Lease Pumper's Handbook Published by the Commission on Marginally Producing Oil and Gas Wells of Oklahoma, First Edition 2003 Written by Leslie V. Langston Table of Contents Introductions A. Cover Sheet Book Title B. Publishing Information First Edition, 2003

The Lease Pumper's Handbook

Published by the Commission on Marginally Producing Oil and Gas Wells of Oklahoma, First Edition 2003 Written by Leslie V. Langston Table of Contents Introductions A. Cover Sheet Book Title B. Publishing Information First Edition, 2003


Written by Leslie V. Langston


Publishing Information. First Edition, 2003. C. Foreword. Rick Chapman, Executive Director (1996-2000) Commission on Marginally Producing Oil and Gas Wells, State of Oklahoma. D. Dedication. John A. Taylor, Chairman (1992-1998) Commission on Marginally Producing Oil And Gas Wells, State of Oklahoma. E. Author’s Introduction. Leslie V. Langston, Author, First Edition F. Commission Introduction. Liz Fajen, Executive Director, Commission on Marginally Producing Oil and Gas Wells, State of Oklahoma.


Purchase a Copy of the Pumpers Handbook From the State of Oklahoma click here

  The Lease Pumper’s Handbook

 Chapter 6

 Mechanical Lift

 Section C


 When a flowing well is converted to a mechanical pumping arrangement, any downhole packers must be removed and a tubing holddown installed as required according to pumping depth requirements. The packer must be removed to lower the formation pressure to stimulate fluids to flow to the well bore because of reduced bottom hole pressure. A second need is to rebuild the wellhead to meet pumping needs. Occasionally, a pumping unit is installed just to lift water blankets off the matrix area so that the well will flow again. In this situation, a choke valve will remain after the wing valve and will be used to control well production. Special downhole pumps can be installed to handle natural gas along with any oil and water produced, but in this section a standard pumping arrangement is reviewed. 

C-1. Preparing the Well for Pumping Downhole. 

Packers are usually removed when the well is being prepared for mechanical pumping. Packers are removed to permit gas to be produced up through the annular space. Some style of holddown is required to prevent breathing of the tubing when the well is pumping. Occasionally, if it is not desirable to remove the packer, it can just be released to allow gas to pass beside it and left in the hole. The operation of holddowns was reviewed in Section A of this chapter and will be discussed further in Chapter 17, Well Servicing and Well Workover. 

C-2. Pumping Wellheads. 

Figure 1 shows one method of connecting the pumping wellhead on the well. The Christmas tree has been removed and an adapter flange or bonnet has been installed with a pumping tee mounted on top. A quarter-round opening valve and a check valve have been installed in the pumping tee and the annular wellhead. These are connected together with nipples and unions. The four-way tee on the tubing header pictured has a flow line pressure safety shutin mounted on top. If the flow line should become plugged, freeze, or break, the safety switch will shut the well in until it receives proper attention. The controls reset when the well is placed back into production. Figure 1. Wellhead with tubing and casing connection and shut-in control. 

Figure 2. A typical pumping wellhead that includes a polished rod, polished rod clamp, polished rod liner, rod lubricator, stuffing box, pumping tee, tubing head, and casing head. (courtesy of Dandy Specialties and Larkin Products) 

C-3. Selection of Polished Rods, 

Clamps, Liners, and Stuffing Boxes. When selecting the polished rod and other wellhead equipment (Figure 2) several factors need to be considered. Some of these are: Polished rod. When selecting polished rods, many people purchase them too short. When working on troublesome wells, the crew will encounter problems when it becomes necessary to lower the rod string to tag or tap bottom and perform other servicing functions The polished rod needs to be long enough to be able to lower the polished rod liner all the way to the top of the stuffing box with the horse head at the top of the stroke. The top of the rod needs to extend through the bridle carrier bar with room to install a suitable clamp and additional room above the clamp to allow the string to be lowered enough to tag bottom. With the horse head still at the top and the maximum amount of rod out of the hole, the polished rod must extend below the stuffing box far enough to lower the liner all the way down against the stuffing box. The polished rod liner. The polished rod liner is placed on the polished rod to protect it from wear. It is easier to prevent stuffing box packing leakage with a larger diameter liner. The polished rod liner should be as long as the maximum stroke length plus at least two feet. If it is too short, it will have a tendency to hang on obstacles in the wellhead on the upstroke or will create problems when trying to tag bottom. When the clamp above the stuffing box is adjusted, the polished rod clamp on the liner must NEVER be tightened. Every time this clamp is tightened on the liner, it puts a series of indentations in the liner. With every stroke of the pumping unit, a small amount of oil and compressed gas is lost to the atmosphere when the damaged section of the polished rod liner comes up through the stuffing box. This leakage will continue as long as the liner is used. The lost oil is continuously running down on the stuffing box and wellhead, creating constant cleaning problems. The one moment of carelessness that put the indentations in the liner can cause problems, time loss, and unnecessary replacement expenses. The polished rod clamp. The polished rod clamp (Figure 3) is used to support the rod string while the weight is being carried by the bridle and carrier bar. These clamps are available with one bolt or up to four or five bolts to match the rod load. Occasionally two clamps are used on a polished rod for safety. There may also be a polished rod clamp below the carrier bar. This is a common practice on wells that have a history of polished rod failures with the rod breaking at the carrier bar. This safety clamp is installed to prevent the rod string from going through the stuffing box where the well may flow. Several spills have been prevented by this practice. Figure 3. A two-bolt polished rod clamp. The stuffing box. In the earlier years of the petroleum industry, most stuffing boxes used donut-shaped packing. It was manufactured with many types of additives, such as graphite and lead, to improve its efficiency. 

