ROTATING CONTROL HEAD APPLICATIONS INCREASING

Adam T. Bourgoyne Jr.
Louisiana State University
Baton Rouge

Rotating control head technology has become an important tool for lowering drilling costs and increasing well productivity, especially in many hard-rock areas and mature oil and gas fields.

Lower drilling costs are achieved primarily by the faster penetration rates, reduced nondrilling time, and reduced mud volume requirements associated with underbalanced drilling.

Greater well productivity can sometimes be obtained because of reduced formation damage from mud. Recent advances in rotating head technology have increased the range of well conditions to which this technology can be applied. In addition, rotating control heads are being used for enhanced safety and environmental protection in areas where underbalanced drilling is not currently feasible.

Approximately one-fourth of the rigs working in the U.S. and Canada today use a rotating control head at some point during the drilling program.

Rotating heads provide a rotating seal that allows drilling to proceed with the well under pressure. In the past, wellhead pressure was typically limited to just a few hundred psi (Fig. 1) (73631 bytes). Today, rotary drilling operations are continued with as much as 1,500 psi peak wellhead pressure while gas-cut fluid is circulated to the surface. Some units are even statically tested to 3,000 psi (Fig. 2) (81396 bytes).

Even though the use of rotating control heads is growing rapidly, this topic has been largely neglected in most well control training programs. Many engineers are not yet familiar with this important emerging technology and some of the modern concepts and practices used.

HIGH-PRESSURE ROTATING HEAD

In a high-pressure rotating control head, steel-reinforced rubber elements provide the seal around the kelly or drillstring, allowing all of the annular well fluid to be diverted to the flow line or choke manifold. The use of multiple rubber sealing elements provides redundant protection against a sudden large leak and allows a higher working pressure.

The type of rubber used can be varied to provide optimal protection for the fluid composition and temperature expected in the return flow. The shape of the sealing element can be selected to cause the closing forces pressing the seal against the kelly or pipe to be assisted by wellhead pressure.

Wear because of kelly rotation can be eliminated by allowing the sealing elements to rotate with the kelly. The rotary force is transmitted to the sealing assembly by means of a kelly-driven bushing that has an inner passage matched to the shape of the kelly.

The bushing rides on the kelly and drops into the rotary drive of the control head when the kelly is lowered. Dogs on the kelly-driven bushing engage the rotary drive of the rotating control head when the kelly is rotated. Wear of the sealing elements still occurs from vertical pipe movement through the sealing elements and is caused primarily by the tool joints, rough hard banding, sharp edges on the kelly, and tong marks.

The difficulty of manufacturing an effective high-pressure seal with an acceptable operating life increases tremendously with the diameter of the tool joints. Drill pipe with a 4.5-in. OD is most commonly used in high-pressure rotating head applications; however, newer designs that can also accommodate 5-in. drill pipe are becoming available.

A bearing assembly allows rotation of the inner seal assembly within a stationary outer housing or bowl. The bearing assembly must resist and operate under a large upward thrust caused by the wellhead pressure. For example, an operating pressure of 1,500 psi in an 11-in. bore containing 4.5-in. pipe would cause an upward force of 118,000 lb.

An oil lubricating system maintains a constant flow of filtered oil through the bearing assembly. In addition, a chilled-water circulating system removes heat caused by rotation under a high thrust load. A power unit skid contains the water chiller, the oil and cooling-water reservoirs, the circulating pumps, and controls.

The bearing and seal assembly lock into a lower bowl. Connections to the flow line and blowout preventer stack are also an integral part of the bowl.

An hydraulically operated clamp at the top of the bowl allows the bearing and seal assembly to be inserted or removed quickly from the bowl. Typically, the bearing and seal assembly are lowered into place through the rotary table by riding on the last joint of drill pipe (just above the top drill collar) when the drillstring is run in the well.

Similarly, the bearing and seal assembly are removed through the rotary table above the top collar when the drillstring is tripped out of the well. A remote monitoring console is generally used on the rig floor to provide the driller with wellhead pressure, oil pressure, and hydraulic clamp pressure information. The control system for operating the hydraulic clamp is also located in this rig floor unit.

Usually the well is dead when the bottom hole assembly is tripped. Killing the well during trips is not thought to cause significant formation damage as long as clear fluids are being used to drill the well.

Fig. 3 (51573 bytes) shows a typical blowout preventer (BOP) stack containing a rotating control head. The rotating control head is located at the top of the stack and provides a barrier to release of fluids beneath the rig floor when the seal assembly is in place.

