mud pump drilling circulation video free sample

There are many different ways to drill a domestic water well. One is what we call the “mud rotary” method. Whether or not this is the desired and/or best method for drilling your well is something more fully explained in this brief summary.

One advantage of drilling with compressed air is that it can tell you when you have encountered groundwater and gives you an indication how much water the borehole is producing. When drilling with water using the mud rotary method, the driller must rely on his interpretation of the borehole cuttings and any changes he can observe in the recirculating fluid. Mud rotary drillers can also use borehole geophysical tools to interpret which zones might be productive enough for your water well.

The mud rotary well drilling method is considered a closed-loop system. That is, the mud is cleaned of its cuttings and then is recirculated back down the borehole. Referring to this drilling method as “mud” is a misnomer, but it is one that has stuck with the industry for many years and most people understand what the term actually means.

The water is carefully mixed with a product that should not be called mud because it is a highly refined and formulated clay product—bentonite. It is added, mixed, and carefully monitored throughout the well drilling process.

The purpose of using a bentonite additive to the water is to form a thin film on the walls of the borehole to seal it and prevent water losses while drilling. This film also helps support the borehole wall from sluffing or caving in because of the hydraulic pressure of the bentonite mixture pressing against it. The objective of the fluid mixture is to carry cuttings from the bottom of the borehole up to the surface, where they drop out or are filtered out of the fluid, so it can be pumped back down the borehole again.

When using the mud rotary method, the driller must have a sump, a tank, or a small pond to hold a few thousand gallons of recirculating fluid. If they can’t dig sumps or small ponds, they must have a mud processing piece of equipment that mechanically screens and removes the sands and gravels from the mixture. This device is called a “shale shaker.”

The driller does not want to pump fine sand through the pump and back down the borehole. To avoid that, the shale shaker uses vibrating screens of various sizes and desanding cones to drop the sand out of the fluid as it flows through the shaker—so that the fluid can be used again.

Before the well casing and screens are lowered into the borehole, the recirculating fluid is slowly thinned out by adding fresh water as the fluid no longer needs to support sand and gravel. The driller will typically circulate the drilling from the bottom up the borehole while adding clear water to thin down the viscosity or thickness of the fluid. Once the fluid is sufficiently thinned, the casing and screens are installed and the annular space is gravel packed.

Gravel pack installed between the borehole walls and the outside of the well casing acts like a filter to keep sand out and maintain the borehole walls over time. During gravel packing of the well, the thin layer of bentonite clay that kept the borehole wall from leaking drilling fluid water out of the recirculating system now keeps the formation water from entering the well.

Some drillers use compressed air to blow off the well, starting at the first screened interval and slowly working their way to the bottom—blowing off all the water standing above the drill pipe and allowing it to recover, and repeating this until the water blown from the well is free of sand and relatively clean. If after repeated cycles of airlift pumping and recovery the driller cannot find any sand in the water, it is time to install a well development pump.

Additional development of the well can be done with a development pump that may be of a higher capacity than what the final installation pump will be. Just as with cycles of airlift pumping of the well, the development pump will be cycled at different flow rates until the maximum capacity of the well can be determined. If the development pump can be operated briefly at a flow rate 50% greater than the permanent pump, the well should not pump sand.

Mud rotary well drillers for decades have found ways to make this particular system work to drill and construct domestic water wells. In some areas, it’s the ideal method to use because of the geologic formations there, while other areas of the country favor air rotary methods.

Some drilling rigs are equipped to drill using either method, so the contractor must make the decision as to which method works best in your area, for your well, and at your point in time.

To learn more about the difference between mud rotary drilling and air rotary drilling, click the video below. The video is part of our “NGWA: Industry Connected” YouTube series:

Gary Hix is a Registered Professional Geologist in Arizona, specializing in hydrogeology. He was the 2019 William A. McEllhiney Distinguished Lecturer for The Groundwater Foundation. He is a former licensed water well drilling contractor and remains actively involved in the National Ground Water Association and Arizona Water Well Association.

