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.

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).

There are also some other economic factors that should be taken into consideration. For example, additional activities like Well Testing must be carried out to figure out the best way to produce your well (which we go into in this post: How To Test Wells In Oil & Gas Production).

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.

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

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.

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.

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.

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. Also, there are a lot of indicators of issues with pumping units that you must be able to identify and correct!

However, fear not! GreaseBook has you convered 😀 Click any one of these write ups if you’d like to learn more about the potential problems (and how to correct them):

• Lease Electrical System and Motors In Oil & Gas Production
• The Basics Of Maintaining Engines For Oil & Gas Production
• Utility Pumps For Oil & Gas Production

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!

Is your appetite for oil & gas operating knowledge insatiable like ours? 😀 If so, check out these related articles,  A Pumper’s Basic Guide to Mechanical Lifts in Oil & Gas Production, A Basic Guide to a Standard Wellhead Design and the Polished Rod in Oil & Gas Production and, The Fundamentals of Downhole Pump Designs in Oil and Gas Production – they’ll be sure to pump you up!!!

Drilling and producing a well requires constant oil well 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 oil and gas well testing procedure 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.

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 and noted on your wells test sheet or GreaseBook app. 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.

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.

Is your appetite for oil & gas operating knowledge insatiable like ours? 😀 If so, check out these related articles: How To Test Wells In Oil & Gas Production, Common Tests For Oil & Gas Production and, Pressure Gauges In Oil & Gas Production  – they’ll be sure to pump you up!!!

Tests of all different sorts are a regular part of running a lease pumping operation. Regular testing of a well using different oil and gas well testing procedures is the only way to discover important information, which will be necessary to making decisions about production as well as determining production allocation.

Some oil and gas well testing 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 oil well testing procedures 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 and you’ll want to note it in your well tests sheet. 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. And, although many pumpers use a log sheet with 12 rows and enough columns to record all the results for these tests, due to the proliferation of smartphones many are switching to mobile apps like the GreaseBook to help track these tests.  The app allow 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, and even stands in for a cost-effective oil and gas production allocation software.

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 oil and gas production allocation 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.

Finally, we go into more depth on the set-up and recording of daily tests in the GreaseBook here: The Basics Of Keeping Records For Oil & Gas Production, here Operational Records For Oil & Gas Production Wells, and here Well Records For Oil & Gas Production.

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.

Is your appetite for oil & gas operating knowledge insatiable like ours? 😀 If so, check out these related articles: How To Test Wells In Oil & Gas Production, Special Tests for Flowing Wells in Oil and Gas Production and, Pressure Gauges In Oil & Gas Production  – they’ll be sure to pump you up!!!

Testing wells is an essential part of any pumping operation. Whether it’s oil well testing to be eventually input into your oil and gas production allocation software or a simple well tests sheet, you’re probably going to spend a fair bit of time around the lease performing tests of different sorts.

Oil and other products of the well need to be tested before they’re sold, as well as to determine the effectiveness of things like chemical treatment. Other oil and gas well testing procedures may need to be performed on meters, valves, and other equipment around the lease.

The well itself will need to be tested, both as it is brought into production and regularly throughout its life. Accurate testing and competent reading of the results can help improve efficiency and provide vital information for managing your operation. Each test is used for a specific purpose (ex: production allocation), so understanding how each works and what exactly is being tested is also important.

Prepping The Well For Testing

Before a well can be tested, it needs to be prepared. In this case, the preparation consists of putting the well in the right state to be tested. For some oil well testing, that will require at least 24 hours of normal operation before the test. Other oil and gas well testing requires the well be shut in before the test, so that it can build up some pressure.

Normalizing

Normalizing a well merely means that it is operating and producing in a standard way for that well, and has been doing so for at least 24 hours. When tests need this sort of preparation, you’re usually measuring, in some way, how the well is performing on a regular basis.

It seems like this should be fairly straightforward; hopefully wells are operating at ‘standard’ production rates most of the time. However, that does mean the well can’t be experiencing any reductions in production from faulty equipment, mis-set valves, and other common problems. If the production measured after normalizing isn’t close to the estimated production, it can mean that there is a problem somewhere.

Normalizing is particularly important when a well has been out of service for any amount of time. The well may have built up additional pressure, which will lead to a temporary increase in production. That increase can potentially last for several days, falling gradually over time. The first day the well is producing again, it may produce an additional quarter day’s production over the standard production. That over-production will fall, but measurements taken right after a well has been brought into service will not reflect the well’s daily production.

Shutting In

There are some cases where you do want to measure the production after the well has built up that additional pressure. For those tests, the well should be shut in for some length of time. ‘Shutting in’ is the process of isolating the well. The master valve and casing valves should both be closed, so that nothing is produced from the well. Any other lines, for example from a chemical injector, that lead to the well should also be closed at a valve. The wellhead should be quiet once the well is shut in; any noise most likely means you missed a valve or that one is leaking.

The standard shut-in time is at least 24 hours before you plan the test. However, that time period can vary, depending on the behavior of the well. The goal is for the well to reach its maximum pressure, which will most likely be learned from experience. When the well is first shut in, the pressure will rise rapidly. As time goes on, the increase will slow, eventually stopping and leveling off at the highest pressure. Wells that draw from formations with a higher porosity, for example in coarse sandstone, are likely to build pressure much more quickly. Formations with lower porosity will most likely need a longer period to reach max pressure.

Prepping The Tank Battery For Testing

Though you’re testing a well, the tank battery may need to be prepped also. Obviously, the tank battery should be able to accept a standard day’s production without a problem. Shutting the well in may require some adjustments at the tank battery. When the well is brought back into production, you should be sure the tank battery is ready to accept the over-production that is likely to follow. Test production from the well will most likely need to be routed into the test separator, and then the oil will be sent to a stock tank so it can be measured; the gas should be metered, and the water volume should also be measured.

Figure 1. An example of a separator used for testing.

Many tank batteries, particularly in smaller single well operations, may simply route both the water and oil through the test separator into the main/only stock tank. While the stock tank probably already has a fair bit of oil in it, it’s possible to figure out what’s been produced during the test easily. Just measure the amount of fluid in the tank before the test, and then again afterwards. Simple subtraction gives the amount of fluid produced in the test.

