The Basics of Gas Lift Pumping in Oil & Gas Production

Gas Lift

Figure 1. A basic gas lift system. (courtesy of McMurry-Macco Lift Systems)

The production of any well is going to eventually drop. Even with a well that at first naturally flows rather than requiring pumping, the volume of oil produced will drop at some point. Production may drop to the point that the number of barrels produced each day falls a significant amount.

One of the methods you can use to bring production back up is gas lift, which involves pumping gas into the tube line below the surface of the liquid in the well. The gas forces the fluid through the tubing and to the surface. It’s a method that’s used commonly, particularly in wells that have lower production volumes, as gas lift can add a few barrels a day to production and still be cost effective. It’s also used offshore commonly, where space is at a premium. Gas lifts don’t take up much room, and it’s possible to use it with a few wells drilled close together. Additionally, no gas is lost in the pumping process.

Gas lift systems are also commonly used for a number of other situations. As mentioned above, it’s a good choice when a well needs a little additional force to produce satisfactorily. It can also be used with wells that have a head of water; the gas lift clears the water, allowing the well to flow as it had previously. In the same vein, it can be used to pump water for use in waterflood operations. Gas lifts are useful in a number of different contexts, and can also be used for injecting chemicals and other additives.


Gas Lift Basics

Gas lift uses gas pressure to, in effect, make the fluid weigh less. This reduces the pressure required to push fluid out of the well system to the point that bottomhole pressure is enough. Gas lift can be used to coax a natural flow, or increase an already existing flow. As long as the bottomhole pressure combined with the gas lift is enough to push fluid to the surface, production will continue.

When using gas lift, there will be a number of valves on the tubing lowered below the fluid level. These valves open automatically at certain predetermined gas pressures, which happens as part of the sequence for unloading the well. Each of the tubing valves is opened in sequence, so that a column of fluid is injected with gas. The fluid is lifted to the surface, and the next valve in the sequence is opened, sending the next column up. More columns are injected and lifted until the total weight of the fluid column, from the bottom of the well to the surface, has been reduced to the point that the well begins flowing.


When Should You Use Gas Lift?

It’s obvious that gas lifts can be used in a wide variety of contexts, but they can also be used in wells producing a wide range of volumes as well, from tens of barrels a day to tens of thousands of barrels a day, making it a very flexible system. Maintenance and installation costs are also usually lower, and it’s generally easy to service. It’s also useful in contexts where sand might clog or damage other types of lifts. It’s particularly useful when a well is deviated, and the wear on rods may be a concern.


How To Get Started With A Gas Lift

A gas lifting system has three primary parts. The inlet provides a supply of high pressure gas. This leads downhole, the second part, to the system in place there. The outlet is where the produced volume is sent and the gas recaptured.

The best option for gas lift is a large supply of high pressure, dry natural gas. Ideally, produced natural gas, which will mostly likely be wet, is sent to a processing plant to strip way fluids. The dry gas can then be sent back to the lease for pumping; usually a central gas distribution system supplies all of the wells which can be placed near the processing plant.

It is possible to use wet gas to power a gas lift system. However, you’ll spend a great deal of time in maintenance, and you’ll need to install some additional equipment. You’ll need to install some sort of scrubber to strip out all the fluids from the gas. You’ll also need to install a compressor to put the gas under enough pressure to be useful. Under the higher pressure conditions of the flow line, water may separate from the fluids. Drop pits are required to keep the condensation contained.
The gas is sent to the well through a control valve that is usually near where a pipe from the compressor meets the wellhead. A choke valve is also installed at the wellhead to vary the amount of gas that is injected into the well. You’ll want to set the choke valve so that you’re using gas as efficiently as possible. Near the bottom of the tubing string, a packer is used to seal off the annular space below the casing perforations from the space above.

Gas Lift

Figure 2. A two pin pressure recorder at the wellhead. (courtesy of McMurry-Macco Lift Systems)

As with other types of lifting systems, a simple recording device at the wellhead can be very helpful when it comes to diagnosing problems. For a gas lift system, a two pin pressure recorder is a reliable way to keep track of the pressures used in the gas lift valves during operation, and to keep track of the lifting system’s overall efficiency. Using the information the recorder provides, you can monitor how much gas is being injected, and adjust that amount so you’re hitting the production amounts you need, as well as diagnose a variety of problems.

It is important to consider the what changes or improvements you’ll need to make to your tank battery to use gas lift. Using gas lift can have an impact on the equipment needed for handling natural gas, water produced from the well, and crude oil, and you should plan for a higher level of production for all three.

Using Hydraulic Systems to Power Multiple Wells in Oil & Gas Production

Hydraulic Systems

Figure 1: An example of a central power system.

Using one central hydraulic system to power multiple wells is a popular setup. A single triplex pump, depending on the amount of power oil needed, could supply power oil to up to eight wells. The advantage of using such a system is that you only need to obtain and maintain a single hydraulic power system. The downside is that when that system is down for repairs or maintenance, all of the wells that depend on it stop producing.


Power Oil Tanks

Crude oil is the most common source of hydraulic power for lease pumping. This oil is stored in the power oil tank in the tank battery. The power oil tank is the last tank in the oil processing system and is located just before the crude oil stock or sales tanks. The power oil tank is usually taller than the sales tanks. This allows the supply from the power tank to be located about two feet below where the excess production equalizes over into the sales tanks.

In addition, two feet below the standard supply line, there is an emergency supply line controlled by a separate valve. The valve can be opened to supply additional power oil in the case of an emergency. When everything goes back to normal, you can just shut that valve to stop the additional flow of power oil. It’s usually straightforward to pump oil in the sales tanks back to the power oil tank if it runs low.


Power Oil Lines

The other major component of using a central power oil system are the power oil lines. The hydraulic system should be placed near the tank battery. Once the header has been installed, a separate power oil supply line is run to each oil well; usually a 1-inch line is enough to do the job. A return flow line is then run from the well bank to the tank battery. Each well will have both of lines to link it to the overall system.

Hydraulic Systems

Figure 2. Power oil lines running from the central power system to each well. (courtesy of Trico Industries, Inc.)


Using Produced Water

It’s possible to use water produced from a well in place of crude oil. It’s not possible in every case, as the water has to be free of scale and corrosive compounds that damage equipment and are hard to eliminate.

However, in areas where it’s possible, it can be a wise choice. Water is easier to control than oil, and easier to neutralize. A special fitting can be added to the heater/treater that draws water from the system. Alternatively, it’s possible to tap directly into the produced water disposal system. That means that when using produced water, you don’t need to add a power oil tank to your tank battery.


Using A Closer Power Oil System

The power oil can be pumped and reused through its own system by adding a third line from the surface to the hydraulic pump. This sort of system would also require a special power oil tank be installed, as well as the additional line to the pump. However, it’s a good option when the produced fluids are too corrosive to be used for power.


Spotting Problems With Multiple Wells

When you’re using a single pump for a single well, problems are usually fairly straightforward to spot. When production starts to fall suddenly, you only have one set of equipment to check for issues.

If you’re operating multiple wells off a single power source, however, that multiplies the amount of work you have to do. It’s helpful to be able to narrow down the problem to a single well and its associated systems. To do that, you’ll have to put together a distribution manifold.

A standard layout is shown on the diagram. It controls five wells, each with a riser and set of valves, while the sixth valve is used in testing. It’s possible to test an individual well’s flow by opening (in this diagram) the first, lower valve on the right, which is the automatic bypass. By opening the second header from the right, which is the individual well test line, it’s possible to send the power oil through a meter which tracks the number of barrels that have gone through in a given period. After the oil goes through the back line and comes forward again to the selected well header, that valve is opened and the front valve is closed so that the test can begin. Returning the valves to their original settings will return the system to normal operation.

It’s possible to modify the manifold header depending on your needs. For example, it’s often helpful to add openings so you can add solubles or chemicals if you need to.

Hydraulic Systems

Figure 3. An example of a distribution manifold for five wells, including a system for testing individual wells using an automatic bypass. (courtesy of Trico Industries, Inc.)

