Abstract

A large Illinois oil field implemented the use of a new low cost manual tubing rotator in 25 marginal oil wells to reduce wear failures. Wear failures were indicated by "tubing splits" (Mechanical Wear1) or "corrosion occurring along a straight line due to corrosion inhibitor being wiped off from wear (Corrosion Due to Wear)". The failure rate was lowered from 203 repairs/year to 49 repairs/year (a 76% reduction) for "all failure mechanisms". Failures due to "Mechanical Wear or Corrosion Wear" were reduced from 108 repairs/year to 18 repairs/year (an 83% reduction). This success yielded over a 100% rate of return since the tubing rotator will normally pay out after eliminating the first pulling job and requires only 15 minutes per year of extra labor. Economics suggest that 100% to 20% investment rate of returns are achievable in wells failing once every 24 months or more often (not considering downtime losses). Thus, the manual rotator is not just for "problem" wells and significantly reduces wear failures.

Introduction

Rod pumped wells have recurring failures, which contribute significantly to a well's incremental operating cost and determines when a well is shut-in due to economic conditions. Reducing these failures will extend the life of wells, increase profitability, and increase the reserves in a field. A majority of these failures are usually related to wear or corrosion. This paper focuses on methods to identify wear failures and the field test results achieved by installing a manual tubing rotator in 25 wells to minimize wear failures.

Wear causes two types of failures:

  • tubing splits or coupling/rod breaks due to friction (termed "Mechanical Wear1"), and

  • corrosion holes due to corrosion inhibitor being wiped off by the wear of couplings or rod guides against the tubing string.

This latter mechanism termed "Corrosion Due to Wear" is corrosion that is accelerated by wear wiping off some or all of the corrosion film inhibitor and causing pits to cause metal loss along with mechanical wear loss. Corrosion inhibitors will help lubricate the rod and tubing string2 and will help Corrosion Wear1 failures versus no chemicals. Unfortunately, "Corrosion hole failures Due to Wear" still occur as indicated by very little corrosion around the tubing except in a straight longitudinal line of wear resembling mechanical wear (but with pits in the wear groove the size of a rod box or rod guide). A poor chemical program would normally be indicated by corrosion spread around the tubing and rod string's circumference. Thus, a good chemical program may not remedy the "Corrosion Due to Wear" failures, but is still more beneficial than no chemical program.

Several techniques help reduce Mechanical Wear failures, but do not help (and may increase) "Corrosion Due to Wear Failures". Common solutions to Mechanical Wear failures are:

  • rod rotators, which benefit the rod string,

  • rod guides, which benefit the rod and tubing string,

  • tubing rotators, which spreads mechanical wear around the circumference of the tubing (automatic rotation may wipe off corrosion inhibitors), and

  • polyethylene lined tubing.

To address failures from "Corrosion Due to Wear" and "Mechanical Wear", a manual tubing rotator was developed. This tubing rotator spreads the wear from normally 10 to 20% of the circumference to 100% of the tubing's circumference (to theoretically extend the tubing's life by a factor of 5 to 10). If a chemical inhibitor is batched after manual rotation, then inhibitor may coat the area previously wiped off of inhibitor from wear. This allows "Corrosion Due to Wear" failures along with "Mechanical Wear" failures to be spread around the circumference of the tubing.

A large Illinois oil field tested these tubing rotators in 25 of its worst performing 1200 wells operating at a 97.5% watercut. The average failure rate per well was improved from 1.5 months to 6.1 months between failures for "all failure mechanisms" (a 76% reduction from 203 repairs/year to 49 repairs/year for all 25 wells). Tubing failures per well due to Mechanical Wear and Corrosion Due to Wear were improved from an average of 2.8 months to 16.2 months between failures (an 83% reduction from 108 repairs/year to 18 repairs/year). This success yielded over a 100% rate of return for a manual rotator costing about the same as one repair job and requires about 15 minutes of labor per year.

It was determined that wear causes "Mechanical Wear" failures and "Corrosion Due to Wear" failures. Manual tubing rotation helped extend the tubing life by 4 to 6 times and may yield 30% to 100% rate of returns on wells that fail more than once every two years (not just "problem wells").

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