Once the total volume has been determined, you’ll want to find out what the ratio of oil to water that was produced. You can find this out by thiefing the tank; in other words, using a tool called a thief to take a sample from the tank at the estimated oil-water interface. Again, you’ll want to thief the tank before the well begins testing, and again after the test has been completed. A little simple math is all that’s required to find the produced oil volume. You’ll also want to find out the percentage of sediment and water in the tank after the test. The gravity and temperature of the oil may have to be measured as well.

Figure 2. Gas recorder with three pens showing temperature, static and differential measurements. (courtesy of ITT Barton)

If the well is producing natural gas, that needs to be recorded. As gas breaks out at the separator, it has to be measured as it flows through the gas line using a gas meter. You can check previous measurements in the lease records to get an estimate of which meter orifice you should use. You’ll want to make sure the meter is operating properly; a few basic things like making sure the pens on the recorder aren’t stuck can save you trouble later on. Many meters these days are computerized; the design and functions on these can vary so it’s a good idea to review how the meter you’re using works.

Common Tests and Testing Information

Wells can be tested for a variety of reasons, but there’s a few basic tests that will need to be run regularly or which are common when first bringing a well into production. The specifics of the tests may vary depending on the operation and what specifically you’re testing for.

Potential Test

The potential test is used to find out how much a well can produce in one day. You should shut the well in and allow it to build to it’s maximum pressure before you run this test. The standard shut in time is about 24 hours, but can vary depending on the behavior of the well.

The potential test is most often done on new wells when their production rates and capability is being discovered. It’s also used with wells that have been worked over to discover what the new production rate will be like.

Oil-to-Gas Ratio Test

The name pretty much says it all. This test determines the ratio of oil and gas being produced from the well. This can be useful information for a number of reasons, but it’s particularly important as too high a percentage of gas can lead to a drop in reservoir pressure. That can have a wide impact on the production of any wells drawing from the same reservoir.

The oil-to-gas ratio test requires the well be shut in prior to the test to build pressure downhole.

Daily Test

The daily test is fairly straightforward, and is used to determine the normal daily production of a well. The daily test is run on the same day every month, and a record is kept to track this amount over the long term. As you’re trying to determine standard production, the well should be normalized before the test.

Productivity Test

This test covers the most area, with the goal of discovering how to produce the most oil while not reducing the well’s producing life. The idea is to operate the well in with few different ‘standard’ setups, and then measure the output of each. For productivity tests, you’ll usually need to normalize the well.

Recording Test Results

Most of the tests that are run on the lease will end up collecting a lot of information, which then has to be interpreted and analyzed. The amount of oil, water, and gas will generally be recorded, as those figures will be among the most helpful to look at. There are numerous oil and gas production allocation methods. And, to properly interpret those numbers, you’ll need to place the production in the context of the well and method of production.

Some basic lease information is usually required for all tests. A lot of it is standard requirements for paperwork, such as the name of the lease, the company that is operating it, the well being tested and the field where it’s located. The date of the test is helpful, as testing records are most useful when looking at the behavior of a well over time. The type of test, the condition of the well, and the length of the test are also important.

Details can help explain variances between the recorded and estimated production volumes, so many forms will require specific information such as the casing pressure before and after the test, the tubing pressure before and after, and more. Information specific to the lift method for a pumping well is also important. The stroke length and frequency can affect production so that needs to be recorded.

Other information that may end up being useful includes the state of the tank battery, and any extraordinary circumstances that may affect production, downtime, as well as any wells that are shut-in and the like. There are a lot of moving parts and these calculations can become complicated in a hurry (you can also check out the GreaseBook, which a simple cost-effective mobile app that can serve as the perfect oil and gas production allocation software…)

Is your appetite for oil & gas operating knowledge insatiable like ours? 😀 If so, check out these related articles: Common Tests For Oil & Gas Production, Special Tests for Flowing Wells in Oil and Gas Production and, Pressure Gauges In Oil & Gas Production  – they’ll be sure to pump you up!!!

The sales process is an important one, and a fair bit of time should be devoted to preparing for it. Once you’ve pumped, separated, and treated a load of oil, it should be made ready for testing and assessment by the purchasing gauger. If the gauger isn’t satisfied, the load can be refused. That’s frustrating for you, leaving you with a full stock tank production backing up. The gauger is unhappy because he has to make sure he has a backup load to pick up, and everyone is making less money. Properly preparing the oil may be time consuming, but it’s a necessary part of the process.

Preparing And Selling Oil

There’s just a few basic requirements the oil needs to meet before it can be sold. If you’re selling by truck or otherwise selling one tank monthly, you’ll need to make sure you have a full load ready to go. In a tank ready to be sold, the total percentage of water, sediment, and other contaminants meets the purchaser’s requirements; usually that percentage is less than 1%. And the amount of bottoms, the emulsion that forms from the heavier elements of the purchased fluid, must also meet the requirements set out by the purchaser. Normally, the level of bottoms should be at least 4 inches below the sales outlet.

The most common methods for selling oil are selling through an automatic LACT Unit and selling by truck transport. Selling by truck is a more complicated process, as it requires you to have a full load of treated and separated oil ready to go by a specific date. It also requires communication with a gauger and transport driver. A LACT Unit allows you to sell oil as soon as it’s ready to go, without waiting. However, LACT Units aren’t available in every situation, and truck transport may be your only option.

There’s another requirement regarding the oil’s temperature, but which only rarely applies. The oil’s temperature can affect its volume, with higher temperature oil taking up more space. For that reason, a corrective factor will be applied to the volume the purchasing gauger measures when he picks up a load, and which is covered a bit more below. In some cases, however, the oil will have been heated to the point that a purchasing company would not accept it. This is most often the case when the oil has been heated to solve treating problems that may arise when a thicker oil with lots of paraffin is being produced from the well.

