drilling mud pump pressure price

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There are three types of mud pumps, depending on the type of client and the size they want. For general, mud pumps, there are three basic types of mud pumps, depending on the type of client and budget. The piston pump is another compressed mud pump, which is a pushed electric compressor mud pumps and by compressed air.@@@@@

Electric mud pumps are largely divided into three categories, among them the electric mud pumps and the semi-trash mud pumps. The piston inflated mud pumps are also classified in terms of the type of mud pumps, among them are electric mud pumps and semi-trash mud pumps. In addition, the piston inflates mud and mud pumps will be inflated by the piston, which is inflated mud pumps.

Boy, oh boy, is it hot! It is 104 degrees here in the Texas sun. This hot weather and some questions from a colleague lead me to today’s column on drilling fluid hydraulics.

I arrived in Fort Worth, Texas, some 20-plus years ago a few months before the annual summer heat hit. A common drilling problem in this area is bit balling and drill cuttings packing off around the drill bit, drill collars, and stabilizers when drilling in some of the local formations.

Now for the hot weather tie-in. I had to go to a drilling location to troubleshoot a slow penetration rate and bit-balling problem. As I recall, the temperature was 109 degrees—and I don’t think there was any shade for 109 miles!

The driller was following my suggestions (made from the comfort of my air-conditioned truck) for his drilling fluid product mix but was unhappy with the results and the cost in relation to the footage drilled.

Drilling fluid alone didn’t solve the problem in this case. We must also consider if the drilling fluid products were mixed correctly so they can perform their intended purposes (addressed in a previous column).

What type of drill bit are we using (roller cone with teeth or buttons, drag bit, PDC)? What are we using for a mud pump (centrifugal or piston)? How much flow (gallons per minute) and pressure (pounds per square inch) do we have available?

Hydraulics describes how fluid flow inside tubulars and annular spaces uses pressure. Mechanical force (pressure) is supplied by the mud pump—a push or pull which tends a system to change its state of rest or motion.

The relationship of physical properties of a drilling fluid in conjunction with a shear stress (pumping pressure) and a shear rate (velocity of the fluid or flow rate) is termed rheological behavior. Bits, pumps, flow rate and pump pressure, and drilling fluid rheological properties all relate to fluid hydraulics.

Drilling fluid design can minimize this effect. Full control needs optimization of drilling fluid hydraulics. As was noted, hydraulics uses pressure and volume produced by the mud pump. If we can focus the pressure and flow against the cutting structure of the bit, we can keep the cutting surfaces clean; in effect, we will be blasting these surfaces clean with high-pressure fluid flow.

The same principle applies to digging a hole with a shovel and the sticky soil sticking to the shovel. Just washing it with an open-ended garden hose doesn’t clean it off, but when you add a nozzle or put your thumb across the end to create pressure, that can clean your shovel.

The pressure in our system comes from the mud pump. We know that the pressure of the fluid at the pump is greater than the pressure of the fluid as the fluid exits the borehole.

So, if the pressure gauge at the pump is reading 500 psi and the pressure is effectively zero as the fluid exits the borehole, where did the pressure go? In its simplest form, the available pressure is lost due to overcoming the internal friction of the moving fluid, the friction of passing through the drill string and drill bit, and moving against the borehole walls.

If we were to run hydraulics optimization software, we would find that 50% to 65% of the total pressure available is lost at the bit and provides the best case for cutting surface cleaning and maximum penetration rate. Therefore, we need to minimize the pressure losses at all other points in the system to maximize the pressure available at the bit.

Internally overcoming friction is really overcoming the resistance to flowing, which we have previously defined as viscosity. The total solids content of the drilling fluid (measured as density) and how these solids interact with each other (measured as plastic viscosity and yield point) are used in pressure loss calculations.

In short, a lighter fluid with minimal solids and controlled rheology (see previous columns) has less pressure loss while flowing and therefore more of the total system pressure is available to be lost at the bit.

Pressure is also lost inside the hoses and drill pipe as the flowing fluid interacts with the inside surfaces of these tubulars. And there is pressure loss in the annular spaces with two surfaces for the drilling fluid to interact with: the outside surface of the drill string and the borehole wall.

Inside our tubulars, turbulent flow can be expected due to pumping volume and rather small internal diameter. Luckily, drill steel will not be eroded by this turbulent flow.

The annulus is a much different environment. We do not want erosion of the borehole walls and we have added drilled cuttings to the drilling fluid that need to be transported to the surface. The magnitude of annular pressure loss is a function of type of flow, annular velocity, and mud properties, requiring laminar flow to maintain borehole wall integrity and effective cuttings transport. An uphole annular velocity of 60 to 120 feet per minute usually meets our requirements.

Rheology and hydraulics calculations provide the means for adjusting the drilling fluid’s properties, the flow rate, and bit nozzle size to optimize system pressure losses under the constraints imposed by the rig equipment.

Exploring this statement may answer some questions about pump type and bit design. The previous discussion would be primarily suited to positive displacement or piston pumps and drill bits that allow for adjusting the bit nozzle size.

Many of you drill with centrifugal pumps and use drill bits with no nozzles or open centers. Sure, you can drill with centrifugal pumps. They do allow for high flow rates, but they also lose efficiency with higher viscosity drilling fluids, have limited pressure limits, and lose efficiency with depth.

