Hydraulic completion unit performs 4-mile Permian drillouts

ExxonMobil Corp. (XOM) drilled 4-mile lateral wells in the Permian basin which extended to 33,000-ft MD. Well completions consisted of plug and perf fracturing with a mixture of about 70 composite plugs at the heel and about 40 dissolvable plugs at the toe.

Traditional coiled tubing and conventional rigs were unsuitable to drill out the frac plugs due to operational limitations related to extreme depth, high wellbore pressures, and equipment limitations. A hydraulic completion unit (HCU) option provided superior pressure handling, torque control, and operational flexibility. 

Through detailed torque and drag modeling, an optimized tapered work string drilled the plugs safely within the torque window of the operations. Despite operational difficulties such as bottom hole assembly (BHA) failures and stuck pipe incidents, the HCU delivered effective extended-reach drillouts. 

Long-range drillout

XOM drilled extended reach Permian basin wells extending to 33,000-ft TD which contained 15,000–21,000-ft lateral lengths. These wells targeted high-pressure reservoirs. The wells were completed with typical plug and perf completions with plug mill-outs required after fracturing to establish production. These wells contained the longest laterals requiring drillout in the basin. 

Coiled tubing and conventional rigs cannot reliably drill out frac plugs under these conditions. The total depth of these wells required a coiled tubing spool which exceeded DOT road transport restrictions. Even with a sufficiently long reel, there was a high risk that buckling  and lockup would prevent the coil from reaching TD.

For conventional rigs, expected maximum surface pressures from these wells exceeded standard well-control equipment ratings when using economical solids-free fluid. Other conventional rig limitations included insufficient snub force to reach TD and insufficient torque available from common power swivels to rotate the string.

A standalone HCU does not have these limitations. It provides similar connection times and circulation rates as conventional rigs but with higher pressure ratings, and it can rotate pipe while snubbing. HCU pressure control equipment does not have a conventional rig’s stack height limitation, allowing for customizable pressure control equipment and spools. HCUs can be used for drillouts, shing, and unsticking stuck pipe. 

Drillout job design

Before starting the drillout campaign, work string torque and drag modeling while using an HCU estimated maximum anticipated torque from wellbore friction. The modeling also estimated buckling potential, pick-up (PU) and slack-off (SO) weights, and surface torques at depth. 

Model inputs included fluid weight, viscosity, wellbore pressure, and mechanical specifications for 2 ⅞-in. 9.5-lb/ft PH6P110, 2 ⅞-in. 7.9-lb/ft PH6 P110, and 2 ⅜-in. 5.95-lb/ft PH6 P110 tubulars. The tubular size combinations represented typical single- or tapered-string drill-out configurations in unconventional US basins. 

A database of 69 well surveys optimized a tubular design to drill out 70-80 composite plugs per well for 3-3.5-mile lateral intervals. A 4-mile lateral dataset averaging 32,000-33,000 ft TD contained more than 100 dissolvable and composite plugs. These additional lengths and plugs resulted in PU weight and torques at TD from dog-leg severity (DLS) in the vertical and extended lateral sections beyond HCU capabilities or pipe safety ratings. 

A tapered string design avoided twist-off by considering the maximum make-up torque (MUT) of each tubing size under a range of typical friction factors. The design failed with a tapered string comprising 21,000 ft of 2 ⅞-in. 7.9-lb/ft x 11,954 ft of 2 ⅜-in. 5.95-lb/ft and a single string comprising 14,000 ft of 2 ⅞-in. 9.5-lb/ft x 18,954 ft of 2 ⅞-in 7.9-lb/ft pipe.

Drilling out 4-mile lateral plugs with the latter configuration required torque above the HCU rotary table maximum operating torque (MOT) for the highest friction factor. Lower friction factors estimated torques below the HCU rating but above maximum tubular makeup torque ratings. Only the lowest friction factor yielded a completion safe from failure from pick up or rotation. 

For the tapered string with 2 ⅜-in. pipe, all scenarios were below the maximum HCU torque rating, but only the lowest friction factor produced a torque estimate below maximum tubular MUT. Both designs could potentially stick the string at depths beyond 26,000 ft.

