drilling mud pump output free sample

Rig pump output, normally in volume per stroke, of mud pumps on the rig is  one of important figures that we really need to know because we will use pump out put figures to calculate many parameters such as bottom up strokes,  wash out depth, tracking drilling fluid, etc. In this post, you will learn how to calculate pump out put for triplex pump and duplex pump in bothOilfield and Metric Unit.

Bourgoyne, A.J.T., Chenevert , M.E. & Millheim, K.K., 1986. SPE Textbook Series, Volume 2: Applied Drilling Engineering, Society of Petroleum Engineers.

Oil and Gas drilling process - Pupm output for Triplex and Duplex pumpsTriplex Pump Formula 1 PO, bbl/stk = 0.000243 x ( in) E.xample: Determine the pump output, bbl/stk, at 100% efficiency for a 7" by 12". triplex pump: PO @ 100%,= 0.000243 x 7 x12 PO @ 100% = 0.142884bbl/stk Adjust the pump output for 95% efficiency: Decimal equivalent = 95 + 100 = 0.95 PO @ 95% = 0.142884bbl/stk x 0.95 PO @ 95% = 0.13574bbl/stk Formula 2 PO, gpm = [3(D x 0.7854)S]0.00411 x SPM where D = liner diameter, in. S = stroke length, in. SPM = strokes per minute Determine the pump output, gpm, for a 7" by 12". triplex pump at 80 strokes per minute: PO, gpm = [3(7 x 0.7854) 1210.00411 x 80 PO, gpm = 1385.4456 x 0.00411 x 80 PO = 455.5 gpm

Example:Duplex Pump Formula 1 0.000324 x (liner diameter, in) x ( stroke lengh, in) = ________ bbl/stk -0.000162 x (rod diameter, in) x ( stroke lengh, in) = ________ bbl/stk Pump out put @ 100% eff = ________bbl/stk Example: Determine the output, bbl/stk, of a 5 1/2" by 14" duplex pump at 100% efficiency. Rod diameter = 2.0": 0.000324 x 5.5 x 14 = 0.137214bbl/stk -0.000162 x 2.0 x 14 = 0.009072bbl/stk Pump output @ 100% eff. = 0.128142bbl/stk Adjust pump output for 85% efficiency: Decimal equivalent = 85 100 = 0.85 PO@85%)= 0.128142bbl/stk x 0.85 PO@ 85% = 0.10892bbl/stk Formula 2

PO. bbl/stk = 0.000162 x S[2(D) - d] where S = stroke length, in. D = liner diameter, in. d = rod diameter, in. Example: Determine the output, bbl/stk, of a 5 1/2". by 14". duplex pump @ 100% efficiency. Rod diameter = 2.0in.: PO@100%=0.000162 x 14 x [ 2 (5.5) - 2 ] PO @ 100%)= 0.000162 x 14 x 56.5 PO@ 100%)= 0.128142bbl/stk Adjust pump output for 85% efficiency: PO@85%,= 0.128142bb/stkx 0.85 PO@8.5%= 0.10892bbl/stk Metric calculation Pump output, liter/min = pump output. liter/stk x pump speed, spm. S.I. units calculation Pump output, m/min = pump output, liter/stk x pump speed, spm. Mud Pumps Mud pumps drive the mud around the drilling system. Depending on liner size availability they can be set up to provide high pressure and low flow rate, or low pressure and high flow rate. Analysis of the application and running the Drill Bits hydraulics program will indicate which liners to recommend. Finding the specification of the mud pumps allows flow rate to be calculated from pump stroke rate, SPM. Information requiredo Pump manufacturer o Number of pumps o Liner size and gallons per revolution Weight As a drill bit cutting structure wears more weight will be required to achieve the same RoP in a homogenous formation. PDC wear flats, worn inserts and worn milled tooth teeth will make the bit drill less efficiently. Increase weight in increments of 2,000lbs approx. In general, weight should be applied before excessive rotary speed so that the cutting structure maintains a significant depth of cut to stabilise the bit and prevent whirl. If downhole weight measurements are available they can be used in combination with surface measurements to gain a more accurate representation of what is happening in the well bore.

