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 5

 FLOWINGWELLS AND PLUNGER LIFT

 A. Producing Flowing Wells 

1. Allowables. · Coning wells and pulling in gas and water. · Effects of poor production techniques. 

2. Several Operators Owning Wells in the Same Reservoir. 

3. What Makes a Well Flow Naturally? · Packer removal. 

4. Producing a Flowing Well. · Master gate valve. · The pressure gauge. · The wing valve. · The check valve · The casing valve. · The variable choke valve. · The positive choke. 

5. The Skilled Pumper and Marginally Flowing Wells. B. Plunger Lift 1. The Cost of Changing a Well to Mechanical Lift. 

2 How Plunger Lift Works. 3. Benefits of Plunger Lift. · Reduce lifting costs. · Conserve formation gas pressure. · Increase production. · Produce with a low casing pressure. · Prevent water buildup. · Avoid gas-locked pump problems. · Reduce gas/oil ratio. · Scrape tubing paraffin. · Improve ease of operation. · Use pneumatic or electronic controllers. · Achieve lower installation and operating costs. 4. Plunger Selection. · Solid. · Brush. · Metal pad. · Wobble washer. · Flexible. 5-ii · Clean-up plungers. 5. Bumper Housings and Catcher. 6. Controllers. 

7. Plunger Lift Configurations. 

The Lease Pumper’s Handbook 

Chapter 5 

Flowing Wells and Plunger Lift Section 

A PRODUCING FLOWINGWELLS 

The gas and water in a formation may create a pressure that forces fluids from the rock when an opening, such as the well, is created. This pressure can be strong enough to force the fluids to the surface. In this case, the well may be referred to as a flowing well. If this level of pressure is less, a pump or lift system must be installed to bring the water, oil, and gas to the surface. Many wells start out as flowing wells but must be worked over to install a lift system in the later years of their production lives. This chapter discusses both flowing wells and wells with plunger lift systems. However, before considering how oil is brought to the surface, the regulation of production is discussed. 

A-1. Allowables. 

Generally, a lease operator would like to produce as much oil and gas as possible because that is what leads to revenues from the well. However, maximum production rates may not be in the best interests of the reservoir or the environment or the economy or other considerations beyond the financial interests of the lease operator. Because the lease operator may not be aware of all the factors that should be considered or may not voluntarily do what is in the best interests of the nation and others, agencies have been established to regulate the production of oil and gas. At a state or local level, such an agency may be called a Petroleum Commission, Oil Commission, Railroad Commission, or other name. These agencies assist petroleum producers in understanding reservoir problems and promote operator cooperation. One of their primary tasks is to regulate the amount of production allowed for a reservoir, often with limits set for both oil and gas. These production limits, commonly called allowables, prevent production abuses in reservoirs through the following objectives: · Protecting the reservoir. Allowables and regulations are aimed first at protecting the longevity and stability of the reservoir. Good production practices can add years to the producing life of the reservoir and result in a much higher final production from the field. · Protecting the rights of other operators. Allowables protect the lives of the wells of all operators who have producing wells in a reservoir. Regulating the amount of gas that may be produced can preserve bottomhole pressure, meaning that producers do not have to resort to lift systems as soon. Because of oil production regulation, reservoirs are not depleted as quickly or unevenly, even when more than one lease operator is producing from the reservoir. Coning wells and pulling in gas and water. Some wells are capable of producing 5A-2 much more oil than is allowed. If the well is water-driven—that is, bottom pressure is supplied by water carrying oil into the casing—the lease pumper may be tempted to over-produce the well. This temptation is especially severe if equipment breakdowns or other problems have put the lease behind its production goals. However, doing so may damage the well’s production capability. Fluids under pressure move to areas of lower pressure. In this case, the low pressure is at the bottom of the well bore, causing fluids to rush from every direction. Oil flows in from each area of the reservoir, unwanted gas forces its way down through the oil bearing sands from above, and water pushes upward into the oil zone from below. Very soon a situation develops where the gas cone stays in position even when the well is at rest. When the lease pumper opens the valve, more gas than usual will be produced, sweeping water into the well. This water will stay in this position while the well is at rest. As water surges up, it drives out the oil. The small differences in weight require many years to fall back naturally so that the oil can return to its original level. The lease pumper can reduce the production capacity of the well to a fraction of its uncontrolled production rate. Effects of poor production techniques. It really does not matter who has decided to overproduce the well: the owner, field supervisor, or the lease pumper. The well has been damaged, and the company must pay the price with lowered production. Treating the well more gently will not casually restore it to the former level of production. The recommended practice is not to overproduce a well by more than ten percent of its maximum daily production potential. This means that if a day of production is lost, it will require ten days to make up the loss. The well may reach the end of the month still short. However, this is much better than damaging the well capability because continued overproduction will soon result in being short every month. Occasionally a lease pumper may hear other pumpers talk with pride of their abilities as a pumper because they make up for lost production in one well by overproducing other wells on the sly. When the production problems get corrected, they have managed to maintain full production overall. Even their supervisors may be extremely pleased. In fact, all this effort has actually accomplished is to shorten the lives of the wells and dramatically reduce their long-range capabilities. 

