TECHNOLOGY Specialized equipment enabled completions with large coiled tubing

Robert W. Taylor, Bruce Conrad
Halliburton Oman Muscat, Oman

• Considerations For Using Coiled Tubing [188680 bytes]
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Specialized equipment enabled successful well completions in Oman with large 31/2-in coiled tubing. Conventional drilling or completion rigs were not needed.

Although the use of 31/2-in. coiled tubing to complete wells is relatively new, it is gaining widespread industry application.

One Middle East operating company felt that if downhole completion equipment could be successfully run using coiled tubing, greater cost efficiency, both in initial deployment and in maintenance, could be derived.1 The accompanying box lists some of the technical considerations for these assumptions.

The long-term advantages regarding production and well maintenance cannot yet be determined, but experience in Oman has confirmed the belief that large coiled tubing completions can be technically achieved.

Deployment

The learning curve for deploying 31/2-in. coiled tubing consisted of prejob site training and equipment familiarization through yard trials and detailed discussions with customer engineers. The ability to learn and then merge experiences into the individual task segments was achieved.

"Team work" and complete familiarization with the equipment is essential for success of these highly mobile and complex operations. Once achieved, these factors contribute significantly in reducing well completion time.

The improved times, as shown in Fig. 1 [119459 bytes], are most significant in those areas in which familiarization of equipment and teamwork are most essential. Rig-up operation improves from 24 to 6.5 hr, pressure testing from 22 to 2.5 hr, and make up of electric submersible pump (ESP) assemblies from 7 to 2 hr. Fig. 2 [254928 bytes] shows typical well completions.

One also should expect that additional operational enhancements will occur and significantly improve the learning curve for these complex operations.

Specialized and uniquely designed equipment also contributed to completing wells with 31/2-in. coiled tubing in a safe and efficient manner.

Initial trial

The uniqueness of using 31/2-in. coiled tubing called for a detailed step-by-step program that increased in complexity over the trial period. At the time, the first installation in Oman represented the largest completion ever attempted with coiled tubing. The trial objectives were as follows:

• Rig up and run 31/2-in. coiled tubing completion.

• Establish costs and times for running coiled tubing completion operations to quantify the benefit to operator.

• Identify any flow improvements resulting from lower turbulence in nonjointed pipe.

• Determine completion integrity of coiled tubing and connections.

• Determine corrosion resistance resulting from reduced turbulence at joints.

• Assess serviceability for wire line, stimulation, and workover activities.

• Assess running life and serviceability of electric submersible pumps (ESPs) on coiled tubing.

  The success criteria are listed in the box.

As noted in the criteria, several of the evaluation points will require several years before an accurate comparative determination can be made.

At this time, the mechanical operation has been completed in six wells and only its success is known.

Unique components

Although the equipment might exist in similar configurations in other parts of the world, the 31/2-in. coiled tubing and the design configuration and fabrication of the completion equipment used in the Oman coiled tubing operations are unique.

Stabbing snake

The nature of the 31/2-in. coiled tubing, such as rigidity, residual bend, weight, and unwieldiness, required a suitable method of stabbing the tubing through the injector. This was facilitated by fabricating a stabbing snake consisting of a 1-in. OD central cable, about 8-ft long, with three 31/2-in. tapered steel upsets along the cable body and a 31/2-in. rounded nosepiece.

When attached to the end of the coiled tubing, the snake's weight was sufficient to overcome the tubing's tendency to turn sideways or flip upward. The snake was also flexible enough to be easily guided into the top of the injector.

Once the snake was in the injector chains, the chains were rotated in the in-hole direction, and the snake pulled the tubing into the chains.

When the snake exited the bottom of the injector, it was removed, and the pipe stabbing operation was safely and efficiently completed.

Lift nubbins

A suitable method of attaching the stabbing snake to the end of the coiled tubing and lifting the gas lift mandrels onto the work floor was enabled by the innovative fabrication of a manually operated variable OD, slip-type lift nubbin.

This tool consisted of a tapered mandrel with three slip sets operated by a knurled collar located on a threaded body above the tapered mandrel. To enable inserting the tool into the item to be lifted, or into the end of the coiled tubing, the knurled collar was screwed along the threaded body, pulling the slip sets down the tapered mandrel until the OD of the tool was small enough to pass into the desired item.

The knurled collar was then screwed back toward the taper forcing the slip sets to travel up the taper until contact was made with the inside tubing wall or gas lift mandrel. Final tightening was applied with a small pipe wrench until the tool was firmly in place.