Single Well Hydraulic Systems in Oil & Gas Production

Single Well Hydraulic Systems

Figure 1. A unidraulic system for a single well. (courtesy of Trico Industries, Inc.)

Hydraulic Systems For A Single Well

Hydraulic systems can be used to pump a single well, or as a central power system for several wells. When using it with a single well, the hydraulic triplex system is placed on the edge of the location. The power line is run from the hydraulic unit to the wellhead. Fluid that has been produced from the well, including the power oil, is returned to the hydraulic system vessel.

The produced fluid is separated by the vessel in three stages. The water falls to the bottom, and by line height automation is duped into the flow line. The water and the produced gas are sent to the tank battery, where the gas comes off the top of the vessel.

The oil in the vessel is first utilized to operate the hydraulic lift system through a special line from the vessel to the triplex pump. The pump places the oil under high pressure, and it is piped to the wellhead and then downhole to operate the pump. Downhole pumps lift oil on both the upstroke and downstroke to pull fluid from the formation, combining it with the power oil before the fluid is pumped back to the hydraulic system vessel. Any oil above the amount needed to operate the pump automatically flows out and is commingled with the produced gas and water in the flow line, returning to the tank battery.

Operating a hydraulic system requires that enough oil be transported from the tank battery to the well to fill the tubing with oil, operate the system until it is full of fluid, and send the produced oil to the tank battery. A small truck can haul enough to oil to activate the system. It can be worth it, however, to install manifold bypass systems at that tank battery and at the well to make the transport unnecessary.

After the system is initially activated, the produced gas and excess liquid are separated, with the excess liquid being dumped into the flow line. The vessel retains enough liquid in the vessel to allow the system to operate for a short time without running out of liquid. That’s a measure that’s intended to reduce the need for pumping or hauling more power oil from the tank battery.


Should You Use A Single Well Hydraulic System?

When problems occur with a triplex pump on a single well, only that well has to be shut in. Other wells on the lease are independent and continue as usual. Additionally, the length of the power oil line is reduced from the distance to the tank battery, just the distance across the location, and the triplex equipment in general is smaller.

However, using a triplex pump for each well is not always the best choice. It means that a pump has to be installed at each location, and also requires either an electrical or mechanical prime mover for every pump. If it’s electric, a power line must be run to each location. It also requires the purchasing and maintenance of many pieces of identical equipment that will require maintenance and repairs.

Different Types of Hydraulic Lift Pumps in Oil & Gas Production

Basics of Hydraulic Lift

Hydraulic systems uses fluid pressure to power a pump. That is done by pumping fluids downhole using a triplex pump designed for extremely high pressure, usually between approximately 2,000 and 5,000 psi. Hydraulic lifts are flexible, and are useful for wells that are producing any volume, from low to high. In general, hydraulic lifts have higher production volumes than mechanical lift pumps.

Hydraulic Lift Pumps

Figure l. A central triplex, high pressure pump.(courtesy of Trico Industries, Inc.)

The hydraulic, reciprocating pump is at the bottom of the well. New oil is pulled from the annulus by the pump. The newly produced oil and power oil are combined, then pumped back to the surface and then to the operation’s tank battery.

Hydraulic Lift Pumps

Figure 2. A hydraulic pump’s up and downstroke. (courtesy of Trico Industries, Inc.)

Fluid is recycled to operate the wells. For a rough guideline, for every three barrels pumped into the well as power oil, you can expect to see five barrels pumped back to the surface. The extra two barrels is new production. The pump will produce oil on the triplex pump’s upstroke and on its downstroke, and its speed can be adjusted using a valve.


Hydraulic Lift Pumps

There are a few different options when using hydraulic lift pumps. Among the different options are:

  • Fixed casing.
  • Free casing.
  • Fixed insert.
  • Free parallel.
  • Jet pump.
  • Closed power fluid.
  • Commingled power fluids.

Some of the options are more complex. We’re going to take a look at some of the simpler options, free parallel and fixed insert pumps, as well as giving a brief overview of what a jet pump looks like.

When you decide to put a hydraulic lift on your lease, you’ll have to choose between a free parallel or a fixed insert system. The pump is similar with both options, but the choice between fixed insert and free parallel can make a big difference on which wellhead you choose, and how you decide to install the moveable pipe.


The Free Parallel Pump

The free parallel pump using two strings of tubing, one of which is a smaller string that is strapped to the outside of the larger tubing string. Once you’ve lowered the tubing down into the well and installed the wellhead, you can simply drop the pump into the tubing.

You can then open the hydraulic valve so that the power oil or water flows down into the well, carrying the pump with it to the bottom. When the pump hits the bottom and seats properly, it will begin to function as lower as a power fluid is being pumped.

That power fluid will flow over with the produced oil and be pumped up to the surface through the smaller tube on the outside of the string. As with any pumping well, natural gas that is produced will mix with the produced oil and power fluid, and travel back to the tank battery.

An important advantage with this sort of pump is that it’s much easier to replace the pump when there’s a problem. The system is designed to allow a single person to bring the pump to the surface by turning a valve on the wellhead. The pump can be retrieved once it’s reached the surface with a few simple pieces of equipment.

Free parallel pumps can sometimes become knocked out of the proper position by solid objects, known as trash. The same valve that brings it to the surface to change can also be used to hop the pump up briefly, which will clear the trash. Returning the valve to its original position allows the pump to reseat. This is just as common with free parallel pumps as with insert pumps.


The Insert Pump

The insert pump is inserted (hence the clever name) into larger diameter tubing, usually. around 2 ⅜ inch. Attached to the top of the pump is a smaller diameter string of tubing, which is also inside the larger tube. The bottom of the pumps seats against the the tubing seating nipple. The pump is designed to use it’s own weight to hold it seated and in place. There’s a packer, so gas is returned to the surface up through the annular space, as with a mechanical pumping well. It’s then combined with the produced fluid from the wellhead, where everything enters the flow line. A pulling unit is required to retrieve the smaller tubing string and change the hydraulic pump.

Hydraulic Lift Pumps

Figure 3. Four different hydraulic pump designs. The fixed insert design is shown at the far left, and the free parallel design is shown third from the left. (courtesy of Trico Industries, Inc.)

As with the free parallel pump, trash can collect under the pump seating, causing production to fall or stop altogether. This can cause the column of fluid inside the larger diameter tubing to fall back into the well. A lift piston can be placed at the top of the wellhead so that power oil can be pumped under the piston. That allows the insert pump to use the same ‘hop’ technique as with a free parallel pump to clear trash and reseat the pump. This will remove the trash, and the pump will begin to operate normally again. You’ll most likely have to do this regularly while this pump is in use.

The valve on a pumping wellhead is designed so that a quarter turn of the valve handle opens the valves the correct amount to get the pump to hop up. Returning the valve to its standard setting will allow the pump and smaller diameter tubing to fall back to the bottom and where the pump will reseat.


The Jet Pump

Jet pumps are more complex. The jet action is produced using a venturi tube, which has a particular cone shape intended to narrow the flow path. The shape creates an area of low pressure by increasing flow rate. Fluid is drawn into that low pressure area.
There are a few contexts where a jet pump is going to work well. It’s common in wells offshore, where space is tight, as a single triplex unit can power several wells at once. Jet pumps can also be used with continuous coiled tubing and in horizontal completions.

Hydraulic Lift Pumps

Figure 4. A jet pump’s basic components. (courtesy of Trico Industries, Inc.)

Should You Use A Hydraulic Lift?

Hydraulic lifts have a few advantages compared to other high volume production systems, but no production system is perfect.

A key advantage of using hydraulic production systems is that it’s easy to adjust the volume of the power fluid pumped. Hydraulic pumps can also handle a high daily production volume. Free pumps, in particular, can be replaced by one or two workers without needing a whole crew.

There are some chronic problems with hydraulic lifts systems, however. Keeping enough clean oil or water to use for power fluid can be difficult in some areas. When equipment fails, it can be time consuming to repair, with one or more wells shut in for long periods. There is also simply more equipment to monitor and maintain, as you’ll need both an additional tank for power fluid, and several tube strings in addition to power fluid lines for the hydraulic systems.