In addition to taking up a greater volume, oil heated to a higher temperature can be dangerous to handle and pump, as it’s much more likely to ignite. You may want to sell the oil right after it’s been heated, as the paraffin and heavier elements of the oil will flow more easily, and so they’ll flow out of the tank when the oil is sold. That can help keep the tank bottom clean. But many transportation companies won’t accept oil that’s over 100 degrees Fahrenheit.

Selling Using A LACT Unit

A LACT Unit (standing for Lease Automatic Custody Transfer) is an automatic method of selling oil directly into a pipeline. The unit is attached directly to the stock tank, which essentially becomes a surge tank. The LACT unit is able to gauge when the oil in the tank is ready to be sold, and also able to monitor the level of oil in the tank. As oil of sufficient quality is produced into the tank, the LACT Unit activates and sells oil into the pipeline. When the level of oil drops, the unit automatically shuts off. It will also stuff off if the quality of the oil falls below the set standards.

Figure 1. An example of a LACT Unit. To left it connects to the tank, and to the right it feeds into the pipeline. You can see the control panel behind the unit.

Figure 2. A second LACT Unit. You can see two lines leading to a prover loop from the front of the unit.

The unit is made up of a few different components. The liquid transfer pump maintains about 30 psi to keep gas from separating further from the oil, and so that a positive displacement meter can accurately measure the flow. A meter of this sort measures flow by using a mechanical flow meter of some sort, like a gear, and so may need more pressure to operate accurately. A backpressure valve before the pipeline helps keep that pressure up.

As meters age, they may lose accuracy, showing a higher volume than was actually sold. Meters have to be tested regularly, and a corrective factor may have to be applied to the meter readings. This factor, usually close to 1.000, corrects for the error measured in the meter. Another safeguard to prevent that sort of problem is the prover loop, which also verifies the reading from the meter.

The LACT unit keeps track of the sediment and water percentage in the oil as it sells it to the pipeline. If the oil doesn’t meet the requirements, the unit will automatically send it back through the tank battery.

Transporting By Truck

Selling using a LACT Unit is great, but it’s often not a method that’s available to everyone. When you’re not able to sell directly to a pipeline, selling by truck may be your only option. This is generally a more complicated process that may require some more work on your part. A gauger representing the purchaser will come to assess and test the oil. Based on his assessment, the purchase price may go up or down a bit, or he may refuse a load of oil altogether. A sales system for pumping oil into the transport truck also has to be built and maintained.

Figure 3. A tanker truck for transporting oil.

Figure 4. A note jar on an oil lease.

Different areas and gaugers will have a different process for getting in touch and scheduling a pickup. Most often, you’ll communicate with the gauger by cellphone or radio. There are some places where there is some sort of visual signal to the gauger, who drives around on a regular route. There should be some way of leaving paperwork on the lease, either a mailbox or a note jar.

The purchasing company will usually require you to have a full load of 210 barrels, or close to it. There’s two primary reasons for that. The first is cost. The expense of driving and pumping a full load is almost the same as that for a half load, so they make a bigger profit with a full load. Perhaps more importantly, driving a full load is actually safer. Oil is lighter than water, but even half a tanker load is still quite heavy. If the oil begins to move around the tank, it can make the truck difficult to control or even tip it over. With a full tank, there’s less room for the oil to move and so less risk. There are baffles that divide the tank up so that the risk is lessened, but a full load is still the safest option.

With that said, if there’s a problem with a tank or other emergency, the purchaser will often make an exception and accept less than a full load.

It may be required that you are present when the gauger tests a tank of oil. Even if it’s not required, it’s usually a good idea. Gaugers tend to be more careful, and it helps the process run a little smoother. Gauging the tank yourself before the gauger arrives is always wise, though the gauging volume will vary depending on the temperature. Consistent readings from day to day are unlikely.

There will be occasions when a tank is rejected by the gauger. That’s not ideal, and should be a fairly rare event. When the gauger does reject a tank, a notice is left for the pumper, and a copy most likely sent to the purchasing company. The notice will list some useful information, such as the date, the name of the pumping company, the lease where the tank was located, and the specific tank that was rejected. It will also list why the tank was rejected, which is probably the most useful piece of information.

The purchasing company will number the tanks in the battery, normally starting with lower numbers to the left, and counting up sequentially to higher numbers on the right. Out of sequence tank numbers usually indicates the tank has been replaced or restrapped.

Figure 5. An example of a run ticket.

A run ticket is a proof of sale, and is usually filled out for each run by the truck driver. In Figure 5 you can see an example. It lists a variety of information, such as the capacity of the tank, the depth measured before and after pumping, and the level of bottoms. It also gives the gravity and temperature read for the tank load, which will be used to correct the sales price. Other information is more relevant to the purchasing company, such as how long the driver took to make the trip, when he left, when he returned, and so forth. A carefully read run ticket can reveal a lot of information about the well. For example, on this ticket there is a wide difference between the old and new seal numbers. That implies the well rarely has a full load, and therefore likely only produces marginal amounts.

You’ll receive a check for the sold oil the following month. The purchasing company will usually take care of the split between operator and mineral rights holder.

Seals And Sealing Lines

When selling by truck, sales lines are usually sealed between pickups. The seals have numbers that are recorded, and are usually only removed and replaced by the gauger. If you do have to remove a seal placed by the purchasing company, you should keep it and record the seal number. You’ll most likely be required to supply the seal as well as an explanation for why it was removed.

Figure 6. Examples of the two types of seals.

There are two general types of seals in use. The first is a flat metal strap that locks down to itself. This style has to be pushed through a dart to work correctly. The other type of seal is a ware and lead ball. The wire is used to seal the valve, and then the lead ball is crimped shut onto the wire. In both cases, the seal has to be removed for the valve to be opened. The seal will be removed by the truck driver and then replaced once the oil is loaded.

Seals will have some information on them, like an identifying number and the name of the purchasing company. For selling by truck, the driver usually handles removing and replacing seals. When selling by pipeline, you may need to have a representative from the purchasing company present.

Is your appetite for oil & gas operating knowledge insatiable like ours? 😀 If so, check out these related articles: Testing And Treating Oil & Gas Production, Basic Methods of Treating In Oil & Gas Production and, Chemical Treatment And Pumps In Oil & Gas Production  – they’ll be sure to pump you up!!!

