mud pump that gives sufficient flowrate but not enough pressure made in china

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The 2,200-hp mud pump for offshore applications is a single-acting reciprocating triplex mud pump designed for high fluid flow rates, even at low operating speeds, and with a long stroke design. These features reduce the number of load reversals in critical components and increase the life of fluid end parts.

The pump’s critical components are strategically placed to make maintenance and inspection far easier and safer. The two-piece, quick-release piston rod lets you remove the piston without disturbing the liner, minimizing downtime when you’re replacing fluid parts.

GDEP is the original creator of the drilling pump and continues to set the standard for durable, high-quality drilling pumps that can withstand the world’s toughest drilling environments. Starting with our PZ7 and rounding out with the market"s most popular pump, the PZ1600, our PZ Series of pumps are the perfect choice for today"s high-pressure drilling applications.

When choosing a size and type of mud pump for your drilling project, there are several factors to consider. These would include not only cost and size of pump that best fits your drilling rig, but also the diameter, depth and hole conditions you are drilling through. I know that this sounds like a lot to consider, but if you are set up the right way before the job starts, you will thank me later.

Recommended practice is to maintain a minimum of 100 to 150 feet per minute of uphole velocity for drill cuttings. Larger diameter wells for irrigation, agriculture or municipalities may violate this rule, because it may not be economically feasible to pump this much mud for the job. Uphole velocity is determined by the flow rate of the mud system, diameter of the borehole and the diameter of the drill pipe. There are many tools, including handbooks, rule of thumb, slide rule calculators and now apps on your handheld device, to calculate velocity. It is always good to remember the time it takes to get the cuttings off the bottom of the well. If you are drilling at 200 feet, then a 100-foot-per-minute velocity means that it would take two minutes to get the cuttings out of the hole. This is always a good reminder of what you are drilling through and how long ago it was that you drilled it. Ground conditions and rock formations are ever changing as you go deeper. Wouldn’t it be nice if they all remained the same?

Centrifugal-style mud pumps are very popular in our industry due to their size and weight, as well as flow rate capacity for an affordable price. There are many models and brands out there, and most of them are very good value. How does a centrifugal mud pump work? The rotation of the impeller accelerates the fluid into the volute or diffuser chamber. The added energy from the acceleration increases the velocity and pressure of the fluid. These pumps are known to be very inefficient. This means that it takes more energy to increase the flow and pressure of the fluid when compared to a piston-style pump. However, you have a significant advantage in flow rates from a centrifugal pump versus a piston pump. If you are drilling deeper wells with heavier cuttings, you will be forced at some point to use a piston-style mud pump. They have much higher efficiencies in transferring the input energy into flow and pressure, therefore resulting in much higher pressure capabilities.

Piston-style mud pumps utilize a piston or plunger that travels back and forth in a chamber known as a cylinder. These pumps are also called “positive displacement” pumps because they literally push the fluid forward. This fluid builds up pressure and forces a spring-loaded valve to open and allow the fluid to escape into the discharge piping of the pump and then down the borehole. Since the expansion process is much smaller (almost insignificant) compared to a centrifugal pump, there is much lower energy loss. Plunger-style pumps can develop upwards of 15,000 psi for well treatments and hydraulic fracturing. Centrifugal pumps, in comparison, usually operate below 300 psi. If you are comparing most drilling pumps, centrifugal pumps operate from 60 to 125 psi and piston pumps operate around 150 to 300 psi. There are many exceptions and special applications for drilling, but these numbers should cover 80 percent of all equipment operating out there.

The restriction of putting a piston-style mud pump onto drilling rigs has always been the physical size and weight to provide adequate flow and pressure to your drilling fluid. Because of this, the industry needed a new solution to this age-old issue.

Enter Cory Miller of Centerline Manufacturing, who I recently recommended for recognition by the National Ground Water Association (NGWA) for significant contributions to the industry.

