Let’s Talk About Mud, Part 2

Understanding why the weight of drilling fluid is important to water well contractors.

By Jeff Blinn

Hello again everyone. I hope you’ve all been turning to the right since we last chatted.

Last time we explored the functions of a drilling fluid, what the drilling fluid does, and talked about the first drilling fluid property—viscosity.


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).

When we first add bentonite to water, we see a viscosity increase and we can measure both the viscosity increase and the fluid density increase. From last time, we know to use a Marsh funnel and cup to measure viscosity.

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.

Why Is Weight of Drilling Fluid Important to Water Well Contractors?

Commercial drilling fluid additives are known as beneficial solids as they are necessary to develop useful properties in the drilling fluid.

A freshly mixed water/bentonite slurry will commonly weigh 8.4 to 8.6 ppg or 1.01 to 1.03 Sg. Drilled solids are considered non-beneficial solids as they do not provide any benefit to the fluid, but they do increase the density of the fluid as they become incorporated into the fluid.

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.

Another effect of high-density fluids is a slower penetration rate. The increased solids content interferes with the drill bit’s ability to cut new formation and penetration slows down. I have never met a driller who wants to go slower!

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.

But what if we have a 10.0 ppg, 1.2 Sg mud weight, and ¼% sand?

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.


Rheology is the science of how matter deforms and flows when a force is applied, and in our context, how the fluid flows through tubulars and annular spaces. Rheology characterizes how the fluid flows when a shear stress and shear rate are applied to the fluid.

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.

A rheometer measures plastic viscosity, yield point, and gel strengths—all of which play a part in determining how the viscosity we see is created.

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.

Gel strengths are the third property measured by the rheometer. This property indicates if the fluid can form an internal structure, a gelled structure, to suspend cuttings when the fluid is static, or not flowing. Gel strengths are measured after the fluid being tested is static for 10 seconds, and then again after being static for 10 minutes.

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.

Filtration Properties of Drilling Fluid

Two final filtration properties of the drilling fluid are filter cake thickness and filtrate volume. They are measured with a filter press.

The formations we drill have porosity and permeability, interconnected pathways that allow movement of fluid through them—exactly what we need for a water well. The reverse is also true: With sufficient pressure we can force fluid back into the formation through these same pathways.

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?

Next time, we will start to make sense of all this and turn drilling mud into an engineered drilling fluid. Thanks for reading!

Jeff Blinn has had a 40-plus year career as a professional drilling fluids engineer. Beginning with mud school in 1978, he has worked in many drilling disciplines including minerals exploration, water well, oil and gas, geothermal, geotechnical, and horizontal directional drilling. He has held positions as field sales engineer, engineering supervisor, account representative, technical services representative, and training manager. He can be reached at jeff@mudwizzard.com.