Tertiary Stage Recovery In Oil & Gas Production

The third stage of enhanced recovery from an oil and gas production well begins when after pressure maintenance and water flood operations have already been in place. The addition of a second force for enhancing oil production progresses a well from the second stage of recovery to the third and final stage. While it’s the last stage, it may often be wise to install both second and third stage recovery systems as early as is practical. At that point, the well is most likely still producing at high enough levels to pay for the equipment and can be used to extend the life of the well.

There can be a wide range of forces used for producing oil, but there are a few that are used commonly. Water and heat can be used together to create steam. Water and CO2 might be injected, or slugged, alternately into the well, as could water and polymer chemicals. Water generally serves as one of the two forces, as it’s easily available and well understood.

The term ‘tertiary recovery’ is an older term that’s not as popular as it once was. As mentioned above, techniques that were once considered part of tertiary recovery may be installed and sued at any point in the well’s life, so the distinction is not as meaningful as it once was.

 

Miscible Displacement

These methods involve injecting a fluid or solvent into the reservoir. Miscibility is the measure of two substances tendency to mix. Water and oil are generally immiscible, meaning they do not mix. Miscible displacement methods use a fluid or chemical solvent that will mix completely with the oil and help release it from the rock formation. A second force, generally water or gas, is injected after the solvent to force it into the formation and to sweep the solvent and oil together to the producing well.

A few of the different solvents, gases, and fluids used for miscible displacement include refined hydrocarbons and hydrocarbon gases, liquefied petroleum gases, CO2, and inert nitrogen gas. Inert gas has become increasingly popular.

 

CO2 Injection

CO2 injection is the most form of miscible displacement. Carbon dioxide is injected into the reservoir and followed up with a slug of water. The CO2 is swept through the formation, and recovered from production wells. The CO2 can be separated from other gases produced from a well and reused. The CO2 will work as a solution gas drive in the reservoir, as it is soluble in both water and oil and will therefore cause the fluids to swell. This increases pressure which results in an increase in production. This is more efficient than natural gas or LPG gas.

While more efficient, using CO2 for miscible displacement does have a few drawbacks. When CO2 and water are used together, the mixture will result in carbonic acid, which is extremely corrosive. When injecting CO2, the wellhead will usually need to be prepared by installing stainless steel bolts, seals, and other fittings. It may also be difficult for CO2 to mix with heavier oil elements, which can reduce the technique’s efficiency.

 

Inert Gas Injection

Injecting inert nitrogen gas is similar to injecting dry natural gas. Inert gas may need a higher pressure than natural gas to best mix with emulsion, but it can be swept through a formation more than once.

 

Thermal Methods

Thermal methods includes different techniques for using heat to increase production.

 

Steam Stimulation

This term refers to injecting steam down a well, and then recovering it directly from the same well. The same general process can also be referred to as huff and puff, steam injection, or steam soak. The steam is injected over a number of days, generally between a week and a month. The well is shut in for a few days, which allows the steam to heat the reservoir. The heat thins the oil, which eases flow of the oil through the reservoir.

After the well is returned to production, the oil is allowed to flow until the rate slows to the point that the process needs to be repeated. At this point, the operation will most likely be changed to steam injection.

 

Hot Water Injection

Steam and hot water flood work essentially the same way as water flood or gas injection; the steam is injected and then sweeps to a second well where it is produced with natural gas and emulsion. As heat spreads through the formation, the oil expands which leads to an increase in production.

Steam and hot water injection make up about ⅕ of enhanced recovery operations. Wells for flooding steam require about 5 acres of land, and the technique can be used with reservoirs from 10 ft to 5,000 ft deep. Hot water can also be used, but is less efficient.

 

In Situ Combustion

In situ combustion is the practice of lighting a fire within a formation, burning the oil and using the heat generated to increase production. Injecting compressed air drives the fire across the reservoir. As the fire moves, the oil’s viscosity drops which allows the oil to expand. That can lead to an increase in production.

In situ combustion can take 2 forms, either forward or reverse. With forward combustion, the fire is ignited near the air injection well and then driven across the formation to the production wells. With reverse combustion, the fire is first driven away from the initial air injection well to producing wells. After a certain point, the direction is reversed and what was initially the injection well becomes a production well.

In situ combustion may not be economical in every case. Variations on this basic process, called wet and partially wet combustion, are being developed to address these issues.

 

Chemical Methods

Methods of tertiary recovery that use chemicals are used in only a few cases. The chemicals are often too expensive too be economical, and the other equipment can also be quite expensive. Using the chemicals also comes with some risk.

 

Surfactant-Polymer Injection

Surfactants are chemicals that breaks down the surface tension between two substances. In this case, the chemicals are used to break down the interfacial tension between water and oil. Surfactants may also be called micro-emulsions, soluble oil, or micellar solution. The surfactants are followed up by a polymer injection, which provides mobility control.

This particular method of enhanced recovery is not as efficient as others, as reservoir rock can absorb the surfactants, and it can also become more difficult to mobilize oil.

 

Polymer Flooding

Polymers have large molecules which can increase the viscosity of water. This can make water flooding operations more efficient. Polymers used in this technique are generally either polyacrylamides or polysaccharides.  Polyacrylamides are used in concentrations from 50 ppm to 1000 ppm. This polymer decreases the permeability of reservoir rock, which can decrease the mobility of injected fluid. Polysaccharides, on the other hand, do little to reduce permeability of rock but increase the viscosity of fluids. Using polymers can increase production over the long term.

 

Alkaline Flooding

Alkaline flooding raises the alkalinity of the water injected into the reservoir, which can improve production. Alkalinity is measured by pH. A pH of 7 is considered neutral. A substance with a lower pH is acidic, while a pH of 7 or higher is considered an alkaline, also called a base. A fluid with a pH of 12-13 is the most you’ll want to use.

The cost of alkaline flooding is fairly low compared to some of the other techniques. The increase in production is not a large as some other tertiary recovery methods, but the cost is low enough that profits are higher.

Second Stage Recovery Methods For Oil & Gas Production

There are three general stages of recovering oil and gas from a well. The first begins as soon as the well is completed, and can include wells that flow naturally as well as those that use some form of artificial lift. The second stage recovery begins when water or gas is injected into the formation to improve production. It’s in this stage that enhanced recovery operations really begin, with water flood and gas maintenance becoming a big part of driving production.

When using the term ‘flood’ in this context usually means that a fluid or gas is injected in one well so it can push oil toward another well. The driving gas or fluid is recovered at the production well. Gas maintenance refers to the practice of re-injecting gas into the formation to keep the reservoir’s pressure high.

Water flood and gas maintenance practices can be complex and difficult to control, but ultimately are worth the effort. It’s possible that efficient use of these techniques can double the production volume of a well over its total production life.

 

Gas Injection

Gas injection, also commonly referred to as pressure maintenance, is used with reservoirs that are at least partly gas driven. The gas that is produced from the well is dried, compressed, and injected back into the reservoir to continue to drive oil flow.

Gas separation is a standard part of the tank battery’s function. When using gas injection, the gas should be run through a gas plant or scrubber, which will remove all the distillate and other hydrocarbons. At this point, the gas can be compressed prior to being injected.

A gas injection well is setup along the same lines as a water injection well, which is described in more detail below. The gas injection setup will also include a safety valve high in the tubing string, near the surface. The valve will protect the well if the surface injection line breaks, which could lead to a blow out.

Second Stage Recovery

Figure 1. An example of a gas injection well.

Gas injection is effective but it also faces some problems. The most obvious is that natural gas is very light, and so it tends to rise in the reservoir. In many cases, that may mean that it rises above the level of fluid in the reservoir, and therefore doing only a little to drive production.

The second problem is that oil is much heavier than gas. While the pressure the gas exerts can push oil out of the well, it’s also possible for the gas to push through the oil, breaking into small streams of gas that does a poor job of driving it to the well. Gas also can have a hard time combining with the oil in the formation, which reduces the effectiveness of gas injection; in some cases, it can make the oil heavier and less likely to flow to the well.

 

Water Flood

Water Flood is one of the earliest methods of enhanced recovery, and one that has become very widespread. In addition to providing an additional driving force for oil production, it also provides an easy means of disposing of water produced from the well. Water flood has since been combined with other methods, such as slugging, and water injection will continue on most wells into the third phase of recovery.

Second Stage Recovery

Figure 2. An example of a well used for injecting water back into the reservoir.

There are a few preparations that need to be made before a well can be used for water injection and a water flood operation. The casing should be tested for leaks, and packer fluid should be used to isolate the annulus space. This process will often have to be approved and observed by a regulating agency. Pressure in the casing and tubing should be monitored to check for leaks.