As the senior design engineer for Ingersoll-Rand’s Deephole Drilling Business Unit, I had the distinct pleasure of working with him and incorporating his Centerline Mud Pump into our drilling rig platforms.

In the late ’90s — and perhaps even earlier —  Ingersoll-Rand had tried several times to develop a hydraulic-driven mud pump that would last an acceptable life- and duty-cycle for a well drilling contractor. With all of our resources and design wisdom, we were unable to solve this problem. Not only did Miller provide a solution, thus saving the size and weight of a typical gear-driven mud pump, he also provided a new offering — a mono-cylinder mud pump. This double-acting piston pump provided as much mud flow and pressure as a standard 5 X 6 duplex pump with incredible size and weight savings.

The true innovation was providing the well driller a solution for their mud pump requirements that was the right size and weight to integrate into both existing and new drilling rigs. Regardless of drill rig manufacturer and hydraulic system design, Centerline has provided a mud pump integration on hundreds of customer’s drilling rigs. Both mono-cylinder and duplex-cylinder pumps can fit nicely on the deck, across the frame or even be configured for under-deck mounting. This would not be possible with conventional mud pump designs.

Centerline stuck with their original design through all of the typical trials and tribulations that come with a new product integration. Over the course of the first several years, Miller found out that even the best of the highest quality hydraulic cylinders, valves and seals were not truly what they were represented to be. He then set off on an endeavor to bring everything in-house and began manufacturing all of his own components, including hydraulic valves. This gave him complete control over the quality of components that go into the finished product.

The second generation design for the Centerline Mud Pump is expected later this year, and I believe it will be a true game changer for this industry. It also will open up the application to many other industries that require a heavier-duty cycle for a piston pump application.

Horizontal drilling and completion are common practice for accessing conventional and heavy oil reservoirs. During the drilling process, the formation pore pressure is less than the drilling fluid"s hydrostatic pressure. This can lead to some fluid loss before a filter cake is formed to prevent further mud losses. For unconsolidated formations, it is prefer to keep the filter cake in the place to maintain the hole"s integrity during the well completion period while running the liner. However, the filter cake can be broken down by the sliding and rotating of the bottom hole assembly. These breakdowns can lead to high completion fluid losses to the formation. Sand production is also a common problem associated with unconsolidated formations. These drilling & completion practices, sand production, have resulted in a demand for well intervention that can economically remove mud damage and produced fill throughout the whole length of horizontal wells.

Since 1995, a technology combining concentric coiled tubing (CCT) with a jet pump has been developed and used to remove both the drilling fluids, filter cake and solids. Initially it was developed for horizontal heavy oil reservoirs where pressures are low and oil viscosity is high, without placing hydrostatic loads on the reservoir. The job data from more than 600 sand/well vacuuming operations worldwide has been compiled into a database.

This paper reviews the well information and the key operating parameters: maximum depth, bottom hole pressure gradient and pump rate. The engineering challenges, best practices and lessons learned from the sand/well vacuuming process are also summarized. Analysis of this data yields a better understanding about the vacuuming technology and provides good guideline for future operations.

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I’ve run into several instances of insufficient suction stabilization on rigs where a “standpipe” is installed off the suction manifold. The thought behind this design was to create a gas-over-fluid column for the reciprocating pump and eliminate cavitation.

When the standpipe is installed on the suction manifold’s deadhead side, there’s little opportunity to get fluid into all the cylinders to prevent cavitation. Also, the reciprocating pump and charge pump are not isolated.

Another benefit of installing a suction stabilizer is eliminating the negative energies in fluids caused by the water hammer effect from valves quickly closing and opening.

The suction stabilizer’s compressible feature is designed to absorb the negative energies and promote smooth fluid flow. As a result, pump isolation is achieved between the charge pump and the reciprocating pump.

The isolation eliminates pump chatter, and because the reciprocating pump’s negative energies never reach the charge pump, the pump’s expendable life is extended.

Investing in suction stabilizers will ensure your pumps operate consistently and efficiently. They can also prevent most challenges related to pressure surges or pulsations in the most difficult piping environments.

