Flowing wells are created when the water and gas produce a pressure forcing the liquid from within the rock through any openings (such as a well). While the pressure may be powerful enough to push the liquids to rise up when created towards the surface; and as time progresses, this pressure will decrease, and lift systems may need to be installed for the remaining life of the well. However, before a lease pumper begins to think about bringing the oil up from the well, you need to consider the different production regulations.
Typically lease operators prefer to obtain as much gas, and/or oil, as possible to maximum revenue. However, while maximum productivity rates can provide more upfront profits, it isn’t always what’s best for the economy, environment, reservoir, or any other considerations aside from the lease operator’s financial interests.
To help ensure all factors are considered by the lease operator, a variety of agencies were created for gas and oil production regulations. For instance, local or state examples may include: Oil and Natural Gas Commission, Petroleum Commission, Environmental Protection Agency, or other similar names.
The goal of these agencies is to aid gas and oil producers in comprehending any problems or concerns with the reservoir. One of the main responsibilities of these agencies is to monitor and control the production of oil and gas reservoirs.
Often times, they set limits for these natural resources. Production limits (more commonly known as allowables) help to prohibit abuse through the subsequent guidelines:
Production limits and regulations help to provide protection for the reservoirs and to ensure their lifespan and durability. Plus, using the proper production practices have been known to extend the reservoir’s production life, and in a higher closing production revenue.
Safeguarding the Rights and Freedoms of All Operators
Production limits help to preserve the lives of all the reservoir wells. Monitoring and controlling the volume of gas or oil a well can produce, preserves the bottomhole pressure. In other words, the operators will be able to postpone the use of lift systems, and prevents reservoirs from exhausting their resources erratically or too quickly. This is especially true when there are multiple lease operators who yield from the same reservoir.
Gas and/or water coning is a serious issue many reservoirs face with producing wells. It generally occurs in an oil zone with either an: overlying aquifer, underlying gas cap, or both. When coning takes place, the zone containing the gas or water moves upward to the wellbore in the shape of a cone.
When this situation occurs, the cone will remain in place while productivity has ceased for the well. However, once the the valve is open, it will create higher gas productivity; and thus water will sweep into the well. As the water rushes upward, it forces out the oil; but these little variances in weight will take years for the well to naturally go back to the well’s initial state, and for lease operators to decrease production volume to a fragment of the normal productivity rate.
Reduces the Effects of Inferior Production Methods
The field operator, lease pumper, owner; it doesn’t matter who was at fault for overproducing the well. When a well is damaged, the entire company pays the price.
Therefore, the advised practice for production is to avoid overproducing the well by over 10% of the well’s daily productivity potential. In other words, if the well loses one day of production; it will take ten days for a single day’s loss to be recuperated. If this occurs, the well could still be short of the productivity standards by month’s end.
Nevertheless, this is still more appropriate than harming the capability of the well, as overproduction will result in a constant shortage.
Sometimes lease pumpers may come across other pumpers boasting of their skills for compensating for lost productivity by secretly overworking different wells. This helps by maintaining a full overall production rate after all production issues are rectified. While supervisors are typically pleased with the numbers, these results only shorten the overall life of the well and decrease their long-term potential.
Wells with Multiple Operators
The U.S. is among only a handful of countries where multiple companies, governments, individuals, states, and/or trusts can own the mineral rights.
Due to this, productivity procedures from one operator can cause extraordinary productivity issues for lease operators of nearby wells; and periodically, extremely severe declines can kill nearby wells.
In other words, they will no longer be able to yield gas or oil. This is due to the hydrocarbons being drawn from the furthest reservoir regions where the counterbalance wells might be.
Whenever a reservoir is off-balanced, it can cause:
- the higher elevated wells to only yield gas
- the lower elevated wells to only produce exceedingly high amounts of water with extremely small amounts of oil, and
- the middle elevated wells to yield large amounts of oil, with extremely small amounts of gas, and little to no water.
When this occurs, a variety of issues could arise; such as:
- a lease operator in higher elevated regions (who yields large amounts of gas) – the reservoir would lose pressure, and thus the wells with high amounts of oil would eventually no longer yield oil.
- a lease operator in lower elevated zones (who yields high volumes of water) – can revitalize the lower the formation pressure and the water drive; which in turn can aid the water table in increasing productivity from large oil production wells rapidly plummets off. A large number of lawsuits have been filed over these type of issues; and the best answer for this is for any and all operators to agree to a productivity schedule for the entire reservoir in advance, this ensures the most effective, efficient, and beneficial wells for all parties involved.
