Abstract

A large percentage of the producing oil wells in the Pembina Cardium Field are equipped with beam pumps. Amoco Canada operates more than 500 of these wells that are completed in the Cardium formation at depths from 1200–1700 meters.

In 1973 and 1974 a significant increase in routine workovers from previous years was occurring due to failures of subsurface equipment. As most equipment had been in service for about 15 years, it appeared that the failures would accelerate with time unless remedial action was taken. A decision was consequently made to test various combinations of surface and subsurface beam pumping equipment to establish guidelines that would reduce failure rates to an acceptable level.

This paper presents case histories of the performance of the various equipment and field wide results to date.

Introduction

Amoco Canada operates approximately 500 wells equipped with beam pumps in the Pembina Field (Figure 1). These wells are completed in the Cardium formation at depths from 1200–1700 meters. The majority of the wells were equipped with beam pumps in the late 50's and early 60's and nearly all leases have been waterflooded for about 20 years. The average well production is 3.4 m3 of oil per day (API gravity 37 degrees) and 1.7 m3 of water/day. Gas-oil ratios vary widely but are generally under 200 m3/m3. The produced water is low in chlorides (1000–3000 ppm) and corrosion is rarely a problem. Fluid production is basically sweet although a trace amount of hydrogen Sulphide is now present on some leases, due to H2S-producing bacteria introduced with the waterflood.

During 1973, a substantial increase in routine workovers was observed. In 1972, the workover frequency was 0.83 workovers/well/year. In 1973, this had increased to 0.95 workovers/ well/year and the trend appeared to be continuing in early 1974. As most downhole equipment had been in service for about 15 years, it appeared that unless remedial action was taken the failures would increase with time. A decision was therefore made to determine the reasons for failure and to establish guidelines that would reduce workover frequency to an acceptable level.

DISCUSSION

In an effort to define failure trends, all workover histories were graphically plotted for each well with the reason for the failures and their location in the rod string. The well histories were then grouped by lease for easy reference.

The majority of failures other than routine pump changes were due to parted rods and tUbing failures. Over 86% of the tubing failures were in the bottom 40 joints of tubing (Figure 2). Nearly all of these failures were due to holes caused by sucker rod coupling wear on tubing. The majority of parted rod failures were occurring in the top 40 rods due to fatigue, although a substantial amount were also occurring in the bottom 20 rods. Nearly all of the bottom failures were due to sucker rod coupling wear on tubing (Figure 3). All rod strings at this time consisted of plain rods on the bottom and metal-scrapered rods in the top 75% of the string.

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