Submersible Electrical Pumps for Oil & Gas Pumping: Automatic Controls

Well Operation and Automatic Controls

You may choose to operate your well continuously, or only run the submersible pump for part of the day. The well capacity and the amount of fluid you need to produce in a day will determine which is best for your operation.

In the past, pump controls were fairly simple and standardized. Computer controls have become much more popular, and allow for greater automation. New versions and control designs are common, however, it’s important to understand how your specific setup works.

Submersible Electrical Pumps

Fig. 1: The wellhead of an electrical submersible pump. It includes a check valve, pressure gauge, union, ball valve, and a hose for monitoring production.

One of the more important parts of the wellhead is the check valve, which must hold when the electrical submersible pump is in operation. If the check valve leaks, the liquid can drain back into the formation. This can cause the pump to freewheel and turn counterclockwise while the well is shut in. If the power is turned on while the pump is spinning in reverse, the sudden torque can cause shaft failure. In order to repair the pump after that sort of failure, you’d need to pull the entire pump. To prevent problems keep an eye on the wellhead gauge, which will usually indicate if a problem is developing.


Well Installation and Controls

Deeper wells and wells that have higher production volumes will have more elaborate controls, as well more complex equipment. In Figure 1, you can see an electrical submersible pump that’s about as simple as it can be. It has everything such a well needs to operate, but on a marginally producing well, it would have a minor impact on the lease income in the event of problems. With a higher producing well, it’s usually worth it to invest in more complex systems. The more information you have, the easier it will be to recognize and analyze production problems and reduce downtime.


Running a Pump Full Time

To monitor a well’s production, you’ll want to install a chart at the wellhead. When the pump is operating continuously, the chart will have two steady lines on it. One indicates the casing pressure while the pump is running, and the other indicates the tube pressure in the flow line. You’ll want to keep an eye on the chart even when the well is operating normally. You’ll then have a set of baselines you can use to diagnose problems. Without the record that a chart provides, analyzing performance to identify problems is more difficult.

Submersible Electrical Pumps

Figure 2. This chart shows a typical record of a pump in continuous operation. (courtesy of Reda Pump Company)


Running a Pump Part Time

There are some particular things to look out for if you’re only going to be running your submersible pump part of the time. When the pump isn’t in operation, the casing pressure will increase and the tubing pressure will be lower. When the pump is on, the reverse will be true, with the casing pressure dropping as the liquid level in the casing falls. Likewise, the line pressure in the tub will increase when the pump is operating. There are sets of diagrams that demonstrate what the chart will show if the pump is not operating normally.

Submersible Electrical Pumps

Figure 3. A chart showing a typical chart record of a pump running only part time.(courtesy of Reda Pump Company)

Fixing Problems

When you do run into problems with a submersible pump, you’ll most likely need some special equipment. It’s also a good idea to have an experienced technician on site who can offer advice and weigh in on decisions.

When you pull the tubing, the cable clamps and bands should be removed, and the electrical line should be spooled onto a special trailer that has been brought to the lease for the workover. After servicing, the electrical line can be re-clamped to the outside of the tubing as it’s run back into the hole.

Using Submersible Pumps for Lease Pumping in Oil & Gas Production

When a well’s production starts to fall due to decreased hole pressure, there’s a few techniques you can use to bring its output back to former levels. Mechanical lift can be one method, but once production begins to fall further, a lift may no longer be effective.

It is possible to extend the usefulness of a mechanical lift and change the lift system in order to make up for the fall in production. You could try adjusting the lift system by increasing the stroke rate, or install a pump with a lighter counterweights and a longer stroke. As you begin to pump more water and less crude oil, another method to try is a waterflood, which uses water pumped in at a reservoir to push oil to wells being pumped.

Eventually, however, production will fall to the point that you’re pumping constantly through the day due to the increase of water production. At that point, you’re going to have to put in a system that can make up for that fall in production. An electrical pump is a good option, particularly in waterflood operations with a high volume.


Why Should You Use An Electrical Submersible Pump Lift?

An electrical pump lift is able to pump large volumes at medium and shallow depths, with casing size not having much of an impact on the production volumes. When waterflood increases, it’s not uncommon to pump a few thousand barrels a day. This system can easily use automation to have the system pump only for a certain amount of time each day, or to have it pump continuously. Electric submersible pumps have a relatively low get-started investment for shallower wells.

With that said, there are some potential problems when using an electrical submersible lift. Build up of scale or gyp sometimes reduce the fluid pumped by submersible pumps. High electrical costs can be another downside, particularly if you’re in a remote area. A submersible pump isn’t as flexible in some situations, and if there’s a problem the whole system has to be pulled.


How Does A Submersible Pump Work?

There are two primary parts of a submersible pump:  the pump itself and the electric motor that powers it. Generally, the pump is above the motor. An electrical cord is attached to the pump tubing, usually protected somehow, and is used to provide power to the motor.

The whole thing is dropped into the well with both the motor and pump submerged. The pump works by rotating a series of disks or cups, driven by the motor. To pump from deeper wells you’ll need to add more cups, which allow the pump to push liquid further up to the surface.


On The Surface

There’s a few things to keep in mind about the surface needs of a submersible pump, you may have to be flexible and innovative. A common suggestion is to run a joint of pipe from the well to the control panel, which will provide a conduit through which to run the power cable. The pipe will protect the cable from being damaged by equipment or weather. You may also want to leave the power cable a little long, and hang it by the control panel. You’ll be able to lower the pump without having to splice additional cable into the electrical cord.

Pump Basics

Submersible Pumps

Figure 1. A pump and motor.

Surface Components:

Control Box: As you might have guessed, this controls the pump motor. It can be set to allow the well to operate continuously, for set periods, or to be shut off. It can also protect the pump motor from electrical surges or other electrical problems.

Transformers: These transform the power received from the electrical grid to the correct specifications for the pump. These are usually placed at the edge of the lease site.

Electrical Supply: The power grid that supplies your transformers. The highest voltage you can get usually produces the best result.

Tubing Head: This component supports the tube and also provides a seal for the electrical cord to pass into the tubing. The seal is commonly designed for at least 3,000 psi.

Chart Meter: A chart meter isn’t required for operation, but it can be worthwhile. It measures the well’s production, providing information that can help identify problems.

Submersible Pumps

Figure 2: Surface components necessary for an Electrical pump.

Submersible Components:

Cable: The cable leads from the surface, down the outside of every joint of tubing. It is strapped to the side of the pump, and leads directly to the motor. It consists of a flat three strand wire where it enters the motor, but is a round cable for most of its length. It may have a metal shield to protect it.

Motor: At the bottom of the pump, it is lowered into the well first. Use the correctly sized motor for your estimated production.

Protector: This is attached to the top of the pump, and seals the motor to allow a drive shaft to drive the pump.

Pump: The pump itself, designed to carry a fluid load. Usually, the shaft is made of an alloy called Monel, with the stages being made of a corrosion and wear resistant material. Most pumps of this type have a rotary centrifugal action.

A Pumper’s Basic Guide to Mechanical Lifts in Oil & Gas Production

Throughout the life of a flowing well, a variety of systems can (and often will) be used. Sometimes these mechanical lifts are used in sequence, on more than one occasion, or even in conjunction with one another. In most oil field cases, there are four common artificial lift types used; these include:

  • Electric Submersible Pump – a pump located at the base of the well, and powered by electricity from the surface.
  • Gas Lift– a type of artificial lift where natural gas is injected into the tubing at specific intervals to help lighten the weight of the fluid, and thus progress upward towards the surface.
  • Hydraulic Lift – contains a hydraulic pump powered by oil or water that is pumped down into the well.
  • Mechanical Lift– a lift operated by an engine or motor located on the surface.

While all four systems have their own distinct advantages and disadvantages; lease pumpers tend to use mechanical lifts more often than other options. To understand a little more about the pump operations of this device, make sure you grasp these important areas.


The Basics of Mechanical Lifts

Mechanical pumping units use the same operating principles as a water well (that contains a standing and traveling ball at the bottom, a string of sucker rods, a power source at the top/surface) or windmill to function. These systems are sometimes referred to as rod pumping units, and utilize an up and down reciprocating motion.

