COLLAPSE TESTS EXPAND COILED-TUBING USES

Eric J. Walker, Clifton M. Mason
BP Exploration (Alaska) Inc.
Anchorage

Tests on coiled tubing have allowed BP Exploration (Alaska) Inc. to decrease well work costs for some operations, especially squeeze cementing.

in 1989, BPX (AK) conducted collapse tests of 1.5 in. (0.095 in. and 0.109-in. wall thickness) and 1.75-in. (0.109-in. wall thickness) OD coiled tubing while under imposed axial load and differential pressure. These tests were performed to define accurate field operating limits for this size of coiled tubing.

Findings from these tests indicated the following:

The 1.5-in. coiled tubing can safely be subjected to 3,000-4,000 psig differential pressures in the normal operating ranges of tension while operating in a 10,000 ft MD (measured depth) well, i.e., less than 20,000-lb tension.
Damage to coiled tubing affects collapse resistance to a significant degree.
The 1.75-in. OD coiled tubing will provide a greater margin of safety while operating under Prudhoe Bay working pressure limits of 5,000 psig at the wellhead. Field use may lower the operating range over time, and further tests are planned once this tubing size is put into service.
Several jobs with 1.5-in. OD coiled tubing involving reverse outs of cement slurries have been successfully performed. Rates of 1 bbl/min at 3,200 psig differential pressure are common while lifting 11-12 ppg fluid, and 0.750.80 bbl/min at 2,100 psig are typically achieved when lifting 13 ppg fluid.

BACKGROUND

Since 1983, 1.5-in. coiled tubing has been used extensively at Prudhoe Bay for a variety of purposes, including well stimulation, logging, perforating, underreaming, fill cleanouts, squeeze cementing, and other operations. The widespread use of coiled tubing at Prudhoe Bay is primarily due to its low cost as compared to other well work options.

Coiled tubing is a continuous string of pipe wrapped around a reel and secured to a mobile control unit. The coil is threaded through an injector head, pulled off the reel, and fed through the well control equipment (including pipe, blind shear, slip rams and pack off) into the well (Fig. 1).

Currently, there are seven 1.5-in. coiled tubing units and two 1.75-in. units available for use on the Alaskan North Slope, with two 1.5-in. and 1.75-in. units under contract to BPX (AK). The maximum operating life for 1.5-in. coil is about 400,000 running ft; equivalent to running into a typical Prudhoe Bay well approximately 40 times. The operating life for 1.75-in. coil has not yet been determined at time of publication.

Since becoming available on the North Slope in 1983, 1.5-in. OD coiled tubing has had many improvements in manufacturing, field repair techniques, and utilization. However, accurate and reliable data concerning actual collapse points have not been available.

Coiled tubing has a relatively small ID and is fragile when compared to other conventional workstrings. It is a thin-walled, reeled tubular with relatively low overpull capacity. BPX (AK) engineering has used conservative coiled-tubing safety factors for field operations when applying pressure and tensile loads. Consequently, operating pressures have been restricted to a maximum 1,500 psig differential pressure to avoid coiled-tubing collapse.

However, the manufacturer's theoretical analysis indicated applied axial loads of up to 20,000 lb, using 1.5-in. OD, 0.095-in. wall-thickness coiled tubing, could safely handle a differential collapse pressure of 4,500 psig (Fig. 4). Another reason for a conservative approach was the collapse of coiled tubing during a number of field operations at differential pressures around 2,000 psig. However, in most of these cases, visible previous damage to the coiled tubing was associated with the collapsed section and was probably the cause of failure.

A representative well bore in the western operating area of the Prudhoe Bay Unit includes 9 5/8-in. production casing set just above the Sag River formation and a 7-in. production liner set through the Sag River (40-50 ft TVD) and Ivishak (400 ft TVD) formations, which are the primary productive intervals in the field. Most of these wells are completed with a 9 5/8-in. packer with a 4 1/2-in. tailpipe set immediately above the 7-in. liner top. The packer and tailpipe assembly is generally completed to the surface with 4 1/2, 5 1/2, or 7-in. OD tubing.

A typical well such as A-5 has the 9 5/8-in. casing set at 9,814 ft MD. The 7-in. liner extends from 9,272 to 11,360 ft MD. Five zones, over the interval 10,806-10,994 ft MD, are perforated. Five gas-lift mandrels are located between 3,223 and 9,033 ft MD.

Collapsed coiled tubing in a well bore results in an extremely expensive, risky, and time-consuming recovery operation. Collapsed tubing cannot be extracted by the injector head; therefore, additional equipment, well killing, and complicated operating techniques are required for recovery.

In almost all coiled-tubing operations performed by BPX (AK) at Prudhoe Bay, applied differential pressures have historically been kept to a maximum of 1,500 psig to minimize the possibility of collapsed tubing. This meant that in normal coiled-tubing operations, reverse circulating was possible only at extremely low rates. In many cases, conventional circulation was utilized, circulating fluid down the coiled tubing then taking returns up the coiled-tubing by production-tubing annulus.