Second Stage Recovery

Figure 3. An example of a wing valve, commonly used in water injection operations. (courtesy of Baker SPD, a Baker Oil Tools company)

The wellhead should also be properly setup for water injection. A full master gate opening will typically need to be installed on the tubing. In Figure 3, you can see an example of a wing assembly. This includes a screen to catch solids, a meter for measuring the water volume, a valve and gauge to regulate pressure, and a check valve.

In order for water flood procedures to be as efficient as possible, the water should move in a solid wall through the formation. However, this rarely, if ever, happens perfectly. The water’s own weight will often pull the leading edge down, missing large amounts of oil that are therefore not pushed toward the producing well. Water may also not move through the formation in an unbroken wall, and instead break into smaller streams.

In some cases, you’ll want to collect the separated water from several wells or tank batteries so that it can all be injected in one well. Wells used for this purpose will often require some specialized equipment, including larger than normal holding tanks, water filters, a pump capable of handling large volumes, choke valves, and more. Some systems use a lower pressure and are simpler to operate.

Oil may sometimes accumulate in lines or tanks used for water injection. When this happens, the solution is fairly straightforward; simply add a skimmer tank ahead of the injector. This is a simplified wash tank, where oil rises and flows out through a higher opening in the tank, while water is drawn from near the bottom to be injected.

Second Stage Recovery

Figure 4. An example of a low pressure water injection setup.

Water injection usually will happen on a set schedule, and if properly setup doesn’t need much watching. That makes it a prime candidate for automation, which can simplify the water injection system dramatically. If the system is small and there’s little chance of it overflowing, you may not even need a backup system.

Second Stage Recovery

Figure 5. An example of an automated water disposal system. The pictured setup includes backup controls as a safety measure.

First Stage Recovery In Oil & Gas Production

Wells have three basic stages of production, the first or primary stage, the secondary stage, and the tertiary stage. Each stage is distinguished by the type and variety of recovery methods used. The primary recovery starts as soon as a well is completed and begins to flow, and continues until water flood or gas injections begin.

There are a wide range of methods used to improve production in the first stage recovery. These can include any type of artificial lift, efforts to manage pressure down the borehole, and changes at the well, among others.

 

Altering And Maintaining The Formation

Primary stage recovery methods can include some techniques for monitoring, maintaining, and altering the reservoir formation to improve the flow of oil.

 

Allowables

These are limits on the amounts that can be produced from a well. The limits are usually placed on gas production, with the goal of maintaining pressure in the reservoir the well draws from. Producing too much gas can lead to lower pressure levels in the formation. If the pressure in the formation drops too low, it will no longer be possible to pump oil from the well.

Many wells, and therefore many companies, will draw from the same reservoir. While it’s in the best interest of all parties to maintain reservoir pressure, some operators may still choose to produce large amounts of gas. The allowable limits set by a regulating agency are intended to prevent that sort of over-production.

 

Fracking

The porosity of the formation is one factor that can limit the rate of oil production. A tighter porosity means that it’s more difficult for oil to flow to the wellbore. The porosity of a formation can be improved by by using fracturing, or fracing, techniques.

There are a range of different fracking methods. Sand fracking uses sand to force a formation open. Openings can be widened using acid and chemical fracking. Fracking is a popular technique in areas with low porosity. Heat and pressure are becoming more popular, as is other new technology like adding tracers to track damage to the reservoir.

 

Stabilizing Formations

This technique uses various methods, including chemicals, to keep sand and scale stable in the formation. This props the formation open while allowing oil to flow freely, which can prevent long term problems and allows more oil to be produced. The orientation and location of the casing and tubing perforations should be considered when stabilizing a reservoir formation.

 

Managing Pressure

It’s important to manage the pressure in the reservoir, but there are also a few ways to manage pressure at the wellhead and tank battery that can help improve production.

 

Beam Gas Compressors (compressing gas to reduce backpressure)

Oil will stop flowing from a well once the pressure of the fluid column, from the bottom of the well to the tank battery, equals the pressure from the oil in the formation. You could simply plug the well and move on at that point, but there are a number of other options to get the well flowing once more. One method is to use a beam gas compressor.

First Stage Recovery

Figure 1. An example of a beam gas compressor. (courtesy of Permian Production Equipment, Inc. )

The compressor draws gas from the well casing, compresses it, and then injects it into the flow line after the check valve. The gas reduces the pressure in the fluid column, allowing the oil to flow from the well once more.

First Stage Recovery

Figure 2. A diagram of how a beam gas compressor works. (courtesy of Permian Production Equipment, Inc.)

The compressor can be powered by the pumping unit. Some stripper or lower production wells have increased production many times over, which often can pay the cost of the compressor and other equipment quite quickly.

 

Venting Casing Gas at the Wellhead

Natural gas can be recovered from the well and used for a range of purposes on the lease, or collected for sale. However, when only small amounts of gas are being produced it’s often not economical to recover it.

While the gas may not be worth recovering, it’s still exerting some pressure down the well. By opening the casing so that the gas is vented, that pressure is relieved. At that point, the pressure from the formation may be great enough for the well to begin flowing again.

Opening the casing to the atmosphere will allow air into the casing, which leads to an increased risk of oxygen corrosion. To prevent that, a ball and seat standing valve can be put vertically in the casing opening. That prevents air from entering the casing, but allows gas to escape to the atmosphere. You can set up a hose from the tubing bleeder valve to a swage in the casing valve. That allows you to check the performance of the well. When you send the fluid back into the casing, it’s coated with oil as the fluid falls which helps prevent the oxygen corrosion.

 

Changes In The Well

There are a few changes that can be made to the well or wellhead that can be used to increase production in the primary phase of recovery.

 

Automated Control Of The Well

Automation and computerized control have become very popular for their increased efficiency. Using some specialized equipment, such as an echometer and dynamometer, the behavior of the well and reservoir can be monitored. A computer can use this information to produce from the well in the most effective way while simultaneously lowering costs. These systems can also provide analysis which can help identify problems before they become serious.

 

Moving Casing Perforations

The level of the casing perforations can have a big effect on production levels. The height of the perforations determine the level at which fluid is drawn into the well. The shape of the formation and the forces driving the well’s production. With reservoirs that are water driven, perforations that are too low will produce mostly water. Perforations that are set too high may lead to overproduction of gas, damaging the formation’s long term production potential.

 

Changing Lift Systems

Several different lift systems will be used throughout the course of a well’s production life, each selected to most efficiently produce from the reservoir. A flowing well may only use gas lift, or no artificial lift at all. As pressure drops and the well stops naturally flowing, electrical submersible lift or mechanical lift may follow.

Each lift system should be chosen to match the behavior of the well. An understanding of the reservoir and the forces that drives fluid to the well can help select the right system for each circumstance. No understanding is perfect, however, so it can sometimes be challenging to select the right system. It’s possible that wells are plugged and production ended simply because the correct method of production wasn’t tried; it’s possible for anyone, even experienced operators, to make this mistake.

 

Horizontal Drilling

Horizontal drilling is one of the most important technological advancements of the last few years. Along with a few other associated new techniques and technological advancements, it has revolutionized drilling and oil pumping. After a well has been sunk down to the reservoir, the drill can be turned 90 degrees so that the hole is drilled horizontally through the pay zone. This allows a much larger amount of oil to collect at the wellbore, which can dramatically increase production. Older wells that have been worked over using these new methods now sometimes produce more than when they were first completed. An experienced and knowledgeable specialist and accurate analysis of the lease records can improve production even further.

New methods for orienting and tracking a mud motor, and the development of a drill bit-mud motor assembly with a small bend in the middle. Together, these improvements allow a hole to be drilled down with the drill assembly having only a slight wobble. The mud motor can turn the drill bit while the tubing string is still, allowing the direction that’s being drilled to be changed with control of the assembly’s orientation. The techniques and technology continues to be improved.

 

Perforation Orientation

The location and height of the casing perforations can have a big impact on what you produce from the well, and how much. However, the relative height of the casing and tubing perforations can also end up affecting production.

 

Tubing perforations might be above, below, or at the same height as the casing perforations. There are a number of reasons for each choice, and each operation will most likely have its own reasoning. Depending on this orientation, a fluid or gas blanket can be maintained on the formation, exerting a small amount of pressure. It can also have an impact on paraffin accumulation, and how that affects production.

 

Innovative Methods

Technology in the last few years has advanced at an ever increasing rate. Horizontal drilling, as well as advancements in computer automation, has led to large improvements in production and efficiency for a number of operations.