The impeller is an extremely high shear point and will break down cuttings to very small sizes that may not be removed from the drilling fluid, thus increasing the fluid’s density. These limitations may or may not be an issue in your local area.

Centrifugal pumps do not work as well as positive displacement pumps when using jetted bits. Often the jets are too restrictive and too much pressure is lost at this point, so open center bits are preferred. Hole cleaning and cutting surface cleaning are accomplished by drilling fluid chemistry and flow volume. Hydraulics optimization is seldom used when drilling with centrifugal pumps.

They work well in many geologic environments, but they do have one big drawback, especially when drilling soft formations such as in the example we discussed earlier.

You can create a “cutting” so large that it can’t be suspended or transported by the drilling fluid. It may be too large to even get past the side of the bit or fit in the annular space around drill collars or stabilizers. This causes packing off and restricts flow. Sometimes these sausages can’t be pumped out of the hole and must be pulled out by tripping out of the hole. In general, drag bits are not good candidates for hydraulics optimization.

The major goal of hydraulics optimization is to balance hole cleaning, pump pressure, and pressure drop across the bit. The drilling fluid’s density and rheological properties are the parameters that affect this hydraulic efficiency.

Returning to our story: It was hot and dry on location. The driller was using my recommended drilling fluid product mix, the crew mixed the products correctly, and they were still only making about 20 feet of new hole every couple of hours.

We looked at each part of the system, using the system approach to troubleshooting. We knew the geology was clay and a shale rock that easily got water wet and sticky. Mud system checked out for this geology. Piston pump for pressure and flow, poor flow coming out of the hole. Long-tooth bit should handle the formations. What’s missing?

We tripped the bit out of the hole and found it all balled up and mud and cuttings packed off around the stabilizer. It was obvious we were not cleaning the cuttings away from the bit teeth and insufficient flow to move them up into the flow stream and to the surface.

It took some convincing and a long discussion about hydraulics optimization, but the driller decided to try something different. He welded some half-inch washers across the jet seats to mimic real bit jets. After tripping back in the hole, continuing with the proper drilling fluid mix, controlling the rate of penetration to allow the circulating fluid pressure to clean the cutting surfaces and the fluid flow to entrain and carry the drill cuttings—the driller made 400 feet that day! I got sunburned but we were successful.

Drilling fluid hydraulics optimization can make a huge difference in your results. You don’t need full-fledged computing power to understand the concepts and get meaningful results.

We didn’t use any math today at all. Know the geology. Formulate the proper drilling fluid and choose the best bit and pump with as much fluid pressure as you can. Put it to work for you.

Drilling in the North Sea is confronted with an ever more challenging pressure management issue due to narrow geo-pressure windows in depleted reservoirs. Further, the occurrence of pack-offs can cause serious damage to the formation and contribute to non-productive time. To address these problems, automation of mud pump management has been developed over the last four years to minimize the chance of fracturing the formation while starting the mud pumps or circulating. To account for abnormal flow restrictions in the annulus, automatic actions are also an integral part of the mud pump automation described in this paper.

Since the downhole conditions are continuously changing (depth, temperature, flow-rate, gel time, cuttings proportion, etc), the necessary safe guards to operate the mud pumps need to be updated constantly. Advanced transient temperature and hydraulic models are used to estimate, in real-time, the downhole situation. Based on the current context, evaluation of maximum pump rates and acceptable flow accelerations are performed and sent to the mud pump control system to be used as an envelope of protection. Furthermore, to assist the Driller during connections, the pump start-up procedure has been semi-automated in order to decrease connection time. Finally, an automatically triggered pump shutdown procedure is also available to minimize the consequences of a pack-off on formation fracturing.

A first version of the system has been tested during the drilling of one well in 2008 in the North Sea. Based on the initial experience, a revised version has been used during the drilling of three wells drilled on the Norwegian Continental Shelf in 2009. The feedback from the Drillers involved in the testing has been used to improve the user friendliness of the system. The automation of the mud pump management has been well accepted by the drilling crews. However, the testing has shown that additional instrumentation at the rig site is necessary before such automation can be rolled out safely.

A well-placed suction stabilizer can also prevent pump chatter. Pump chatter occurs when energy is exchanged between the quick opening and closing of the reciprocating pump’s valves and the hammer effect from the centrifugal pump. Pump isolation with suction stabilizers is achieved when the charge pumps are isolated from reciprocating pumps and vice versa. The results are a smooth flow of pumped media devoid of agitating energies present in the pumped fluid.

Suction stabilizer units can mitigate most of the challenges related to pulsations or pressure surges, even in the most complex piping conditions. The resulting benefits prevent expensive unplanned downtime and decrease costs and inconvenience associated with system replacements and repairs.

The X-series mud pump type PD X-3.004 SG HDD manufactured by PRIME DRILLING impresses with its robust and low-wear design. The 7-fold bearing mounted drive shaft, which is equipped with 3 eccentric wheels, replaces the conventional crankshaft. Due to the revolution of these shafts and their maximum 230 rotations per minute operational wear of rubbers and liners are reduced to a minimum.

The pump is driven by a 470 kW CAT engine. This type of mud pump is exclusively manufactured in our Wenden plant, i.e. „made in Germany“. Its electronic gearshift in combination with eccentric wheels used instead of a crankshaft make it a high- power but low- maintenance product. All valves and plungers also comply with API standards.