Natural Well Flow
For a natural well flow, a well must have ample bottomhole pressure that is powerful enough to force the liquid to surge from within the rock formation, up to the surface, and into the stock tank; all without any external or internal support.
As the gas and oil are taken, water can fill the void left from the hydrocarbons as a result of the region’s lower pressure. This process typically takes years to transpire.
In order for a well to flow, there must be a powerful enough bottomhole pressure to:
- lift the line of fluid through the tubing to the wellhead,
- force the liquid throughout the entire flow line to the tank battery, and
- push the fluid into a pressurized differentiating container; all while maintaining enough pressure for the liquid to push through any additional treatment tanks, ending in the sales or stock container.
To determine the proper amount of pressure, most lease pumpers use a common guideline stating if a mineral well contains a standing flow of fluid, and a wellhead pressure of 100 pounds; there will be ample enough pressure for natural well flow.
The greater the pressure, the larger the maximum yield capacity and the easier the well flow.
Figure 1. An example of a wellhead for a natural flowing well. (ABB Vetco Gray)
To prevent the surge effect from occurring, packers are often installed around the tubing string base in the well flow annulus. Without a large bottomhole pressure or a packer, the flowing well will have inconsistent productivity.
For example: if the flowing well did not contain a packer, and mainly produced gas with little to no fluid amounts for small intervals of time; the majority of the fluid within the casing and tubing will originate near the tank battery.
Once the casing has depleted of fluid, the gas pressure within the annulus will splinter throughout the entire area and inside the tubing perforations. The abrupt increase in gas will remove the majority of the fluid within the well, all the way up to the tank battery.
However, once the loss of gas occurs, there will be a significant drop in gas pressure in the casing throughout the entire system. Once this pressure depletes, and the fluid starts to once again pool in the well’s base, the casing pressure operates as a flow buffer or pressure surge tank.
In order for the well to flow again, it will require the casing pressure to improve to a level that will grant the well the ability to cultivate enough bottomhole pressure. This unpredictable well flow activity is often reduced and/or eliminated by situating a packer near the base.
However, flowing wells with extremely high volumes generally do not have packers, and can be produced throughout the casing.
Packers are removed once a well is no longer flowing naturally. It is then transformed from a flowing well into a pumped well.
Once the packer is removed, and all is said and done, the casing valve will be constantly open to the tank battery to remove the formation of bottomhole pressure. Near the wellhead, a check valve is positioned to prohibit oil from being forced out of the tubing and flowing back down into the casing.
This allows the bottomhole pressure to deplete to the weight of the separator pressure, the flow line resistance, and the weight of the fluid line within the annulus.
However, the lease pumper must constantly be mindful of any and all situations that could change this delicate harmony; because even the smallest changes can affect the well’s oil productivity.
For instance, if the lease pumper were to make a five pound increase to the separator pressure; then the formation pressure will also have been increased by five pounds, and the oil productivity will consequently diminish. Once the gas production has reached the trace classifications, casing valves can be exposed to the air and atmosphere.
Generating Flowing Wells
Generally a flowing well contains a Christmas tree comprising of: a wing valve, a variable choke valve, a master gate valve, a positive choke, and a pressure gauge; with each Christmas tree containing at least one check valve.
To fully understand how this works, make sure you educate yourself in the basics of each area.
Figure 2 – An example of a typical flowing well Christmas tree configuration containing a: check valve, flow line, master gate valve, wing valve, and variable choke.
Whether or not a packer is utilized in the annular space at the base of the well, a casing valve (a multiple round opening gate valve) is almost always fastened to the Christmas tree and to the flow line towards the tank battery. This allows the casing valve to be bled down, closed, opened, or even to permit the flowing well to advance to the casing and tubing. In cases where packers are utilized, this connection isn’t used until the packer is either loosened or completely removed.
The casing valve can generally tolerate high pressures; and similar to wing valves, do not have to use a full opening. This type of valve is often utilized to help determine if the tubing or packer has developed a leak.
Check valves are generally inserted as soon as the flow line vacates the well, a second one is typically placed near the well’s tank battery; or to be more precise where the tank battery separator head meets the well’s flow line.
Some lease operators prefer to have the check valve directly behind the wing valve, yet still in front of the choke valve; while others prefer to place it close to the ground, near the tank battery.
Having the optional check valve along with the ground level option, allows for the Christmas tree and riser pipe to be easily eliminated when they are no longer needed. Depending on the operator or company, all three may be installed.
This type of valve is made of a superior grade valve. It has the ability to open up to match the inside tubing, which allows any specialized tools that may be required to pass through. Master gate valves require the ability to hold the entire pressure of any anticipated events that could occur to ensure well safety. This valve typically remains unblocked, and it is not utilized as a butterfly valve (or throttling valve) for controlling production flow.