Mechanical Lifts

Figure 1. Example of a Conventional Pumping Unit (beam-style)

The pumping unit crank uses a circular motion created by the rotation of the sheaves/pulleys, belts, and gearbox; driven by the prime mover, the gearbox typically uses an electric motor or gas-powered engine. The pitman arms are attached to the walking beam, and the circular action is altered into a responding power to the walking beam and horse head. To offset the weight of the string of rods (usually extend through the tubing all the way to the base of the well) , and the weight of the fluid within the tubing; counterweights are used. In most cases, lease pumpers will utilize a ball and seat standing and traveling valves design to pump the liquid from the bottom of the well, through the line, and into the tank battery.

When the pumping unit begins, the pumping unit head moves upward, raising the pump’s sucker rod string and plunger. As it moves upward, the traveling ball or ball closes, preventing the oil from traveling through the plunger. This movement lifts the fluid up to the surface, while decreasing the pressure below the plunger. The standing valve at the base of the pump opens as a result of the reduced pressure, thus allowing the additional liquid to flow into the bottom of the pump.

Once the rod string moves downward, the pressure increases above causing the standing valve to close. This impedes the oil entering the pump barrel from flowing back into the formation, and allows the pressure between the valves to build up. Once the pressure is greater than the weight of the liquid within the tubing, the traveling valve will open and the plunger will pass down through the liquid and into the pump barrel during an upstroke. At the top, the plunger will get trapped causing the traveling valve to close at the start of the next upstroke; with the cycle continuing as production continues. The specific cycle time (referred to as SPM, or strokes per minute) is determined by a number of factors, including:

  • the pumping unit configuration
  • ratio of gearbox gears
  • size of sheaves/pulleys
  • speed of the prime mover

Mechanical Lifts

Figure 2. Example of a ball and seat valve. This design is a typical design found in the standing and traveling valves of mechanical lift systems.

A mechanical pumping action description illustrates how the unit raises the fluids to the surface during the upstroke; while hydraulic lift pumps raise the fluid on both the upstroke and the downstroke. Since no rods are moving in hydraulic pumps, this allows it to move more rapidly than pumps with rods. Hydraulic pumps are also capable of lifting higher volumes of liquids.

Both gas lift and electric submersible pump systems lift continuously during operation, allowing all three of these artificial lift systems the capability to lift higher production volumes each day than mechanical lift options. However, the majority of wells are not continuously run. Therefore, whether an artificial lift can be used during the whole operation, or during only part of the cycle, is not typically a deciding factor.

Many changes occur downhole during the pumping cycle as the rod string moves up and down, such as:  

  • As the rod string proceeds upward, the oil within the tubing is shifted from the standing valve to the traveling valve.
  • The rod string length grows longer as the plunger attempts to lift the weight of the fluids up and aims to overcome both the oil and tubing friction and surface tension.
  • As the weight within the column is raised, there is less weight placed onto the tubing, and thus the tubing string length shortens (or the tubing string travels the short distance up the hole).
  • The friction caused by the upward motion of the oil causes a small lifting force to the tubing.
  • As the plungers travels downward, the weight of the oil within the tubing is transported from the traveling valve back to the standing valve.
  • As the freshly gathered liquid pushes back against the rod string, the rod string decreases in length.
  • Once the traveling valve opens, the weight from the liquid is placed on standing valve and against the tubing string, causing the tubing string to lengthen and the load to increase. Depending on the column fluid weight, the depth of the well, and the size of the tubing; the bottom of the tubing string will move downward anywhere from a few inches to several feet.
  • The downward motion of the tubing causes the pump to overtravel, meaning the pump is traveling away from the surface during the downstroke and gathering additional liquid.

The cyclic load factor is the reaction from the tubing and rods responding to these changing forces, while breathing refers to the up and down motion from the tubing in the hole. Changes to the rod and tubing string length can be determined to calculate the proper adjustments required for the surface stroke length.


Implementing Mechanical Pumping Systems

One of the most productive ways to date for producing artificial lift wells is to utilize a mechanical pumping unit; and is also a great method for marginally producing wells. Mechanical pumps are a great system for low production wells because the equipment requires very little monitoring.

Once the installation is made, it is not only very economical to maintain, but it is ideal for continuous or intermittent production, due to its easy automation. However, the exact lift method chosen is based on what is most appropriate for the exact situation at hand. For instance, other lift options may be chosen to allot for higher production rates; while shallow offshore wells may choose a mechanical lift for a variety of application purposes.

Cyclic Load Factor Issues

The breathing action of the rod and tubing strings and the cyclic loading can cause a variety of issues. These can include:

  • Liquid leaking back into the tubing (caused by collars and tubing wearing where it falls back to the bottom of the hole); and in severe cases, can cause the tubing string to separate.
  • Holes worn into the casing string (eventually causing the casing to leak)
  • Malformations of the rods and tubing (ex. rod stretching or tube shortening) – This causes a decrease in overall pumping efficiency and production; and as a result, the lease pumper will have to pump the well longer to overcome the pump stroke loss.

To help reduce the up and down motion at the base of the string, a tubing holddown (similar to a packer except it lacks the rubber seal) can be placed at the base of the tubing string allowing fluids to move freely. This helps to prevent motion in the upper area of the tubing string. However, it may require several thousand pounds of tension. For example, if a 10,000 foot well used a 2 7/8 inch tubing, it could require a 25,000 pound tension weight to pull on it above the weight of the string; and is a common type of installation in deeper wells.

Operating at Incorrect Speeds

The cyclic load factor can create many issues, which can be further complicated by the unit pumping at incorrect speeds. For instance, medium to deep wells may experience issues with the top rod moving downward toward the surface while the pump traveling valve is still moving upward (or vice versa). This problem can be magnified when the pumping operations are not carefully arranged in advance. Otherwise, the RPM, sheave diameter, SPM, and/or various other factors may not match the specifics of the well for the best production and longevity.

In cases where the cyclic load factor is large, there is a greater chance for stretch in the rod and tubing strings, and for their relative travel to one another to get out of sync. In these situations, increasing the number of strokes per minute can actually decrease the stroke length at the bottom of the well. However, it is important to keep in mind that although the strokes per minute has increased, the amount of fluid produced will have decreased.
The majority of pump companies provide some type of service where they will determine the proper pump component plans based on your pumping conditions (ex. depth of the well, size of rods, strokes per minute, etc.). By planning ahead with the proper well characteristics, the lease pumper can help confirm if a mechanical lift is appropriate for the lease.

A Lease Pumper’s Basic Guide to Plunger Lifts

Over the past decade, plunger lift use has grown drastically; which in turn, has created a boost in oil productivity. Other contributions have included: improved computers and technology, equipment reliability, and other service alternatives. Lease operators can find plunger lifts with simple straightforward arrangements to more complex computer operated options. To help understand a little more about these popular devices, check out these plunger lift essentials.

The Fundamentals of Plunger Lift Mechanic

One of the most common initial questions about plunger lifts is ‘how do they work?’. While it may seem like a complex system, plunger lifts are pretty straight forward in their operations. On to top of the wellhead there is a wing valve control which closes the flow line to the tank battery, this allows the operator to stop the fluid flow through the tubing to the tank battery.

Also on the wellhead is a bumper housing and catcher used to release a free-falling gas lift plunger. This device uses the wellhead’s natural downward gravity to descend through the tubing. When the valve is open, the plunger allows fluids to pass through as it falls; gravity then continues the plunger’s plummet to the bottom of the well.

Once the gas lift plunger hits the bottom of the well, it will come into contact with a footpiece spring, and thus closes the valve. As the increase in downhole pressure steadily persists, it allows the water and oil to gather above the plunger. Then after either a specific tubing pressure or time frame is reached, the controller will open the flow line motor valve; thus allowing the accumulated fluids and gas within the tubing to again flow to the tank battery.

The pressure change differences throughout the plunger lift valve typically generate travel speeds of around 500 – 1,000 feet per minute. Each lift will vary in speed depending upon the various options for: bottomhole pressure, choke settings, and fluid loads. The plunger lift moves upward toward the surface fueled by the built-up formation pressure beneath it, and bringing the the fluid located above it as it returns.