Sigma Drilling Technologies’ Charge Free Suction Stabilizer is recommended for installation. If rigs have gas-charged cartridges installed in the suction stabilizers on the rig, another suggested upgrade is the Charge Free Conversion Kits.

A kick is a well control problem in which the pressure found within the drilled rock is higher than the mud hydrostatic pressure acting on the borehole or rock face. When this occurs, the greater formation pressure has a tendency to force formation fluids into the wellbore. This forced fluid flow is called a kick. If the flow is successfully controlled, the kick is considered to have been killed. An uncontrolled kick that increases in severity may result in what is known as a “blowout.”

Several factors affect the severity of a kick. One factor, for example, is the “permeability” of rock, which is its ability to allow fluid to move through the rock. Another factor affecting kick severity is “porosity.” Porosity measures the amount of space in the rock containing fluids. A rock with high permeability and high porosity has greater potential for a severe kick than a rock with low permeability and low porosity. For example, sandstone is considered to have greater kick potential than shale, because sandstone has greater permeability and greater porosity than shale.

Yet another factor affecting kick severity is the “pressure differential” involved. Pressure differential is the difference between the formation fluid pressure and the mud hydrostatic pressure. If the formation pressure is much greater than the hydrostatic pressure, a large negative differential pressure exists. If this negative differential pressure is coupled with high permeability and high porosity, a severe kick may occur.

A kick can be labeled in several ways, including one that depends on the type of formation fluid that entered the borehole. Known kick fluids include:

Another way of labeling kicks is by identifying the required mud weight increase necessary to control the well and kill a potential blowout. For example, if a kick required a 0.7-lbm/gal (84-kg/m3) mud weight increase to control the well, the kick could be termed a 0.7-lbm/gal (84-kg/m3) kick. It is interesting to note that an average kick requires approximately 0.5 lbm/gal (60 kg/m3), or less, mud weight increase.

Kicks occur as a result of formation pressure being greater than mud hydrostatic pressure, which causes fluids to flow from the formation into the wellbore. In almost all drilling operations, the operator attempts to maintain a hydrostatic pressure greater than formation pressure and, thus, prevent kicks; however, on occasion the formation will exceed the mud pressure and a kick will occur. Reasons for this imbalance explain the key causes of kicks:

Insufficient mud weight is the predominant cause of kicks. A permeable zone is drilled while using a mud weight that exerts less pressure than the formation pressure within the zone. Because the formation pressure exceeds the wellbore pressure, fluids begin to flow from the formation into the wellbore and the kick occurs.

These abnormal formation pressures are often associated with causes for kicks. Abnormal formation pressures are greater pressures than in normal conditions. In well control situations, formation pressures greater than normal are the biggest concern. Because a normal formation pressure is equal to a full column of native water, abnormally pressured formations exert more pressure than a full water column. If abnormally pressured formations are encountered while drilling with mud weights insufficient to control the zone, a potential kick situation has developed. Whether or not the kick occurs depends on the permeability and porosity of the rock. A number of abnormal pressure indicators can be used to estimate formation pressures so that kicks caused by insufficient mud weight are prevented (some are listed in Table 1).

An obvious solution to kicks caused by insufficient mud weights seems to be drilling with high mud weights; however, this is not always a viable solution. First, high mud weights may exceed the fracture mud weight of the formation and induce lost circulation. Second, mud weights in excess of the formation pressure may significantly reduce the penetration rates. Also, pipe sticking becomes a serious consideration when excessive mud weights are used. The best solution is to maintain a mud weight slightly greater than formation pressure until the mud weight begins to approach the fracture mud weight and, thus, requires an additional string of casing.

Improperly filling up of the hole during trips is another prominent cause of kicks. As the drillpipe is pulled out of the hole, the mud level falls because the pipe steel no longer displaces the mud. As the overall mud level decreases, the hole must be periodically filled up with mud to avoid reducing the hydrostatic pressure and, thereby, allowing a kick to occur.