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.

The gas over fluid internal systems has limitations too. The standpipe loses compression due to gas being consumed by the drilling fluid. In the absence of gas, the standpipe becomes virtually defunct because gravity (14.7 psi) is the only force driving the cylinders’ fluid. Also, gas is rarely replenished or charged in the standpipe.

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.

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.

A comprehensive range of mud pumping, mixing, and processing equipment is designed to streamline many essential but time-consuming operational and maintenance procedures, improve operator safety and productivity, and reduce costly system downtime.

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.

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.

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.

Last month, we started a discussion on drilling fluids viscosity with a look at some terms drillers should know and the basics of viscosity testing. This month, we get into detail to help drillers understand how viscosity affects mud pump performance.

First off, know that all mud pumps are calibrated with water at sea level which, to remind readers, has a 26s viscosity. That means that, at 40s viscosity, you lose 10-15% capacity; at 60s viscosity, up to 30%; and at 80s viscosity, up to 50%. Operators need to take this into account when calculating flow requirements. The gauge on the control panel of the drill does not automatically calculate viscosity, nor is there a magic dial on the pump to take viscosity into account. It is up to us to account for this and apply it correctly.

The above example is for a pilot hole. As tools get bigger, the gaps in capacity increase exponentially. For a 16-inch bore, the math calls for 31.34 gallons per foot; however, if you dial in 32 gallons at 40s, you only pump a little over 26 gallons. Adjust up, and dial in 37 gallons. The difference in volume is directly related to failure or success of our bore.

The gauge on the control panel of the drill does not automatically calculate viscosity, nor is there a magic dial on the pump to take viscosity into account. It is up to us to account for this and apply it correctly.

The reverse applies applied to clays where we require less viscosity and gel strength when drilling. The natural clays break down into fines and work in concert with the bentonite. This means the fines will increase our viscosities and, although a filter cake is required, there is less chance of fluid losses in clay. Using a 35s to 40s fluid is recommended. If we use a 60s to 80s fluid, densities skyrocket quickly, and it will be difficult to flow out the cuttings. We would be just re-constituting the ground conditions behind the drill head and increasing the risk of inadvertent returns on the bore path.

To wrap up our foray into viscosity, last month we attempted to more clearly describe some of the terms you hear in the industry. We also familiarized ourselves with the Marsh funnel and cup to determine viscosity. (People with testing questions can, of course, ask their drilling fluids rep for a demonstration.) This month, we talked about using the proper viscosity for our ground conditions, and wrapped with tips to adjust your flow rate based on the viscosity to ensure the proper amount of fluids downhole and — ultimately — success.

MUDSheet app covers the most essential calculation and data in mud engineering. Designed for mud engineers and drilling engineers, MUDSheet is an app which contains 22 most commonly used calculations, ranging from pipe capacity, pump output to mud additives. We, engineers, are often overwhelmed by the information scattered around in various media forms. Now, the most essential information from engineering handbooks, SPE textbooks, IADC manuals, has been distilled into MUDSheet, a must-have application for every mud engineer and technician to get the job done accurately and efficiently.

For sustainable development of the mineral resources in the Arctic offshore, it is necessary to develop and implement efficient technologies that are suitable for Arctic conditions and safe from an environmental point of view. The construction of oil and gas wells offshore comes with certain problems that hinder efficiency and increase the cost of drilling operations. One of the main challenges before the drilling process is selecting the optimal drilling fluid, which depends on geological conditions, formation pressure, and absorption pressures. It is also necessary to note the system’s ability to preserve the reservoir properties of the productive formation, ensure wellbore stability and integrity; include high zenith angles during the entire drilling interval until its casing; and higher drilling speeds through various sedimentary rocks, such as shale, clay shale, and limestone, etc.