However, for weak gas wells and/or oil wells, once the plunger arrives at the surface, a magnetically controlled sensor will automatically close the flow line motor valve, and thus conserving formation gas pressure and tubing for the next lift cycle. The catcher (located within the bumper housing) frees the plunger; and the plunger once again begins to fall and thus restarting the entire process again. The process is repeated as often (or as little) as the pressure and settings allow.

A Lease Pumper's Basic Guide to Plunger Lifts

Figure 1. Example of a Plunger Lift System (Production Control Services, Inc.)

The Price of Switching to Mechanical Lifts

After the well’s bottomhole pressure is no longer able to produce an adequate flow, the lease operator will have to decide whether it would be beneficial or not to equip a lift system. Two major factors in this are the significant initial upfront costs when using lift systems (even for minimal installation options), and the longevity (and therefore,  profitability) of the well. However, before a lease pumper rushes to make the transition from flowing to pumping well; they need to ensure they remember to meet the following requirements:

  • A Well Servicing Crew – These workers will be utilized to help rig the packer and remove it. They may also help to re-equip the tubing string, install the hold-down, and/or for setting up the rod string.
  • Purchase of Equipment – This includes: the downhole pump, the pumping unit, and string of rods.
  • Construct and Set-up a Base
  • Position and Install the Pumping Unit – This should be located on the base, and on top of the hole.
  • Remove the Current Christmas tree
  • Reconstruct the Wellhead (See Figure 2)
  • Supply Power to the Pump – This is typically accomplished by running electricity to the site or by using an engine. Electrical setups require automatic controls, and use an electric motor; while engine powered pumps usually operate on either stored fuels, or gas from the well.

A Lease Pumper's Basic Guide to Plunger Lifts

Figure 2. Two Examples Wellhead Designs Used for Wells with Plunger Lifts

The Bumper Housing and Catcher

The bumper housing and catcher carry out a variety of functions. For instance, the bumper offers a cushioned bumper to halt the plunger as it reaches the end of its journey and into the housing (where it receives lubrication for the next journey). Once there, the arrival unit will register the plunger has reached its topside destination; and will then either signal the controller, or control panel, to close the flowline valve.

Once completed, the lease pumper can then engage the catcher (allowing the plunger to catch the next time it arrives). The pumper can then remove the plunger to inspect, service, or replace the device to get back into operation at lease pumper’s discretion.

A Lease Pumper's Basic Guide to Plunger Lifts

Figure 3. Examples of Common Components Found in a Plunger Lift System – from right to left: a housing with lubricator and electronic sensor, bumper, plunger, and a controller.  (Production Control Services, Inc.)


The majority of controllers (See Figure 4) have the ability to operate with either pressure cycles or time control. Timers can be utilized for specific shut-in times. They can also be used to operate using high/low pressure measurements using a differential pressure switch and the flow line throttle pilot pressure. By decreasing formation gas loss and having this available flexibility, controllers provide the most ideal method for a majority of wells (and lease pumpers).

A Lease Pumper's Basic Guide to Plunger Lifts

Figure 4. Example of an Electronic Controller  (Production Control Services, Inc.)

The Perks of Using Plunger Lifts

There are many perks for transforming a minimally producing plowing well into well with a lift system. In many situation, there are significant benefits for choosing a plunger lift system over the other available options. These can include:

  • Avoids Gas-Locked Pump Issues
  • Conserves Formation Gas Pressure
  • Decreases Gas/Oil Ratios
  • Decreases Lifting Costs
  • Enhances the Ease of Operations
  • Improves Production
  • Lower Installation and Operating Costs
  • Produces with a Lower Casing Pressure
  • Prohibits Water Buildup
  • Scrape Tubing Paraffin
  • Utilizes Electronic or Pneumatic Controllers

However, it is important to remember when utilizing a plunger system, you should use a gauge ring (with the identical size as the mandrel planning to be used in the plunger lift system) to run down the well. This will help to pinpoint any issues that could arise, preventing the plunger from  being able to free-fall within the tubing.

Avoids Gas-Locked Pump Issues

When working with a high gas producing well, mechanical pumping units (unlike plunger lift systems) have a tendency for the pump to gas lock; thus preventing the well from producing.

Conserves Formation Gas Pressure

As soon as the plunger appears at the bumper housing on the surface, the well’s flow line is shut in, preventing any additional gas accumulation from flowing to the tank battery and gas system. Since the gas pressure is required for the well to continue to produce, conservation of formation gas is essential to the longevity of the well; and is therefore, one of the most outstanding perks of utilizing a plunger lift.

Decreases Gas/Oil Ratio

Depending upon the oil field, the production may be regulated by the amount of gas produced along with each barrel of oil. Due to this, it is essential to retain as much gas in the reservoir as possible. Plunger lifts are a great option for reducing gas production, and increasing oil allowables; which in turn dramatically extend both the oil production and the life to the reservoir.

Decreases Lifting Costs

Plunger lifts have one of the lowest lifting costs out of the various artificial lift systems. This is due to the well self-supplying the gas pressure required for operations; even the more complex electrical system options require very little power, and can easily be supplied using a solar panel.

Enhances the Ease of Operations

In general, plunger lift systems are very simple and basic to operate; and with new developments in technology, even the more complex systems are becoming easier and easier to operate. Technological advances in electronic miniaturization and personal computers have increased so dramatically, controllers are able to perform job functions almost to the point of making the decisions.

Improves Production

While productivity testing can vary due to a wide variety of parameters, plunger lifts are beneficial in determining the best production parameters to follow. For instance, often times by lowering the amount of fluid raised, and lifting more frequently; productivity can increase.

Lower Installation and Operating Costs

In most situations, plunger systems cost less to install, maintain, and operate than any other type of artificial lift systems.

Produces with a Lower Casing Pressure

Most plunger lifts permit well flow production even with less than 100 pounds of casing pressure. The plunger remains at the bottom of the well until ample lifting pressure has built up; then a signal is sent through the casing pressure to the surface to open the flow line valve.

Prohibits Water Buildup

When the productivity of the well is generated by choke control and lifting pressure, the well flow is minimal to the point where the well barely flows. However, since water is heavier than oil; the gas and oil have a tendency to flow back down to the bottom of the well with the falling water. This water buildup can cause a well to become waterlogged, which requires the well to stop flowing until the water has either been blown or swabbed off. A plunger lift system does not have this water accumulation, as the plunger lifts the water along with the oil during every trip to the surface.

Scrape Tubing Paraffin

During each cycle as the plunger travels within the tubing, the plunger acts as an outstanding wiper for eliminating the paraffin clinging to the tubing. The paraffin vacates the formation suspended in oil; and as the temperature of the wellbore drops, the paraffin emerges from the solution and deposits into the tubing. The plunger is also great for removing any soft scale.

Utilizes Electronic or Pneumatic Controllers

Automated controls help to aid in a more precisely controlled pumping time for the well, thus allowing a more energy efficient option, and reducing the amount of lost gas.


Plunger Lift Options

In all, there are five key plunger options: brush, flexible (See Figure 5), metal pad, solid, and wobble washer.

A Lease Pumper’s Basic Guide to Plunger Lifts

Figure 5. Examples of Plunger Options Available (McLean & Sons, Inc.)


Brush plungers comprise of a brush segment (which depending upon the brush segment, has the possibility of being replaceable) and a mandrel; with the over-sized brush segment (in regards to the internal tubing diameter) creating a sealing mechanism. This type of plunger is a particular good choice for wells subject to tubing imperfections and/or sand flowback.

Cleanup Plungers

In Figure 5, there are a variety of plunger types pictured. Among these is a cleanup freefall plunger with fishing neck (the fishing neck allows for easier retrieval if the plunger gets stuck in the tubing). This type of plunger is utilized to handle formation sand, frac sand, scale, and other materials. Once the well has cleaned itself, the cleanup plunger is usually replaced by the expanding blade plunger.