The main advantage to reverse circulating is that it requires significantly less fluid volumes to remove fill or cement from a well bore, saving time and cost.

In late 1988, BPX (AK) decided to differentially test 1.5-in. coiled tubing while under imposed axial loads to determine the appropriate differential working pressure. These tests were planned and conducted with the assumption that a higher differential working pressure could be used thereby allowing reverse circulation at higher rates. In addition, 1.75-in. coiled tubing was tested in anticipation of its use in the field.

TESTING PROCEDURE

Two different setups were employed for the various collapse tests performed. The different setups were necessary as a complete spool of 1.75-in. tubing has not yet been mounted on a coil unit. The setups and procedures are as follows.

TEST 1

Collapse tests performed during these initial tests were done on the North Slope using a coiled-tubing unit and miscellaneous equipment. Tubing from a truck-mounted coil was fed through the injector down through the packoff and an 11-ft riser, then through an upside down BOP stack.

A pump truck was used for a pressure source during the test, and pressure was applied across the coil at the midpoint of the riser. Pressure control was achieved with pipe rams at the bottom and a pack-off at the top.

Tension was applied to the coiled tubing with the injector head pulling the tubing, while the slips in the reversed BOP stack acted as an anchor. A majority of the tests were performed outside in -30 to -40 F. temperatures with equipment partially heated by indirect-fired forced air heaters. Test details are shown in Fig. 2 and Table 1.

TEST 2

This series of collapse tests was conducted at a coiled tubing service facility in Calgary using a machined test chamber with an approximate length of 21 in. Pressure control was provided by use of an O-ring seal assembly.

Axial loads were applied by a 60 ton hydraulic jack applying an upward force against a welded template, with the coil anchored to a welded template, with the coil anchored to a welded bull plug threaded to a base plate.

Temperature control was achieved by circulating methanol, cooled with liquid nitrogen, through the test chamber until the desired temperature was reached. Test details are shown in Fig. 3 and Table 1.

RESULTS

Collapse testing of 1.5 in. and 1.75-in. coil tubing showed that manufacturer-supplied theoretical curves are reliable for undamaged tubing. For actual test data and graph see Table 2 and Fig. 4 for 1.5-in. results. Fig. 5 and Table 3 show the results for 1.75-in. tubing.

Given the lower collapse resistance for damaged tubing, operators may want to use conservative estimates from these tests to ensure trouble-free operation. BPX (AK) is presently operating under the conditions defined in these tests and experiencing excellent results through improved job performance and faster, treatment times.

Although experience to date is excellent, several of the following qualifications must be considered when developing guidelines for operating coiled tubing under axial loads and differential pressures.

TEMPERATURE

Temperature affected the results differently between Test 1 and Test 2. Test 1, performed on the North Slope using equipment previously described, showed coiled tubing collapsed with lower pressures at colder temperatures, when compared to tests done with heated equipment at similar pressures.

Test 2, using a machined test chamber as previously described, showed higher collapse resistances at colder temperatures when compared with warm tests. This difference may be explained by the different pressure-control methods.

When using a pack-off and pipe rams at cold temperatures (Test 1), more hydraulic pressure is needed to ensure pressure control, This increased pressure creates a weak spot in the coil, while the O-ring seals used in Test 2 for pressure control, places only minimal pressure against the tubing. This explanation is supported by field observation.

Failure generally occurred during Test 1 between the lower pipe ram and the packoff (where the coil was visually necked down), while in Test 2 collapse usually occurred at the midpoint of applied tension.

DAMAGED TUBING

Significant differences in collapse resistance was observed between undamaged and visibly damaged 1.5-in. tubing.

It is important that tubing be free of damage such as egging or gouging.

TUBING LIFE

With the exception of a single test, all 1.5-in. tubing tested has between 200,000 and 400,000 running ft and came from the beginning of the spool (first in the hole) or between 8,000 and 10,000 ft into the spool.

Tubing from different areas of the spool may show varying results.

It should be noted that experience in the western operating area at Prudhoe Bay shows 400,000 running ft (=40 jobs) to be the useful life of a spool of tubing; any further use dramatically increases the chance of tubing failure.

TUBING SIZE

All 1.75-in. tubing tested was new, and collapse resistance of used 1.75-in. tubing may be affected differently than the used 1.5-in, tubing.

Further, the new 1.75-in. tubing samples tested were slightly egged, from 1.69 to 1.82-in. OD.

COLLAPSE RESISTANCE

The surge/cycle tests of 1.75-in. tubing at cold temperature showed a 10% loss in collapse resistance vs. the straight cold temperature tests.

Repeated pressure shocks to 1.5-in. tubing also caused some loss in collapse resistance. Further testing in this area is needed.

BUTT WELDS

Two tests were done on butt-welded, 1.75-in. tubing, one at 65 F. and one at -26 F.

The higher temperature test showed a 16% loss in collapse strength while the cold temperature test was in line with other tests.

TENSION

Given the limited number of tests across the entire range of tension vs. differential pressure possibilities, caution must be used in areas where few tests were performed.