Crude oil, the fluid that’s pumped right out of the ground, is full of stuff that’s not oil, gas, or another hydrocarbon. Separation is the process of removing as much of that other stuff as is possible, as well as separating the various elements of oil. Treating oil is a key part of the separation process.

The process of treating oil can actually start even before it’s pumped out of the well, and will continue until the oil is sold. Chemical treatment is the most common way of treating oil, and most crude oil will have chemicals added to it at some point to help water and sediment separate out. Chemical treatments can also be used to prevent corrosion of pipes and tanks, and for a few other uses as well. For some specific problems, there are also some special ways of treating oil beyond the standard chemical additives.

Treating Oil With Chemicals

There are a variety of chemicals out there that can do a few different things. Different companies may refer to the same chemicals by different names, and obviously there may be different brands that do essentially the same thing. In addition to that, chemicals are used to accomplish a few different things when it comes to treating oil, and so it’s often more helpful to talk about those goals rather than specific chemical or brand names.

Removing Water

Water and oil naturally want to separate due to their differing densities, and simple gravity and time will do a lot to remove water from oil. Chemicals can help that process along, both speeding it up and improving its effectiveness. Most chemicals used for this purpose are called detergents or surfactants. Detergents bind with impurities and separate them from oil. Like soap, surfactants lower the surface tension in fluids. Surfactants used in oil and gas production are usually both water and oil soluble, so the same chemical will affect both fluids.

To understand how lowering surface tension aids in separating the liquids, it might be helpful to imagine the oil and water as a big pile of oil and water bubbles (sort of like a ball pit at your local fast food joint). It’s hard for the bubbles to move around and push past each other, and smaller bubbles of oil and water will be more difficult to separate. Reducing the surface tension through the use of a surfactant allows the bubbles to collect and become larger. The larger bubbles are heavier, allowing the oil to float up and the water to fall down.

Paraffin Thinners

Wells that produce heavier weights of oil may also produce other, heavier hydrocarbons like paraffin or occasionally asphalt. These thicker products from the well can cling to the inside of pipe or tubing. It can also sometimes form a barrier between the water and oil in a tank, which can end up sending oil down the drain. Some chemicals will thin paraffin so that it flows more easily and doesn’t collect in pipes and tanks.

Casinghead gasoline actually has a similar penetrating ability as paraffin thinners, and so can be used as an alternative. This is the drip that condenses out of gas lines. It’s much less expensive to use than chemicals, and so can save you some money. It’s important to be aware that casinghead gas can be volatile, and so should be handled carefully.

Cleaning Tank Bottoms

Keeping the bottom of tanks clean can be a chore, but it’s a chore that needs to be done on a regular basis. Sediment and other elements that are separated from the oil can collect on the bottom of the tank and form an emulsion. This emulsion will be thick and reluctant to flow out through the drain. Buyers will often require that tank bottoms meet certain standards, and a clean bottom makes treating oil easier.

Chemicals called bottom breakers will thin the emulsion on the bottom, allowing it to flow more easily. These are the most expensive of the standard chemicals used to treat oil, with a 5 gallon bottle costing over $100. When using bottom breakers, you may need to blend it to address the particular problem you’re facing.

You can reduce the amount of bottom breaking chemicals you use by keeping up with a few regular practices. Tank batteries will often have a couple of stock tanks. One is for storing oil ready to be sold, and the second is to hold overflow, hold oil waiting to be treated, circulating bottoms, and a variety of other uses. When the sales tank is emptied, there will be almost a foot of oil left on the bottom of the tank. This should be circulated back through the separation system and into the second tank. If your tank battery only has one stock tank, you can pump the oil from the bottom of the tank to the top, which will have a similar circulating effect.

When you’re circulating tanks, you may want to add chemicals to the oil being circulated. A simple, cheap, and effective way to do this is to punch a small hole in a container, like a empty plastic gallon jug. Add the chemicals and hang it over the thief hatch, and the chemical will slowly drip into the moving oil. The chemical will drop into the oil over 15 minutes.

Another option for keeping bottoms clean is to use butane to roll the tank. A hose is connected to the butane tank, weighted, and then lowered to the bottom of the tank. Chemical is gradually dripped into the oil as the butane bubbles to the surface and mixes it in. Dry ice can also be used instead of butane. In some cases, to adequately clean a tank bottom you may need to call in a vacuum truck. These have diaphragm operated pumps which can handle whatever may be in the tank.

Chemical Pumps

The longer the chemicals are mixed with the oil, the more good they can do. For this reason, you’ll often want to introduce chemicals into your system as early as possible. Adding chemical to the formation is sometimes possible if you’re treating for scale and sand, but it’s generally too expensive to be worth it. It’s much more common to add chemicals through the casing, at the perforations where the pump draws oil in. Alternatively, chemicals can also be added at the wellhead, or at the tank battery before the separator.

Figure 1. An example setup for injecting chemicals into the bottom of the well.

You can see a system for injecting chemical downhole in the picture above. On one side of the pumping tee is the casing valve that’s used to send gas from the well into the flow line. Chemical and oil is added through a small bypass line to the pumping tee’s bleeder opening. Using the chemical/oil mixture adds some weight to the chemical, so it reaches the bottom of the well faster.

This setup requires a check valve near the pumping tee so that chemical isn’t sent down the flow line instead of down into the well. It’s helpful if this line has valves at both ends so that it can be closed off if you need to do maintenance or repairs. Another line run to bypass the circulating line, shut by a valve, will allow you to also send chemical into the flow line from the same injection system.

Figure 2. This mechanical pump is used for adding chemical to oil. The pump is powered by a sash cord run from the walking arm.

In Figure 2, you can see an example of a pump designed to send chemical to the bottom of the well. It’s a mechanical pump, rather than an electrical one, powered by the sash cord at the center left of the picture. That’s attached to the walking arm of the pump that’s lifting fluid from the bottom of the well. With two containers, one can inject paraffin thinner to keep downhole components free of any buildup, while the other injects other chemicals into the flowline or downhole.

