A drilling team has focused on increasing lateral lengths in the Marcellus Shale. The team determined which operational practices would need to be revised in order to drill and case laterals in excess of 18,000 ft. During a 12-month period of revised processes and upgrades, the team drilled 34 horizontal wells, each exceeding 12,000 ft in lateral length, which represented the first Marcellus lateral to exceed that length.
Introduction
At the time of writing, the team had drilled more than 1,050 Marcellus wells in the state of Pennsylvania. In the first decade of development (2006–2016), it drilled hundreds of Marcellus horizontal wells with laterals ranging from 1,500 to 11,000 ft. The average lateral length over that period was 3,950 ft. In late 2016, focus was placed on developing the core acreage of the Marcellus field with extended laterals. This change in planning resulted in dozens of wells being scheduled that would feature lateral lengths exceeding 12,000 ft. As a result, the average lateral length increased to 9,450 ft over a span of 200 additional wells drilled starting in 2017.
Throughout the initial years of drilling Marcellus horizontal wells, tools and practices were used that efficiently drilled laterals under 4,000 ft in length. Routine operations included use of rigs with 5,000-psi circulating systems, directional tools with bent housing motors, saltwater-based polymer drilling fluids, and standard drilling procedures. In re-evaluating processes, the team focused on cost per lateral foot (Fig. 1). Increased performance coupled with maintenance of consistent overall drilling costs helped lower the cost per lateral foot.
Rig Selection
While focusing on what are now deemed as shorter laterals, the team had experienced success drilling with super single rigs because of their versatility and efficient design. The second iteration of a rig fleet to meet the challenges of developing the Marcellus Shale came in the form of high-performance rigs with new enhanced horizontal-drilling capabilities. The team used this style of rig to meet lateral-length challenges successfully from 2010 until late 2016, drilling 805 Marcellus horizontal wells in that time period.
In the spring of 2016, the first 14,000‑ft lateral was placed on the drilling schedule for the end of that same year. The rig fleet would need to be upgraded in order to meet the upcoming required changes in lateral length. Size of the rig and equipment became another critical consideration for the rig fleet, because, by then, returning to sites with actively producing wells had become routine, so the upgraded rigs selected would have to fit onto these sites.
After finding suitable candidates that fit the change in the drilling program, an additional rig was added in the fall of 2016 that featured the following characteristics:
- 1,500-hp drawworks
- 2,000-hp mud pumps (7,500-psi maximum rated working pressure with 4.5-in. liners)
- 500-ton topdrive (37,500 ft-lbf maximum continuous drilling torque capability)
- 1,365-kW generators
- 5-in.-outer-diameter drillpipe
- 750,000-lbm capacity mast, capable of racking back 21,500 ft of drillpipe
Directional Tools
As lateral-length average reached 6,000 ft, the ability to slide drill effectively and hold consistent tool face suffered and the drilling team used oscillating tools (initially, a rocking tool). Drilling laterals greater than 7,000 ft, however, required a different type of oscillating tool called an agitator. This is a downhole tool that is run on the bottomhole assembly (BHA) that increases the effectiveness of slide drilling by axially moving the drillstring as fluid is pumped through the tool. Agitators make each slide and rotate sequence more effective, especially when paired with surface oscillating tools.
When the drilling schedule increased to 10,000 ft and greater by the end of 2016, however, the team evaluated the currently used directional tools and determined that rotary-steerable tools would be required to reach these lateral lengths. Rotary-steerable tools allow the drillstring to steer while rotating the entire drillstring, eliminating the need to have a bent housing and slide drill. Fully rotating the drillstring throughout the drilling process reduces the friction between the drillpipe and wellbore. Rotary-steerable capability eliminates the need to use oscillating tools and the additional risk associated with each technology. Rotary-steerable tools also have precise directional steering ability in tighter target windows. Improved wellbore cleaning leads to improved rate of penetration and wellbore stability.
Drilling Fluids
Saltwater-based polymer drilling mud was used widely on lateral lengths up to 10,000 ft until 2015. This system used a high-chloride-based mud for improved inhibition drilling through the Marcellus shale, with effective rheologies for hole cleaning and additives to improve lubricity. This system was effective on shorter lateral lengths, but the drilling team experienced several instances of instability as the program developed from the early stages of drilling. Major lessons learned pointed to fluid-loss reductions and mud-weight increases.
Diesel-oil-based muds feature improved shale inhibition and lubricity. When paired with rotary-steerable tools, the time spent on wells and wellbore cleaning is reduced, leading to greater lateral drilling success.
By the end of 2016, the upgraded rig fleet with improved rig horsepower and additional pressure rating, combined with rotary-steerable tools and diesel-oil-based drilling fluid, were crucial to the team’s success in drilling laterals between 10,000 and 18,000 ft. Wellbore stability dramatically improved.
The changes resulted in a drastic increase in daily lateral footage per day. From the beginning of 2017 until the time of writing, there have been more than 30 days (24-hour report time) that have exceeded 5,000 lateral ft, including 2 days that have eclipsed 6,000 ft. These days have pushed the daily lateral average above 3,400 ft, which is close to the record day from 2015.
Casing Flotation
When running a long string of casing, increased drag must be considered before the casing run is begun. If the drag associated with running casing is modeled to reach a critical limit in which the pipe will not be able to be slacked off to bottom, a casing flotation sub can be used to achieve a desired set depth with minimal operational changes.
A flotation sub can be placed strategically in the casing string to aid in floating casing to bottom. With a single-drilling-fluid system, a specified length of casing is left empty (air-filled) with the area above the flotation sub filled with drilling fluid to aid in weight transfer. In the lateral, a buoyant effect on the casing caused by the difference between the drilling fluid and the air-filled portion of the casing helps float the casing to bottom.
After the casing is landed at the desired set depth, depending on the type of flotation sub used, the sub is then opened or ruptured to allow the lower portion of the casing to fill with drilling fluid. The air is then allowed to swap with the now-drilling-fluid-filled portion of the casing string and circulated back to surface, where it is bled off in a controlled manner. Afterward, the void is fully filled back to surface and prejob circulations can begin to condition the wellbore before cementing the production casing string.
Best Practices
Hole-cleaning practices and parameters have changed as lateral lengths have increased. Shorter laterals saw less of a procedural focus on wellbore-cleaning practices. The drilling-engineering team typically reproduced standard procedures in well after well. As laterals continued to lengthen, an abnormal number of wellbore issues were encountered in 2014 and 2015. An in-depth review determined that, while drilling, parameters including flow rates and rotational speed needed to be increased. After drilling to total depth (TD), the circulations increased with specific parameters to maintain.
In addition to cleanup-cycle parameters, an added focus also was put on tripping procedures. Standard procedure for shorter laterals focused on fast tripping in order to get the wellbore cased and cemented in a short time. As laterals were extended, a point was reached at which pulling the drillstring off bottom without needing the drilling contractor’s overpull approval was unachievable. In those instances, back-reaming was the recommended method to get off bottom. The first two laterals exceeding 15,000 ft required back-reaming to trip out of the hole once TD was reached. In both of those wells, while tripping out, the drillstring encountered tight hole spots where back-reaming was required to continue out of the hole. On the third 15,000-ft lateral, back-reaming operations resulted in the drillstring sticking and leaving the BHA downhole. An investigation uncovered that the drillstring was being back-reamed out of the hole at higher-than-recommended speeds. Even with the drillstring being back-reamed out of the hole, at those speeds, it was pulled into a cuttings bed that ultimately packed off the BHA. New back-reaming standards were implemented to limit tripping speeds while back-reaming.
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