Two-in-one rotary drilling/coiled-tubing rig enhances performance for Permian Basin wells

Posted on 02 November 2009

By J. Gregory Nutter and Reg Layden, Xtreme Coil Drilling; Cody Grasmick and Don Eubank, XTO Energy

Wells have been drilled in the Permian Basin since 1920 and continues today. For a drilling campaign in 2008, one producer sought to improve drilling rates of penetration (ROP) and to reduce overall well construction costs by implementing a plan that included innovative technologies.

The company analyzed offset bit records in the area and, after consulting with bit companies, switched from roller cone bits to PDC bits. After this technology was proven and implemented, the operator XTO Energy decided to replace the standard rig with a new design that combines a full top drive rotary rig and a coiled-tubing drilling rig into one model.

This article details the wells drilled with this rig and outlines the resulting reductions in well construction costs.

The wells discussed here are in developed fields where the well plans and drilling curves have changed very little since drilling began in the Permian Basin – even though drilling technology has changed substantially.

The status quo was to drill most wells with 5-4-7 IADC and 6-2-7 IADC type roller cone bits due to the extremely hard heterogeneous formations. Compressive strengths can change abruptly from 5,000 psi to 30,000 psi.

Seeking to reduce drilling costs, XTO analysed new PDC bit technology for its potential to reduce rotating hours.  Discussions with local bit vendors indicated there were few PDC bit offsets and not many successful implementations in most areas of the Permian Basin. However, recent developments in the quality of diamond cutters showed promise with regard to bit strength and durability.

A program to optimize a fit-for-purpose PDC bit required establishing a partnership between the operator and the bit company, Ulterra Drilling Technologies, who worked together to develop the appropriate well plan, drilling parameters, and changes to bit designs. The operator first reviewed a developed field northwest of Odessa, Texas, where a few PDC bits runs had been attempted but with little success.

Figure 1 (left) compares rotating hours required for wells drilled using a rotary rig and introducing PDC bits. There had been few successful applications of PDC bits in the area. Figure 2 (right) shows the Xtreme Coil drilling rig XTC200 Series in rotary drilling mode with the top drive directly aligned above the wellbore. For drilling with coiled tubing, the rig’s mast tilts to allow the coil injector to align directly with the wellbore.

The 7 7/8-in. production portion (1,400 ft to 6,700 ft) of the well was routinely being drilled with two 5-4-7 IADC type roller cone bits in an average of 185 rotating hours (Figure 1, “Roller Cone AVG”).

Previous unsuccessful PDC bit runs were analyzed, allowing the bit company to provide a new durable PDC bit with improved diamond cutters. The operator was committed to running the PDC bit to total depth (TD) regardless of how many bit runs were required. This allowed the team to gather valuable data.

The initial well required three PDC bits to drill to TD and drilled the production hole in 116 rotating hours, 69 hours faster than with the two roller cones (Figure 1, “CAG #1704”). After examining the dull bits, design changes were again made. The bit was modified, built and on location by the time they were needed for the next well. The production hole portion of next well, with the new bit design, was drilled with one PDC bit in 97 rotating hours (Figure 1, “CAG #1708”).

Figure 3 compares rotating hours required for wells drilled in the NE Prentice Unit with roller cone bits, PDC bits and rotary rigs and a coil rig.

Using knowledge gained, Ulterra was once again able to evaluate the dull condition of the bit regarding running parameters required to get the bit through the hard formations with WOB (35,000-40,000 lbs) and RPM (65–70 RPM). The high WOB and low RPM parameters are opposite of industry norms and were incorporated into the design of a new bit before the next well commenced drilling.

Discussions between the drilling engineer, drilling superintendent and the bit company resulted in a decision to pull the first PDC at 5,100 ft after it drilled through a known hard transition zone. A new PDC bit was then installed in the BHA with new cutters.

Both runs were successful, and the production hole portion of the well was drilled in 87 rotating hours, which was 98 hours faster than the average two roller cone bit runs that had been characteristic over the past several years (Figure 1, “CAG #1709”).

After that well, further changes were made to the 7 7/8-in., 6-blade, 16-mm cutter PDC bit, including:

• Additional cutters for better weight distribution per cutter.
• Extra matrix webbing to the center of the bit for better durability.
• Changes in chamfer angle on the cutters for more or less aggressiveness depending on whether it was the first or second PDC bit run from under surface casing.