As our understanding continues to expand, and as technology continues to advance, new methods of improving oil production are likely to become available. An understanding of the science underlying oil production, as well as the latest methods and technology, is often essential for maximizing a well’s production. This is true even with lower production or marginal wells, as small improvements can have a big effect on the bottom-line. With some developments, such as horizontal drilling, a marginal well might be brought back to higher level of production.

When considering new techniques, it’s important to keep a few questions in mind. The answers can be helpful in deciding whether it’s something that might be helpful for your own operation. The type of reservoir and its drive, the flow from the well, and several other factors should be kept in mind. It’s also a good idea to consider the equipment and production methods already in place.

Basic Stages Of Recovery In Oil & Gas Production

In any oil and gas production operation, the goal is to recover as much oil as possible while keeping operating costs as low as possible. As technology has advanced and the the demand for oil has increased, new techniques have been developed to increase the amount of oil that can be produced from one reservoir.

In the early years of the US oil industry, the biggest demand was for kerosene that would be burned in lamps. There was little understanding of how reservoir drives worked and how best to recover oil from a reservoir. As a result, wells were produced until the natural pressure in the formation dropped enough that oil wouldn’t flow on its own. At that point the well was considered played out, leaving more than 80% of the oil still in the reservoir.

Time has improved our understanding of geology and the forces that drive an oil reservoir. Using modern methods for oil and gas production, more than half of the oil in a formation may be recovered.

 

Stages Of Recovery

There are three basic stages of recovery operations. A well will move through each stage, first as it is first completed, then as the natural formation pressure falls and the oil has to be helped along through artificial means. These techniques are called enhanced recovery techniques, which is a broad term that covers all of those methods of artificial recovery. Equipment will most likely be replaced and improved as new techniques are used.

Techniques and technology continue to evolve as more is learned and new methods developed. However, it’s likely that an oilfield in the future will most likely look very similar to one today. Newer technology is often expensive and prone to problems, and older and more reliable methods are often a better option for smaller and marginal wells. The basics of producing and treating oil will most likely still depend on gravity and the different densities of water and oil. While it’s important to keep up with new developments, the skills and knowledge developed working any field is going to be useful.

 

Primary Recovery

When a well is completed and begins to flow, it has entered the first, or primary, phase of recovery. It also includes using basic method of artificial lift, such as different types of mechanical, hydraulic, and electrical lift. Basic methods of treating and stimulating well production are also considered part of the primary recovery stage.

 

Secondary Recovery

When an operation begins to use water flood or gas injection to maintain the reservoir’s pressure, the well has entered the secondary recovery stage. Flood techniques refer to the practice of injecting a fluid or gas at one well, pushing oil toward a second well where the fluid or gas is recovered. Water flood is one of the most common methods used. Flooding operations can be complex, as the volumes injected, injection patterns, fluid channeling, and many other factors have to be accounted for.

 

Tertiary Recovery

Third stage recovery is considered to have begun when two or more forces are used to aid in the production of oil from a well. This can include combinations such as CO2 and natural gas, water and and chemical flooding, and the use of heat and water to produce steam. Slugging is commonly used in third stage recovery operations. With that method, two different fluids are injected alternately. This is common when one of the fluids are expensive chemicals used to improve production; water is injected after the chemicals to improve their effectiveness.

Pressure Gauges In Oil & Gas Production

Pressure gauges are an essential, if delicate, measuring tool for oil and gas production. Flow lines, separators, and even atmospheric vessels like stock tanks are all under some amount of pressure. Gauges allow you to monitor pressure levels throughout the operation, from the wellhead to the tank battery. Monitoring pressure downhole is also important for extending the production life of the well for as long as possible. If you plan on working in oil and gas production, it’s a good idea to be comfortable using, maintaining, and calibrating pressure gauges.

 

Pressure Gauge Basics

Pressure gauges are used all over a pumping lease, with a range of sizes, costs, and accuracy levels. Some gauges can take more abuse, but generally are less accurate. Others are more precise, but have to be treated more carefully.

Pressure Gauges

Figure 1. A few different example gauges. (courtesy of Helicoid Instruments)

Less expensive gauges can be used for tasks where an approximation is enough, such as monitoring the pressure in a flow line. It’s more important to know the exact pressure at the wellhead and downhole, however, and so a more accurate gauge should be chosen for those uses. An appropriate gauge should be chosen for each task. The life of a gauge that’s measuring pressure down the flow from a triplex pump, or in another situation where pressure fluctuates rapidly, can be extended by using an adjustable vibration dampener to lessen the shock.

One type of gauge uses a spring to measure pressure and move the hand on the gauge’s face. A second, more common type uses something called a Bourdon tube. That’s a thin, flat tube that is curved into a c-shape. As pressure builds in the Bourdon tube, it attempts to straighten from its curved shape. This moves the hand on the gauge’s face, indicating the pressure.

Pressure Gauges

Figure 2. The interior of a Bourdon tube gauge. (courtesy of Helicoid Instruments)

 

Types Of Gauges

In some contexts, it is wise to use a gauge with some built in safety measures, such as a stronger glass face. Some will have a rubber plug in the back of the gauge that can blow out if the pressure grows too great. Otherwise, safety glasses should be worn whenever opening a gauge or when reading a valve on a high pressure line.

Most gauges are gas filled, but some may be filled with liquid instead. Gas filled gauges may become scratched or otherwise difficult to read over time. Liquid filled gauges will remain readable much longer, but may have a bigger problem with corrosion.

 

Well Testing Gauges and Calibrating

Gauges used for testing well pressure work the same as any other gauge, they’re just generally more accurate and can be calibrated.

Pressure Gauges

Figure 3. An example of a gauge and dead weight tester.

A test gauge will have an adjustment screw with which any error from the indicating hand can be corrected. Using a dead weight tester, the gauge can be checked for accuracy. Well testing gauges are generally fairly expensive and should be treated gently. A cam and roller geared gauge is a good option, as they are long lasting and accurate. It’s also usually best to select gauges that have the hand pointing directly up when indicating the middle of the pressure range. Gauges of this sort are more reliable. Occasionally it may be necessary to have a gauge calibrated at a laboratory, or by the factory, in situations when precision is important.

Calibrating a test gauge requires a dead weight tester. To calibrate a gauge using the dead weight tester in Figure 3, the black gauge in the back left (hidden by part of the tester) should be closed. The black valve in the front left should then be opened and the handle cranked up. Hydraulic fluid will be pulled under the crank’s plunger from the center reservoir. Now the two valves’ states are reversed, with the front valve being closed and the back opened. Cranking the handle downward puts pressure on the fluid so that it is pushed to the center pedestal stem. You can fit the gauge onto the tester, and then place the test amount of weight on the pedestal in the center. The left hand screw raises the weights to the correct height, and you can then check the gauge to see if it’s reading accurately. The gauge’s hand can be adjusted with a screw driver.

 

Measuring Pressure Without A Gauge

A dead weight tester can also be used to measure pressure directly when you need a very precise reading. Using a small diameter, high pressure hose, the tester can be connected directly to the wellhead. The tester can then be used to measure pressure.

The Fundamentals of Downhole Pump Designs in Oil and Gas Production

It doesn’t matter what type of mechanical lift system you use; it will use some sort of pump configurations for transferring the hydrocarbons from the well to the surface. While there are several styles offered, every pump utilizes the same key components.

To differentiate one style from the next, each pump is distinguished by how each pump functions, and how the various components are put together. However, to be a successful operator; a lease pumper should be aware of both the similarities, and the differences, of each mechanical lift pump style.

 

Downhole Pump Components

Downhole mechanical pump lift systems consist of five key components. These include:

  • Barrel Tube
  • Holddown Seal Assembly
  • Plunger
  • Standing Valve
  • Traveling Valve

Barrel Tube. The pump portion where the fluid flows from the formation is known as the barrel. Depending upon the pump design, the barrel can either be a section of the tubing, or an entirely separate component the lease pumper will be required to insert into the tubing.

Other than that, the key differences between barrels are:

  • type of metal
  • metal thickness, and
  • the method the barrel houses the plunger

In most cases, you can find pump barrel tubes in one of three thickness sizes: heavy wall, standard wall, and thin wall.

The material used can vary in both the type and grade of the metal; and is typically either: brass, carbon steel, Monel, or stainless steel. Depending upon the manufacturer, it is often common for the metal to be treated in order to help protect it from chemicals and corrosion. This also helps to further harden the metal for additional strength.

Prior to installation, the barrel tubing has to be machined in order to ensure the correct thread design and clearances are utilized for each specific type of plunger. Depending upon the pump, a liner may also be used; in these situations, the barrel design must also accommodate for this extra layering.

Downhole Pump

Figure 1. Barrel Tube Examples (Harbison Fischer)

Holddown Seal Assembly. The entire purpose of the holddown (or holddown seal assembly) is to create a seal between the tubing and the pump.