A-2. Several Operators Owning Wells in the Same Reservoir. 

The United States is one of the few countries in the world where mineral rights can be owned by individuals, companies, trusts, states, and the government. As a result, occasionally the production practices of one lease operator may cause extreme production problems for offset wells—that is, wells operating near the first lease. This reduction can become so severe that nearby wells are killed, meaning that they no longer produce oil or gas, because hydrocarbons are pulled away from the outer areas of the reservoir where the offset wells may be. If the reservoir is high in some areas and low in others, wells in the higher elevations may produce only gas. Wells drilled in the lowest area may produce extremely high volumes of water and very little oil. Wells in the middle range may produce high volumes of oil with very little gas and virtually no water. If the operator of the wells in the higher area produces high volumes of gas and 5A-3 lowers the reservoir pressure, the wells producing a high volume of oil will gradually stop producing oil. If the lease operator owning wells in the lower zones produces massive amounts of water, this will stimulate the water drive and, with the lowered formation pressure, allow the water table to rise so that production from the high oil-production wells falls off. Many lawsuits have been filed from these types of problems. The best solution is for the operators involved to agree to a production plan for the whole reservoir so that it can be produced efficiently for the benefit of all the operators. 

A-3. What Makes a Well Flow Naturally? 

A well flows naturally when it has a sufficiently high bottomhole pressure to force the fluids to flow from the formation all the way to the stock tank without external or internal assistance. Most naturally flowing wells receive their bottomhole pressure from water drive, which is the pressure created by the movement of water within the formation. As oil and gas are removed from the formation, water may fill the space vacated by the hydrocarbons due to the lower pressures in that area. This is a relatively slow process taking many years to occur. For the well to flow, the bottomhole pressure must be great enough to lift the column of fluid in the tubing to the wellhead, push the fluid through the flow line to the tank battery into a pressurized separating vessel, and still retain enough pressure to push it through any additional treating vessels and into the sales or stock tank. So how much pressure is required? A common rule of thumb is that if the well has a wellhead pressure of about 100 pounds with a standing column of liquid in the tubing, this is usually sufficient pressure to allow the well to flow. The higher the pressure, the higher the volume capacity and the ease of flow. 

Figure 1. A typical wellhead for a naturally flowing well. (courtesy ABB Vetco Gray) 

Packers are placed near the bottom of the tubing string in the annulus of flowing wells to prevent the surge effect that will occur if no packer is present. The flowing well without a high bottomhole pressure will produce erratically without a packer. As an illustration, if a flowing well without a packer produces mostly gas with very little liquid for a short period of time, most of the liquid in the tubing and casing will be produced toward the tank battery. As the casing is emptied of liquid, the gas pressure contained in the annulus will break around into the tubing perforations. This sudden surge of gas will empty most of the liquid out of the well all of the way to the tank battery. This loss of gas will reduce the gas pressure dramatically in the casing all of the way through the system. After this pressure has blown down, and liquid once more begins to accumulate in the bottom of the well, the casing pressure acts as a flow cushion or as a pressure surge tank. The casing pressure must build back up to a level that will allow the well to develop enough bottomhole pressure to cause it to flow again. This erratic action of flowing wells can be reduced or eliminated by placing a packer in the well near the bottom. Very high volume flowing wells may be produced through the casing, however, and these wells do not have packers. Packer removal. When a well will not flow and is converted from a flowing well to a pumping well, the packer may be removed, and the casing valve is eventually opened to the tank battery at all times to remove bottomhole formation pressure. A check valve is placed in the casing line near the wellhead to prevent the oil that is being pumped out of the tubing from circulating back into and down the casing. The bottomhole pressure of the well has now been reduced to the separator pressure plus flow line resistance, plus the weight of the column of fluid in the annulus. The lease pumper must always be aware of any situation that might change this balance, because every change will affect the oil production from the well. If the pumper raises the separator pressure by 5 pounds, the formation pressure has been raised by 5 pounds, and oil production will decline accordingly, especially for a short period of time. When the gas production has been reduced to the traces classification, the casing valve may be open to the atmosphere. 