In most cases, the Christmas tree atop the well (see Figure 3) contains the positive choke, or it is located at the inlet manifold immediately in front of the first separating vessel (see Figure 4). However, many operators are known for using positive chokes at each site.
Figure 3 – Example of a positive choke situated atop the wellhead.
Figure 4 – Example of a positive choke placed near the tank battery.
An unmistakeable advantage to using the variable choke instead of a positive choke is the ability to easily change the settings. Positive chokes can easily regulate the flow, allowing the well to match the proper daily productivity levels.
This is accomplished utilizing a correctly sized flow bean. As shown in Figure 5, these beans are offered in 74 different sizes and are created to permit an increase in flow from anywhere from 5-10%.
Figure 5 – A chart showcasing the various flow bean insert sizes available to use with positive choke valves. (Cooper Cameron Valves)
This type of gauge is made of a high-pressure steel. It is typically situated just atop of the well’s master gate valve. It will also have a ½ inch needle valve (including gauge), and a tapped bull plug.
Each of the high pressure needle valves can be used in 90 degree (ell) and 180 degree (straight) options. This allows the worker to read the valve pressure from a favorable angle.
Figure 6 – Example of a valve with pressure gauge located atop the well.
Variable Flow Choke Valve
This type of valve is generally a type of extremely large needle valve. It has a calibrated opening for workers, so the device can be customized using 1/64 inch sized measurements.
Variable flow choke valves are very expensive; and are typically made of stainless steel, steel, or tungsten carbide steel. Since the valve requires the ability to tolerate the high speed flow of the various abrasive materials, a high quality steel must be used. In most cases, this will help safeguard against damages for several years.
Figure 7 – Example of variable choke valve with a unibolt (or wellhead) design. To help illustrate the flow path and quality of the steel, a section of the device has been removed. If you look closely, you can see where the two union joint halves meet; it contains a seal ring like the ones you would see on a wellhead section, and/or a Christmas tree. This allows the seal to withstand high pressures of up to several thousand pounds. (Cooper Cameron Valves)
Due to financial reasons and the productivity volume, ¾ inch valves are most commonly used. However, high productivity wells typically require variable choke valves of 1 inch or more.
Each valve is carefully marked to identify the specific opening size. You can indicate the size of a fully open valve by the last number. For instance, if the valve is 32; it is 32/64ths or ½ inch.
It is important to keep up with all aspects of the well. For instance, if there is any paraffin or salt water in the oil, it can cause the opening to clog. Therefore, it is recommended to periodically have the choke open to higher settings for short intervals; followed by periods of opening and closing it back up. This allows the well flow to clean out the seat and eliminate any buildup gathered within the variable flow choke valve.
On occasion, this type of valve can be set to productivity speeds permitting water to collect at the base of the well by dropping back down through the tubing string. As the water pools, it will slowly start to prevent the oil productivity; and at times, can even destroy the well.
When this occurs, it will be necessary to use a swabbing unit to swab from the tank battery to the water blanket in order to obtain proper flow. Increasing the flow rate in the choke by widening the opening for short intervals can help to prevent this issue.
A wing valve can be either a multi-round opening valve or a quarter-round opening. Often times lease operators will utilize plug valves; but in recent years, the ball valve has become increasingly popular due to its operational ease, and great economical value.
However, wing valves are customarily used to shut a well. This is due to their ability to easily read the tubing pressure.
Highly Proficient Lease Pumpers and Stripper Wells
Whenever bottomhole pressure decreases, there will always be a corresponding reaction (or downturn) in gas and oil productivity. During this lower productivity stretch (or as the reservoir hydrocarbons near exhaustion), the well is commonly referred to as a marginally producing well, or a stripper well.
As the stripper well’s productivity diminishes, lease operators will be required to determine if an artificial lift system should be utilized.
In most cases, a flowing well’s maximum lifespan (before it requires an artificial lift) is determined by the lease operator. One of the most vital skills for operators is the competence for making the best decisions for the productivity and longevity of each well during the marginally productive period before installing the artificial lift.
Some lease pumpers have the experience, interest, patience, and ability to perceive what is occurring downhole that allows them the ability to generate productivity months (or even years) longer than others; while other may never accurately establish this ability. Skilled pumpers know it takes time and experience to understand rocking a well. (A process where you bleed pressure from a depleted well. First from the tubing, then the casing, and so forth; so that the well may come back to life.)
This ability can not only create satisfactory productivity levels with lower down time; but it can also extend the lifespan of the flowing well before it requires an artificial lift.