Reverse circulation drilling was developed to allow for larger borehole drilling without limiting the factors of drilling fluid pump capacities. Rotary rigs designed for reverse circulation have larger-capacity mud pumps and air compressors to allow for increased pressures that are needed to ensure the removal of cuttings from large boreholes. These drill rigs are far larger than those used for domestic purposes.

Centrifugal mud pumps often are used instead of displacement because the cuttings will more easily circulate through a centrifugal-type pump than through a positive displacement pump.

Reverse circulation rotary drilling is a variant of the mud rotary method, in which drilling fluid flows from the mud pit down the borehole outside the drill rods and passes upward through the bit. Cuttings are carried into the drill rods and discharged back into the mud pit.

Reverse circulation requires a lot of water and sediment-handling, as the boreholes are large in diameter. Stability of the borehole depends on the positive pressure from the fluid in the borehole annulus. If the positive pressure is not sufficient, the borehole wall or parts of it might collapse, trapping the drill string.

For reverse circulation rotary drilling, the drilling fluid can best be described as muddy water rather than drilling fluid; drilling fluid additives seldom are mixed with the water to make a viscous fluid. Suspended clay and silt that re-circulates with the fluid mostly are fine materials picked up from the formations as drilling proceeds. Occasionally, low concentrations of a polymeric drilling fluid additive are used to reduce friction, swelling of water-sensitive clays, and water loss. Because fewer drilling muds are used, no wall cake is created, and the stabilization by the borehole fluid is needed.

To prevent caving of the hole, the fluid level must be kept at ground level at all times – even when drilling is suspended temporarily – to prevent a loss of hydrostatic pressure in the borehole. The hydrostatic pressure of the water column, plus the velocity head of the downward moving water outside the drill pipe are what support the borehole wall. Erosion of the wall usually is not a problem because velocity in the annular space is low.

A considerable quantity of makeup water usually is required and must be immediately available at all times when drilling in permeable sand and gravel. Under these conditions, water loss can suddenly increase, and, if this causes the fluid level in the hole to drop significantly below the ground surface, caving usually is the result. Water loss can be addressed by the addition of clay additives, but this action is only taken as a last resort.

Often, to aid the upward movement of water through the drill string, air is injected, lifting the contents to the surface. Another reason to use air is the fact that the suction pump lift is limited in its capacity to create enough vacuum to start up the water movement after a rod change. When air lifting is used to assist in reverse mud drilling, this method becomes similar to the reverse air rotary method.

Advantages of Reverse Circulation Mud RotaryThe near-well area of the borehole is relatively undisturbed and uncontaminated with drilling additives, and the porosity and permeability of the formation remains close to its original hydrogeologic condition.

This article is provided through the courtesy of the International School of Well Drilling (ISWD), which serves operators around the country, providing a wide variety of training and consulting services. The school has provided customized training programs ranging from those for experienced employees to basic training for those new to the industry. Specific consulting projects also are undertaken. To contact ISWD, telephone 863-648-1565; e-mail director@welldrillingschool.com; or visit www.welldrillingschool.com.

The next fluid property to describe the drilling fluid is density, or how much the fluid weighs. The two most common ways to express density are in pounds per gallon (ppg) or specific gravity (Sg). As a reference, water weighs 8.34 ppg or has 1.0 Sg. Anything added to water that has a specific gravity greater than water will increase the density of the mixture.

In the world of water well drilling, commercial drilling fluid products—such as bentonite and drilled solids created during drilling—when added to water increase the resulting fluid’s density. Bentonite and most drilled solids have an average specific gravity of 2.6 (or 2.6 times heavier than water).

Mud density is measured with a mud balance. There is a functional limit as to how much density increase can be achieved when adding bentonite. By the time the viscosity of the fluid is so high or so thick you can’t pump it any longer, you are only at a density of approximately 9.0 ppg or a 1.08 Sg.

Drilled solids are another story. Adding drilled solids to a water plus bentonite drilling fluid continues to raise the density past 9 ppg to 10 ppg or more. I’ve never experienced a mud weight above 11 ppg with just native drilled solids.