One of the newest plungers to hit the market, this type of plunger has a flexible mandrel to help with  coiled tubing and deviated hole applications. This new feature is available for both articulated cups and blush plungers. Flexible plungers can be found in a wide range of sizes, typically between ¾ inch to 2 ⅞ inch. Often times flexible plungers are used in standard tubing string consisting with crimps (or bends) to help reduce the need for pull tubing.

Metal Pad

Unlike other types of plungers, metal pad plungers have multiple spring activated metal pads that adapt to fit the internal tubing diameter. This style of plunger can have one or several sets of these pads arranged into a variety of different patterns and designs. When properly sealed, metal pad plungers offer the highest quality mechanical seal.


Solid plungers are solid steel cylinders that have either a grooved or smooth surface. When gas tries to travel around the plunger during the upward decent, it will have to have a velocity far greater than both the liquid and plunger load; and as the gas travels along the plunger it wipes the tubing clean of any liquids, helping to diminish liquid fallback.

Wobble Washer

Wobble washer plungers were formulated to keep tubing free of salt, paraffin, and scale. These plungers consist of shifting steel rings or washers fastened along a solid mandrel. As the lift operates, the washers rub the tubing clean, getting rid of all the unwanted products before the possibility of crystallizing.


Configuring Plunger Lifts

Plunger lift systems can be arranged in a wide variety of ways to meet the needs and wants required for each individual well. By matching the specific components with the proper controller settings for the well conditions, the lease pumper can maximize the overall well efficiency.

As you can see in Figure 6, just below the oil well bumper housing, arrival unit, and catcher, is a full opening gate valve. This specific design used a solar panel for power (which was located to the right of the image, just out of sight of the picture). The casing valve contains a pressure gauge and a connection supplying pressure to the controller. The line that controls the shut-in of the flow line is located just off the right of the bumper housing.

A Lease Pumper’s Basic Guide to Plunger Lifts

Figure 6 – Example of a plunger lift wellhead showcasing the arrival unit, bumper housing, catcher, and controller. (McLean & Sons, Inc.)

Elvis Has Left the Oil Patch

Okay GreaseBookers, I know that most of us love our dogs.

Since I have been in the oilfield, I have met only one person who did not like a dog in a pumping truck. It happens to be the man I pump for now – although unless there is a large rain (not likely where I live) I usually use my own pickup. There’s a story that goes with this…and you will hear it later in this blog.

The point is while there are many liabilities to being a pumper, including people thinking we just drive around taking meter readings and that we are fundamentally dumb, there is at least one benefit to the job aside from a decent paycheck. Many times the company allows us to take our dog with us pumping.

Elvis Has Left the Oil Patch

For me, this particular benefit fell into the top three benefits of the job as a full-time company pumper. I mean, let’s face it; where else can you go to work where you can take your best four-legged friend with you? Also, where else can you avoid having to work with people most of the day? But that’s another column isn’t it?

All that said, I learned in the first year of my life as a pumper working in Perryton for Chaparral Energy, this freedom to take my dog also held its liabilities. And I am not alone in that discovery. Most of my pumper friends who toted a dog along also discovered these problems.

My best friend, Evelyn discovered the hard way several times what it means to carry a pet along on the work day. And just a note here, in her 38 years in the oilfield she has been known to carry everything from a pet raccoon to a pet bobcat, two German Shepherds at separate times, a Pitbull cross, two Blue Heelers at separate times and now a ginormous Mastiff named Giget and a whiney, neurotic Blue Heeler named Norman who has an anxiety disorder.

I, on the other hand, had one pumping dog. Her name was Nipper. She was a Cairn Terrier and I soon began referring to her as a “terrierist” because she literally terrorized me at times.

Nipper liked to find long dead animals and eat them and then puke it all up into the console of my pickup. She also found a pile of fresh, human poo after a work-over rig had been on one of my wells and rolled in it.  People who don’t know what a Wheaten Cairn Terrier looks like, they have very long, blond hair.

So the day I allowed Nipper to ride with me in my current boss’s brand, spanking new pickup (about three years ago) I didn’t realize what kind of a day it was going to be. The whole reason I took his truck was that he was out of town on a vacation and the lease roads were muddy. My truck, Ol’ Greenie, doesn’t have four wheel drive, see. So sensing a good day, Nipper bailed into my Boss’ 2014 (with velour seats…I know…go figure).

Anyhoo, everything was fine but that particular route is really uppy-downy. Lots of hills. And so Nipper got sick and puked in the console and on the seats before I could say Jack Sprat. Before he came home I cleaned and cleaned. I felt that his pickup was better than when he bought it when I left it in his drive, ready for him to start his next working day.

He called me on the phone around 10 a.m. I answered, confident that he was just asking about his wells. “Hello?”

“I found a long, blond hair in this truck. Did you have your dog in here?”

“No! Of course I didn’t,” said I. “Where’d this hair come from,” he asked.

“Well, the truth is, one of my best friends wanted to go and watch me pump and she has long, blond hair. I sure hope you don’t mind,” said I.

“Well, as long as they don’t get out at the well site,” he said.

Later that month, he took me to show me a couple of new wells he had acquired. He stared into my face. “What was your friend’s name?”

“What friend?”

“The one who left the long hair in my truck.”


“It was your dog wasn’t it?”

“I was biting my hand by now and I looked at him guiltily and nodded.”

“I knew it.” He just laughed and told me not to do it again.

Since then he’s purchased another new pickup. Oddly, I haven’t ever been in his pickups since. Even in the mud, he lets me take Greenie. Hmmmm. I wonder why?


GreaseBookers, this has been a tough year for everyone. In Northwestern Oklahoma, pumpers, farmers, residents – we have all struggled to push through not one but two disasters. First we had an epic ice storm that kept many well sites inoperable for more than one month and then we have had one of the single most devastating fires in history in my area. We have lost more than 1 million acres up here and easily over 1,000 cattle. There has also been damage to oilfield assets and again, the power has been affected. Ranchers have, in some cases, lost their entire businesses. It will be a tense and heartbreaking year ahead for these people.

So I felt I would write a little something that just took our minds off of the awfulness for a moment. And to that end, I decided writing about our love of living things seemed appropriate, given the tragedy we have suffered of late.

Those of us who haul our dogs with us pumping, know what a comfort they can be when the days get long.

But I digress. When I met my best friend Evelyn, she told me of some of her pet hauling disasters and yet for some reason I failed to take her seriously when I got into the business. I had to learn on my own I guess.

Principal among her animals was Elvis, her most beloved dog – a beautiful German Shepherd. In a flash one day Elvis chased a rabbit under the weights of a pumping unit and was badly injured when the weights came down and crushed his hip.

He lived through that accident though, with a combination of effort from me and Evelyn, each hauling him back and forth to the vet for treatment.

For several years after that Elvis trotted behind Evelyn everywhere she went on the location.

I took him with me a time or two and I can still hear the gentle thud, thud, thud of his feet falling in the dry Oklahoma dust behind me. And there was the cadence of his panting, huh, huh, huh, huh, right beside me as well, as I worked on my own locations.

For some reason, I never felt alone with him around. The other benefit of having Elvis around was that he was my dog Nipper’s only true friend. Nipper had some sort of mental disorder and she hated everyone but Elvis. In fact, Nipper was so in love with Elvis that when she would bolt from me and be running, totally out of control down the lease road after a coyote or rabbit, the only thing I could holler was “Elvis” to get her back. When she heard his name, she would come screeching to a halt and turn around and come back because she thought he must be here or I wouldn’t be calling him.

Just a note here, this only worked about three times before she realized what a liar I was.

Anyhoo, Elvis was like having a human being with you. He would look at you with his golden eyes and tilt his head when you talked to him. I expected him to say in English, “And then what happened?”

If Elvis wanted you to notice something he felt was important on the location, he would come over and place his huge front paw on your arm and pull at you to follow him.

But most notably, Elvis loved to play the game Hide-and-go-Seek. I’m not kidding.

This is how this went. I would set him down with his back to me somewhere and tell him to stay and I would go find a place to hide really well. Then I would call and tell him to find me. And he would look and look until he’d find me. When he did, he would be so excited and I would laugh that kind of laugh you only have when you are really having fun.

