Extremely long laterals in the Delaware Basin are key to a development strategy aimed at improving return on investment (ROI) through greater reservoir exposure at a lower cost. Recent drilling of a 3.14-mile super lateral with a Permian Basin record measured depth (MD) of 26,745 ft was achieved with greater efficiency and less risk while overcoming multiple challenges in the Wolfcamp reservoir interval. The operator estimates the well will significantly improve recovery with only a minimal increase in cost compared to shorter laterals.

For on-target drilling of the 16,574-ft lateral, an integrated approach using Halliburton drilling fluids, a rotary steerable system (RSS) and bits was used. The combination satisfied many drilling requirements including low equivalent circulating density (ECD), high fluid stability, minimal torque and drag, a high penetration rate and ultimately a high-quality, on-target wellbore.

Halliburton’s approach integrated a BaraXcel high-performance nonaqueous fluid (NAF) system, the iCruise intelligent RSS, a NitroForce high-flow, high-torque motor and a GeoTech GTi PDC bit.

The well in Eddy County, N.M., is part of a larger drilling program based on very long laterals. The pad included four wells, including this well, with 3-plus-mile laterals. All four wellbores were successfully drilled using Halliburton’s integrated approach.

The extreme lateral lengths in these designs contribute to a variety of challenges. It is important to maintain low torque and drag and provide efficient hole cleaning in the long holes. Water influx, weak zones and barite sag during long trips must be addressed. The conditions require a highly stable fluid system and tight control of ECD. Steering accuracy and hole quality are very important to delivering an effective, on-target wellbore, and efficiency requires the wellbore be drilled at optimum penetration rate and footage. Development and execution of the best solution depended on close coordination between the multidiscipline service provider team.

Extensive fluid testing was done to ensure that the selected formulation delivered tight control of ECD with no barite sag. (Source: Halliburton)

Fluid system
The high-performance drilling fluid system BaraXcel has an extensive track record in the area due primarily to its stability, hole cleaning capacity, and torque and drag reduction. Its custom design is based on extensive laboratory testing and field monitoring. Area variations by well typically include adjustments for formation water salinity in the fluid or to mitigate increased water ratios.

For this operator, prior experience with the fluid system included 13 super laterals with measured depths in excess of 21,000 ft. Nine of them were drilled to 24,000 ft MD or longer.

Additional fluid design iterations were developed to drill the wells because the operator uses several different base oils. The system was modified and tested for stability and compatibility, and treatment guidelines were established to ensure maintenance of the desired properties.

One of the key challenges is water influx from nearby completions. While the situation is typically detrimental to an oil mud, the system has a greater water tolerance than traditional NAF systems, allowing properties to be closely maintained.

The fluid system’s lower ECD has helped drilling stay within a narrow pressure window determined by a weak zone higher in the hole. The fragile gel structure of BaraXcel averted barite sag during long static periods and helped avoid pressure surges when breaking circulation.

Baroid technical and field teams closely monitored fluid properties while drilling and close collaboration helped ensure optimal RSS and motor selection and settings based on the fluid system properties. 

The engineered fluid system delivered excellent hole cleaning and ECD control throughout the lateral section. No lost circulation incidents occurred while drilling the lateral, and torque and drag remained within acceptable ranges.

RSS and motor
The iCruise intelligent RSS drilled the lateral with minimal deviation from the centerline. The wellbore reached total depth accurately and on target with minimal tortuosity.

In addition to collaboration on fluids, the team collaborated to optimize the bit for the formation and the RSS. Because it is a hydraulically controlled tool, it is important to understand fluid system characteristics, including mud weight, components and base fluid (oil or water), and their effects on the RSS. For example, fluid characteristics can change flow to the RSS pads and steering.

Fluid properties also figure in mud pulse telemetry, which can affect data transfer. In the subject well, a potential issue due to water influx was resolved by BaraXcel fluid’s higher water tolerance. This characteristic also helped manage torque that would have risen with the addition of water to a conventional oil-based system. 

Directional accuracy that was critical in the long hole was aided by the ability to make adjustments to RSS steering sensors while drilling. Adjusting the sensors, which take directional readings at more than 1,000 times per second, avoided the need to mitigate vibrations that typically complicate conventional directional readings.

Autonomous drilling made a significant contribution to improving accuracy and minimizing tortuosity. Making small directional adjustments downhole versus the surface resulted in a faster response time for delivery of a smoother, on-target wellbore.

A NitroForce high-flow, high-torque motor was selected to complement the RSS and bit. It was configured for a 0.23-revolutions-per-gallon motor running at about 600 gpm. The slower motor speed was selected to help extend bit life and achieve as long a run as possible. Lack of wear on the GeoTech GTi bit after drilling the long interval suggests it may be possible to increase motor speed to improve ROP further.

A GeoTech GTI 8½-in. PDC matrix body bit used in the lateral achieved the model’s longest run for the operator. The bit drilled a total 8,162 ft in shale, sandstone and limestone, and it completed the run in 140.8 drilling hours for an average ROP of 58 ft/hr—a rate in line with shorter offset runs. The bit finished the run with a very good dull condition.

The six-blade bit with 16-mm cutters was designed using the Design at Customer Interface approach to focus on the application and operator objectives. Input from deployed technology, field operations and business development groups provided the basis for fast customization for the application. The GeoTech GTi bit model is designed for use with the iCruise RSS to enhance steerability and cutting efficiency. It features PDC cutters for higher average ROP and footage. The Stega efficient cutter layout technology also was used to optimize backup cutter placement for increased durability, and the Cerebro electronic data capture system collected performance-enhancing data that will be beneficial for future runs.

Highly abrasion-resistant PDC cutters were important to drilling the very long lateral. The cutters were specified to increase the amount of rock removed with less wear to achieve a high average ROP and up to four times the footage of earlier technology.

Increasingly longer laterals are being drilled to improve reservoir exposure at a lower cost. Efficient, trouble-free operations benefit from the integration of fluid, RSS and bit services to help the operator maximize asset value and minimize risk.

Check out the other "2019 Permian Playbook" chapters that appeared in the October issue of E&P magazine:


Produced Water, Well Interference Challenge Growth in the Permian Basin


Permian Operators Delivering Strong Production


New Technology Primed and Prepped For Permian Challenge


Long-Haul Capacity from the Permian Close to Pulling Even with Production

Changing Paradigm of the Permian


Permian Poised to Deliver Strong Oil and Gas Production Growth

Producing Unconventional Wells without Electricity

Super Lateral Integrates Services to Increase ROI

Preventing Cementing Failures with Laboratory Testing