A design with 18,000 ft of 2 ⅞-in. 7.9-lb/ft specialty high torque connection pipe crossed over to 14,954 ft of 2 ⅜-in. 5.95-lb/ft PH6 P110 tubulars produced torque and drag estimates at TD which were within HCU and pipe ratings for Well 1 estimated trajectory (Fig. 1). The 2 ⅜-in. tubing in the first section drilled the first 15 plugs before connecting the high torque 2 ⅞-in. work string. Maximum make-up torque is safely available once the tubing crossover enters the lateral.

To stay within the safe operating envelope caused by the MOT discrepancy between the two pipes, tables provided maximum applied surface torques by depth. 

These tables accounted for the location of the smaller pipe and 2 ⅞-in. × 2 ⅜-in. crossover in the well during operations. Calculated maximum applied surface torque at each depth used the highest expected friction factor (0.24) with 1,500 ft-lb of applied surface torque subtracted as the crossover approached the MOT. The safety factor ensured that MOT would not be exceeded at the crossover in the event of motor stall. 

Real-time drillout monitoring

Real-time analytics developed for HCU operations recorded hydraulic pressures on the unit and translated them into rotary torque, rpm, hookload, tubing pressure, casing pressure, and flow rates. Threshold alarms warn operators when parameters veer out of safety limits. 

A real-time plot of applied torque on each plug in the lateral section against torque projections under a range of friction factors infer cleanout effectiveness and friction response cleanout chemicals pumped during the job (Fig. 2). Poor chemical programs, fluid system efficiency, or debris removal produces applied torque oscillations among projections using a range of friction factors. The data guide personnel to adjust treatments to obtain a torque window within two friction-factor deviations.

In multiple-well campaigns the system can also determine by comparison the best bottom hole assembly (BHA) equipment for efficient plug drill-out. 

Three-mile laterals

Frac plug drillouts on four 3-mile lateral trial wells qualified tools and techniques before attempting drillouts on 4-mile lateral wells. The 3-mile wells had similar well profiles, formations, well construction, and dates for drilling and stimulation. 

XOM drilled out the first of these four wells with the HCU without incident, but work-string and tool failures occurred in the following two wells. A specialty high-torque connection on a single string, optimized to eliminate the split work string in the job-design phase, failed significantly below the operational torque limits of the pipe. Also, excessive friction from this longer, stiffer coupled connection occurred when running through the heel and high DLS areas.

Other premium connections did not produce this additional friction. 

Based on these experiences, the 4-mile lateral drillouts used 2 ⅞-in. 9.5-lb/ft PH6 x 2 ⅜-in. 5.95-lb/ft PH6 split work strings. Torque tables limited applied torque beyond 80% of the 2 ⅜-in. work string’s MOT. 

The 3-mile trial wells also tested an extended reach tool (ERT) in the BHA. ERTs help break friction and straighten pipe in coiled tubing applications, but testing in these HCU operations showed a 12% increase in average wash speed throughout the 3-mile lateral. The ERT was therefore incorporated into the 4-mile well program. 

Four-mile lateral drillouts

Wellbore configurations of the four wells in the 4-mile lateral campaign differed from the trial wells in that they were cased with 6-in. 26-lb/ft production casing vs. 5 ½-in. 23-lb/ft casing in the 3-mile laterals. Well trajectories are shown in Fig. 3. Interpolated color bands represent DLS, with green representing the lowest DLS (0°/100 ft) and red representing the highest allowable DLS (10°/100 ft). Maximum horizontal stepout from the surface location to the furthest well's landing target (Well 4) is about 5,000 ft.

Well completions consisted of plug and perf fracturing with a mixture of about 70 composite plugs at the heel and about 40 dissolvable plugs at the toe. Dissolvable plugs served as safety measures to prevent milling slowdown towards the toe and provide self-opening plugs in case the milling BHA mechanically locked up before reaching TD.

Given that each wellbore had its own trajectory and step-out, torque and drag modeling produced bespoke torque tables per well to ensure that the entire wellbore could be drilled out. 

Cleanout operations started with Well 2 because it had the shortest total MD (about 32,100 ft). The work string consisted of 2 ⅞-in. 9.5-lb/ft PH6 on top and about 13,400 ft of 2 ⅜-in. 5.95-lb/ft PH6 on bottom. The BHA was the same as used in the test wells except for a smaller 4.75-in. rock bit than the planned 5-in. bit due to sections of possible defective casing. The millout operation successfully drilled the plugs until a BHA disconnection five plugs from TD.

