Marc Graham Mobil Exploration & Producing U.S. Midland, Tex.
Charlie Brown Bock Specialties Inc. Arlington, Tex.
Installation of tubing rotators has decreased tubing failures in West Texas waterflood sucker-rod pumped wells. Pumping unit movement powers the rotator system, turning the tubing string at about 1 revolution/day. The rotator System has both surface and subsurface components (Fig. 1).
A reduction gear box attached to the walking beam converts the pumping unit's reciprocating strokes into rotary motion. A drive line transfers this rotary motion to a gear-driven suspension mandrel in the rotating tubing hanger.
Near the bottom of the tubing string, a rotating tubing anchor/catcher allows the entire tubing string, including the tail pipe, seating nipple, and gas and mud anchor to rotate.
The rotator hanger suspends the weight of the tubing string on a bearing system.
One model of the hanger has a load capacity of 135,000 lb.
A surface swivel allows rotation below the pumping tee so that the flow lines remain stationary. Also included in the string is a safety shear coupling to prevent over torquing the tubing.
TUBING WEAR
Tubing failures are both expensive and time-consuming. The most common failure results from rod cutting, or, erosion of the tubing ID because of continuous, reciprocating contact with the rod string.
Wear can be reduced by low-string-based methods such as sinker (weight) bars and low-friction rod guides. These products serve primarily to reduce rod compression and the subsequent rod buckling that causes much of the rod-tubing wear.
One method uses wheeled rod guides. These have proven very effective in reducing rod-tubing friction and overall rod-string lading. Rod guides require a relatively good grasp of the well bore track.
Without accurate deviation information, it is difficult to effectively place a set of wheeled rod guides.
FIELD EXAMPLES
Rod-cut tubing failures averaged about one every 4 months in Mobil Oil Co.operated Texas University Section 15 & 16 Well No. 1540, Crane County, Tex. The failures persisted even after doubling chemical treatment and redesigning the rod string to minimize rod compression and buckling.
Because of the failure frequency and the relatively low oil production rate of 8 b/d, the maintenance cost began to exceed the well's revenue.
A new tubing string was installed in April 1990 and, after seven tubing failures (Fig. 2a), the well was placed on the marginal well list in September 1992.
The well needed either a production increase or a decrease in the number of failures; other-wise, it would be shut in.
After installing a rotating tubing anchor and rotating wellhead on the same tubing string, the well was put back on production in September 1992.
Except for a rod part and pump failure, because of handling problems, the well operated without a failure for 14 months.
During this time, production increased to 12 b/d because of improved waterflood response. In November 1993, after a suspected tubing leak, the tubing was pulled.
A survey found from 0 to 62% internal wall loss, but no holes. A leak was due to a worn-out seating nipple.
On the same lease, Well No. 1560 averaged a failure every month and a half. The first failure occurred 4 months after running new tubing. In March 1993, after 11 tubing leaks in 2 years, a tubing rotator was installed in the well along with inspected API "blue-band" tubing.
The blue-band tubing was about half the cost of new tubing. No other design changes were made, and the well was put back on production.
To date, the well has operated for 10 months without a failure (Fig. 2b).
Also operated by Mobil, the Sandhills Tubbs Unit Well No. 57 had experienced 14 tubing failures in less than 3 years. Subsurface maintenance efforts relating to rod design, chemical treatment, and coated tubulars failed to significantly affect tubing run time.
The new tubing installed in February 1992 failed in October 1992 and then again both in January and February 1993.
Anticipating another failure, the tubing was pulled and run back in the well with a rotating system.
The tubing was tested and no tubulars were replaced.
This well has since operated 10 months without failure (Fig. 2c).
Economics
A common method of determining the economic viability of a project is the net cash recovery (NCR) generated by the project (essentially, revenue less expenses). The options compared were as follows:
- Install the tubing rotator system
- Purchase new tubing for well
- Repair the tubing string by hydrostatically testing the tubing and replacing any failed joints.
Table 1 shows the relative economics of these options for each of the wells discussed previously. In each case, installing the tubing rotator system generates the highest NCR and profit per dollar invested over the time period specified.
For the rotator case, the NCR was calculated using actual production values, less the cost of the rotator installation, and average operating expenses for the lease.
NCR for the new tubing option was determined by using the same revenue for the well and subtracting the cost of new tubing and expected well failure expenses.
These well failure expenses were estimated by assuming a run time for the new tubing based on recent averages and an expected period between subsequent failures derived from historical well failure data.
In the tubing repair scenario, the NCR was calculated by the same method without the cost or extended run time associated with new tubing (Fig. 3).