Figure 4. Stuffing box with cone style packing. (courtesy of Trico Industries, Inc.) During recent years, cone-shaped packing (Figure 4) 

has become very popular, and many thousands of packing boxes with coneshaped packing are in service across the industry. An improved model is on the market that is virtually leak-proof, though its cost may not be justified for marginal stripper wells. With a marginal well of medium to shallow depth, the cone style is still highly satisfactory. If common sense and caution are used when installing and periodically 6C-4 tightening the packing, a set of packing can last for several years and have almost no leakage. Various qualities of packing are available. By keeping careful records and tracking costs, a lease pumper can determine which is the most economical practice in the selection and maintenance of packing. The most important action, though, is to keep the pumping unit carrier bar well centered over the hole. Most stuffing boxes have a grease fitting on the side of the box. If the stuffing box is made so this fitting points toward the pumping unit, the lease pumper must get between the stuffing box and the pumping unit to lubricate the box. Since this is done while the unit is running, the edge of the horse head can strike the worker on the downstroke. People have been seriously wounded in this situation. Even on large units, the fitting should always point out or to the side. The polished rod lubricator. A freefloating polished rod lubricator with wickaction felt wiper pads may be installed on the polished rod just above the stuffing box. This device supplies additional lubrication to the polished rod and extends the life of the packing. When no oil is being produced, this lubrication prevents the polished rod from heating up and damaging the packing, so such a lubricator is particularly helpful on wells that produce erratically. An inexpensive non-detergent oil is satisfactory for use. The rod rotator. One of the by-products of oil production is paraffin. Paraffin is a waxy mixture of hydrocarbons that can coat rods, tubing, valves, and surface pipe internally as the fluids come into contact with them. At depths, the heat of the earth will maintain the paraffin in a liquid state. However, as the paraffin rises in the hole with the production fluids, it hardens. Paraffin will turn from a liquid to a solid and be deposited in the tubing and on rods. Figure 5. A rod rotator used to remove paraffin and scale. One way of combating paraffin buildup is the use of a rod rotator (Figure 5). The rod rotator is installed on the wellhead and connected to the walking beam. With each stroke of the pumping unit, the rotator will rotate the rods a fraction of one revolution. Scrapers are fixed to the rods close enough to have a slight over-travel with each stroke. As the rods are rotated, paraffin is scraped off. There are many styles of paraffin-cutting paddles, most of which are flat or circular. Other methods of dealing with paraffin include the injection of chemicals and running hot oil down the well. Once paraffin reaches the surface with the oil, it is generally addressed with chemicals and/or heat from a heater/treater. Steam is often used to remove paraffin from parts such as rods and tubing after it has been pulled and laid out on racks. 6C-5 

C-4. Tubing, Casing, and Flow Line Check Valves. 

Another possible source of problems at a wellhead are check valves. When trash or scale accumulates under the seat of the check valve or an internal failure occurs, the check valve may lose its ability to seal and allow fluid to leak back into the wellbore. Two wellheads are shown in Figure 6. The one on the left has a working pressure of 300-500 pounds. The one on the right has a working pressure of 2,000 pounds. The pressure rating of a valve and screw connections can be determined by observing the embossed numbers molded into the forgings. Every lease pumper must be able to determine fitting pressure ratings by casual examination. Both illustrations show all three wellhead check valves. One is located on the upper horizontal line from the tubing just after the wing valve. The second is located directly below the upper one in the line from the casing. This line also has a wing valve. After both lines come together and are directed toward the tank battery, a third valve and check valve are installed. The tubing check valve. During certain types of productivity tests, it is necessary to check the downhole pressure applied to the tubing. For the test to be accurate, this pressure must be isolated from casing pressures. The check valve just past the tubing wing valve prevents casing pressures from flowing back through the bleeder valve when the downhole pump action is checked at the 1-inch bleeder valve next to the pumping tee. Figure 6. Two pumping wellheads. The one on the left is a medium-pressure unit and the one on the right is a high-pressure unit. The casing check valve. The casing check valve allows the produced gas from the casing to flow to the tank battery. This action is essential to allow new production to migrate from the formation into the well bore, where the gas flows to the tank battery through the casing and the liquid is pumped to the tank battery through the tubing. The casing check valve prevents the produced liquids pumped out of the tubing—both oil and water—from circulating back to the bottom of the well. 6C-6 Even a slight leak in this check valve will result in loss of new production and will confuse the pumper as to the amount of oil being produced. The flow line check valve. The check valve in the flow line near the wellhead prevents several problems from occurring in the event that one or both of the wellhead check valves fail. If the tubing should develop a leak, then the weight of the column may draw the oil in the flow line back into the bottom of the well. These check valves can also prevent produced oil in the header from flowing back to the well, and the production from all wells flowing back into the formation. By configuring these check valves properly, the lease pumper can gain a more accurate picture of what is occurring at the well.