The BHA was fished with an overshot. While successfully retrieved on the first shot, the operation added non-productive time (NPT) because the depth of the fish required extended tripping time and the HCU lacked pipe-rack back pipe capability. Also, spacer spools required on the HCU BOPs to account for the added length of the fish needed additional rig-up time to safely retrieve the fish to surface.

Failure analysis revealed that the BHA length-to-size ratio was too stiff and caused excessive bending forces on the BHA. Re-running the BHA with additional bent subs resulted in successful drilling of the remaining plugs. This redesign was used for the drillout of Well 1, the next well in the series. 

Well 1 landed at about 32,700 ft TD. The workstring consisted of 2 ⅞-in. 9.5-lb/ft PH6 on top and about 12,700 ft of 2 ⅜-in. 5.95-lb/ft PH6 on bottom. 

The drillout operation performed similarly to Well 2, with a BHA failure after Plug 61 which also required a fishing operation. 

The BHA was fished in a single run and experienced the same failure mechanism as in Well 2 even though an additional bent sub was added. A new provider supplied BHAs for the  remainder of the 4-mile lateral campaign, and the remainder of the wells were drilled out without BHA failures.

Rotation was required while tripping out of hole from TD through areas of higher wellbore tortuosity such as the crossover joint entering heel. At this location in Well 1 the applied surface torque exceeded the torque table MOT for the 2 ⅜-in. section of the workstring, and it  twisted off, leaving a large fish in the wellbore. The fish was left while drilling out the remaining two wells for later recovery. A subsequent update to the HCU dashboard provided an alarm to alert operators of an approaching MOT condition. 

Well 3 used the same BHA design from Well 1. Well 3 also landed at about 32,900-ft MD and the final workstring consisted of 2 ⅞-in. 9.5-lb/ft PH6 on top and about 13,000 ft of 2 ⅜-in. 5.95-lb/ft PH6 on bottom. The well was drilled out to TD without a BHA failure, but a motor stall occurred at TD. While attempting recovery, the pumps and pipe rotation stopped, leading to stuck pipe upon restart due to pipe settling. 

Before the stall, the HCU registered about 85,000-lb rotating off-bottom weight, consistent with pre-job modeling. Modeling of the stuck pipe, which could not be rotated, estimated 160,000-lb pickup weight, but exerting up to 170,000-lb pull on the pipe yielded no movement. 

The BHA was subsequently cut under the assumption that the pipe was stuck at the bit, and the pipe moved with about 225,000-lb pull (compared with 230,000-lb buoyed weight of the work sting in the drillout fluid), which reestablished rotation. The BHA was left on bottom and the campaign moved to Well 4.

Well 4 landed at about 32,500-ft MD. The work string consisted of 2 ⅞-in. 9.5-lb/ft PH6 on top and about 12,500 ft of 2 ⅜-in. 5.95-lb/ft PH6 on bottom. 

Based on the Well 3’s stuck pipe experience, a hydraulic disconnect was added to the BHA in case of motor stall at TD. A drillout plan revision included drillout in two runs. The first run cleaned out the composite plugs and a second run with a new BHA cleaned out the remaining lateral. 

The second run improved drillout reliability. The added friction in the fourth mile of the lateral significantly added to BHA motor- and bit-revolution count, and Well 3 drillout resulted in about twice the manufacturer’s recommended revolutions. The new BHA in the second trip eliminated the risk of excessive BHA fatigue in the last mile. 

Well 4 drillout went according to plan without incidents. The second trip added to the planned drillout time, but overall drillout operations on Well 4 ran 16% faster than the other wells because of the absence of NPT events.

The long lateral drillout workflow developed for these 4-mile wells was subsequently applied to 67 wells, and the operator plans to continue using and refining the process for about 120 wells with 3.5+ mile laterals in the 2025 campaign. 

Drilling improvements

Well tortuosity and difficulties associated with running the drillout BHA in the last mile resulted in a reevaluation of the drilling for these extended-reach wells. Consultations on drillout optimizations with drilling and geo-steering teams resulted in future planned well paths which define cumulative DLS restrictions to improve drillout running. Previously, drillers did not have to consider such restrictions because sub 4-mile drillouts had not pushed their technical running limits.