Typically, one of three types of holddown assemblies are used: two mechanical options and one cup type (as seen in Figure 2)Each assembly must be accurately installed and utilize the appropriate seating nipple in the tubing string.

Cup-type assemblies generally use one of two seating nipple lengths. The short model provides one seating area, while the longer seating nipple option offers the ability to be reversed, allowing it to turn around in the tubing to create a new seating area during situations where the other area has been damaged. However, while both cup and mechanical style holddowns both offer satisfactory installations; in cases where the bottom hole temperature is 250 degrees Fahrenheit or above, the operator should opt for a mechanical holddown option.

Downhole Pump

Figure 2. Examples of a Holddown Seal Assembly. The one on the right is a cup option, while the two on the left showcase the mechanical style options. (Trico Industries, Inc.)

Plunger. The purpose of the plunger is to remove the liquid from the pump’s base and to bring it up to the top of the pump. This motion is either due to: the barrel traveling around the plunger, or the plunger traveling within the barrel.

They are categorized in one of two areas: metallic or nonmetallic; with each available in a large array of metal arrangements. Most of these arrangements offer the option for treatment using the similar procedures used on the barrels.

For a successful downhole pump assembly, the space between the metallic plungers and the barrel must be extremely precise. Therefore, these spaces often have to be corrected once the installation in the hole is complete. This is generally due to the system normalizing to the pump temperature and bottom hole temperatures. Both barrels and plungers are created and/or treated to withstand corrosion from both H2S and CO2. The conditions of the well will determine whether to utilize a grooved or non-grooved plunger.

Soft-pack plungers (also known as non-metallic plungers) are available in a variety of cup and ring designs. Ring design options are also known as the: composition ring, regular flexite, soft-packed, wide flexite, or an assortment of additional terms. The softpack cup assembly and composition are typically selected for well conditions with highly abrasive or corrosive fluid properties, high temperature fluids, larger fluid gravity, and/or assemblies with poor lubrication.

Downhole Pump

Figure 3. Plunger Examples (Harbison Fischer)

Standing Valve. The standing valve located at the base of the pump is a one-way valve that permits the liquid to flow from the formation to the barrel.

As shown in Figure 1, the standing valve consists of a ball that rests on a small-lipped seat; and the ball and seat assembly is contained within a valve cage with a ball located on top (or up) as it is positioned into the well.

Since the pressure from below can cause the ball to unseat, and for the fluid to leak past the valve; this pump option uses the pressure from above the ball to keep it situated in the seat, and to prevent the fluid from flowing back past the valve.

Downhole Pump

Figure 4. Example showing the components of a ball and seat standing valve. (Harbison Fischer)

The ball and seat are completed and placed together against one another as a set, and then sealed together as a unit. These two components should always be kept together. Each seat size has two sizes of balls available. They are the standard API (American Petroleum Institute) size and a smaller alternative option that permits violent fluids and debris to travel between the ball and valve guides. In some circumstances, double valves are installed in order to resolve specific issue.

Traveling Valve. The traveling valve is located at the pump’s height. Similar to the standing valve, the traveling valve is a one-way valve. This permits the oil to flow out of the barrel, while keeping the fluid from flowing back into it.

Although the traveling valve and standing valve are separate parts for each pump; these two valves can be the same composition and size, allowing them to be interchangeable. As a result, the construction and operation of these valves are the same.

 

Downhole Pump Designs

There are three types of pumps and one tubing pump (see Figure 5) used in the four basic styles of downhill pumps. These include:

  • Insert Pumps
  • Stationary Barrel, Bottom Anchor Insert Pumps
  • Stationary Barrel, Top Anchor Insert Pumps
  • Traveling Barrel, Bottom Anchor Insert Pumps
  • Tubing Pumps

Downhole Pump

Figure 5. Examples of the 4 main pumps used in the majority of downhill pump designs (Trico Industries, Inc.)

Insert Pumps. When working in oil production, the word “insert” specifies the pump has already been constructed as a complete and working pump, and has been placed into the tubing string. Insert pumps can contain either a stationary or moving barrel, and is typically anchored that is typically anchored to either the bottom or top.  

Due to this, the three insert pump styles include:

  • Stationary Barrel, Bottom Anchor

A stationary barrel, bottom anchor pump can be used in shallow to very deep wells, and is typically the most accepted insert pump option. Due to the design, the traveling valve has the option to be smaller than the standing valve. The fluid column inside the tubing helps to constantly support the pump barrel; with the reduction in differential pressure, the pump has improved efficiency and a longer pump life.

A common disadvantage to this style of insert pump is sand tends to settle around the barrel and the scale can make it difficult to pull the pump. Thankfully, this issue can be resolved by stripping-the well (or stripper job) where the workers simultaneously pull the rods and tubing.

  • Stationary Barrel, Top Anchor

This pump style has the holddown located at the top of the pump. It is situated so the pump hangs below both the tubing perforations and the seating nipple. This type of arrangement is great with sandy wells (especially shallow ones with a depth of less than 5,000 feet), due to the fluid’s whirling motion created during operations in the area at the pump’s top.

Inside the barrel pump, the pressure is far higher than the casing pressure located outside of it. Allowing the barrel pump’s inside the ability to resist the pressure created by the fluid column. However, this does limit the depth at which the downhole pump can operate safely; due to gas pounding (a very serious issue known to split the barrel).

  • Traveling Barrel, Bottom Anchor

This versatile barrel option will operate in corrosive, normal, and sandy wells with positive results. During each stroke, the barrel rushes the liquid around the bottom of the pump causing the possibility of sand to stick to the pump inside the hole to reduce.

If the design uses an open-style valve cage, it will provide less restriction during the pumping of heavy crude oils; while the traveling barrel option offers a better defense against bursting, especially for designs using a heavy barrel.

One of the disadvantage to this style of pump is it more likely to gas lock than stationary barrel options. The traveling barrel is more likely to experience wear during operations because the traveling barrel is larger than the standing valve. This also makes it less productive in situations with crooked holes; and therefore, the pump may require a guide.

Tubing Pumps. You can differentiate an insert and tubing pump, because the tubing pump is placed down the hole as a portion of the tubing string, with the standing and traveling valves typically running on the rod string. Once the standing valve has dropped to the hole’s base, the rods turn and discharge it. Then once the rods are repositioned a few inches higher, the pump is prepared to pump again. Standing valves can be attached (and re-attached) for re-running, pulling, and servicing rods.

As you can see in Figure 5, the up-arrow indicates both where the clutch is located and where the pump splits, allowing it to pump. The portion above the up-arrow is commonly referred to as the action section. This section moves along with each pump stroke (going up and down), and also contains both the plunger and traveling valve. While the section below the up-arrow indicates the stationary section of the pump containing the standing valve.

One of the clear advantages of using a tubing pump is the ability to pump larger volumes in water flood plans. However, there are plenty on the flip side. For instance, a big disadvantage is the necessity for removing the tubing string for pump barrel maintenance and service.

Another big tubing pump disadvantage is the rod string’s high fluid load; as the weight from this load can stretch the rod resulting in a bottom hole stroke loss.

Other Pump Types. Like other devices, there are a wide variety of downhole pump designs. While some are variations of the previously described options; others are more unique, and are created to meet the specific requirements of an installation. Therefore, pump manufacturer assistance is indispensable when planning your pump installation design, especially for wells with special requirements.

A Basic Guide to a Standard Wellhead Design and the Polished Rod in Oil & Gas Production

When operating oil & gas wells, there are a variety of requirements to keep in mind when converting a flowing well to one utilizing a mechanical pumping configuration. For example, in order to extract the downhole packers, a tubing holddown is installed (if/when required) to ensure the correct pumping depth. This is due to the reduced bottom hole pressure; the removal of a packer helps to reduce formation pressure, and aids in promoting fluid flow.

Other requirements can include the need to reconstruct the wellhead in order to meet the particular requirements of a pump. For instance, some pumping units are used to remove water blankets from the matrix section to allow the well to flow properly again.

During these circumstances, a choke valve is typically left in place once the wing valve is utilized to help manage well production. While there are a variety of dedicated downhole pumps you can install to help better production, we will currently focus on the standard pumping configurations.

 

How to Prepare the Well for Downhole Pumping

During mechanical pumping well preparations, typically workers will remove the packers to help permit gas production throughout the annular space. It is mandatory for some type of holddown during production in order to thwart movements from the lower tubing section. However, it can be unconfined just enough to permit gas to flow adjacent to it and into the hole, if the operator prefers to keep the packer.