Extra play was incorporated into the collar so that if extreme pull was applied to the tool, the slips were free to travel up the tapered mandrel slightly, thereby increasing its "bite."

The maximum tool OD of 31/2 in. allows it to be run through the injector chains.

Connectors

Slip-type connectors were designed and built for attaching the bottom hole assemblies and tubing hangers and for incorporating gas lift mandrels into the coiled tubing string.

The connectors contain two sets of eight slip inserts, one metal-to-metal seal ring, and an O-ring with a polytetrafluoroethylene non-extrusion ring.

The connector is installed without rotating the tubing, and the only tools needed are pipe wrenches. The torque necessary to make up the connectors is 600-800 lbf, which is easily applied with two 36-in. pipe wrenches.

The connectors are rated at 100,000-lb axial load, 6,000 psi internal pressure, 5,000 psi collapse, and 2,100 lbf torque resistance.

Protection tray

When installing the slip-type connectors, the sixteen slip inserts are manually placed. To guard against the possibility of dropping these inserts into the well, a plate, about 18 sq in., was fabricated.

This tray had a slot barely larger than 31/2-in. wide with a rounded end that allowed the tray to be slipped onto the pipe with a close enough fit that none of the tools or slip dies could pass through if accidentally dropped.

The open side of the slot was covered by a door that swiveled into place and a latch that caught on the lip of the tray. Once this tray was clamped around the tubing, it rested on the safety clamp above the floor slips.

During the operations, several slip dies were indeed dropped but were caught in the tray.

Crimp connectors

Because the slip-type connectors are in excess of 31/2-in. OD, a suitable connector for pulling the completions was needed. A connector manufacturer suggested internal crimp-type connectors.

The connector consists of two male ends with a 31/2-in. upset in the middle of the tool. When a gas lift mandrel is removed from the coiled tubing string, the internal crimp connector is inserted into the opposing ends of the coiled tubing, and the exterior of the coiled tubing is crimped onto the male ends of the connector.

An air-over hydraulic power unit with appropriately sized dies is used to effect the crimp. O-rings on the male ends effect a pressure-containing seal. Once the connector is installed, it may be pulled through the injector, over the gooseneck, and onto the storage reel.

Similarly, an external-type crimp connector was designed and manufactured. The external connector enables quick connections in the event stabbing a valve is needed.

A 31/2-in. Kelly cock with a 31/2-in. external crimp connector torque on the bottom thread was kept on the work floor. At any time that the pipe was cut, the Kelly cock could easily be lifted onto the tubing with the integral air tugger system, positioned on the coiled tubing, and crimped into place for well control purposes.

Power beveling tool

Before any of the previously listed connectors are installed, it is necessary to bevel both the inside and outside end of the coiled tubing. During yard trials, this was done with files and a rotary grinder, but this method was time-consuming and provided inconsistent results.

A power beveling tool was secured to effect consistent bevels. This tool worked well and saved time and manual labor.

Work floors

To incorporate various components into the coiled tubing string as it is run in the hole, the tubing must be accessible between the bottom of the injector and the top of the blowout preventers (BOPs). This access was afforded by stacking two quad-pod windows.

The lower window was complete with a 1/4-in. plate floor and an integral 11 in., 10,000-psi spool to connect the window to the well head. Because the lower window floor area was of insufficient size, cantilever extension platforms with hand rails had to be added to all four sides. One extension platform had an integral tool box.

These four platforms allowed plenty of room for access ladders from the ground and to the upper work floor. The upper work floor began as a skeleton quad-pod frame with no integral floor. Cantilever platforms were added to the lower portion of this window, and two pieces of heavy-duty grating were cut to fit the lower portion of the frame to provide a removable floor.

Each piece had a half circle cut from the center edge to allow tubing and tools to pass. When the coiled tubing was cut, one crew on the lower work floor dressed the bottom end of the tubing to accept the slip-type connector. When that operation was completed, the gas lift mandrel could be lifted into place, and the slip-type connector could be fitted to the lower coiled tubing.

At the same time, the crew on the upper work floor dressed the upper end of the tubing. Once the tubing was dressed, the gas lift mandrel assembly could be connected to the upper end of the tubing. After the mandrel assembly was incorporated into the tubing string, pressure testing could commence.

Air tugger

To lift the various tools and components to the work floors, a 1,000-lb capacity air winch was integrated into the lower work floor by mounting the winch to the frame under the floor and cutting an access hole in the floor through which the cable could pass.

A sheave, which allowed anything in the work area to be lifted as high as possible, was hung from the bottom of the injector.

Mouse hole

Although not truly a mouse hole by definition, a 12-in. round hole was cut in the front part of the lower work floor to allow various tools and components to be lifted up into the work area.