Flow from the well could be routed either through the atmospheric pressure flow line (blooey line) or through the high-pressure choke line to surface separation equipment. An annular preventer is usually placed just below the rotating control head and provides the next barrier in case the working pressure of the rotating control head is exceeded or if the stripper rubbers in the rotating control head begin to leak under wellhead pressure. The annular preventer provides a barrier regardless of the size or shape of the pipe in the wellhead.

Pipe rams with a higher working pressure provide a third redundant barrier available to stop flow when drill pipe is in the well. The blind rams provide a redundant barrier that backs up the annular preventer if no pipe is in the well.

The lower pipe rams are the last line of defense and should be used only to repair or replace worn or leaking components in the stack above this point. This example arrangement in Fig. 3 (51573 bytes) would not permit high-pressure ram-to-ram stripping operations unless an auxiliary BOP stack were added on top of the existing preventers.

APPLICATIONS

The main purpose of a rotating control head is to enhance personnel safety and environmental protection. In many applications, the well is being drilled underbalanced (the formation pore pressure exceeds the well bore pressure). If a permeable zone is encountered, the rotating control head provides the primary barrier shielding the rig floor from a release of formation fluids. The BOP stack provides additional barriers if the rotating control head fails or if its working pressure rating is reached.

Example underbalanced drilling applications include drilling with natural gas, air, foams, or mist in impermeable rock; flow drilling (also called producing while drilling); and geothermal drilling (steam wells).

In other drilling applications, the well is drilled with sufficient mud density to control formation pressure, and the rotating control head provides a secondary barrier to the release of well fluids at the rig floor. Example overbalanced drilling applications include drilling in an environmentally sensitive area with a closed loop system, drilling with oil-based muds, drilling in an area known to contain H2S, drilling while reverse-circulating, and drilling in extremely cold climates.

In addition to these drilling applications, workover operations involving the use of nitrogen or other gases also sometimes call for the use of a rotating control head.

GAS OR AIR DRILLING

Air and natural gas drilling were some of the first applications of rotating control heads, and these applications continue to account for a significant number of the units in service. Air or gas drilling can be used for intervals of a borehole that have a high rock strength and a very low permeability, such that the borehole will not collapse and the well cannot flow. The drilling rate possible with air or natural gas is usually at least twice as fast as that with clear water and four times as fast as that with mud.

Fig. 4 (73830 bytes) shows a typical equipment arrangement for this application. A rotating control head diverts potentially hazardous gas and dust away from the rig floor through a blooey line to a reserve pit that is located at least 200 ft from the rig.

If natural gas is used, the gas is burned continuously at the end of the blooey line. When natural gas is not available in the field, air can be used as the circulating fluid. Multiple compressors may be needed to provide the necessary air pressure and flow rate. Small amounts of formation hydrocarbons mixed with compressed air can be explosive. Also, spontaneous combustion can occur downhole.

During air drilling, the rotating control head is an essential safety device needed to protect the rig floor area from explosions and fire. A rotating control head working pressure of 500 psi is generally used for this application. A conventional blowout preventer stack is used below the rotating control head to allow the well to be shut in if an unexpected permeable formation is encountered, and the well begins to flow.

When formations that produce small volumes of water are encountered, the rock cuttings tend to stick together and no longer can be easily blown from the well. This problem can sometimes be solved by injecting a mixture of soap and water into the gas stream to make a foam-type drilling fluid. Drilling rates with foam are generally less than with air but more than with water or mud. Depending on the capability of the formations to produce water, a mist-type flow pattern could be more economical than foam.

FLOW DRILLING

The fastest growing application of rotating control head technology is flow drilling or producing while drilling (Fig. 5) (106071 bytes). This technique often is used in horizontal wells drilled into fractured formations having a low permeability matrix, such as the Austin chalk or the Bakkan shale. Flow drilling has also been practiced in horizontal wells to exploit coal gas methane.

One of the most difficult problems to solve in drilling a horizontal well is to prevent formation damage or plugging of fractures during drilling and completing the well. If these problems are not addressed, the productivity of a horizontal well will be much less than expected from theoretical calculations and could be uneconomical.

In flow drilling, the productive zone is drilled underbalanced so that flow is from the formation to the well. The formation must be competent enough so the borehole will not collapse because of the pressure underbalance.

Because maintaining underbalance during tripping operations may not be possible, clear fluids are usually used to minimize damage during these periods. If clear fluids are not economically feasible for the density range needed, then the mud should be designed to minimize formation damage to the extent possible.

Fig. 5 (106071 bytes) shows a typical surface equipment layout for flow drilling. A rotating control head is used to divert the flow from the wellhead through the surface separation facility. The sizing and configuration of the surface equipment must be carefully designed to allow drilling to proceed safely. The size of the separators and flare lines must be large enough to handle the maximum anticipated peak gas rate from the well. Flow drilling should not be attempted if an upper limit of gas flow rate cannot be estimated and designed for with a high degree of confidence.