 

Pumping Wellheads

The image in Figure 1 is one of many techniques used for attaching the pumping wellhead. In this configuration, they removed the Christmas tree and placed a pumping tee with bonnet (or adapter flange) is installed.

As seen on the tubing header in the picture, a four-way tee includes a mounted pressure safety shut-in for the flow line on top. In the event of a clogged, frozen, or broken flow line; the safety switch shuts down the well until the proper attention is received. Once the well resumes production; the controls will reset.

Wellhead Design

Figure 1. Example of a Wellhead Design featuring a Casing Connection, a Typical Shut-In Control, and Tubing.

Wellhead Design

Figure 2. The Most Common Pumping Wellhead Designs include: a Casing Head, Polished Rod, Pumping Tee, Polished Rod Clamp, Rod Lubricator, Polished Rod Liner, Stuffing box, and Tubing Head.  (Dandy Specialties and Larkin Products)

Selecting Wellhead Equipment

When determining the appropriate wellhead equipment, workers need to keep several factors in mind. This includes:

Polished Rod. It is very common to procure too short of polished rods when choosing polished rods. If this occurs while working on a troublesome well, it can also cause issues when the crew drops the rod string to tap the bottom and/or to complete other servicing tasks. During each stroke when the horse head is at its peak, an appropriately sized polished rod will be able to allow the polished rod to completely drop to the peak of the stuffing box.

The top of the polished rod should extend throughout the entire bridle carrier bar with enough allotted space to install an appropriate clamp, with enough additional room for the string to drop to the base to tap bottom.

When the horse head is at its peak, and the rod has the highest rod exposure outside the hole; the polished rod should be able to extend far enough beneath the stuffing box to drop the rod liner until it is up alongside the stuffing box.

Polished Rod Clamp. As seen in Figure 3, polished rod clamps are utilized during transportation to reinforce the rod string while the additional weight is carried by the carrier bar and bridle. The polished rod clamp is obtainable anywhere from one bolt up to four or five bolts (depending upon the rod load requirements). In some situations, lease pumpers may utilize two clamps for safety purposes.

Polished rod clamps have also been known to be placed beneath the carrier bar. This widespread practice is often used for wells with a record of polished rod failures (where the rod breaks at the carrier bar). The goal of the additional safety clamp is to help the rod string avoid traveling into the stuffing box. This clamp is often used to prevent a variety of different spills from occurring.

Wellhead Design

Figure 3. Two-Bolt Polished Rod Clamp Example

Polished Rod Liner. In order to protect the polished rod from wear, a polished rod liner is situated overtop of it. This method is simpler to avoid packing leakage from a stuffing box with a larger liner diameter. To ensure the proper polished rod liner is utilized, it should measure the optimum stroke length with an additional two added feet.

If the polished rod liner isn’t long enough, it is inclined to hang onto the obstacles in the wellhead during the upstroke, or it can even create issues while attempting to tap bottom. Workers should NEVER tighten the polished rod clamp while adjusting the clamp on top of the stuffing box.

If this occurs, each clamp tightening on the liner will create a series of indentations; and with each pumping stroke, a little quantity of compressed gas and oil is released into the atmosphere through the flawed section(s) of the polished rod liner goes through the stuffing box.

As long as the damaged polished rod liner is used, the leak will continue; and at the same time, other issues can (and will) occur as a result of the lost oil continuously running down the stuffing box and wellhead.

Unfortunately, even one slight instant of thoughtlessness can cause liner indentations. Each of these indentations can result in a variety of issues, including: lost time and needless replacement expenses.

Polished Rod Lubricator. In some cases, a free-floating polished rod lubricator with wick-action felt wiper pads is typically equipped to the polished rod. It is generally placed directly over the stuffing box.

This apparatus also provides additional lubrication for the polished rod and lengthens the packing life. During periods when oil is not produced, this additional lubrication helps the polished rod avoid getting too hot and destroying the packing; making this a particularly useful lubricator for erratically producing wells. In most cases, low-priced, non-detergent style oil is sufficient for use.

Rod Rotator. Paraffin is one type of by-product created during oil production. This waxy combination of hydrocarbons can cover the internal rods, surface pipes, tubing, and anything else the valves may come into contact with.

During specific depths, the earth’s natural heat helps keep the paraffin in a fluid-like state. However, once the paraffin elevates up into the hole, it solidifies. This causes the deposit on the rods and tubing.

Wellhead Design

Figure 4. Example of a rod rotator utilized for eliminating scale and paraffin.

To help prevent paraffin buildup, a common practice is to use a rod rotator (See Figure 4). This device is attached to the walking beam and situated on the wellhead. As the pumping unit pumps, the rotator slightly turns the rods with each stroke. Scrapers are utilized and placed close enough so that as the rods rotate with every stroke, the small over-travel scrapes the paraffin off.

While there are several paraffin-cutting paddle types, the majority of them are either circular or flat. However, these are not the only methods for eliminating paraffin. Other common options include:

  • injecting chemicals
  • pouring hot oil
  • steam (often used on rods and/or tubing once pulled and laid on the racks)

The Stuffing Box. During the early years of the petroleum industry, the majority of stuffing boxes utilized a donut-shaped packing. To help improve the stuffing boxes’ efficiency, it was manufactured with a variety of different additive types (ex. lead or graphite). However, in more recent years the cone-shaped packing has become the more popular option (See Figure 5). While there is a more improved model that is practically leak-proof; for most marginal stripper wells, the costs for these models are not justified.

Wellhead Design

Figure 5. Example of stuffing box with a cone-style packing (Trico Industries, Inc.)

In most situations, the donut-shaped packing is still highly successful for marginal to shallow depth wells. If workers utilize caution and common sense during both installation and maintenance (including periodically tightening the packing); a packing set can last the lease pumper for several years, and in many cases with practically no leakage.

However, packing can be purchased in various qualities. Therefore, it is vital to keep accurate records and to keep track of all packing costs, in order for the lease pumper to determine the most economical and productive choices for the well. Through it all, the most important action is to keep the pumping unit carrier bar well centered over the hole.

Generally stuffing boxes have a grease fitting located on the side of the box. To prevent serious injuries, this fitting should never point towards the pumping unit. No matter what size pumping unit is utilized, the fitting should always point to the side or outward. Otherwise the edge of the horse head could strike a worker during the downstroke.

 

Casing, Flow Line Check Valves, and Tubing Issues

Check valves are another common source of issues for wellheads. During times when scale or trash accumulates under the check valve seat, or during internal failure; the check valve can fail to properly seal, allowing the fluid to escape and flow back into the wellbore. 

Figure 6 shows two examples of wellheads. The left wellhead has 300-500 pound working pressure, while the right wellhead has a 2,000-pound working pressure. By monitoring the embossed numbers shaped into the forgings, the lease pumper can ascertain the screw connections and the pressure rating of a valve. (Determining fitting pressure ratings by a casual assessment is something each lease pumper should be equipped to do.)

Both wellhead examples contain each of the three wellhead check valves. The first is situated just following the wing valve on the upmost horizontal line. The second valve is situated directly beneath the first, while being properly aligned with the casing. (This second line also contains a wing valve.) Once both lines join, they are pointed towards the tank battery and to the third installed valve and check valve.

Wellhead Design

Figure 6. Example of two pumping wellheads with the right showcasing a high pressure unite, and the left showing a medium pressure-unit.

Casing Check Valve. This valve is used to permit the gas produced to flow from the casing to the tank battery. This feat is vital for new production to travel from the formation to the wellbore. From there the gas streams into the tank battery and throughout the casing. The fluid is propelled into the tank battery using the tubing. The casing check valve thwarts the fluids from being produced and flowing back into the bottom of the well. Even the slightest check valve leak can cause new production loss and befuddle the worker as to the correct quantity of oil production.

Flow Line Check Valve. The flow line check valve by the wellhead thwarts several issues from occurring if either (or both) wellhead check valves falter. If a tubing leak develops, then the column weight could pull the oil from the flow line back into the well. Flow line check valves also help reduce the produced oil from flowing from the header and into the well. When checked properly, this can correctly illustrate how things are transpiring to the lease pumper.

Tubing Check Valve. During certain productivity tests, it is necessary for the lease pumper to check the downhole pressure applied to the tubing. In order for accurate results, the pressure must be isolated from casing pressures. The check valve located just past the tubing wing valve prevents casing pressures from flowing back through the bleeder valve when the downhole pump action is checked at the bleeder valve.

A Basic Guide to Operating and Servicing Pumping Units in Oil & Gas Production

It may come as a surprise, many of the lively oil wells in the world are only slightly producing wells converted to artificial lift systems. In fact, the portion of wells using mechanical lifts is so high, most (if not all) wells on multiple leases utilize pumping units. Why? Because mechanical lifts are both reliable and straightforward to run.