The wellhead in Figure 2 also has a way to inject chemical at the wellhead, rather than downhole. To keep the pressure in the flow line from getting too high, the wellhead has a pressure switch which can shut in the well. If you don’t want to inject chemicals downhole, the next best option may be to add them at the wellhead. The flow of the fluid from the well to the tank battery is enough to do a good job of mixing the chemical into emulsion. However, it’s usually more expensive than it’s worth to have a chemical injection system at each well that flows to a single tank battery. If you have to shut in the well with the chemical injection system, no chemical is getting added to the oil produced at the other wells.

Figure 3. A system for adding chemicals at the tank battery.

When chemicals are added at the tank battery, they’re generally added after the header where all the flow lines come together. It should be added before the oil reaches the first vessel, usually a separator, in the tank battery.

Figure 4. An example of a chemical pump intended to be moved from location to location. (courtesy of Arrow Specialty Co.)

It’s important that you have the correct equipment or decent equipment when you’re adding chemical. Every piece of equipment has a purpose, and you should make sure you’re getting the right thing to do the job. Most pumpers will work solo, so one person should be able to use and transport all equipment. This is true in particular for circulating pumps, which can be large but are often moved.

Treating Oil To Solve Problems

When people talk about treating oil, they are usually referring to chemical treatment. However, there’s a number of other methods for treating oil that are used to solve particular problems.

Figure 5. An example of a hot oiler.

Hot oilers are used when enough paraffin has built up, combined with a large amount of water, that the separation process doesn’t work the way it normally would. It’s more common when the weather’s cold, and the oil tends to be thicker.

A hot oiler will pump oil from the stock tank into the truck’s holding tank. The oil is then heated and pumped back into the tank that’s clogged with paraffin. A tube is run from the truck, and through the thief hatch to the bottom of the tank. The heated oil will raise the temperature in the tank enough that the paraffin will thin and begin to flow. The process can take a few hours, but at the end water has fallen to the bottom of the tank and is then drained. The oil can be allowed to cool and then sold.

Figure 6. An example of a slop tank.

Slop tanks have become popular in areas where lined pits aren’t used. Operations that have regular problems with too much build up on the bottom will pump some of the bottom emulsion into the slop tank. That will bring the bottom down to the level required by the buyer, so the oil can be sold. The bottoms in the slop tank is sent back through the tank battery so that it all ends up back in the stock tank.

Is your appetite for oil & gas operating knowledge insatiable like ours? 😀 If so, check out these related articles: Testing And Treating Oil & Gas Production, Basic Methods of Treating In Oil & Gas Production and, Preparing and Selling Oil & Gas Production  – they’ll be sure to pump you up!!!

Most oil can’t just be pumped out of the ground and sold. It needs to be treated, to one extent or another, to separate the water, sediment, and other contaminants from the hydrocarbons. There’s a few basic methods of treating crude oil, some as simple as time, and others more complex. If separation happens in just a few moments or minutes, as when gas separates from fluid, it’s called flash separation. Separation that takes longer is called slow separation.

Depending on how the well is producing, different treatment methods might be available. In higher producing wells, using more chemical may be necessary in order to speed up the separation process. Wells that only produce small amounts may have more time to treat the oil, and are able to let gravity and motion do more of the work. In most cases, the best option is going to be to use several different treating methods together.

Chemical Treatment

Chemical treatment is used on most operations, and is often the first step in separation. One type of chemical, called surfactant, can be added before the separator or even at the wellhead. Surfactant is oil soluble, and will reduce the surface tension of water and heavier elements of oil. This aids in water breaking out and falling away from oil.

Figure 1. Here you can see a tank for holding chemical, and the pump and lines for adding chemicals at the wellhead.

Chemicals can be added to crude oil for several reasons, not just as part of the separation process.

Heat Treatment

Heat can be applied to oil as a way of reducing its viscosity, so that it floats to the top of the water. Heater-treaters are vessels that use heat from a firebox to aid in treating oil. The firebox may only be lit during colder months, and heat from the sun used in warmer months. Flow lines are often run above ground so that they can also be heated by the sun.

Figure 2. An example of a heater-treater.

It’s often a goal to use as little heat as possible, as gas fuel for the firebox can be expensive. A growing trend is to eliminate artificial heat all together. Methods toward that goal are being developed, but it may be a few years before it’s truly possible to not use any heat at all.

Electrical Treatment

A variation of the standard vertical heater-treater is the electrical heater-treater. For high volume production, it may be the most efficient method of treating oil. However, it’s usually costly to run electrical lines to a lease, and the cost of using electricity for that purpose can also be expensive. Electrical heater-treaters are going to be economical for operations where the volume is high, or on offshore platforms where space is at a premium.

Gravity Separation

The process of gravity separation is constantly underway. Even the heaviest elements of oil are lighter than water. As a result, oil will float on top of water. You can see this for yourself by pouring a glass half full of water, and then pouring vegetable or olive oil on top. The division between the two will be very apparent.

The water, oil, and sediment that come from a well are all mixed together. However, because of their different weights and densities, they will gradually separate over time. Again, you can see that by mixing the oil and water in the glass together. Leave it long enough, and the oil and water will separate naturally once more. With the emulsion coming from the well, the different elements are obviously mixed much more thoroughly. Gravity will do a lot to remove the heavier parts, the free water and sediment, from the oil. Over time, however, gravity will become less effective. Bigger water droplets fall out of the oil more easily, but smaller droplets tend to be more stubborn. Gravity is always working to separate different parts of the oil, but it will usually need to be helped along by other techniques.

Separation Through Movement

Lighter elements will tend to separate from heavier elements under motion. It’s the least expensive way of separating, short of simple time. Oil can be circulated through stock tanks and other vessels, and the simple motion will break out some gas and water. As with gravity, movement works best in conjunction with other methods of separation.

Separation Over Time

Using time along gravity will work to separate a lot of the sediment and water from oil, if the oil can be left to sit long enough. To maximize the amount of time oil is allowed to separate, treatment should begin as soon as the last load is sold. The amount of time you have should be used wisely, as it’s a limited resource which depends on the well’s production rate. Wells that have higher production rates will sell oil more quickly, and so the oil will have less time to sit and separate. Higher production means more money for other methods. However, wells that don’t produce as much will be able to let oil sit longer, and will have more time for gravity and motion to have an effect as well.