Several methods can be used to fill up the hole, but each must be able to accurately measure the amount of mud required. It is not acceptable—under any condition—to allow a centrifugal pump to continuously fill up the hole from the suction pit because accurate mud-volume measurement with this sort of pump is impossible. The two acceptable methods most commonly used to maintain hole fill-up are the trip-tank method and the pump-stroke measurements method.

The trip-tank method has a calibration device that monitors the volume of mud entering the hole. The tank can be placed above the preventer to allow gravity to force mud into the annulus, or a centrifugal pump may pump mud into the annulus with the overflow returning to the trip tank. The advantages of the trip-tank method include that the hole remains full at all times, and an accurate measurement of the mud entering the hole is possible.

The other method of keeping a full hole—the pump-stroke measurement method—is to periodically fill up the hole with a positive-displacement pump. A flowline device can be installed with the positive-displacement pump to measure the pump strokes required to fill the hole. This device will automatically shut off the pump when the hole is full.

Pulling the drillstring from the borehole creates swab pressures. Swab pressures are negative, and reduce the effective hydrostatic pressure throughout the hole and below the bit. If this pressure reduction lowers the effective hydrostatic pressure below the formation pressure, a potential kick has developed. Variables controlling swab pressures are:

Gas-contaminated mud will occasionally cause a kick, although this is rare. The mud density reduction is usually caused by fluids from the core volume being cut and released into the mud system. As the gas is circulated to the surface, it expands and may reduce the overall hydrostatic pressure sufficient enough to allow a kick to occur.

Although the mud weight is cut severely at the surface, the hydrostatic pressure is not reduced significantly because most gas expansion occurs near the surface and not at the hole bottom.

Occasionally, kicks are caused by lost circulation. A decreased hydrostatic pressure occurs from a shorter mud column. When a kick occurs from lost circulation, the problem may become severe. A large volume of kick fluid may enter the hole before the rising mud level is observed at the surface. It is recommended that the hole be filled with some type of fluid to monitor fluid levels if lost circulation occurs.

Warning signs and possible kick indicators can be observed at the surface. Each crew member has the responsibility to recognize and interpret these signs and take proper action. All signs do not positively identify a kick; some merely warn of potential kick situations. Key warning signs to watch for include the following:

An increase in flow rate leaving the well, while pumping at a constant rate, is a primary kick indicator. The increased flow rate is interpreted as the formation aiding the rig pumps by moving fluid up the annulus and forcing formation fluids into the wellbore.

If the pit volume is not changed as a result of surface-controlled actions, an increase indicates a kick is occurring. Fluids entering the wellbore displace an equal volume of mud at the flowline, resulting in pit gain.

When the rig pumps are not moving the mud, a continued flow from the well indicates a kick is in progress. An exception is when the mud in the drillpipe is considerably heavier than in the annulus, such as in the case of a slug.

A pump pressure change may indicate a kick. Initial fluid entry into the borehole may cause the mud to flocculate and temporarily increase the pump pressure. As the flow continues, the low-density influx will displace heavier drilling fluids, and the pump pressure may begin to decrease. As the fluid in the annulus becomes less dense, the mud in the drillpipe tends to fall and pump speed may increase.

Other drilling problems may also exhibit these signs. A hole in the pipe, called a “washout,” will cause pump pressure to decrease. A twist-off of the drillstring will give the same signs. It is proper procedure, however, to check for a kick if these signs are observed.

When the drillstring is pulled out of the hole, the mud level should decrease by a volume equivalent to the removed steel. If the hole does not require the calculated volume of mud to bring the mud level back to the surface, it is assumed a kick fluid has entered the hole and partially filled the displacement volume of the drillstring. Even though gas or salt water may have entered the hole, the well may not flow until enough fluid has entered to reduce the hydrostatic pressure below the formation pressure.