Can a drilling fluid have a density higher than this? Yes, it can if the density of the added material is greater than 2.6 Sg. The drilling fluid additive for this purpose is the mineral barite, with a specific gravity of 4.1. With this additive you can reach mud weights of greater than 19 ppg.

By monitoring mud weight, you are really tracking how many non-beneficial solids are being carried in the mud. These solids become critically important as we drill the production zone as these solids can plug the formation and can lead to a less productive well.

Ideally, a mud weight of less than 9.0 ppg, 1.08 Sg, including beneficial and non-beneficial solids, will provide the best results. The reality is that this is hard to accomplish, and the mud weight often will be higher than 9.0 ppg.

While on the subject of solids in the mud, sand content is another property that tells us a little more about the solids in the drilling fluid. This test measures the percent by volume of sand-sized or larger particles in the fluid. Sand in this sense is a size and not a mineral and is any solid in the fluid greater than 74 microns in diameter. All commercial drilling fluid additives, except lost circulation materials, are much smaller than 74 microns and pass through the 74-micron openings in the screen used for this test. Therefore, anything captured on the screen is a drilled solid.

As the drilling fluid exits the wellbore during drilling, we expect it to be weighted with drilled cuttings, and a sand content taken on this sample would show a high percentage of sand-sized material. As this fluid moves through the pit system, gravity helps to settle these large particles out of the fluid—and if solids control equipment is being used, this will remove more of these larger particles.

If we take a sample of the drilling fluid at the pump suction, we should theoretically have zero percent sand in the sample. Comparing the sand content of the fluid coming out of the borehole with the sand content of the fluid at the pump suction will give a good idea of the efficiency of our solids control measures.

Using mud weight and sand content together will tell us even more about what is happening with the drilled solids in our fluid system. As mentioned above, if we have an acceptable mud weight of 9.0 ppg, 1.08 Sg, and ¼% sand at the pump suction, we are doing pretty well.

Most of the solids that contribute to mud weight are smaller than 74 microns. This could be from the intersected formations being comprised of small particle sizes such as clay, silt, or shale. Or it could indicate that larger particles were not removed from the mud system at the surface and were recirculated downhole where the drill bit ground them into smaller and smaller pieces. Or maybe the larger particles were never removed from the borehole to begin with because they could not be suspended in the drilling fluid and had to be ground down to a size small enough to be transported to the surface.

To determine what is the truth of the matter, we must look at the whole drilling systems approach. Understanding the geology is the first step. What formations we are intersecting tells us what particle sizes to expect. The type of bit being used also tells us what size cuttings can be created. The pump volume and flow rate determine what size cuttings we can expect to reach the surface (more on this topic later). And finally, mud properties. Do we have enough viscosity to transport cuttings to the surface but not so much to prevent cuttings removal at the surface? We’ll get more into the details of viscosity, the science of rheology, coming up.

Three properties of drilling fluids—viscosity, density, sand content—measured with three simple tools will give us the basic information to know if we have an acceptable drilling fluid. Luckily, all three can be purchased separately or as a slurry test kit from your drilling fluid supplier of choice. Instructional videos on how to use these tools are readily available on YouTube or other internet resources.

This is complex science, so we need to simplify it. Viscosity was previously defined as the fluid’s resistance to flowing. The drilling fluid in your pit stays there until you start to pump it. The pump supplies pressure (the shear stress) and flow volume (the shear rate) to move the fluid from the pit, down the drill pipe, and up the annular space. The higher the viscosity, the thicker the fluid is, the more pump pressure is required to move it.

Therefore, rheology is really the science of viscosity and defines three properties that determine if the drilling fluid can transport cuttings, suspend cuttings, or allow for removing cuttings. The Marsh funnel only gives a simple number for viscosity.

Plastic viscosity is a measure of how the solid particles in the drilling fluid interact physically with each other. This varies due to the size, shape, and concentration of solids in the fluid. You can think of this as friction between particles. Higher concentrations of solids and more angularity of the solids contribute to higher plastic viscosity.