Is your appetite for oil & gas operating knowledge insatiable like ours? 😀 If so, check out these related articles: Testing And Treating Oil & Gas Production, Chemical Treatment And Pumps In Oil & Gas Production and, Preparing and Selling Oil & Gas Production  – they’ll be sure to pump you up!!!

Pumping crude oil out of the ground is a complicated process. Understanding reservoirs, pressure, and the advantages of different pumping methods might all be necessary to get the most out of a working well.

But once the oil gets to the surface, the work is actually just beginning. Before the oil can be sold, it has to go through a separation process, removing water and sediment, that includes treatment with chemicals. It also has to be tested so that the amount of sediment and water can be determined before it’s sold. Both of these processes are, at their base, fairly straightforward. However, as with many things, the details are important to understand.

Treating Oil

There are a range of chemicals that can be added to crude oil for various purposes. Specific products might actually do a few different things, but it’s possible to class the different additives into a few basic categories.

The basic use for chemical additives is to aid in the separation process. Crude oil usually includes water and sediment from the well. The buying company will set requirements for the amount of basic sediment and water, or BS&W, in the oil that you must meet before they’ll accept what you’re selling. Chemicals can help in a few different ways. Surfactants help the water to separate from the oil. Paraffin thinners keep heavier elements of the oil flowing, and demulsifiers also help in separating different elements of the crude oil.

Chemicals can also be added for other purposes. Corrosion inhibitors and oxygen scavengers are commonly added to reduce corrosion. Scale inhibitors are also added to prevent scale accumulating in equipment. There are also a range of other chemicals for more specific purposes.

Overuse of chemicals can cause long term problems with the emulsion. There are more chemicals that can be used to correct these sorts of problems, but are much more expensive than standard chemical treatment.

We go into more depth on the set-up and use of chemical recording and inventory in the GreaseBook here: Tracking Inventory In Oil & Gas Production.

Or, you could also get smart and just have it all done for you by checking out www.greasebook.com 😉

Testing Oil

You’re going to be testing and measuring the oil in a number of ways and for a range of purposes. When getting ready to sell the oil, however, you’re testing to make sure it meets requirements set by the buyer. As part of the buying process, the buyer’s gauger will come around and perform a few tests to determine if the oil is ready to be sold. The gauger is more likely to take a careful measurement if you’re there, and particularly if you understand the tests being performed. Performing the tests yourself can also help you make sure the oil is ready to be sold. Other tests will help determine how the oil needs to be treated and with what.

Testing Bottoms

Oil usually weighs 8 pounds or less per gallon, depending on its weight and makeup. Salt water like what’s coming from a well will usually weigh at least 8.33 pounds per gallon and can weigh up to 9 ½ pounds. Even the heavier weight oil and elements like paraffin are lighter than water, and so will form a layer between water below and the oil floating above. This layer will usually be an emulsion, consisting of salt, water, asphalt, sediment and sand, and oil bound up with the other elements.

The build up of emulsion is called ‘bottoms’, and its height above the tank bottom needs to be established. Most buyers will require the level of BS&W should normally be no more than 8 inches above the bottom of the tank. The tank needs to be circulated, and other steps taken, to keep the tank bottom clean. Otherwise, the emulsion will continue to build over time.

The level of emulsion can be found using a thief. This is a measuring tool that consists of a cylinder of glass or brass with a lid. The cylinder can be lowered into the tank, and then the lid opened automatically. The thief will take a sample of the fluid at the depth it’s opened. You should have some idea of where the water/oil interface is, which gives you a rough idea of where to open the thief. You can get a more precise measurement using the thief with a gauge line.

The thief is attached to the gauge line with the trip rod set. You can lower it into the tank, and then give it a small lift and sharp drop, which will open the thief. It’s important that the thief be moved slightly and only enough to open the thief. Too much movement can disturb the BS&W. You won’t be able to get an accurate reading until the oil, water, and sediment have a chance to settle back down.

Testing For BS&W

Gravity, chemicals, and some heat will do a lot to separate the oil you want from all the other stuff you pump out of the ground. But no process is perfect, and oil will still have some amount of water and sediment suspended in it even after the separation process. You’ll need to make sure that water and sediment make up a very small amount of the oil sold; usually the buyer asks that it be no more than 1% of the volume.

Because the separation does use gravity to a large extent, the oil at different depths in the tank will have a different amount of BS&W. To get an overall picture of the oil’s makeup, you’ll need to take samples of the oil at a couple different depths. Take one sample from a shallower depth, and a second closer to the bottom. The amount of BS&W can be added and then divided by 2 to get an average. You can add a third sample and divide by 3 to get a slightly more accurate reading.

To find out how much BS&W is in a sample, you’ll need to use a centrifuge. These are expensive and delicate pieces of equipment. They also require using centrifuge tubes, which are also delicate and fairly expensive. There’s a few different styles of centrifuge tubes, including a 100ml cone shaped variety that is most likely what will be used when the oil is sold. A pear shaped 100ml tube is also used, and is slightly more accurate for measuring very low amounts of BS&W. Most often, however, pumper and operators get estimates using a 12.5ml tube with a basic shakeout centrifuge. Shakeout machines are less accurate, but also less delicate and so better suited for use in the field. Ideally, the shakeout machine should have a bracket on your truck where it can be mounted when in use.

Oil Weight

The weight of the oil isn’t actually a measure of how heavy it is, but how dense it is. Specific gravity is a method of measuring density by comparing the density of one material to a standard. For oil, the scale is compared to the density of water at 60 degrees Fahrenheit. Oil with a higher specific gravity will be denser, and oil with a lower specific gravity will be densest.

Oil has its own scale for measuring specific gravity, the API gravity (American Petroleum Institute, named for the body that set the standard) system. With that scale, water at 60 degrees Fahrenheit has a gravity of 10. Most oil will measure between 15 and 50, with condensation above that is up to the 70s. Higher API oil is usually easier to treat and separate. Lower numbers mean thicker and darker oil, and higher numbers mean lighter and clearer oil. Oil that is about 16 on the API scale will weigh about 8 pounds per gallon.

