Vance Norton
Amoco Production Co.
Oklahoma City
Fred Edens
Amoco Production Co.
Countyline, Okla.
Glenn Coker
Amoco Corp.
Naperville, Ill.
George King
Amoco Production Co.
Tulsa
Amoco Production Co. has used large-diameter coiled tubing strings to avoid damaging gas wells with kill fluids. The coiled tubing is stripped in the gas well under pressure.
In Amoco's case, the gas flows up the tubing/casing annulus. The coiled tubing string provides a way to blow down the well whenever the well loads up with liquids from completion, workover, or naturally produced fluids.
To date, Amoco has installed coiled tubing in four wells. The oldest has 18 months of service. Although some tubing longevity questions must be answered, the first four completions have proven fast and trouble free.
COILED TUBING
The basic equipment for handling coiled tubing is shown in Fig. 1. The transport trailer and tubing injector head are similar to standard servicing equipment and not considered experimental.
The production tubing reel is capable of carrying 14,000 ft of 2 in. tubing or 18,000 ft of 1-3/4 in. tubing. For shallower wells, multiple tubing strings can be wound on the same spool.
Because of handling difficulties of large tubing, spools must be wound at the factory, Most of the larger sizes are made to order, making lead time a necessary consideration.
Gross trailer weight is about 73,000 lb. This weight is within normal highway restriction limits.
The injector head is a standard chain-drive unit that provides full control of tubing movement.
The tubing is manufactured from flat steel strip (skelp) by ERW (electric resistance welding) in the same manner as coiled tubing used in the service industry. The shaping operation requires rolling, welding, heat treating, inspection, and trimming the seam.
Joints are required at the maximum strap spool length, commonly 3,500 ft. Butt welds may be made on a diagonal in the strap to increase joint strength. The tubing specifications are rated as adequate for pressure control but more selection is needed to match corrosion needs in some wells properly.
Additional data on tubing physical properties, sulfide stress cracking, pressure limitations, pressure drop at flow rates, pickup and slackoff tension, and manufacturing specifications are available from the principal manufacturers,
Quality control is extremely important to ensure proper heat treatment along the weld seam. Of the few problems reported globally, splitting at the weld seam is occasionally mentioned, especially when welds are improperly heat treated.
RUNNING COILED TUBING
One of the wells in the Red Oak gas field, Latimer County, Okla., completed with coiled tubing has a plug-back depth of 8,865 ft. The top perforation is at 8,666 ft. The well produces a sweet gas containing 1-2% CO2.
In this well, the bottom part of the original hole was lost. A window was milled in the 5-1/2 in. casing and the well was redrilled. A 3-1/2 in. liner was run with the top set at 7,718 ft.
After the well was perforated and fractured, the work string was snubbed out of the well. The workover wellhead configuration consisted of two sets of blind rams immediately over the bowl, followed by three blowout preventors (BOPs). These BOPs were pipe rams equipped with stripping rubbers.
The top two rams were used in the snubbing operation. The third ram was for safety.
Atop the BOPS, a "working window" offers an open space to attach the head to the coiled tubing unit and provides the necessary ridged coupling between the BOPs and the injector unit.
While the tubing is being run, the portion of the tubing within the window is encased with steel supports that help prevent the tubing from buckling.
Dry tubing was run in the well. The bottom assembly consisted of a pump-out plug and an X-profile located immediately above the plug. If the tubing is pulled, the profile allows setting a wire line plug.
The coiled tubing was connected to a manifold at the surface that permits fluid injection, if necessary. A pump was on standby to kill the well, if needed.
While the tubing was being run, the well was vented through a small choke to reduce surface pressure. After the tubing was landed and the wellhead installed, the plug was pumped out with nitrogen.
After the coiled tubing to the desired depth was run, a few feet of tubing were reeled back to the spool until the tubing within the working window corresponded to the location for setting the tubing in the hanger.
The supports within the window were removed and a two-piece tubing hanger head from FMC Corp. was bolted around the tubing (Fig. 2) within the working window.
After installation, the head was snubbed through the BOPs and landed in the bowl (Fig. 3). The anchor bolts were set in the bowl to secure the tubing hanger head, and the unit was tested for leaks.
Once a leak-tight seal was assured, the tubing was cut off in the window and the BOPs were stripped off.
After being cut off, the tubing had burrs removed, and it was lubricated to receive the wellhead (Fig. 4).
The internal wellhead seals (Fig. 5) seal on the outside of the tubing. A small lip in the wellhead bore, just above the tubing top, serves as an entry guide for wire line tools.
After installing the wellhead and connecting the flow line (Fig. 6), the plug was pressured out, and the well was flowed.
About 5 hr were spent in running tubing, setting the wellhead, and getting the well ready for production.
BENEFITS AND DRAWBACKS
The accompanying box summarizes the benefits and drawbacks of running coiled tubing production strings.
In some instances, the elimination of tubing kill fluid on the formation has increased the deliverability and production rates from the wells by eliminating formation damage even in wells that were thought to be insensitive to water. The speed of running and hook-up is certainly a benefit as is running the tubing without a conventional workover rig.
Drawbacks to the procedure are the lack of corrosion information and repair techniques. Needed workover information includes hole repair and pulling or fishing guidelines.
Currently, repair techniques require pulling and welding. The use of tubing anchors or packers must also be investigated although some available equipment seems well suited.
Red Oak production contains 1.5% CO2 with no H2S--From a brief corrosion analysis of the tubing, the lifetime of the tubing in the well may be shorter 3 than a string of J-55 tubing.
Lifetimes for the coiled tubing of 2.2 to 4.3 years (49 to 25 mils/year) have been predicted after short-term lab tests. This compares to 5.2 to 10. I years for jointed J-55 tubing. Pitting from erosional corrosion may reduce the structural integrity much sooner. Because of the lack of joints in the coiled tubing, pin-end corrosion as a result of turbulence at the coupling is expected to be reduced over that experienced with jointed pipe.
Coiled tubing crush tests were run to determine the strength of the weld to lateral (mechanical) loading. The tubes were tested by positioning the weld at 0 and 90 to the application of load. The variation in this measurement of resistance to mechanical crushing was less than 10%, regardless of weld position.
Copyright 1992 Oil & Gas Journal. All Rights Reserved.