Yield point is a measure of how the particles in the drilling fluid interact electrically with each other when the fluid is flowing. High yield point means particles are attracted to each other and low yield point indicates particles are repelling each other. This is the component of viscosity that defines the fluid’s ability to carry cuttings. Some yield point is necessary for transporting cuttings from the bit to the surface.

The 10-second gel strength indicates if a sufficient gel structure is immediately created to suspend cuttings in the annulus when the pump is turned off. The 10-minute gel strength shows us if the initial gel strength varies with time. An increase in gel strengths is acceptable up to a limit. As the gel strength increases with time, more pump pressure is necessary to get the drilling fluid flowing again. It can reach a point where the pressure required for flow is greater than the pressure needed to break down the formation and we create our own loss of returns.

Drilling fluid is water and solids. Under pressure, the drilling fluid deposits solids on the borehole wall creating a wall cake, or filter cake, and loses the water phase or filtrate into the formation. A filter press is used to re-create this scenario and measure these properties. A filter cake is created on the filter paper in the pressure cell as the filtrate is forced out of the cell and collected. The filter cake is measured for thickness and its texture evaluated using terms such as slippery, sticky, gritty, soft, mushy, or tough.

The filtrate volume is measured in milliliters collected over 30 minutes of testing time. 2/32 of an inch or less filter cake thickness and 15 milliliters per 30 minutes or less of filtrate volume is considered ideal for most drilling conditions.

All these words above can drive a water well driller crazy. You ask, what does this have to do with me? Why do I need to know this? I can just look at my mud and tell if it’s going to work.

Okay, sometimes I stick my hand in it and watch how it runs off my fingers. But what do you do when it doesn’t work, when you have drilling problems? Call your mud man and tell him his mud’s no good?

API rated burst strength is de-rated for temperatures from 10 to 600 F° (-12 to 316 C°) Drilling Condition – Gas/oil kick while drilling below the shoe with partial or total mud evacuation (user selects evac percent), with shut in pressurized column of gas/oil to surface and old mud weight gradient behind casing. The old MW that was behind the casing when it was cemented is used for annulus hydrostatic burst calculations and the present MW is used for internal hydrostatic calculations. The user inputs the gas/oil gradient that most closely fits their design for internal pressure gradient.

Drilling burst loads are calculated assuming a shut in gas/oil kick with Leak off EMW pressure at the shoe and a casing evacuation percent chosen by the user (typically 10 – 40 %).

Production burst loads are calculated assuming a full shut in column of pressured gas/oil (i.e. 100% mud evacuation), with Leakoff EMW pressure at the shoe and a column of salt water behind the casing. .

Drilling collapse loads are calculated assuming the casing has been partially or fully evacuated of mud (resulting from lost circulation, or a blowout), while drilling below the shoe, with a non-pressured column of gas/oil to the surface (i.e. atmospheric pressure at the surface) and a full column of old MW behind the casing. The user inputs the gas/oil gradient that most closely fits their design for internal pressure gradient.

. Production collapse loads are calculated assuming 100% mud evacuation with an un-pressured column of gas/oil to the surface. The old MW that was behind the casing when it was cemented is used for annulus hydrostatic collapse calculations. The user inputs the gas/oil gradient that most closely fits their design for internal pressure gradient.

Cementing Collapse loads are calculated with applicable hydrostatic columns of mud and cement slurries outside the casing and displacement fluid column inside the casing. The small hydrostatic difference of the cement in the shoe joints is ignored and displacement fluid is assumed to the shoe TVD. Cementing collapse is typically a concern with big OD conductors and surface casings.

Tensile Design API rated tensile strengths (body and joint), are de-rated for temps 10 to 600 F (-12 to 316 C). . Drilling and Production Casings are calculated with the same assumptions.

Tensile analysis considers the total hanging weight of the casing as it is being run in the hole. The user selects Vertical or Directional tensile analysis to calculate tensile loads assuming buoyant weight of steel in a mud filled hole. . Buoyancy factor = (65.4-MW)/65.4