Oil weight is determined using a hydrometer. A hydrometer is usually a bulb with a long graduated cylinder above it. The hydrometer is lowered bulb first into the oil, and will float at a specific depth, with the cylinder sticking up. The specific gravity is indicated by the level of fluid on the side of the cylinder. It may be necessary to have a set of hydrometers for measuring the gravity of different densities of oil.

The weight of the oil will impact its sale price, and so an accurate measurement is important.

Oil Temperature

The oil’s temperature will also have an impact on its sale price. Oil pumped from the well will be the same temperature as the earth surrounding, with deeper wells generally being warmer. Oil will cool as it is pumped to the surface and it won’t flow as easily. It can also have an impact on how easy it is to treat the oil, with cold oil being more difficult than warm oil. Thicker oil will hold a larger ratio of water and sediment, and may need to be heated in a heater-treater. Most flow lines are run on the surface as the sun heats the pipe and keeps the oil at a higher temperature, which makes it easier to treat water and sediment out. For the same reason, it may be easier to add chemicals at the wellhead so that it mixes with the oil in the annulus.

When the oil is tested and measured before it’s sold, it’s temperature will be gauged. A temperature adjustment is then applied to the purchase price, so it’s important to have a good idea of the average temperature of the oil in your sales tanks. A higher temperature will lead to a lower adjusted price (as warmer oil takes up more room and therefore has a greater volume), and colder oil will actually have a slightly higher purchase price.

Is your appetite for oil & gas operating knowledge insatiable like ours? 😀 If so, check out these related articles, Basic Methods of Treating In Oil & Gas Production, Chemical Treatment And Pumps In Oil & Gas Production and, Preparing and Selling Oil & Gas Production  – they’ll be sure to pump you up!!!

Monitoring production will take up a big chunk of time working a lease pumping operation. Most of your day will more likely be spent doing maintenance and basic repairs, however, on a wide range of equipment. A pumper will become competent in a whole range of skills while working on a lease, as their job covers a number of different duties.

This is particularly true as time goes on and production begins to drop. As a reservoir loses pressure, production inevitably falls. That fall in production means that there’s less money to hire specialists when there’s a problem. That means the pumper will most likely have to make more repairs on their own. Most of the equipment on the lease is repairable, from patching tanks to putting leak clamps on a line.

A Work Day

It’s important that the pumper not take on more than what can be done by a single person. As production drops, the pumper will have to do a wider range of tasks, but safety is important. You may need to perform a wider range of tasks, as production slows so does the pace of the operation. There’s more time for repairs, and time to schedule help for tasks that require it.

Oil has more time to sit, and so less chemical can be used in treating it. Vessels like heater-treaters may be turned into three phase separators, without using heat. Gas production will usually also fall, meaning that the gas system is easier to run. Less automation will be needed to handle all of this.

Maintenance of automation systems can sometimes be difficult, as the equipment is specialized and may be unfamiliar. The manufacturer will usually have resources to help you puzzle out problems and understand any repairs that may be necessary. Local suppliers are also usually good sources of information.

Safety

Your personal welfare is always important. There are many tasks and situations around the lease that can be dangerous if not treated seriously, but are perfectly safe when a little common sense is used. When repairing gas leaks and handling gas there are some particular safety rules to keep in mind, outlined below.

Working At The Tank Battery

The tank battery is the biggest above ground part of a pumping operation, so you can expect to spend a fair amount of time working there and maintaining the different parts. Every day should begin with look around the battery, inspecting the lines and tanks for problems. Leaks are usually very easy to see, as there will be a trail of black fluid trailing to the ground. When patching a leak on a tank, always lower the level of liquid below the leak. That will make the process much easier. Likewise, when tightening a leaking fitting there should be no pressure on it.

You’ll also want to keep the battery as clean as you can. It’s much easier to spot a leaking tank if the side of it isn’t already covered with drops of oil. Whacking weeds and keeping plants from overgrowing equipment will also make problems easier to spot. Other small tasks include lubricating valves and pumps, adjusting controls and valves, painting to prevent rust, and a whole range of other tasks to keep the battery operating.

Maintaining And Repairing Lines

A line leak can usually be stopped by applying a line clamp, which can be tightened around a leaking pipe. Special care should be taken when working with gas lines. Natural gas pumped from the well obviously doesn’t have the smelly stuff in it that the gas company adds later, so it’s possible to stop smelling it. That makes it particularly dangerous, as inhaling gas can lead to a loss of consciousness or worse. Always stand upwind of leaking gas, and have a second person standing by if possible. When a breeze is blowing, the small pocket of lower pressure created by your ‘wind shadow’ will draw gas into your face, even if you are standing up wind. Stand so that you’re facing at an angle to the wind, or shift a few steps to one side or the other regularly so that gas will be blown away from you.

This rule should also be followed when gauging tanks, as gas will be released then as well.

Figure 1. Keeping an eye on the wind’s direction is always a good idea.

Maintenance At The Wellhead

Maintaining the well and pump downhole is one of the pumper’s major responsibilities. You’ll need to keep engines and pumps maintained by changing oil and lubricating bearings. Other tasks you may be asked to perform includes tightening or replacing belts, checking stuffing on valves and pumps, replacing fuses, checking chemical levels and pumps, and treat fluid produced from the well with chemical.

Is your appetite for oil & gas operating knowledge insatiable like ours? 😀 If so, check out these related articles below – they’ll be sure to pump you up!!!

• The Basics Of Working A Lease In Oil & Gas Production
• Gauging And Gauging Equipment For Oil & Gas Production
• Troubleshooting Problems In Oil & Gas Production
• Unusual Operations In Oil & Gas Production

Each well and operation is going to be unique, depending on your experience, the behavior of the well, and a whole range of other factors. Every operation will face different challenges, and so it’s important to approach problems with an open mind. Some problems are best solved by working with other pumpers, either to prolong the life of the well or to save on equipment costs. It is often worthwhile, and can do a lot to make a well more profitable.