Therefore, the majority of lease pumpers favor this method over all other types of artificial lift systems. To understand more about the maintenance and services required for these dependable devices, operators should understand these basic pumping unit fundamentals.

Pumping Units

Figure 1. Electric Motor Driven Pumping Unit Example. If you look at the power line pole, you can see the power control box. There are also two additional power control boxes located alongside the pumping unit.

Electric Prime Motor Mechanical Lifts

Wells using electric prime motor mechanical lifts are both easy to learn how to operate, and to program to full automation. Generally, in electrical control setups (see Figure 1) the power line will carry the electrical energy to an area close to the site, but away from the guy line location.

Usually an underground power line with a mounted fuse panel (in most cases this is at the rear of the pumping unit). Many locations also utilize a second electrical panel, which is typically equipped with an on/off switch, automatic control box, and is placed on a post. Lease pumpers should be able to comprehend the mechanics and how to run each of the components, as well as how to identify any issues that could occur.

 

Natural Gas Engine Mechanical Lifts

Natural gas engine mechanical lifts are fairly dissimilar from electrical prime motor units. This is particularly true for wells using the gas from the well for its fuel supply.  With these conditions, lease pumpers need to vent the gas within the well not being utilized for fuel in order to try and sustain the formation backpressure. The goal is to be as close to zero as possible.

In most cases, lease pumpers are on site each day for 8 hours or less. Therefore, in situations where workers utilize manual controls (ex. starting or stopping the controls manually), only a limited amount of schedules are available for the pumping unit. While a pumping unit can operate 24/7, it does not mean it will result in a higher oil production.

Another option for lease pumpers is to turn on the pumping unit right before they leave, while shutting it down once they arrive the following day. This results in roughly 16 hours of operations, and can also cause lower overall oil production.

The last option is to run the unit throughout normal business hours. During this timeframe, the lease pumper can utilize multiple scheduling options. This includes 8 hour on/off cycles, running continuously, or other scheduling options. However, the most capable approach is for the lease pumper to utilize an engine controlled approach. This approach permits the engine to operate automatically without anyone having to be present (including starting and shutting down).

Engines provide options not available for electric motors. For instance, by setting the controls, the pumping unit can be positioned to tag the bottom within as close as 1 inch. However, if the pump is unable to pump oil, raising the engine RPM will cause the rod to stretch and the device to tag the bottom. After the pump has re-established operations, the worker can fine-tune the RPM to avert issues with tapping the bottom.

In order for the best possible operation reliability, the pumping unit engine must be modified accurately. When workers do not use a proper maintenance schedule, it can (and will) end in a production loss, as well as add additional responsibilities to the worker’s already hectic schedule.

 

Rotation Direction

It is very common for companies to change the rotation direction of conventional gear-driven, walking beam pumping units either every six months or annually. This prevents the wear and tear to the gears by changing the forces that cause the wear to these parts, and applying it to the opposite sides of the gear teeth. This is typically accomplished by reversing the connection of any two three-phase motor wires. Note that this option is not available for natural gas pumping units.

Many pumping units (like the Mark series) utilize weights that must rise toward the wellhead during operations. Generally, chain drive gearboxes will usually require unit counterweights in order to move in a specific direction and to properly lubricate the gearbox.

Lease pumpers should also record the rotation direction for each pumping unit in the field manual to ensure the pumper can alert the person replacing the motor of the unit’s rotation direction prior to the issue.

 

Timing Controls

There are two main categories of pump operation timing controls:

  • 24-hour clocks can be utilized for operating the pump within a given time frame, and
  • percentage timers which can typically be found in many of the newer automatic control box options

24 hour clocks come in several different styles. For example, some can be controlled to cycles of 15 minutes on and 15 minutes off; while other timing controls can be set for smaller intervals (time frames less than 5 minutes). These types of clocks are great for setting pumps to operate with irregular pumping cycles or for operating at specific times of the day.

Percentage timers are available to use for cycles consisting of 15 minutes or more. They have one control dial granting the lease pumper the ability to set the timer to operate for a specific percentage of the cycle. For instance, if the percentage timer is set for 15 minutes at 50 percent runtime; the pumping unit will operate for 7 ½ minutes, then shut off for 7 ½ minutes during each 15-minute cycle period. With 96 15-minute intervals in a day, the pumping unit will run for 7 ½ minutes for each of the 96 cycles throughout the day. The same goes for other percentage timers.

For example, a 2-hour timer set for 25 percent runtime will continually operate for 30 minutes, and shut off for 90 minutes during each cycle. This repeats 12 times per day resulting in a total runtime of 6 hours (or 25 percent).

 

Pumping Schedules

In order to figure out the most suitable schedule and exactly how long a pump should run in a 24-hour period can be tough. For instance, if a well is producing both water and oil, and requires a 12-hour pumping day for the highest oil production; the worker can utilize several different schedule options to reach this goal. These schedule options can include:

  • Around the Clock Cycles of 15 minutes operating and 15 minutes without operations
  • Around the Clock Cycles of 30 minutes operating and 30 minutes without operations
  • 12 Cycles of 1 hour operating and 1 hour without operations
  • 6 Cycles of 2 hours operating and 2 hours without operations
  • 2 Cycles of 6 hours operating and 6 hours without operations
  • 1 Cycle consisting of 12 hours operating and 12 hours without operations

During periods when the well is not operating, the liquid level builds up in the casing at the hole’s base. As the levels increase, the column weight increases causing a buildup of the backpressure; as the backpressure rises, the rate of oil production will decrease until the backpressure is equivalent to the hydrostatic pressure (which will stop all operations).

Therefore, there is specific timeframe to allow the fluid to collect, any amount of time beyond that does not create an increase in oil production. Hence, whether you operate for 20 minutes an hour or 12 hours per day, the overall results can create the same outcome only requiring 8 hours of production time. Therefore, if the unit is able to pump the entire oil accumulation to the surface utilizing only 30 minutes of operation, then there is no reason to operate the pump for longer than one hour or more for each cycle.

Then again, if the lease pumper operates the pump without permitting the fluid to accumulate completely, it can decrease the backpressure, allowing a more stable hydrocarbon flow.

For instance, if the formation flow rate drops each hour by half the oil flow, until the flow ceases around 18 hours. Afterwards the well typically takes around 6 hours of operations to eliminate the fluid buildup. In these instances, a typical pumping schedule may consist of operating the pump for 6 consecutive hours per day.

Nonetheless, operating the pump more often will help keep the back pressure from accumulating, and helps maintain a greater formation flow rate. An example of this would be having the pump operate for 15 minutes (or more) every hour, equaling a total of 6 operational hours per day. This in turn helps to prevent the formation flow from stopping and results in a better possibility for higher overall production. That said, it is important for the lease pumper to remember there are multiple financial factors to consider prior to creating the ideal pumping schedule.

 

Pumping Unit Maintenance

To properly maintain a pumping unit, one of the first things the lease pumper should do is create a proper maintenance schedule (including daily, weekly, and monthly inspections) and to stick to it. This information should also be recorded into the GreaseBook app to help the lease pumper make certain the proper procedures are performed.

For example, many supplies store offer a wide variety of lubricants. They can have different additives, weights, even the container types used. During each on-site application, there are typically only a small amount of lubricant options appropriate for use; and often times, only one is really suitable for the task.

It is unrealistic to expect lease pumpers to recall every type of required, and/or the exact location each lubricant should be used. To help ensure the proper lubricants are used, accurate and complete record records should be maintained. This can help assure the correct quantity and lubricant type is applied, as well as when the lubricant should be changed out. Furthermore, it can prevent mixing non-compatible lubricants with one another.

 

Daily Inspections

One of the positives of oil field equipment is its reliability, and with the proper maintenance can function for years before experiencing any serious issues. However, in order to prolong the unit’s life expectancy, daily inspections should be performed to locate any issues prior to occurring damage.

When making inspections, lease pumpers should ensure the radio volume in the vehicle is completely down (or shut off). By listening carefully, you can determine a great deal about the pumping unit’s condition. Lease pumpers should also include checks for: leaks (ex. lubricating oil) or loose objects (ex. nuts, bolts, washers, etc.) in their daily inspections.

 

Weekly Inspections

Weekly checks should include the following:

  1. Perform Daily Inspection Steps
  2. Observe the Pumping Unit (make sure to completely walk around the unit)
  3. Stop at Proper Observation Points and Watch Each Component for One Entire Rotation (The lease pumper should be looking for any signs of unusual motion, uncommon noises, or vibrations.)
  4. Examine the white safety line to ensure the pitman arm safety pins are correctly aligned. (For more information see Gearbox and Pitman Arm Issues below.)