Elvis and Evelyn were inseparable. Since the loss of her husband Wayne in 2005, Elvis had become her helper – her confidant. He was whose furry neck she cried into when the people in Evelyn’s life had grown weary of her grieving for her husband of 24 years. Elvis understood, there is no real time limit for deep grief.

In the evenings, after a full day of seeing oil wells, Elvis was who would gladly run around in the house, playing Hide-and-go-Seek with her too. The two would put on a country music CD and Elvis, who was as tall as Evelyn when he stood on his hind legs, would stand up and the two would dance like crazy.

Elvis had a cat too. Her name was Savanna. Savannah slept literally in the leigh of Elvis’ neck, where his jaw met his neck.

It was Thanksgiving of 2013 and I was pumping wells but Evelyn had left to go see family. Earlier that day she told me Elvis wasn’t feeling good and would I go to her house and check on him . He had just thrown up a couple of times and while that didn’t seem too odd for dogs that sometimes eat myriad dead animals while working with us, it still concerned her.

When I got there, I could see right away, something was terribly wrong. Elvis was standing, leaning forward and could hardly move. He wouldn’t even look up at me. I could sit down, he couldn’t lay down. He was in misery.

I called her and told her, he had gotten much worse. She dropped what she was doing and made the nearly two hour drive back and rushed him to the vet.

The day after Thanksgiving, Elvis died. We are not sure what killed him and we will never know. We fear he might have gotten into someone’s garage and possibly drank some coolant.

He was so well loved that several people in the community came out for his little burial service. I brought his best friend, my dog Nipper who was pretty upset. She went to see her friend’s body and sat next to him and shook uncontrollably.  As much as I try, I can’t unsee that. Nipper was never the same after that. Something was just wrong with her and she ended up dying a year later.

And as we all said our goodbyes to Elvis that day, one thing was so clear.

The oilfield industry out here in the Panhandle was somehow indelibly changed that day and was the worse off for it.

Because, Elvis had left the oil patch.

~ Rachael Van Horn aka “Wench with a Wrench”

A Lease Pumper’s Basic Guide to Producing Flowing Wells

Flowing wells are created when the water and gas produce a pressure forcing the liquid from within the rock through any openings (such as a well). While the pressure may be powerful enough to push the liquids to rise up when created towards the surface; and as time progresses, this pressure will decrease, and lift systems may need to be installed for the remaining life of the well. However, before a lease pumper begins to think about bringing the oil up from the well, you need to consider the different production regulations.

Production Limits

Typically lease operators prefer to obtain as much gas, and/or oil, as possible to maximum revenue. However, while maximum productivity rates can provide more upfront profits, it isn’t always what’s best for the economy, environment, reservoir, or any other considerations aside from the lease operator’s financial interests.

To help ensure all factors are considered by the lease operator, a variety of agencies were created for gas and oil production regulations. For instance, local or state examples may include: Oil and Natural Gas Commission, Petroleum Commission, Environmental Protection Agency, or other similar names.

The goal of these agencies is to aid gas and oil producers in comprehending any problems or concerns with the reservoir. One of the main responsibilities of these agencies is to monitor and control the production of oil and gas reservoirs.

Often times, they set limits for these natural resources. Production limits (more commonly known as allowables) help to prohibit abuse through the subsequent guidelines:

  • Safeguarding Reservoirs

Production limits and regulations help to provide protection for the reservoirs and to ensure their lifespan and durability. Plus, using the proper production practices have been known to extend the reservoir’s production life, and in a higher closing production revenue.

  • Safeguarding the Rights and Freedoms of All Operators

Production limits help to preserve the lives of all the reservoir wells. Monitoring and controlling the volume of gas or oil a well can produce, preserves the bottomhole pressure. In other words, the operators will be able to postpone the use of lift systems, and prevents reservoirs from exhausting their resources erratically or too quickly. This is especially true when there are multiple lease operators who yield from the same reservoir.

  • Helps Reduce Coning

Gas and/or water coning is a serious issue many reservoirs face with producing wells. It generally occurs in an oil zone with either an: overlying aquifer, underlying gas cap, or both. When coning takes place, the zone containing the gas or water moves upward to the wellbore in the shape of a cone.

When this situation occurs, the cone will remain in place while productivity has ceased for the well. However, once the the valve is open, it will create higher gas productivity; and thus water will sweep into the well. As the water rushes upward, it forces out the oil; but these little variances in weight will take years for the well to naturally go back to the well’s initial state, and for lease operators to decrease production volume to a fragment of the normal productivity rate.

  • Reduces the Effects of Inferior Production Methods

The field operator, lease pumper, owner; it doesn’t matter who was at fault for overproducing the well. When a well is damaged, the entire company pays the price.

Therefore, the advised practice for production is to avoid overproducing the well by over 10% of the well’s daily productivity potential. In other words, if the well loses one day of production; it will take ten days for a single day’s loss to be recuperated. If this occurs, the well could still be short of the productivity standards by month’s end.

Nevertheless, this is still more appropriate than harming the capability of the well, as overproduction will result in a constant shortage.

Sometimes lease pumpers may come across other pumpers boasting of their skills for compensating for lost productivity by secretly overworking different wells. This helps by maintaining a full overall production rate after all production issues are rectified. While supervisors are typically pleased with the numbers, these results only shorten the overall life of the well and decrease their long-term potential.

Wells with Multiple Operators

The U.S. is among only a handful of countries where multiple companies, governments, individuals, states, and/or trusts can own the mineral rights.

Due to this, productivity procedures from one operator can cause extraordinary productivity issues for lease operators of nearby wells; and periodically, extremely severe declines can kill nearby wells.

In other words, they will no longer be able to yield gas or oil. This is due to the hydrocarbons being drawn from the furthest reservoir regions where the counterbalance wells might be.

Whenever a reservoir is off-balanced, it can cause:

  • the higher elevated wells to only yield gas
  • the lower elevated wells to only produce exceedingly high amounts of water with extremely small amounts of oil, and
  • the middle elevated wells to yield large amounts of oil, with extremely small amounts of gas, and little to no water.

When this occurs, a variety of issues could arise; such as:

  • a lease operator in higher elevated regions (who yields large amounts of gas) – the reservoir would lose pressure, and thus the wells with high amounts of oil would eventually no longer yield oil.
  • a lease operator in lower elevated zones (who yields high volumes of water) – can revitalize the lower the formation pressure and the water drive; which in turn can aid the water table in increasing productivity from large oil production wells rapidly plummets off. A large number of lawsuits have been filed over these type of issues; and the best answer for this is for any and all operators to agree to a productivity schedule for the entire reservoir in advance, this ensures the most effective, efficient, and beneficial wells for all parties involved.

Natural Well Flow

For a natural well flow, a well must have ample bottomhole pressure that is powerful enough to force the liquid to surge from within the rock formation, up to the surface, and into the stock tank; all without any external or internal support.

As the gas and oil are taken, water can fill the void left from the hydrocarbons as a result of the region’s lower pressure. This process typically takes years to transpire.

In order for a well to flow, there must be a powerful enough bottomhole pressure to:

  1. lift the line of fluid through the tubing to the wellhead,
  2. force the liquid throughout the entire flow line to the tank battery, and
  3. push the fluid into a pressurized differentiating container; all while maintaining enough pressure for the liquid to push through any additional treatment tanks, ending in the sales or stock container.

To determine the proper amount of pressure, most lease pumpers use a common guideline stating if a mineral well contains a standing flow of fluid, and a wellhead pressure of 100 pounds;  there will be ample enough pressure for natural well flow.

The greater the pressure, the larger the maximum yield capacity and the easier the well flow.

Producing Flowing Wells

Figure 1. An example of a wellhead for a natural flowing well. (ABB Vetco Gray)

To prevent the surge effect from occurring, packers are often installed around the tubing string base in the well flow annulus. Without a large bottomhole pressure or a packer, the flowing well will have inconsistent productivity.

For example: if the flowing well did not contain a packer, and mainly produced gas with little to no fluid amounts for small intervals of time; the majority of the fluid within the casing and tubing will originate near the tank battery.