Working With Other Operators

Working with other pumpers has its own problems. Any potential disagreements can be avoided with clear procedures and a professional attitude. However, there are also some technical problems when working with other pumpers, but they can be solved with a little ingenuity.

Satellite Tank Batteries

Some lease properties cover a lot of area and have a few different wells. Nature is rarely considerate enough to put good well locations all in one spot together, so oil might have to be sent quite a distance to a central tank battery before it can be processed. To save a bit on the cost of running multiple lines, the flow lines for two wells that are close together might be joined into one flow. This joint allows for a smaller tank battery that can have a few vessels, like a separator or gun barrel, to treat the oil. The oil is sent on to the main tank battery, to the stock tanks where it will be held until it’s sold.

Gas might be stored at the tank battery, as well as water before it’s disposed of. When you’re partnering with another pumper, the place where the flow lines from the different wells is a good place to build a satellite battery. It’s also a good place to put a header and a testing separator.

One of the bigger problems to solve when sharing a tank battery with another operator is how to test the flow and measure the flow of the fluid coming from the well. The testing needs to be done before the two flows join in order to get an accurate measurement for each. A small header allows you to switch flows from individual wells into the meter and test separator, so each flow can be assessed. Each setup should meet the needs of the well and pumper, or pumpers, and so every tank battery will be custom designed.

Figure 1. This well tester can be brought to each wellhead.

If a test manifold isn’t going to work, then it’s possible to move the testing right to the wellhead. A testing manifold will also need to be installed in the flow line at a good spot near the well. This manifold will consist of two tees, each holding a 6 inch nipple and a plug valve. These can be connected to a well tester that’s brought to the wellhead. The well tester will accept the emulsion coming from the well and separate it into gas and liquid so that each part can be measured. The two are then sent back to the flow line and allowed to mix back together. The tester will also take a sample of the liquid, which can be used to determine the amount of oil and water in the sample.

Figure 2. An example of a satellite battery. There’s no stock tanks as oil is sent on to the main tank battery stock tanks.

In Figure 2 you can see an example of a satellite tank battery. The battery contains two separators, a line heater, a heater-treater, and other equipment. This example is automated, and includes a communications shack with equipment that alerts the pumper if there’s a problem.

Unitizing A Reservoir

Unitizing an oilfield means to bring several different wells, being operated by different pumpers, under the control of one company. Obviously, that can be a fairly complex proposition, especially when considering lease payments, property rights, and all that nonsense. However, it can often solve or prevent problems that can arise when several companies all are pumping from the same reservoir, so that everyone ends up benefiting. The unitized field is worked by the largest company, or whichever is going to be best able to operate the wells.

There are some safeguards so everyone’s interests are protected. Well tests and gauging will need to be witnessed. After the amounts of oil, gas, and water has been determined, and the operating company has covered their costs, the profit is split among the different parties.

Unitizing a field is most often necessary when several companies are drawing from the same reservoir. Each operator is going to want to produce as much as possible from their well, but some techniques for improving production can have an impact on other pumpers also working the reservoir. For example, if the reservoir is higher on one side, the upper wells will produce more gas, and lower wells will produce more water. The higher well might want to inject water to force more oil up to their well, but that will increase the amount of water the lower wells produce. Unitizing a reservoir means that the reservoir as a whole can be considered in each case, meaning that pressure is maintained and wells can all be produced efficiently.

Commingling Wells

When two wells from two different areas are producing oil of similar quality, from property owned by the same company, it’s possible to commingle the flow from those two wells. That simply means to run the fluid produced from both wells through a single flow line to the same tank battery. This can have a number of benefits, from requiring less pipeline to be run, to decreasing loss of lighter oils due to evaporation. Records of the individual production of each well needs to be kept, but they can otherwise be treated and stored together.

The biggest advantage of commingling flow with another operator is that it will save money. Splitting the cost of the lines from well to tank battery can be savings, and there are also other ways to lower costs. An example of a tank battery handling commingled flows can be seen in Figures 3 and 4.

Figure 3. A tank battery used by two lease pumpers. There’s a range of equipment here, including a few three phase separators and meters.

Figure 4. Equipment can be owned and used by each operator. In this picture, one heater-treater is shared by the tank battery and one is reserved for testing.The other two are owned individually by the pumpers.

Figure 3 is a long view of a tank battery used by two operators. On the left are stock tanks and gas meters. On the right are heater-treaters. Each has a sign showing which company owns it, and the heater-treaters each have a meter so that the production for each company can be tracked. Figure 4 shows a close of the heater-treater, facing the stock tanks. You can see the signs showing ownership of each tank, as well as the circulating pump on the far left.

Figure 5. Two headers, one for each operation.

Each company has its own header for handling flow through its tanks and from its wells. There’s also a separate, shared test line. A gas meter on the right measures gas separated from the fluid before sending it back into the main flow line. The metering separator uses gas operated valves, which allow the separator to be used, and then dump automatically back into the main flow line. These measurements, as well as when the test separator dumps, are recorded at about the same time every day.

Figure 6. A smaller separator used for measuring the oil coming from each heater-treater before it’s routed to the common stock tanks.

Working For Two Companies

It’s possible that you may want to maximize your work time pumping for two different companies. There are operations where that’s not a big deal. Some smaller companies with wells that don’t produce high volumes may not have enough work to keep a pumper occupied every day. If you’re driving your own car and using your own tools, it’s generally not a problem.

Larger companies may have many more wells, or wells that produce higher volumes. They’ll often have plenty of work, as well as supplying some of the tools and equipment that you use. It’s usually wise to check with the company before taking on a second job. They won’t want your attention being pulled away by other responsibilities, and so have the quality of your work suffer.

The key is to do the best job you can, and make sure everyone is clear with what you’re doing and when you’re doing it. With some common sense and professional approach to your work, most problems can be overcome.

Is your appetite for oil & gas operating knowledge insatiable like ours? 😀 If so, check out these related articles below – they’ll be sure to pump you up!!!

• The Basics Of Working A Lease In Oil & Gas Production
• Gauging And Gauging Equipment For Oil & Gas Production
• Troubleshooting Problems In Oil & Gas Production
• Maintenance and Repair For Marginal Wells In Oil & Gas Production