A-4. Producing a Flowing Well. 

The typical flowing well will have a Christmas tree composed of a master gate valve, a pressure gauge, a wing valve, and a choke. The Christmas tree may also have one or more check valves. The functions of these devices are explained in the following paragraphs. Figure 2. A typical flowing well configuration with a Christmas tree, master gate valve, wing valve, check valve, variable choke, and flow line. Master gate valve. The master gate valve is a high quality valve. It will provide full opening, which means that it opens to the same inside diameter as the tubing so that specialized tools may be run through it. It must be capable of holding the full pressure of the well safely for all anticipated purposes. This valve is usually left fully open and is not used as a throttling valve to control flow. 

The pressure gauge. A high-pressure steel tee is placed above the master gate valve. A tapped bull plug and a ½-inch needle valve with gauge are placed on top of the well. The high-pressure needle valves are available in both straight (180-degree) and ell (90-degree) configurations where the valve pressure can be read from a convenient angle. Figure 3. Pressure gauge and valves used on top of the well. The wing valve. The wing valve can be a multi-round opening valve similar to the master gate valve or it can be a quarterround opening. Plug valves are sometimes used, though the ball valve is becoming popular because of the ease of operation. Further, it is easy to determine even from a distance if the valve is open or closed. Ball valves cannot collect water in the bottom of the valve as can some plug valves. Ball valves are usually also more economical to purchase. When shutting in the well, the wing gate or valve is normally used so that the tubing pressure can be easily read. The check valve. Almost without exception, a check valve is installed in the flow line as it leaves the well. A second one is installed at the tank battery just before the line enters the tank battery separator header. Occasionally, an operator will prefer to install the check valve just after the wing valve but before the choke. Other operators install the check valve on the ground, after the line has turned toward the tank battery. This optional union and a ground-level check valve may be installed to permit easy removal of the Christmas tree and riser pipe for well workover. Some operators will install all three. The casing valve. Even if a packer has been installed in the annular space near the bottom of the well, the casing will usually be connected to the Christmas tree and the line going to the tank battery. This will permit the casing to be opened, closed, bled down, and, in some cases, allow the flowing well to be produced through the casing as well as the tubing. If a packer is installed, this line connection serves no purpose until the packer is turned loose or is completely removed by a well servicing crew. The casing valve is usually a multiple round opening gate valve and can withstand high pressure. Like the wing valve, it does not have to be full opening. This valve can be used to determine packer leaks or determine if the tubing has developed leaks. The variable flow choke valve. The variable flow choke valve is typically a very large needle valve. Its calibrated opening is adjustable in 1/64 inch increments. Chokes are available in steel, stainless steel, and tungsten carbide steel and are, therefore, expensive. High-quality steel is used in order to withstand the high-speed flow of abrasive materials that pass through the choke, usually for many years, with little damage except to the dart or seat. 