 

Monthly Inspections

Monthly inspections should include:

  1. Completing the weekly check duties
  2. Examining the gearbox fluid levels (helps to determine if any leaks are present)
  3. Lubricating any worn components such as the pitman arm bearings, saddle, or tail.

Pumping Units

Figure 2. Worker examining both the condition of the gearbox and the oil level (Lufkin Industries, Inc.)

Pumping Units

Figure 3. Worker lubricating the tail bearings and saddle (Lufkin Industries, Inc.)

Quarter and Semi-Annual Inspections

Quarter and semi-annual inspections are essential. This is especially true for many new units, as many of these devices require semi-annual lubrication procedures (as shown in Figure 4).

As the pumping unit gains wear over time, it will require the interval to gradually change first to five months, then four, and eventually every three months. However, some units may require monthly lubrication, as well as additional special maintenance requirements in between lubrications. A portion of these examinations are performed during operations, while others require the unit to be completely shutdown and to set the brake lever.

Pumping Units

Figure 4. Worker examining the air cylinder (air balanced unit) to determine the level of oil. (Lufkin Industries, Inc.)

 

Gearbox and Pitman Arm Issues

There are a variety of harmful pumping unit situations, but the two typically causing the most damage include when the pitman arm comes loose, and when the gearbox gear teeth are stripped. Therefore, it is essential to provide extreme care when changing the stroke length (see Figure 5).

This includes accurately cleaning, keying, lubricating, and tightening the crank pin bearing wrist pin. If for some reason the nut were to loosen and fall off; it will damage the hole in the crack, triggering the walking beam to twist and breaking the wrist pin.

Pumping Units

Figure 5. Worker modifying the length of the pump stroke (Lufkin Industries, Inc.)

The lease pumper should have a white safety line painted across one nut face. It should be placed stretching from counterweight to the safety pin, as well as on the crank for several inches. This allows the workers to recognize any alignment alterations of the components – both during operations and downtime.

As daily inspections are performed, pumpers should make not of even the slightest changes that could indicate a nut (or other components) is coming loose. After a stroke length change, workers should inspect nuts and other components on a daily basis for movement starting the very first week.

Lease pumpers should always pay close attention when examining the gearbox oil level, making sure to check the oil for metal shavings. You can obtain small samples from the plug or lower petcock.

Typically, you can detect metal shavings by placing a small amount of oil onto a clean, dry cloth. If the pumper discovers any metal shavings, the worker should remove the cover, flush and clean out the gearbox, and add new oil.

Occasionally, workers should remove the gearbox cover (typically at least once annually) and closely examine the gearbox interior using a flashlight (see Figure 6), particularly when it comes to chain-driven units.

Lease pumpers should always look at the lubrication troughs. This helps to ensure the appropriate oil levels so every bearing receives the proper quantity of oil needed to engage all the necessary components (ex. gears, oil dippers, etc.). Periodically workers should change the oil out, clean the filter, and remove any water or sludge that has accumulated.

Pumping Units

Figure 6. Example of a gearbox without its cover detached for an inspection (Lufkin Industries, Inc.)

Oil in the Gearbox

Pumping units have a variety of sizes, styles, gearboxes, and types of gearbox oil. This can include: chain drives, double-gear drives, and single-gear drives. In addition, each of these gears contain dippers, and with each rotation the dipper will pick up the oil, carry it, and empty it into a lubrication trough (allowing for the four shaft bearings to be lubricated). However, poor maintenance can cause a variety of problems. This includes:

  • Accumulating Sludge – typically caused by aged oil, incorrect additives, or mixing oil
  • Difficulty Starting – typically caused by low oil or overly viscous oil, especially in cold weather  
  • Foam – typically caused by an overfilled gearbox
  • Gear Wear – typically caused by contaminants (ex. bits of dirt, metal, etc.) in the oil
  • Poor Lubrication – typically caused by low oil levels
  • Rust – typically caused by water in the oil
  • Poor Gear Surface Coverage – typically caused by overheating the oil, or too thin of oil

In most cases, these issues can be corrected by properly flushing the gearbox and completing an oil change.

Pumping Units

Figure 7. Manufacturers and suppliers are a great resource for finding out about equipment maintenance or other servicing techniques like lubricating the points (as shown in picture)

Understand, not only is it vital for operators to recognize the various problematic pumping unit indications, but also how to fix these issues!

Special Tests for Flowing Wells in Oil and Gas Production

Drilling and producing a well requires constant testing of many different kinds. The weight and quality of the oil has to be tested, as well as the amount of water and gas produced. Some tests will reveal if there’s a leak or faulty equipment, others can help decide if a new well will be profitable and pay off. Most major decisions regarding how a well is produced will start with one test or another.

There are a couple tests that are particular to flowing wells, where the pressure in the reservoir is great enough that no pump is needed to bring fluid to the surface. The first gauges the pressure of the fluid in the well, and the other measures its temperature. Both require equipment be run downhole.

 

Temperature Surveys

Temperature surveys are useful for a number of reasons. The temperature of the fluid downhole is going to be determined by the temperature of the surrounding earth; oil at the bottom of the well is generally warmer than that at the top. As it cools on the way up, heavier elements of the oil and paraffin can fall out and accumulate on the tubing. Additionally, temperature surveys can be used to find casing leaks. Gas escaping through the leak will expand, and therefore cool rapidly. The temperature change will show up clearly on the survey.

The temperature recording instrument is lowered on a solid metal wire, mounted on a short lubricator (somewhat similar to a swabbing lubricator). There will usually be instructions for the instrument that should be followed closely; in general, it should be stopped regularly so that you’re getting clear readings over the depth of the well.

 

Pressure Surveys

Pressure surveys are extremely useful for a number of reasons, particularly for naturally flowing wells. Tracking pressures changes over time can allow a pumper to estimate the production life of a particular well, for example. As a note, it’s important to remember that air pressure depends largely on the altitude above or below sea level. As with temperature surveys, the pressure gauging instrument must be stopped regularly to get clear readings. The local altitude and air pressure may have an effect on how often and where the instrument is stopped to take readings.

Tests

Figure 1. An example of a quartz pressure gauge. (courtesy of GRC Amerada Gauges)

Tracking pressure is a key part of monitoring a well’s activity, so pressure surveys should be run at least every 6 to 12 months. The well should be shut in prior to the test, to allow the well to build to its maximum pressure. The pumper may not be the one to run this test, but still should most likely be present to bring the well back into production after the survey has been completed.

Tests

Figure 2. A diagram of the inside of a quartz pressure gauge. (courtesy of GRC Amerada Gauges)

Other Downhole Tests

While just about every well will have a temperature and pressure survey run on a regular basis, there are some other surveys that are run downhole that are less common, or are only needed in some specific circumstances.

 

Caliper Survey

This is a test that will need to be run more regularly for wells that are prone to corrosion damage. The caliper is an instrument with steel fingers that are spring loaded so that they press outward against the inside of the casing. The caliper is lowered to the bottom of the casing and then dragged up with the fingers running along the inside. The fingers draw lines on a chart, and when one encounters a pitted spot or some rust, the finger will jump or dip in response. It’s fairly easy to see where damage is occurring in the tubing, and how much, using a caliper survey.

 

Scrapers

In some cases, it may be necessary to run a scraper up the inside of the tubing before a measuring instrument is lowered. This is done when a well produces a lot of paraffin, asphalt, and heavy weight oils that can collect on the inside of the tubing. That sort of accumulation can make running instruments downhole risky, as the expensive instrument might get stuck down the well. To prevent that, a scraper is run inside the casing to scrap out most of the stuff that might pose a problem.

Common Tests For Oil & Gas Production

Tests of all different sorts are a regular part of running a lease pumping operation. Regular testing of a well is the only way to discover important information, which will be necessary to making decisions about production. Some tests can be quite specialized, but there are a few that you’ll almost certainly have to conduct. Well testing is ultimately about the behavior of the reservoir it draws from, so it might be helpful to understand something about how reservoir pressure works.

 

The Basics Of Reservoir Pressure

The reservoirs that are pumping wells draw from are under some amount of pressure. That pressure is essential to the processing of extracting oil from reservoirs, and in some cases is enough to push oil to the surface as soon as the reservoir is tapped. In most cases, the pressure is low enough that some artificial lift is needed to bring oil to the surface; that lift is provided by a pump. Pressure is still required to push new fluid to the bottom of the hole as it is pumped out. Pressure declines as fluid is drawn from the reservoir, eventually to the point where it’s no longer possible to produce oil from the reservoir.

