TUBING SAVER ROTATOR

(TSR, Patent Pending)

Reduces Tubing Failures by 83%

Omega Technologies Inc. has developed the innovative Tubing Saver Rotator (patent pending), TSR, to substantially reduce the number of failures in pumping wells by 75% to 90% (4 to 10 times the life between failures). A majority of pumping failures is due to the wearing of the rods or rod guides on about 20% of the tubing’s circumference (causing tubing splits or “Corrosion due to Wear”). The TSR distributes this wear pattern over the entire tubing’s circumference (5 times the area to wear down). This is accomplished by the TSR allowing one person to manually rotate the tubing string about once per month or quarter with a pipe wrench. It consists of a bowl that sits below the wellhead and houses a thrust bearing to hold all the tubing weight (in lieu of slips) on a tubing mandrel with a swivel located between the wellhead and pump tee. The TSR is priced to be roughly the cost of one average tubing failure repair job, which enables Rate of Returns between 40% and 100% to be achieved for wells failing more than once every 24 months. Thus, the TSR is an excellent investment for wells with an average or poor run time between failures. This easily and quickly installed mechanism should be the preferred investment before rod guides are installed and the corrosion program changed (see Theory of Tubing Wear).

HISTORICAL PERFORMANCE

Several failure mechanisms are present in a pumping well, but are normally related to (1) Wear, (2) Corrosion, (3) Stress on rods, (4) Pump Failure, and (5) Other miscellaneous categories (sand, paraffin, scale, etc.). Wear is the principal culprit in most pumping operations in wells with a proper downhole design and proper installation (see Theory of Tubing and Rod Wear). The TSR theoretically should reduce the number of these failures by 75% to 90%, which corresponds to extending the run time between failures by 300 to 900%. In 25 wells installed with the TSR equipment for 4 years, the run time was improved by 313% (76% reduction) for all failure mechanisms (wear, stress, scale, etc.). These same wells saw the run time between failures due to Wear only (Tubing Splits or Corrosion Hole due to Wear) increase by 484% (83% reduction).

An experiment was performed in a large oil field (1200 rod pumped oil producers) to reduce failures. The worst performing 25 wells were installed with the TSR equipment from 1996 to 1998 with significant improvements (see Table 1 below). The average run time between failures was improved from 1.5 months (8 month average) to 6.1 months per well (48 month average) with further improvement to 9 months per well 1 year after installation. This improvement yielded a 100% Rate of Return (ROR) and a 3-month payout. In addition, this 76% reduction (4.1 times the life) is for all failure types (not just wear related, but also includes rod parts, stuck pumps, etc.). If one only considered wear related failures, the average run time per well was improved from 3 months to 16 months (an 83% reduction or 6 times the life). Thus, it appears one could assume that the TSR could extend the life between failure repairs by 4 to 6 times. These savings generate around 40% to 100% Rate of Returns for wells that fail at least once every two years or more often (assuming the TSR cost is equal to one repair cost). Thus, the TSR is applicable for the average well and the problem wells.

TABLE 1: Case History of 25 Wells installed with the TSR for 4 years

	All Failures Types (#Repairs/yr)	Run Time for all Failure Types (Months)	Wear related failures (#Repairs/yr)	Run Time for Wear related failures only (months)
Before TSR	203	1.5	108	2.8
After TSR	49	6.1	18	16.2
Improvement	313 %	313 %	484 %	484 %
Reduction	76 %	76 %	83 %	83 %