The maximum operating pressure of the separator is set by the depth of the liquid seal (U-tube) placed in the ground downstream of the separator and the density of the drilling fluid. The liquid seal design shown has been found to be much more dependable than float-controlled valves previously used for this application.

The working pressure of the rotating control head or equivalent safety device must be large enough to prevent too much liquid from being unloaded from the well when a highly gas-contaminated region of fluid is pumped to the surface.

During flow drilling, a kick is usually taken when a fractured portion of the reservoir is penetrated. Drilling is not stopped to circulate the kick to the surface in the conventional manner, however. Instead, drilling continues with the choke wide open and the well bore pressure below formation pressure by the desired amount of underbalance.

When crossflow between different fracture systems is not too severe, a constant underbalance can be maintained while the kick is circulated to the surface if the drilling fluid density, pump rate, and circulating drill pipe pressure are held constant. The flow from the fractures tends to decrease with time as the compressed fluid in the fracture is depleted or the fracture zone is drilled through.

As the kick is circulated to the surface and begins to expand, it is usually necessary to gradually close the choke to hold the circulating drill pipe pressure constant and prevent excessive unloading of the drilling fluid from the annulus. The wellhead pressure then increases.

The higher the working pressure of the rotating control head or equivalent device, the larger the range of control afforded the choke operator. Also, the higher the circulating rate, the higher is the needed wellhead pressure to prevent excessive unloading. Thus, flow drilling is especially challenging in large diameter boreholes.

Underground crossflow within the lateral section of the well often occurs when a new fracture system is encountered. This crossflow greatly complicates the well control strategy and often leads to a trial and error approach, in which circulating bottom hole pressure and drilling fluid density are varied in an attempt to again find the best operating conditions for the available surface equipment.

The returns from the well must be constantly monitored to assist in detecting the downhole loss of fluids. The vertical part of the well can act as a separator, with much of the drilling fluid being lost to one fracture system while hydrocarbons preferentially flow to the surface. In many cases in the Austin chalk, drilling continues even without returns to the surface. Cuttings are very fine and are taken by the lower-pressured fractures.

Ideally, the entire lateral in a horizontal well should be drilled with one bottom hole assembly to avoid tripping operations during which the underbalanced pressure condition opposite the productive formation is usually lost. Failure of one of the components in the bottom hole assembly (such as the mud motor, measurement while drilling tool, or bit), however, is common before the lateral is completed.

The following is one technique used to top-kill the well during trips:

• Strip back into the casing under pressure using the rotating control head.
• Begin pumping a heavy fluid down the annulus while stripping out of the hole using the rotating control head.
• Pump at a rate that will fill the annulus with a volume of mud equal to the displacement plus the capacity of the pipe being removed from the well (Fig. 6) (104458 bytes).

The casing pressure will continually decline as pipe is pulled, and the well is usually dead by the time the top drill collar is reached. The density increase of the kill slug can be based on the observed casing pressure when pumping is started and the effective length of the total kill slug volume to be placed in the well.

Another alternative is to bullhead heavy mud into the well, but this method may increase the risk of formation damage.

GEOTHERMAL DRILLING

Rotating control heads are also an important component for drilling steam wells in a geothermal field. These wells are allowed to produce steam during drilling operations.

Because the location of the fractures and hot rock are often difficult to predict, the quality of steam coming from the well is continuously monitored. Drilling is stopped when steam of sufficient quality is produced.

A high working pressure is not needed for geothermal drilling, and dual rubber sealing elements (with dual clamps) are available that will allow a seal to be maintained on both the drill pipe and the drill collars.

The top seal is removed when the top drill collar is reached, and the lower seal becomes effective. When the bit reaches the surface, the blind rams can be closed below the bit to seal against steam production while the bit is changed.

OVERBALANCED DRILLING

Flow through the rotary table is also possible during overbalanced drilling (Fig. 7) (103204 bytes). The gas contained within the pore space of the rock being destroyed by the bit will always become mixed with the drilling fluid. This gas is often called drilled gas. If an oil-based drilling fluid is used, the drilled gas will normally dissolve in the mud. When the mud containing the dissolved gas is pumped near the surface, however, the release in hydrostatic pressure allows the gas to come out of solution.

Hazardous situations can result in which the gas/mud mixture is violently spewed through the rotary table. Cases have been reported in which oil mud and gas spewed to the crown block while the blowout preventers were being closed.

