By: Joel Park/National Oilwell Varco
Nov/Dec 2011

Working in the shale plays poses some new challenges for coiled tubing. Currently in these fields a large majority of the wells drilled are horizontal wells. Due to the length of horizontal sections that are now being drilled, one of the challenges has been horizontal reach with the coiled tubing due to helical buckling.

A 2-3/8” deep well unit working in the Eagle Ford Shale.

Most wells in these shale plays require some type of stimulation to maximize production. Currently multi-stage hydraulic fracturing is the method of choice. During the hydraulic fracturing, the well is treated from the bottom up. The treatment begins with the bottom treatment zone or stage being perforated and treated. After the treatment is complete a composite plug is set above the zone to isolate it from the subsequent treatments (in the long horizontal sections the plugs are pumped down when they will no longer fall with wireline). The next zone up is then perforated and treated and another plug is set. This will continue until the entire horizontal section has been treated. Wells can have 15 or more treatment stages depending on the length of the horizontal section. After the final zone has been treated the plugs need to be removed from the well. It is not economical to attempt to pull the plugs so a coiled tubing unit is used with downhole motors and mills to drill these composite plugs. These jobs are called “coiled tubing drillouts” or CTDO.

Buckling of the CT
One of the challenges associated with CT operations on extended-reach shale wells is to utilize techniques to delay the onset of CT “buckling” so that CT can reach the target working depth. Buckling of the CT occurs when the axial force required to push the CT to the toe of the well exceeds a critical level. When pushing CT into a long horizontal lateral, the CT first buckles into a sinusoidal shape. As the CT is pushed further into the horizontal section, the increased axial force applied to the CT (required to overcome additional friction between the CT and wellbore) will then cause the CT to deform into the shape of a helix inside the wellbore, which is referred to as helical buckling. Frictional drag forces on the CT will increase exponentially when the axial force applied on the CT exceed the critical helical buckling limit. If additional axial force is applied to helically buckled CT, it will rapidly reach a point where 1 percent or less of the additional weight applied at surface reaches the downhole end of the CT. This is known as CT “lock-up” and will prevent any further movement of the CT into the horizontal lateral.

Increasing the OD and wall thickness of coiled tubing will help extend the reach of coiled tubing. But it comes with the added size and weight of the extra coiled tubing and larger equipment. Larger, two-trailer coiled tubing units are being manufactured to accommodate the extra weight and bulk. One of the larger two-trailer CTUs has been utilized in the Eagle Ford Shale in South Texas. This unit can carry 23,000' of 23/8" coiled tubing. It is 12' wide x 14'8" high x 61' long and has a HR-6100 injector with a pulling capacity of 100,000 lbs. and snubbing capacity of 50,000 lbs. These units can weigh up to 200,000 pounds with a full reel of tubing and are permit loads in the lower 48. These units are not single purpose, their main use is for milling plugs following frac jobs but they also have a history of being a go-to service in horizontal wells for operations such as coiled tubing logging, toe shots (frac prep) and coiled tubing fracturing.

Horizontal well completions have also led to a step change in the coil tubing manufacturing business. Three years ago the primary market for coiled tubing was vertical well cleanouts and the typical size was 11/2" and 13/4" coil with lengths ranging from 17,000' to 20,000'. Today the horizontal extended reach wells have changed that market mix to 2.00" and 23/8" strings ranging from 18,500' up to 24,000' in length.

Larger coil tubing sizes
The challenges for coil tubing in the horizontal wells is to make sure the plugs are properly drilled out, getting to the end of the horizontal sections and removing all the debris from the wellbore. The key to accomplishing all of these challenges is the larger coil tubing sizes, higher flow rates and higher surface treating pressures. So not only has the size of the coil strings changed, the wall thickness and grade of coil strings have changed too. In today’s shale play market higher grades of coil tubing such as QT-900 and QT-1000 have become the predominant grades of choice. Wall thickness designs have also changed. In order to operate at surface treating pressure from 7,000 to 10,000 psi, which is needed to clean out these sections and have the tube strength needed to snub in the horizontal sections, string designs have changed to heavier walls usually ranging from .175" to .203" wall thickness. As the length of the horizontal sections of the shale plays grows so will the demand for higher strength, larger OD, heavier wall and longer length coil tubing strings.

As coiled tubing sizes increase, the need for larger bore pressure control equipment also increases.

Larger bore pressure equipment
Larger bore BOP’s are required to run the larger diameter mills, the mills are up to 43/8" diameter, which is too large for a 41/16" BOP. The bore size has stepped up to a 51/8". Depending on the surface pressure it could be 10,000 psi or 15,000 psi working pressure well control equipment. The BOP stacks used have a dual barrier philosophy. The dual barrier provides two barriers between the well bore and the environment in case of an emergency. The BOP will have a blind shear ram in the stack that will be able to shear the coiled tubing and provide a seal after shearing. The Blind shear rams used have been qualified to the most recent API specifications. The additional rams used in the BOP stack include pipe rams, slip rams and grip seal rams. The grip rams are bi-directional and are qualified to hold the coiled tubing and prevent the tubing from moving so the pipe rams can seal on the tubing.

The BOP stack features include integral equalizing valves, hydraulic ram change, low torque bonnet bolts, metal x metal well bore seals, indicator rods on all rams, and Viton ram seals. The two main bore sizes used are 41/16" and 51/8". Depending on the type of CT application that is being run will determine which BOP stack will be required.