The wells that followed the three experimental wells led to an overall optimization of well planning, drilling parameters, and changes in design of drilling operations.

Figure 4: Xtreme Coil Drilling’s Rig 200 Series is shown in rotary drilling mode with the top drive over the hole.

Today in this field, the operator is consistently drilling wells in 85 rotating hours and has set a field record of 78.25 rotating hours.

The reduction from two roller cone bits at 185 hours to two PDC bits at 85 hours is more than a 50% reduction in rotating hours and has since lowered drilling costs by reducing wells from an average drilling time of 15 days to an average of 9 days.

After the successful with PDC bits, XTO began investigating further opportunities to reduce drilling times. One method was the use of coiled tubing to drill the 7 7/8-in. hole to TD. The operator discussed with Xtreme Coil Drilling its new dual-purpose rigs for drilling re-entry wells in the Permian Basin, as well as their capability to drill vertical wells in developed fields.

The rig selected had a full top drive combined with a full coiled-tubing unit (Figure 2). XTO selected several grassroots vertical wells for drilling with the rig in the Prentice NE Unit. Wells in this field have well-known lithology, which allowed the drilling engineer to fully optimize two PDC bit runs using conventional rotary drilling rigs.

Documented reductions in drilling times using coiled-tubing drilling are usually based on reduction of nonproductive time (NPT). Coiled-tubing drilling eliminates connections with faster tripping speeds and generally quicker rig-up/rig-down time. In this case, expected NPT reductions were taken into account, but further drilling time reductions were also captured.

Every connection creates the possibility of damaging the PDC bit when not allowing proper drill off time or by setting the bit back on bottom too hard. Both events can cause uneven loading of cutters, which in turn creates delaminating, chipping or breaking of individual cutters. The use of coiled tubing reduces the potential for catastrophic damage to the PDC bits from these on-bottom/off-bottom events and can result in longer bit life and reduction in trips.

Drilling with coiled tubing in the Prentice NE Unit, we anticipated that the reduction in on/off bottom events at connections would prolong the life of the first PDC bit from under surface casing at 2,400 ft and the bit would be able to drill to TD at 7,400 ft.

Once equipment issues were resolved from the first well and the upper portion the second well, the section from 3,434 ft to 7,720 ft on the second well was drilled in 42.25 rotating hours (average ROP of 101 ft/hr), with the bit being picked up off bottom only 10 times (every 500 ft as opposed to every 31 ft to make connections) to take inclination surveys. Previous wells in the field were drilled with two PDC bits in an average of 90 rotating hours on a rotary rig.

This second well drilled with coiled tubing completed the entire section of the production hole with one PDC bit in a field record of 53.25 total rotating hours (Figure 3). The previous record for rotating hours was 67.5 hours completed with one PDC bit on a conventional rotary rig. Very few wells in that field were drilled with one PDC bit, and none of the conventional rigs were able to sustain the ROP of the coil rig due to the increased damage caused by the on/off bottom events.

The PDC bit used on coiled tubing dullgraded as a 1-3-WT-A-X-IN-NO-TD, a much improved condition than the bit that set the previous record, which had a dullgrading of 2-3-BT-A-X-1-DL-TD.

The reduced damage and improved dull condition generated lower cost per foot for the PDC bits due to reduced rebuild costs and the potential to rerun bits on future wells.

Drilling a 5,000-ft open-hole section with a rotary rig in this basin requires about 160 connections. If each connection takes five minutes to complete, then up to 13 hours of NPT is created. If connections take longer, more NPT is created. Connection times can increase when the driller must backream, then circulate cuttings out of hole to reduce ECD.

After the connection, the time to return the bit to bottom can increase if downhole tools need to synchronize and new drilling parameters are established. Observations show cases where connection times can be as long as 20 minutes from off bottom to on bottom. With coiled-tubing drilling, no connections are required so NPT is reduced compared with drilling with drill pipe.

Drilling with coil also delivers continuous and constant control of WOB. This drives a near 100% efficiency of on-bottom time. Drilling ahead is controlled by the driller or automatic driller on the drill floor. The dual-purpose rig can use either WOB or downhole motor pressure increases, or combine both of these variables, to control the automatic driller. The driller can send real-time data to the operator’s office for review. During drilling of the first well, the automatic driller was not functional.