Figure 4. A unibolt design variable flow choke valve. A portion of the valve has been cut away to show the high-quality steel construction and the flow path. (courtesy Cooper Cameron Valves)

The valve pictured in Figure 4 is of the unibolt design. The seal where the two halves of the union joints is a seal ring similar to the ones where the wellhead sections and the Christmas tree join the wellhead. This is a high-pressure steel seal and will withstand several thousand pounds. The unibolt union is often referred to as the wellhead union. The variable choke valve can be installed where the production flows with the dart, or running, or it can be installed where it flows against the pointed end of the dart or stem. As pictured, the unibolt choke has been installed to flow with the point of the dart. The choke valve in Figure 3 is installed so that the well flows against the point. Because of the expense of the valve and the amount of fluid produced, the ¾-inch variable choke is very popular. Chokes of 1 inch or more are available but are practical only for very high producing wells. Choke valves are marked to show the size of the opening. If the valve is fully opened, the last number will indicate its size. For example, if the last number is 48, then the valve is 48/64ths or a ¾-inch choke. If the final number is 64, then it is a 1-inch choke and can be opened to 64/64ths. The indicator sleeve can be loosened, usually with a set screw, and the setting corrected while the valve is closed. If the well flows oil that may have a little paraffin, salt water, and scale, production may slowly drop as the orifice becomes clogged. Periodically opening the choke to a higher setting for a short period of time, then closing it, then opening it back up to flush the seat clean, and finally slowly pinching it back to the original setting may eliminate the scale that can collect in the choke. Occasionally, the choke valve will be set at a rate of production that allows water to fall back down the tubing string and collect at the bottom of the well or in the matrix area. As this water builds up, it will begin to restrict oil production. It may even kill the well. This will require a swabbing unit to be called out to swab the water blanket up to the tank battery to allow the well to continue to flow. The use of soap sticks is a common means of stimulating flow from a well loaded up with water. Opening the choke to an increased flow rate for a short period of time occasionally, then setting it back at its usual setting may prevent this problem. In order to monitor this situation, the lease pumper will need to write down the well head pressure before beginning and for at least one or two more periods to determine if the flow characteristics of the well have improved. Another solution is to conduct a productivity test to determine if other flow cycles would be more appropriate. 

The positive choke. The positive choke may be located at the well on the Christmas tree (Figure 5) or on the inlet manifold just ahead of the first separating vessel (Figure 6). In many situations, there will be a positive choke at both locations. When the positive choke is located at both the wellhead and at the tank battery, it gives positive benefits. Figure 5. A positive choke installed on the wellhead. Figure 6. A positive choke installed at the tank battery. One of the distinct advantages of the variable choke over the positive choke is the ease with which the setting can be changed. Flow through positive chokes is regulated by choosing a properly sized flow bean that will allow the well to produce the correct amount of oil daily. The chart in Figure 7 offers 74 sizes of beans shut-in to 14/64ths of an inch. These flow beans are sized to permit 5% and 10% increases in flowing rates. Figure 7. Chart showing sizes of available flow bean inserts for positive choke valves. (courtesy Cooper Cameron Valves) If the orifice size in the flow bean is a little larger at the well than at the tank battery to allow for expansion of the fluids. The final expansion occurs at the tank battery. The fluids will undergo a temperature reduction at the wellhead and also at the tank battery. Permitting this pressure reduction to occur in two steps instead of one can reduce the possibility of the line freezing. The intermittent control for all wells is at the tank battery, and this centralizes the automation at one location instead of being at each wellhead. When the positive choke is at the wellhead, a wing gate is installed between it and the wellhead. A second valve is installed after the positive choke. This allows the choke to be easily isolated, bled down, and repaired or changed. 

A-5. The Skilled Pumper and Marginally Flowing Wells. 

As bottomhole pressure declines, there will be a corresponding decline in oil and gas production. During this period of reduced production or as the hydrocarbons in the reservoir are nearing depletion, the well is referred to as a stripper well or a marginally producing well. Much of the nation’s oil production comes from marginally producing wells. As production from a flowing well declines, the lease operator will have to make a decision as to whether an artificial lift system should be installed. To a large degree, the maximum life of a flowing well before it must be converted to artificial lift is controlled by the lease pumper. One of the most important skills of a lease pumper is the ability to make the correct decisions of how to produce each well in the marginally producing period before it goes on artificial lift. Some people have the interest, experience, patience, and ability to understand what is going on downhole, and the skill to make a flowing well produce for months or even years longer than other people. Some people never truly develop this skill. A skilled lease pumper, who takes time to learn how to rock a well, alternately opening and closing the tubing bleeder and occasionally the casing valve, may bring a well back to life and do an outstanding job in obtaining a satisfactory volume of production with limited down time. This ability can extend the life of a flowing well before artificial lift is necessary.