When not in use, the mouse hole was closed with a cover that had a beveled lower guide to ensure that the cover remained in place.

Tubing straightener

During yard trials, it was discovered that a residual bend remained in the tubing, even after it was run through the injector. Additionally, the 31/2-in., heavy-wall coiled tubing proved difficult to manage in this unstraightened state.

A coiled tubing equipment manufacturer who was consulted regarding the availability of a hydraulic straightener, advised that the existing straightener was mounted on top of the injector. Because of operational reasons, it was felt that a straightener mounted to the bottom of the injector would be more efficient, and the manufacturer was requested to submit a design.

After the design was accepted, the straightener was fabricated and sent to Oman.

The lower frame of the injector has two holes to pin the side-door stripper in place with two 11/4-in. steel rods for more conventional rig-ups. The straightener was designed to be pinned into place with these rods. This arrangement kept the straightener concentrically positioned during operations.

With the straightener mounted on the bottom of the injector, only a few feet of pipe had to be run to determine whether or not the tubing was being properly straightened.

The system included over-travel stops to preclude the tubing from being reverse bent. Once the over-travel stops were properly set, any excess amount of hydraulic pressure had no further effect on the tubing.

Positioning rams

In some cases, once the tubing is cut and dressed, it may be necessary to run the tubing from the straightener almost to the lower work floor, such as when making the connection to the bottom hole assembly (BHA). Almost the entire length of the access area-about 16 ft-must be traversed.

Although the straightener did an excellent job, there was still some deflection, especially after 16 ft of travel. Some means of placing the tubing over the center of the hole was needed. This problem was solved by the design and fabrication of two hydraulic positioning rams mounted on the back two legs of the quad-pod window.

The two rams were mounted so that they could freely pivot. Both rams were tied into a polytetrafluoroethylene-lined hub that included a hinge and latch so that it could be placed around the coiled tubing and latched into place.

Because the two rams could pivot on their mounts, the pipe could be placed anywhere on the X and Y axis. This system proved to be an efficient and reliable means of positioning the tubing for making connections.

Gooseneck rollers

Although no gooseneck rollers failed in the yard test or on the trial well, on the first actual completion, the ball bearings in the gooseneck rollers proved unable to withstand the extreme side and direct loads imparted by the 31/2-in. coiled tubing. On two separate occasions, ball-type bearings in the gooseneck rollers failed, and on one occasion, broken bearing races and balls fell between the tubing and the injector gripper chain and damaged the tubing.

It was decided to use tapered roller bearings to handle the side and direct loads and also to use a larger-size bearing.

To accommodate larger bearings, new rollers were fabricated with more metal left on either side so that larger insets could be cut to mount the larger bearings. After this was done, several more jobs were completed without bearing failures.

Slotted spool

When an ESP is run, a power cable is strapped to the exterior of the tubing. If it is necessary to set the floor slips on the tubing, the power cable must be protected. This protection was accomplished by fabricating a slotted spool with the same OD and ID as the 11 in., 10,000-psi spool incorporated into the lower work floor.

There was a bolt pattern cut in the lower flange of the slotted spool that also matched the 11 in., 10,000-psi spool so that several bolts could be placed in the lower flange to hold the spool centered over the hole. The overall height of the spool was 12 in.

One side of the spool had a 4-in. slot cut from top to bottom through which the power cable traveled while the tubing was run in the hole. The spider bowl and slips were placed on the upper flange of the slotted spool, and if it became necessary to set the slips on the tubing, this could be done without damaging the ESP power cable that entered the well bore through the slot in the spool under the slip bowl.

When the spool was not in use, a "door" was pinned in place across the 4-in. opening so that nothing could be inadvertently pushed into the well.

Operational highlights

The operations in Oman included a number difficulties that were faced and solved.

Securement bands

Because of the tremendous amount of energy stored in the spooled 31/2-in. coiled tubing, extra precautions were taken when cutting the factory securement banding from the tubing.

A winch truck cable was laid out and attached to a slip-type tubing clamp that was attached to the outboard end of the tubing on the spool. The winch cable was partially tensioned, the spooling foundation was placed in the out-of-hole position, and the cable was tensioned further until the tubing was observed to be pulled down tighter than the factory spooling.

It was then safe to remove the bands from the tubing.

Circulating system

None of the wells completed with the coiled tubing unit were capable of maintaining a full column of fluid, and losses ranged from 7 to 300 bbl/hr. All wells contained H2S; thus, it was imperative that the wells be kept full of fluid.