The driller drilled the well using feedback from the dual-purpose rig surface system. The automatic driller was functioning during the last three wells, and the driller used WOB to control the drilling process.

During the drilling planning phase, the operator viewed the rig design featuring a full top drive rig and a full coiled-tubing drilling rig or two rigs in one. If there were any issues with the planned coiled-tubing drilling phase, the operator could revert to use of the rig’s top drive capability. The rig features a top drive and drawworks with a hookload capacity of 200,000 lbs (88,000 DaN) and a coiled-tubing injector system capable of pulling 200,000 lbs (88,000DaN) or snubbing 60,000 lbs (26,400 DaN).

The mast is vertical when the rig is drilling with drill pipe. When the mast is vertical, the top drive is located above the well center. With the mast tilted at 15°, the rig transitions from drilling with jointed drill pipe to drilling with coiled tubing, and the coil injector is placed over the well center so that coil can enter the well. This mast tilt enables a quick transition from one mode to the other. The coiled tubing stays stabbed into the injector while the rig is on location. This also saves time while changing from one mode to the next. A programmable logic controller (PLC) in the doghouse manages all rig functions.

While drilling the first well with coiled tubing, there were issues that could not be addressed quickly on site. The operator decided to switch from coiled tubing to deepen the hole with drill pipe using the top drive. The change was accomplished in less than four hours, including handling of the bottomhole assembly. The first well was drilled to TD using drill pipe. However, the next three wells were drilled to TD with coiled tubing.

There have been significant advances in recent land rig design and construction. One reason for rig redesign is to move the rig more easily and faster. Breaking down the rig into loads that make sense to the rig crew improves efficiency and speed. The ease of rigging up and down is simplified for the crew by minimizing the connections required between loads and by standardizing load placements on the drilling pad.

The rotary rig previously used could be moved in approximately 12 hours. One reason the operator changed to the dual-purpose rig was its quick and efficient moves. The new rig performed in-field moves in six hours, and its best move time was 4.5 hours. It required only 12 loads.

One issue requiring resolution to achieve general acceptance of coiled-tubing drilling in the Permian Basin is stuck pipe due to lost circulation. In many parts of the Permian Basin, many shallow productive zones have been drilled in the past and production has reduced the in-situ pore pressure levels. When liquid drilling mud escapes into these zones and because the coil tubing is not rotating, a differential sticking hazard is created.

The coiled-tubing rig can alleviate most stuck pipe risks by continuously moving the pipe, which is made easier because there are no tool joints. No incidents of stuck pipe occurred in this example. In this case history, the risk of differential sticking was low, which justified the use of coiled-tubing drilling.

The introduction of PDC bits and dual-purpose drilling rigs to a mature basin helped the operator to deliver wells in reduced time. PDC bits perform best when continuous development can be driven from the wellsite to the manufacturing of the next bit. This cycle is shortened to the point that bits are developed not only according to the geology but also according to what was learned as recently as yesterday.

This shortened cycle of development leads to reduced rotating times compared with roller cone bits. The step-change of moving from roller cone bits to PDC bits delivered a 50% reduction in drilling time.

A second step-change occurred when the operator moved from a conventional rotary rig to a dual-purpose rig that can drill with either coil or drill pipe. The operator selects the mode used to drill the well and can change modes at any time during drilling. By optimizing the on-bottom time, reducing PDC bit damage and tripping faster, overall drilling times are reduced.

Drilling times were reduced by up to 40% compared with average drilling times of a conventional rig.

Acknowledgment: The authors express their appreciation to XTO’s management for agreeing to the presentation of the data in this case history.

This article is based on a presentation at the IADC World Drilling 2009 Conference & Exhibition, 17-18 June, Dublin.

2 Comments For This Post

  1. Rohit Kakade Says:

    I am Drilling Engineer and would like to know the operating dayrates of Hybrid CTD rigs like the ones you have discussed above.
    Also plz mention any other additional charges as “coil charge” etc are included.
    Thanks !

  2. sami marouf Says:

    Dear Sir
    Please let me know if you are ready to cooperate with my company for a project of drilling 32 wells in ABU DHABI using hybrid rig
    so as to send you the details of the project

Leave a Reply



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