The uppermost piece of equipment in the BOP stack is the Stripper Packer. The latest technology has a design that has two individual packer elements. These high-pressure packer elements will seal around the coiled tubing while it is stripped in and out of the well at pressure up to 15,000 psi. The unique feature of this tool allows the packers to be run alone or in combination. Inhibitors can also be pumped between the packer elements to lubricate the coiled tubing.

The lower section of the Stripper Packer has a special rotating flange that provides a means to allow a flanged rig up to align the injector, wellhead and the spool if there is a misalignment. The rotating flange was designed for the high-pressure flanged rig ups and has reduced the time spent on alignment in tight job sites dramatically.

Milling operations
The ability of keeping the motor and mill on bottom drilling efficiently and reliably is an economical factor that cannot be overlooked. Drilling 15+ plugs in a single run not only requires an experienced operator with a knack for drilling plugs, it also requires top-of-the-line equipment.

What is needed in shale play milling operations is an economical, conventional type, power section that can generate higher power and torque, has the proper elastomer to deal with temperature extremes found in the shale plays, and is capable of running on commingled fluids containing N2 or air. A power section capable of generating 75 percent more torque and power (compared to current offerings) allows the BHA to better withstand sudden tension releases in the CT without stalling and allows the mill to “drill through” plugs without having to constantly cycle the CT string off bottom. In addition, a power section capable of generating high differential pressures (i.e., between 2500 – 3300 psi on a 27/8" power section) means the tool operator can predict potential stalls more readily. As a result, fatigue damage to the CT is substantially reduced due to less frequent off bottom cycling while at the same time increasing ROP. A power section delivering these properties would be a welcome addition to the industry; lowering initial expenditure, delivering increased performance, and reducing costs due to CT cycling fatigue.

Vibration for extended reach
Vibratory tools have been used for several years to overcome the extended reach issue with CT. A tool that can effectively excite the CT string axially, along its entire length, will reduce the fictional drag between the CT and the wellbore tubular. This will delay the onset of helical lockup and also offers a side benefit of shorter plug milling times. There are two main types of CT vibratory tools available. One that utilizes a piston to create the pulses (similar to a downhole hammer) and one that uses a patented rotor/stator arrangement driving a valve pack that creates the pressure pulses. Piston style tools, by design, have to completely block the fluid flow to achieve vibration. This will affect the flow of fluid to the power section and can affect its performance. They also are erratic, and sometimes uncontrollable, when pumping a multiphase fluid or straight gas. The vibration is usually localized close to the tool. The other type of vibratory tool that uses the rotor/stator combination never completely blocks the flow of fluid. The operation of this type of tool is smooth and controlled, regardless of whether a multiphase liquid or straight gas is being pumped through it. This type of tool is widely regarded as the standard tool to use in the shale plays to gain extended reach and decrease plug milling times.

Roller cones
Roller cones are fast becoming the defacto in composite plug milling in the shale plays. A series of roller cone bits, sized from 41/2" to 43/4", are in trials now. They feature improved hydraulics and sealed bearings, along with improvements to the roller cone bearing surfaces. Compared to current bit offerings, early indications are extended bit life and improved hole cleaning.

Pre-job modeling software
Another very recent technical development involves the use of enhanced pre-job modeling software (Cerberus™ by NOV) to determine the expected maximum obtaining depth when utilizing an agitator on the end of the CT. The modeling software utilizes multiple inputs (such as circulation pump rate, internal pressure drop of the pulsation device, and tool size) to quantify the amount of downhole friction mitigation. With proper use of this newly-enhanced pre-job modeling software, field personnel can now eliminate guesswork and actually predict the amount of additional extended reach that can be obtained on their well with the application of a downhole agitator. The answers obtained from this type of pre-job modeling increases the success rate of field operations, which translates to significant time and cost savings.

Straightening the CT
Another effective method of delaying the onset of buckling is to straighten the coiled tubing. Although the idea of straightening the coiled tubing has been around for a while, the concept has been effectively utilized in the long horizontal sections of the major shale plays. Contractors have found that removing the residual bend from the coiled tubing can reduce the well bore friction to extend the reach. Most cases the downhole end is straightened to cover the distance from TD to the top of the build section.

Friction reducers
Another method to delay the onset of buckling is the use of friction reducers and other chemicals. Use of friction reducers is the simplest method because it is an additive to the mud system and utilized “as needed.” Most mud companies will provide personnel, and chemicals for coil tubing drillout operations. CTDO require blended sweeps to clean out the wellbore after each plug is drilled and regular additions of friction reducer, to the active fluid system. In addition surfactants, in conjunction with friction reducers, helps reduce friction as well as torque and drag during coil tubing operations. Friction reducer also reduces the surface tension of the drillout fluid which in turn aids in friction reduction, allows the fluid to more easily flow back, and minimizes the amount of friction reducer required during the CTDO. Other optional products that may be used during a CTDO are lubricants and coil tubing corrosion inhibitor.

The HR-6100 injector with coiled tubing straightener.

Take your pick
These are some of the options to the challenges of coiled tubing while working in the long horizontal sections now being drilled. There is no hard and fast rule about which method or methods should be used. Some operator’s use the economical approach of “just enough to get me there” and others use all of the above, “remove all doubt” approach.