Water was supplied to the locations by a 6-in. hose, and 1,000-bbl buffer tanks were kept full on location. The circulating system comprised a 45-bbl trip tank, a 6 x 6 centrifugal pump, and a dual pump truck. A batch mixer, which was plumbed into the water supply system, was also on location in case a lost circulation material (LCM) pill was needed if fluid losses exceeded pump or water supply capacities.

Water was pumped across the wellhead with the centrifugal pump by means of an 11-in., 3,000 psi mud cross mounted between the tubing head flange and the 11-in., 3,000 psi BOP stack. Fluid that was not taken by the well was returned to the trip tank and recirculated.

The small size of the trip tank (45 bbl) enabled the pump crew to keep an accurate account of fluid losses to the formation. Additionally, an ultrasonic pit level indicator, mounted on the tank, was programmed to sound an alarm in the coiled tubing operator's enclosure if any unusual gains or losses were detected.

H2S

All wells completed with coiled tubing contained significant H2S. Therefore, all employees were trained in H2S awareness and protection procedures, and all personnel on location were issued personal H2S detectors.

Additionally, an H2S detection package was configured and used. This package consisted of two remote detectors, one mounted at the trip tank and the other mounted on the lower work floor. Both of these sensors were connected to an alarm and digital readout system in the coiled tubing unit operator's enclosure.

This package also contained the trip tank level indicator mentioned previously.

Cutting tubing

One paramount concern was the cutting of coiled tubing on the work floor to install various downhole components. This concern had prompted the acquisition of the hydraulic straightener previously described.

The primary concern, however, was that if the tubing was not completely straightened, it would release a significant amount of energy when cut. Because the tubing was cut with a manual cutter, employees would be in immediate proximity of any deflection that might occur.

The hydraulic straightener proved to be an excellent deterrent to this problem with a maximum deflection of only 2-3 in./cut. This was the case through the first four wells completed, but on the fifth well, the men on the work floor cut the tubing without checking if the straightener had hydraulic pressure. Because the straightener was not pressurized, the cut tubing rapidly returned to its deformed curved shape and propelled the manual cutter into one worker's arm.

Fortunately, the employee was not seriously injured, but this incident highlights the need for a fail-safe system incorporated in the straightener's hydraulic supply.

The remedy was to place mechanical locking devices on the hydraulic valves controlling the straightener and installing a pressure gauge with a large face so that personnel working on the floor could check the pressure without having to climb to the upper work floor.

Guying the rig up

The lower work window was fitted with integral support legs to aid in the stabilization of the rig-up. A diagram of the rig-up was used to analyze the guying requirements.

Calculations were prepared based on a 93 knot side-wind load and ignored the stability offered by the window legs. Additionally, a reel pull of 12,000 lb was factored into the calculations. The final analysis called for placing anchors on a symmetrical pattern spaced at 90 with two independent sets of four guys, one set at the bottom of the upper quad-pod window and the second set at the base of the injector.

To counteract the tension applied by the reel pull, two additional guys were placed directly behind the injector and attached to the top rear of the injector frame. This guying arrangement coupled with the support legs provided an extremely stable rig-up.

Personnel

When preparing to execute operations as complex as the 31/2-in. coiled tubing completions, experienced personnel contribute greatly to the success of the program. However, so few such jobs had been done in the world that it was impossible to locate personnel with that experience.

Personnel were available with extensive experience running 23/8-in. tubing, both as completion strings and drilling strings. This core of supervisors was complimented by a cross section of personnel with experience including hydraulic work over, completions, electronic data acquisition, and standard coiled-tubing operations.

This team proved to be resourceful and tireless, and provided the spark necessary to bring the project to its successful conclusion under mid-summer desert conditions.

Management

Management in Oman allowed the coiled tubing completions department to do what was necessary to prepare for this project, although at times, it did seem that recovery of the funds invested in the project might not be possible.

Substantial capital funding had been secured, and regional management was supportive of the technological breakthrough. The latitude to create and innovate enabled the team to safely and efficiently complete six wells in Oman with 31/2-in. coiled tubing.

Acknowledgments

The authors would like to acknowledge Petroleum Development Oman (PDO) for its involvement in this project and contribution to the technical achievements. The authors also wish to thank Perry Courville, Regional Coiled Tubing Manager for Halliburton and Tom Sherwin, Technical Engineer for Halliburton Oman for their many contributions.

Reference

1. Al-Rawahi, Salim, and Al-Hookani, Said, "Coil Tubing Operations in PDO," IADC Middle East Regional Meeting, Sept. 22-25, 1995, Muscat, Oman.

The Authors