTG data and subsequent interpretation offer strong correlation to known shallow hazards and cave systems, making it a useful tool for risk assessment. It recommended to locate future drill pads in the identified moderate risk areas and that any new wells be located away from elevated risk areas. This is the first application of FTG to classify drilling risk of karst features in the Permian basin. The FTG hazard map improves operational integrity of surface location selection and is a complement to surface topography and geology considerations. The FTG data and analysis also holds promise for fault mapping and for water drilling efforts.

Nikaitchuq is the largest single-stakeholder development on the North Slope of Alaska. It is a multiyear, very shallow extended-reach drilling (ERD) project with more than 50 wells drilled from two sites, one of which is an artificial gravel island, targeting Schrader Bluff sands. A number of key drilling advances were implemented to reach the milestone of one million feet drilled as the scope of the development plan expanded to include new producer wells targeting a shallower sand, new in-fill multilateral producer branches, and a new extension plan targeting pay that is much more distant than the original development plan envisioned.The minimum slot distance of 8 ft and the increasing density of wells drilled drove the development of a systematic anticollision management plan. Significant economic value was conserved by explicitly forming shut-in/turn-on criteria for offset wells, managing surface conductor drift, controlling drilling parameters exiting the surface conductor through the kickoff, implementing a new surveying technique, and identifying and accounting for directional Љdeadzones.Љ Abrasion wear occurs in the intermediate hole section bottomhole assembly (BHA) caused by high-angle well path geometry, often surpassing 85°inclination in tangent, combined with the presence of frequent hard stringers. The impact of wear has increased as the extended reach drilling ratio and directional difficulty index have increased year-on-year from 6.34 to 6.69, respectively. Well path geometry has progressed to limit the measured depth drilled through intervals where hard stringers are expected and to account for reduced directional performance at the later part of the hole section. The reduction of downhole tool repair costs and the elimination of downhole tool failures, ultimately leading to single-run, shoe-to-shoe drilling of a section 13,500-ft measured depth (MD) long-a record for Alaska-are the results of the focus on improving BHA design to limit wear.Multiple reentry laterals have been geonavigated in close proximity with the parent wellbore among offset producer grassroots wells. A point-the-bit rotary steerable system has been introduced to drill ahead and deviate from the bottom of the milling rathole, below the whipstock and window, eliminating a motor run and saving substantial rig time on each lateral. A sourceless density logging-while-drilling (LWD) tool was introduced to manage drilling risk through zones of depletion.These technical advancements demonstrate consistent improvement of the drilling learning curve over the course of 5 years drilling at Nikaitchuq. This will be the first literature that details the long-term drilling advances achieved in the project and a valuable technical reference for very shallow ERD wells where abrasion wear is a concern.

The field development of Tubular Bells, in the Mississippi Canyon (MC) area of the Gulf of Mexico, began with a nine-well batch set drilled riserless in water depths of approximately 4,500 ft. The batch drilling concept was implemented to mitigate the risk of various shallow hazards and to maximize performance through repetition of operations (Valdez and Fleece 2005;Eaton et al. 2005;Flannery and Choo 2008). Each well in the batch set consists of a 36-in. conductor, a 32.5-in. drill-ahead section to set 28-in. casing, and a 26-in. section to set 22-in. casing approximately 3,400 ft below mudline (BML). A lowinclination, low-dogleg batch set was critical for the development plan because the target reservoirs are at 25,000 ft true vertical depth (TVD) and up to 10,000 ft of step-out from the surface location. Rapid evolution of the drilling learning curve enabled reduction of jet-in times by 75% and an increase in rate of penetration (ROP) by 30%. The batch set was delivered in 86 days of continuous operations, was completed 31 days ahead of schedule, and underspent the authorization for expenditure (AFE) by 13%. Considering total days, the average time per well was 9.5 days, or 7.5 days per well when considering operating time alone. The well with the shortest duration took 5.8 days to complete compared to the longest well of 12 days.2 SPE 165897-MS  Generate detailed mud and cement consumable estimates and assemble necessary infrastructure additions to maximize available volume at the loading points.  Develop extensive logistics plan and obtain adequate vessel support.  Planning focused to maximize critical-path uptime and reduce crew exposure. Drilling ChallengesShallow water flow from the Ursa Blue and Ursa Green units (Eaton 1999; Winker and Stancliffe 2007a and b) and gumbo issues were responsible for a significant amount of non-productive time (NPT) during drilling of the discovery and appraisal wells. The locations selected for the development drill centers had the additional risk of shallow faults cutting the mudline and munitions encompassing the western drill center.Given the deep and distant target reservoirs, smooth riserless vertical well paths were necessary to limit the possibility of high side forces and casing wear while drilling the development wells to total depth. The decision to batch-set the field was made to mitigate these drilling risks early in the development, before installation of the subsea architecture, while capitalizing on lessons learned and repetition of operations to optimize performance. Well Construction and Operations SummaryA minimum well spacing of 75 ft was selected for both drill centers to provide sufficient spacing for subsea architechture and a margin of safety for wellpath drift. Each well was designed first to jet-in and set 36-in. conductor to approximately 305 ft BML to provide structural support to the blowout preventer (BOP) stack, subsea tree, and production casing and tubing (Akers 2006). After ensuring sufficient skin friction had developed during the jettin...