The pressure can be the result of a few different natural processes. Many wells will be driven by gas, having either a gas solution drive or a gas cap drive. In either case, the gas is contained under pressure within the reservoir so that oil is pushed to the surface. With gas solution drive, the gas is dissolved into the fluid. The gas will break out of the fluid as it is pumped to the surface. With gas cap driven reservoirs, the gas sits on top of the fluid.

Water can also provide the pressure that powers the well. As oil and gas are drawn from a reservoir, water may flow into the newly empty space, helping to maintain the reservoir’s pressure. As oil is removed, the level of water will rise, so the tubing perforations will have to be regularly raised to keep pace with the oil. Otherwise, the amount of water you’re pumping will increase until that’s all you’re pumping out. Injecting water back into a formation is a popular technique for maintaining pressure in a reservoir as oil is pumped out.

In some cases, the pressure may be provided just by the force of gravity, the weight of the oil itself forcing it down to the wellbore. With a gravity drainage reservoir, the oil level will fall as oil is pumped out, so the perforations will need to be lowered gradually over the life of the well.

 

Tests

Each test is designed to reveal specific information about a well. To get a full understanding of how a well is behaving, it may be necessary to run a range of tests and examine the results over a period of time. The tests listed here are run as a standard part of operating a well or bringing a well into operation.

 

Potential

The potential test is designed to measure a well’s production potential for a single day. It’s a test that’s run on new wells or on wells that have been worked over. Before a potential test can be performed, the well has to be prepared by shutting it in until it reaches its maximum pressure. The standard shutting in period is 24 hours, but can vary depending on the well.

The potential production of a well is obviously a handy piece of information. For a new well, the potential will be helpful in deciding whether the well will be profitable (meaning turning a profit while producing) and if it will pay out (meaning it will generate enough profit over the life of the well to pay for the expense of exploiting it). It can also give you a good idea if there may be a maximum allowable production for that well, which will be set by a regulating agency. The potential production will also inform the design of the tank battery, whether offset wells should be drilled, and whether it’s worth it to collect and sell gas produced from the well.

If the well isn’t new, but instead has just been worked over, potential tests are used for slightly different purposes. Primarily, it will tell you whether the work over had the intended effect, solving problems or increasing production. It will also tell you whether the work over was worth it, meaning the well will generate enough additional production to pay the cost of working it over. The potential of one worked over well can also help you decide if it’s worth it to work over other wells nearby.

 

Daily Production

As the name implies, a daily production test measures the standard production of a well in one 24 hour period. It measures the gas, water, and oil when the well is working normally, which is helpful for tracking the well’s production over the long term. It can also be helpful in identifying problems, but the real strength of the daily production test is showing how the behavior of a well changes over time. The well needs to be running without any problems, reductions, or interruptions for at least 24 hours before the start of the test. This process is called normalizing, and is important for getting an accurate measurement of the well’s true standard daily production.

It’s a good idea (and usually required) to run a daily production test at least once a month. Ideally, it should be done on the same date of each month. The results of the test should be recorded in a record book with a separate section for each well. Many pumpers use a log sheet with 12 rows and enough columns to record all the results for the test. This allows all the results from a year’s worth of daily production tests to be laid out in one spot where they can be easily seen and compared.

The results of these tests are very useful, and can help you find and repair problems, anticipate the lifespan of pumps and other equipment, and estimate production and plan ahead. Without a reliable record of past production, everything essentially comes down to guesswork and intuition, which is not a great way to operate a profitable well.

When a tank battery only receives production from one well, it can be tempting to simply use the average daily production from over the course of the month, rather than performing a daily test. The problem with that method is that the average will include any downtime for repairs or maintenance, problems downhole that may have affected production, or any other loss. The daily production numbers based on this average will be lower than the true standard daily production. It’s also difficult to measure the amount of time and production that has been lost to repairs and other problems when taking the average, which can make decisions regarding the well’s operations more difficult.

 

Gas-to-Oil Ratio

This test, as you might guess, measures the ratio of gas to oil produced from the well. The results of these sorts of tests are usually forwarded to some sort of regulatory agency, which will track the amount of gas produced and potentially set limits on the maximum amount of gas an operation is allowed to produce from the well over a given span of time. The well will need to be shut in for about 24 hours before the test is run.

Limits on oil production are usually higher than the well can produce, so they are rarely a barrier. Limits on gas production can be more strict, but it is for a good reason. As mentioned above, reservoirs have to be under pressure for oil to be drawn from a well. Even when the well is not tapping a gas drive reservoir, natural gas will usually exert some amount of pressure. Drawing too much gas from the reservoir will lower the pressure, with the result that the well’s production drops or even stops altogether.

Reservoirs are almost always large enough that several different companies may have wells drawing from it. While Company A may have measures in place to manage gas production and so extend the life of the well, Company B may simply decide to produce all the gas possible from the well. Company B’s decision to over-produce gas will have an effect on Company A and any other companies with wells in the same reservoir, possibly reducing the production potential by years. An allowable production rate actually ensures that every pumper is operating responsibly. In many cases, it’s possible for one company to take over managing most or all of the wells in a particular area or reservoir. That company can then manage the whole field for the maximum return and efficiency, sharing the resulting profits with the other operations. This process is called unitizing a field.

 

Productivity

The idea of a productivity test is to produce the well in a couple different ways, with the goal of discovering the most efficient way of pumping oil for that particular well. Running productivity tests on a regular basis is important, as the well will change over time and adjusting your operations to match it is going to be necessary at some point. The test may take a number of days, as it may take a short while after a change is made before production settles down to a consistent rate. The well should be normalized by running it without problems or interruptions for at least 24 hours before the test.

A productivity test will usually begin by pumping the bottom of the well clear of fluid. The pump should then be shut in so that the well bottom can fill with fluid once more. Ideally, you’ll want to monitor and measure the rate at which the fluid seeps back into the bottom of the well. Some pumpers can get a good idea of the time required just by understanding the characteristics of the well and reservoir, and by drawing on experience. Getting an accurate, specific measurement will require an echometer and dynamometer. The echometer uses a process somewhat similar to SONAR to measure the fluid level in the well. A dynamometer is helpful in measuring the action of the pump, which can have an affect on the volumes produced as well. Once fluid has flowed back into the bottom of the well, the pump can be activated and the echometer used again to measure how quickly the pump draws the fluid level down.

An echometer and dynamometer are both expensive and delicate pieces of equipment, and it’s possible that you may not want to spring for one, or the operator you work for won’t want to. Oil was pumped out of the ground for many years before those two measuring instruments were invented, so it’s certainly possible to run a successfully operation without them. However, the more information that is available to you, the more likely you are to make a good and profitable decision.

There are some productivity tests that can be performed without a great deal of special equipment. Essentially, this boils down to making small changes gradually to see how they affect production.

Some information can also be gathered just by paying attention and understanding what’s happening. For example, you can take two fingers and lightly pinch the rod so that you can feel the action of the pump. You’ll be able to feel the difference between a pump pushing liquid and a pump hitting bottom. A cool rod means the well is pumping properly,  while a warm rod can mean there is a problem. Other workarounds are also possible.

A wide range of factors can have an effect on a well’s operation and the best way to produce it. Factors can include the reservoir’s drive, the porosity of the formation, the weight of the oil and percentage of paraffin, and the potential for scale and corrosion. Some wells will produce more if pumps are run intermittently, which allows fluid and pressure to build up at the bottom of the well when the pump is shut in. Likewise, a smaller pump won’t pump as fast. The frequency and length of the strokes on the pumping unit, backpressure in the flow line, and the depth and setting of perforations can also affect production, and can be adjusted during productivity tests.

 

Other Regular Tests

Shorter or less complex versions of these tests can be run if there’s a specific problem and you’re looking for the cause. Troubleshooting and diagnosing problems is going to be a big part of a pumper’s duties, so it’s a good idea to get familiar with the equipment and how to test if it’s working correctly.

Barrel tests are an example of a quick test that can be run to look for specific problems. For example, if there’s a drop in production but several wells are producing to the same tank battery, it can be difficult to even figure out which well is having the problem, let alone the cause. Running a daily production test on each well can take days or weeks, and during all that time production is less than it could be.

Barrel (or bucket) tests are usually performed by taking a small sample through the bleeder valve at the wellhead. The barrel or bucket should be of a known volume. You can then measure the amount of time it takes to fill that barrel. A simple formula can be used to determine how many barrels per day is produced at that flow rate.

A problem with drawing oil from the bleeder valve is that it may cause a drop in pressure in the flow line. This can cause gas to break out of the fluid, which can throw the results of the test off. Installing a valve to maintain backpressure on the bleeder valve addresses that issue.