Once the casing has depleted of fluid, the gas pressure within the annulus will splinter throughout the entire area and inside the tubing perforations. The abrupt increase in gas will remove the majority of the fluid within the well, all the way up to the tank battery.

However, once the loss of gas occurs, there will be a significant drop in gas pressure in the casing throughout the entire system. Once this pressure depletes, and the fluid starts to once again pool in the well’s base, the casing pressure operates as a flow buffer or pressure surge tank.

In order for the well to flow again, it will require the casing pressure to improve to a level that will grant the well the ability to cultivate enough bottomhole pressure. This unpredictable well flow activity is often reduced and/or eliminated by situating a packer near the base.

However, flowing wells with extremely high volumes generally do not have packers, and can be produced throughout the casing.

Packers are removed once a well is no longer flowing naturally. It is then transformed from a flowing well into a pumped well.

Once the packer is removed, and all is said and done, the casing valve will be constantly open to the tank battery to remove the formation of bottomhole pressure. Near the wellhead, a check valve is positioned to prohibit oil from being forced out of the tubing and flowing back down into the casing.

This allows the bottomhole pressure to deplete to the weight of the separator pressure, the flow line resistance, and the weight of the fluid line within the annulus.

However, the lease pumper must constantly be mindful of any and all situations that could change this delicate harmony; because even the smallest changes can affect the well’s oil productivity.

For instance, if the lease pumper were to make a five pound increase to the separator pressure; then the formation pressure will also have been increased by five pounds, and the oil productivity will consequently diminish. Once the gas production has reached the trace classifications, casing valves can be exposed to the air and atmosphere.

Generating Flowing Wells

Generally a flowing well contains a Christmas tree comprising of: a wing valve, a variable choke valve, a master gate valve, a positive choke, and a pressure gauge; with each Christmas tree containing at least one check valve.

To fully understand how this works, make sure you educate yourself in the basics of each area.

Producing Flowing Wells

Figure 2 – An example of a typical flowing well Christmas tree configuration containing a: check valve, flow line, master gate valve, wing valve, and variable choke.

  • Casing Valve

Whether or not a packer is utilized in the annular space at the base of the well, a casing valve (a multiple round opening gate valve) is almost always fastened to the Christmas tree and to the flow line towards the tank battery. This allows the casing valve to be bled down, closed, opened, or even to permit the flowing well to advance to the casing and tubing. In cases where packers are utilized, this connection isn’t used until the packer is either loosened or completely removed.
The casing valve can generally tolerate high pressures; and similar to wing valves, do not have to use a full opening. This type of valve is often utilized to help determine if the tubing or packer has developed a leak.

  • Check Valve

Check valves are generally inserted as soon as the flow line vacates the well, a second one is typically placed near the well’s tank battery; or to be more precise where the tank battery separator head meets the well’s flow line.

Some lease operators prefer to have the check valve directly behind the wing valve, yet still in front of the choke valve; while others prefer to place it close to the ground, near the tank battery.

Having the optional check valve along with the ground level option, allows for the Christmas tree and riser pipe to be easily eliminated when they are no longer needed. Depending on the operator or company, all three may be installed.

  • Master Gate Valve

This type of valve is made of a superior grade valve. It has the ability to open up to match the inside tubing, which allows any specialized tools that may be required to pass through. Master gate valves require the ability to hold the entire pressure of any anticipated events that could occur to ensure well safety. This valve typically remains unblocked, and it is not utilized as a butterfly valve (or throttling valve) for controlling production flow.

  • Positive Choke

In most cases, the Christmas tree atop the well (see Figure 3) contains the positive choke, or it is located at the inlet manifold immediately in front of the first separating vessel (see Figure 4). However, many operators are known for using positive chokes at each site.

Producing Flowing Wells

Figure 3 – Example of a positive choke situated atop the wellhead.

Producing Flowing Wells

Figure 4 – Example of a positive choke placed near the tank battery.

An unmistakeable advantage to using the variable choke instead of a positive choke is the ability to easily change the settings. Positive chokes can easily regulate the flow, allowing the well to match the proper daily productivity levels.

This is accomplished utilizing a correctly sized flow bean. As shown in Figure 5, these beans are offered in 74 different sizes and are created to permit an increase in flow from anywhere from 5-10%.

Producing Flowing Wells

Figure 5 –  A chart showcasing the various flow bean insert sizes available to use with positive choke valves. (Cooper Cameron Valves)

  • Pressure Gauge

This type of gauge is made of a high-pressure steel. It is typically situated just atop of the well’s master gate valve. It will also have a ½ inch needle valve (including gauge), and a tapped bull plug.

Each of the high pressure needle valves can be used in 90 degree (ell) and 180 degree (straight) options. This allows the worker to read the valve pressure from a favorable angle.

Producing Flowing Wells

Figure 6 – Example of a valve with pressure gauge located atop the well.

  • Variable Flow Choke Valve

This type of valve is generally a type of extremely large needle valve. It has a calibrated opening for workers, so the device can be customized using 1/64 inch sized measurements.

Variable flow choke valves are very expensive; and are typically made of stainless steel, steel, or tungsten carbide steel. Since the valve requires the ability to tolerate the high speed flow of the various abrasive materials, a high quality steel must be used. In most cases, this will help safeguard against damages for several years.

Producing Flowing Wells

Figure 7 – Example of variable choke valve with a unibolt (or wellhead) design. To help  illustrate the flow path and quality of the steel, a section of the device has been removed. If you look closely, you can see where the two union joint halves meet; it contains a seal ring like the ones you would see on a wellhead section, and/or a Christmas tree. This allows the seal to withstand high pressures of up to several thousand pounds. (Cooper Cameron Valves)

Due to financial reasons and the productivity volume, ¾ inch valves are most commonly used. However, high productivity wells typically require variable choke valves of 1 inch or more.

Each valve is carefully marked to identify the specific opening size. You can indicate the size of a fully open valve by the last number. For instance, if the valve is 32; it is 32/64ths or ½ inch.

It is important to keep up with all aspects of the well. For instance, if there is any paraffin or salt water in the oil, it can cause the opening to clog. Therefore, it is recommended to periodically have the choke open to higher settings for short intervals; followed by periods of opening and closing it back up. This allows the well flow to clean out the seat and eliminate any buildup gathered within the variable flow choke valve.

On occasion, this type of valve can be set to productivity speeds permitting water to collect at the base of the well by dropping back down through the tubing string. As the water pools, it will slowly start to prevent the oil productivity; and at times, can even destroy the well.

When this occurs, it will be necessary to use a swabbing unit to swab from the tank battery to the water blanket in order to obtain proper flow. Increasing the flow rate in the choke by widening the opening for short intervals can help to prevent this issue.

  • Wing Valve

A wing valve can be either a multi-round opening valve or a quarter-round opening. Often times  lease operators will utilize plug valves; but in recent years, the ball valve has become increasingly popular due to its operational ease, and great economical value.

However, wing valves are customarily used to shut a well. This is due to their ability to easily read the tubing pressure.

Highly Proficient Lease Pumpers and Stripper Wells

Whenever bottomhole pressure decreases, there will always be a corresponding reaction (or downturn) in gas and oil productivity. During this lower productivity stretch (or as the reservoir hydrocarbons near exhaustion), the well is commonly referred to as a marginally producing well, or a stripper well.

As the stripper well’s productivity diminishes, lease operators will be required to determine if an artificial lift system should be utilized.

In most cases, a flowing well’s maximum lifespan (before it requires an artificial lift) is determined by the lease operator. One of the most vital skills for operators is the competence for making the best decisions for the productivity and longevity of each well during the marginally productive period before installing the artificial lift.

Some lease pumpers have the experience, interest, patience, and ability to perceive what is occurring downhole that allows them the ability to generate productivity months (or even years) longer than others; while other may never accurately establish this ability. Skilled pumpers know it takes time and experience to understand rocking a well. (A process where you bleed pressure from a depleted well. First from the tubing, then the casing, and so forth; so that the well may come back to life.)

This ability can not only create satisfactory productivity levels with lower down time; but it can also extend the lifespan of the flowing well before it requires an artificial lift.