The drilling process is often complicated by the integrity of the borehole walls being compromised by unstable clay deposits (clays, shales, and mudstones). This can result in cavings, rockfalls, borehole constriction, and cavern formation, with cavings becoming more likely with the increase in depth and inclination angle. The increased danger of cavings is caused by the collapse of weakly cemented siltstones and mudstones, which are in contact with solution filtrate; and by plastic flow of montmorillonite clays during osmotic swelling [1]. In order to prevent and eliminate these complications, it is recommended to weight the drilling mud or use systems with low water loss. However, worldwide experience in offshore drilling has shown that such actions do not fully exclude borehole stability disruption [2].

The drilling of easily swollen clays disperses them and produces an increased amount of colloidal particles, resulting in complications, such as pinches, landings, sticking, packing, and reduced efficiency of the flushing system. Consequently, when selecting drilling fluids for drilling in caving zones, the density and water loss of the flushing fluid are not the determining factors. Under these conditions, the choice should be made in favor of the most inert drilling system in contact with unstable formations [3,4].

In order to improve the quality of drilling-in the formation, the solution must be designed to reduce the natural permeability of the productive interval slightly or not at all, in order to provide excellent borehole cleaning and to facilitate further development of the well [5,6]. In addition to being safe and economical to use, drilling-in solutions must be compatible with natural fluids to avoid salt deposition or emulsion formation [1,7]. A suitable non-polluting fluid should form a filter cake on the formation surface, but should not penetrate too deeply into its pore section. The mud filtrate should also prevent swelling of active clay particles within the pore base [8].

When constructing wells in the Arctic offshore, it is advisable to opt for environmentally safe drilling fluids. One of the criteria for the safety of reagents for offshore drilling is the HCMS (Harmonised Mandatory Control Scheme), developed within the framework of the international Oslo–Paris agreement in 2002 [9,10,11]. This assessment is carried out to determine the possible environmental impact of a chemical release at sea in the event of an accident or spill [12]. The research is based on controlling ocean algae growth inhibition and biodegradability in seawater. Only those reagents that pass safety testing are eligible for use in drilling fluids used in offshore drilling and especially under Arctic conditions [13,14].

The drilling of oil and gas wells under offshore conditions has a special focus on the disposal of drilling sludge, which has a negative impact on the environment. Environmental pollution is much greater with the use of hydrocarbon drilling systems than with water-based muds [9,15,16]. Drilling sludge is a mixture of drilling mud and drill cuttings, which, on contact, adsorb on the surface various components of the drilling mud and, as such, remain on the drilling site for a long time, in particular, in sludge pits [17,18].

All of the above-mentioned complications of offshore drilling increase the cost of drilling operations in the Arctic shelf environment. Therefore, search, development, and improvement of environmentally safe drilling muds on the water basis, containing different additives that could give properties similar to those of solutions on the hydrocarbon base, without negative influence on the environment, is a very urgent task.

Existing drilling fluid systems are divided into water-based fluids (WBF), hydrocarbon-based fluids (HBF) and synthetic-based fluids (SBF), and gaseous systems. Factors such as cost, technical characteristics, and environmental impact have a major influence on the choice of solution [19].

A drilling-fluid system is a component of the well construction process that remains in contact with the wellbore throughout the drilling operation. The design of the drilling-fluid system involves the development of its formulation and is carried out so as to perform effectively under the expected conditions in the wellbore [20]. The main functions of drilling fluids and their corresponding properties are shown in Table 1.

In addition to the functions described above, drilling fluids should be selected in such a way as to improve efficiency and safety during the drilling process.

The aim of the work is to develop, improve, and study compositions of weighted drilling muds with low solid content based on organic salts of alkali metals and polymers for the construction of wells prone to rock swelling and/or caving, as well as for drilling muds for productive drilling-in the formation.