Drilling fluid provides a buoyant effect to the drillstring and reduces the actual pipe weight supported by the derrick. Heavier muds have a greater buoyant force than less dense muds. When a kick occurs, and low-density formation fluids begin to enter the borehole, the buoyant force of the mud system is reduced, and the string weight observed at the surface begins to increase.

An abrupt increase in bit-penetration rate, called a “drilling break,” is a warning sign of a potential kick. A gradual increase in penetration rate is an abnormal pressure indicator, and should not be misconstrued as an abrupt rate increase.

When the rate suddenly increases, it is assumed that the rock type has changed. It is also assumed that the new rock type has the potential to kick (as in the case of a sand), whereas the previously drilled rock did not have this potential (as in the case of shale). Although a drilling break may have been observed, it is not certain that a kick will occur, only that a new formation has been drilled that may have kick potential.

It is recommended when a drilling break is recorded that the driller should drill 3 to 5 ft (1 to 1.5 m) into the sand and then stop to check for flowing formation fluids. Flow checks are not always performed in tophole drilling or when drilling through a series of stringers in which repetitive breaks are encountered. Unfortunately, many kicks and blowouts have occurred because of this lack of flow checking.

Fortunately, the lower mud weights from the cuttings effect are found near the surface (generally because of gas expansion), and do not appreciably reduce mud density throughout the hole. Table 3 shows that gas cutting has a very small effect on bottomhole hydrostatic pressure.

An important point to remember about gas cutting is that, if the well did not kick within the time required to drill the gas zone and circulate the gas to the surface, only a small possibility exists that it will kick. Generally, gas cutting indicates that a formation has been drilled that contains gas. It does not mean that the mud weight must be increased.

Drilling-efficiency data, such as downhole weight on bit and torque, can be used to differentiate between rate of penetration changes caused by drag and those caused by formation strength. Monitoring bottomhole pressure, temperature, and flow with the MWD tool is not only useful for early kick detection, but can also be valuable during a well-control kill operation. Formation evaluation capabilities, such as gamma ray and resistivity measurements, can be used to detect influxes into the wellbore, identify rock lithology, and predict pore pressure trends.

The MWD tool enables monitoring of the acoustic properties of the annulus for early gas-influx detection. Pressure pulses generated by the MWD pulser are recorded and compared at the standpipe and the top of the annulus. Full-scale testing has shown that the presence of free gas in the annulus is detected by amplitude attenuation and phase delay between the two signals. For water-based mud systems, this technique has demonstrated the capacity to consistently detect gas influxes within minutes before significant expansion occurs. Further development is currently under way to improve the system’s capability to detect gas influxes in oil-based mud.

Some MWD tools feature kick detection through ultrasonic sensors. In these systems, an ultrasonic transducer emits a signal that is reflected off the formation and back to the sensor. Small quantities of free gas significantly alter the acoustic impedance of the mud. Automatic monitoring of these signals permits detection of gas in the annulus. It should be noted that these devices only detect the presence of gas at or below the MWD tool.

When a kick occurs, note the type of influx (gas, oil, or salt water) entering the wellbore. Remember that well-control procedures developed here are designed to kill all types of kicks safely. The formula required to make this kick influx calculation is as follows:

where gi = influx gradient, psi/ft; gmdp = mud gradient in drillpipe, psi/ft; and hi = influx height, ft. The influx gradient can be evaluated using the guidelines in Table 1.

It is necessary to calculate the mud weight needed to balance bottomhole formation pressure. “Kill-weight mud” is the amount of mud necessary to exactly balance formation pressure. It will be later shown that it is safer to use the exact required mud weight without variation

Because the drillpipe pressure has been defined as a bottomhole pressure gauge, the psidp can be used to calculate the mud weight necessary to kill the well. The kill mud formula follows:

Because the casing pressure does not appear in Eq. 2, a high casing pressure does not necessarily indicate a high kill-weight mud. The same is true for pit gain because it does not appear in Eq. 2. Example 1 uses the kill-weight mud formula.

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