Even when a water-based mud is being used, drilled gas can cause severe gas cutting at the surface. This gas cutting is particularly dangerous in H2S areas. Rotating control heads can provide a secondary barrier in addition to the mud hydrostatic pressure to provide additional personnel safety and environmental protection. In environmentally sensitive areas with zero-discharge requirements, a rotating control head helps to maintain a closed loop system.

One recommended arrangement for containing drilled gas is to use a flow line degasser upstream of the shale shaker (Fig. 8) (74090 bytes). This arrangement also provides a convenient location for sampling and monitoring mud gas composition.

Rotating control heads can also function as an annular pack-off device in a diverter system designed to handle unexpected shallow gas flows. In some cases, the shallow gas kicks reach the rig floor before the rig crew has time to close the diverter head.

Some operators use a rotating control head as a backup system to a diverter head in extremely cold climates where the hydraulic control lines to the diverter head have an increased risk of freezing.

WORKOVER OPERATIONS

Many workover operations are conducted with snubbing units with coiled tubing or small diameter drill pipe. The new high-pressure rotating control heads offer economical conventional methods of well re-entry for some of these applications that do not require extremely high surface pressures.

The high-pressure rotating heads offer some advantages for making bit trips or running fishing tools which require stripping and rotating the drill pipe to complete the workover task successfully.

Rotating control heads can also be used for special drilling or milling situations which call for reverse circulation of the cuttings up the workstring while the pipe is rotated from the surface.

Rotating control heads have also been used when nitrogen or other gases were injected into the well bore.

OPERATING GUIDELINES

Sealing elements used in rotating control heads have a finite service life. Hardbanding on drill pipe, tong marks on drill pipe and saver subs, sharp edges on kellys and kelly cocks, and BOP stack misalignments all reduce sealing element life.

The three-sided design of the tri-kelly is better for rotating heads than a hex-kelly because of the larger radius used to round the corners. The hex-kelly is better than a square kelly for increased sealing element life, however. A square kelly cannot be used with the high-pressure rotating control heads.

There is no means for rotating the sealing elements of a rotating control head with the pipe when a top drive is used to rotate the drillstring. This slightly reduces the life of the sealing element in a rotating control head. Because drill pipe is round, however, the rate of wear is not as great as would be present if the kelly were rotated inside a stationary sealing element.

Periodic inspections should be conducted to ensure that the center line of the BOP stack is maintained within 1/2 in. of alignment with the center line of free hanging pipe. The drillstring (including all components to be stripped through the stripper rubbers), kelly, and kelly cock should also be inspected periodically for external damage and tong marks.

Changing sealing elements only after a leak develops is bad practice. Each sealing element should be inspected during every trip and at least once a day. For flow drilling operations, it is a good idea to inspect the sealing elements at least once per tour.

The elements should be changed whenever uneven wear is detected or when about 50% of the useful life has been expended. In addition, the rotating control head should be pressure tested to its working pressure whenever the BOP stack is tested.

In H2S areas, it is imperative that H2S monitors be used and maintained in calibration. Flow drilling should be stopped if H2S is detected in the air.

RIG CREW TRAINING

It is important to include the rotating control head in the routine training program used for field personnel. Operation and inspection procedures should be established before drilling begins.

BOP drills must address the type of operations conducted. In underbalanced drilling, emphasis must be placed on monitoring pressures while drilling and during stripping operations. It is important for field personnel to understand the pressure criteria being used to discontinue drilling and the additional pressure barriers afforded by the BOP stack. Contingency plans for various potential problems, such as seal failures, H2S detection, and fires, should be developed and practiced.

The standard kill sheets and procedures usually taught in well control schools do not apply to flow drilling operations. Prior to becoming involved in flow drilling operations, the crew should have more specialized training in the kick circulation procedures to be used.

BIBLIOGRAPHY

Collins, G.J., "Proper Planning Improves Flow Drilling," World Oil, October 1994.

Joseph, R.A., "Underbalanced horizontal drilling--1: Planning lessens problems, gets benefits of underbalance," OGJ, Mar. 20 1995, pp. 86-89.

Joseph, R.A., "Underbalanced horizontal drilling--Conclusion: Special techniques and equipment reduce problems," OGJ, Mar. 27, 1995, pp. 41-47.

O'Bryan, P.L., and Bourgoyne, A.T. Jr., "Methods for Handling Drilled Gas in Oil-Based Drilling Fluids," SPE Drilling Engineering, September 1989.

Stone, C.R., "Horizontal Underbalanced Drilling," 1994 Society of Petroleum Engineers Distinguished Lecture.

Williams, J.R., Williams, V., Etherington, D., and Crouse, P.C., "RCH Boosts Flow Drilling Economics," American Oil & Gas Reporter, September 1994.

THE AUTHOR