Lost Drilling Returns

It’s important to know to best prevent and control it.

By Jeff Blinn

Mud is simple! A little dirt-in-a-bag and slime-in-a-bucket, add water, and you have drilling mud. Of course, I have written this tongue in cheek!

We have looked at drilling fluids from two points of view in this Water Well Journal column. We began by looking at the science of drilling fluids. This included defining the functions of a drilling fluid and the properties of the fluid that indicate the ability of the fluid to perform those functions. We also introduced several classes of drilling fluid additives, and when properly mixed, provide defined and measurable properties to control the subsurface geology that the bore path will intersect.

Some of these discussions could easily cause your head to explode and that wouldn’t be good for any of us. So, our second point of view was to simplify the science and make it usable for each of us—maybe not as simple as my statement above but at least understandable.

Drilling can be looked at as system drilling fluids being just one part along with geology, equipment, and fluid flow and fluid pressure. Choosing the proper drilling fluid formulation is as easy as remembering how to use the five-finger method—treat the makeup water, create suspension, protect the borehole, protect the cuttings, and address any local issues.

One of the most widespread local issues is loss of circulation. Loss of circulation is losing whole mud to the formation, which we see as getting less volume of fluid back to the surface as compared to what was pumped down.

The severity of the loss can be minimal, commonly called seepage loss. It can also be a total loss of returns, and it can be any point in between. We can usually live with seepage losses, but all other degrees of lost returns need some sort of intervention on our part to control them.

Finding the Cause

Before we can devise a solution, we first need to find out what is causing the loss. The science behind lost returns is simple. Two conditions must be present for loss of returns.

First, the formation must have porosity and permeability. Porosity is having spaces or holes through which liquid or air may pass. Permeability means these spaces are connected and allow fluids to move through them. Gravel is porous and permeable with large-connected spaces. Clay is porous with very small pore spaces but has almost zero permeability as fluids cannot easily move through them.

Other examples of geologic porosity and permeability are sand, solution cavities and voids in limestone, fractures, faults, and bedding planes within a formation.

Second, a pressure differential must exist between the pressure exerted by the fluid in the borehole and the pressure in the formation. We intuitively know the pressure exerted by the fluid in the borehole is higher than the formation pressure if we are losing drilling fluid.

An example is when drilling through a gravel formation above the water table where the void spaces are filled with air, the hydrostatic pressure of the drilling fluid is greater than the air pressure in the formation, and fluid moves into the formation. The opposite is true if we have an artesian or flowing well; the pressure within the formation is higher than the pressure exerted by the drilling fluid, and fluid flows out of the borehole.

We seldom know exactly what the pressure from the formation is in the water well drilling business. We can calculate the hydrostatic pressure of our drilling fluid by this formula:

PSI = MW × D × 0.052

Hydrostatic pressure in pounds per square inch (PSI) equals mud weight (MW) in pounds per gallon times the depth (D) in feet where you want to know the pressure times a conversion factor (0.052) to connect all the units of measurement.

An example using 10 pounds per gallon drilling fluid and 100 feet deep:

Hydrostatic pressure = MW × D × 0.052

PSI = 10 × 100 × 0.052

Hydrostatic pressure = 52 PSI

If this drilling fluid was present in our dry gravel example above, the only thing we know for sure is the hydrostatic pressure of 52 PSI is far greater than the formation pressure. The loss of returns in the dry gravel would be almost instantaneous. As the pressure exerted by formation fluids increases, the rate of drilling fluid losses decreases.

I have only talked so far about hydrostatic pressure, which means the drilling fluid is sitting still in the borehole and not being pumped. For the drilling fluid to circulate, additional pressure needs to be added by means of a mud pump.

As mentioned in a previous column, the pressure added is used up moving the drilling fluid from the pump to the drill pipe, down the drill pipe to the drill bit, through the bit, and up the annular space to the surface.

In the annular space, the remaining pump pressure must be added to the hydrostatic pressure to get a true fluid pressure against the formation. Most of these calculations are beyond the scope of this column, but suffice it to say a circulating fluid’s pressure against a formation is greater than the hydrostatic pressure at any given point. You may have experienced this phenomenon if you have had a borehole stand full when not circulating but start losing fluid while circulating.

One takeaway from the mathematics involved is the circulating pressure can be used to calculate an equivalent mud weight if the fluid was static. This is the drilling fluid’s equivalent circulating density.

Dealing with the Operator

Up to this point we have put the blame for lost returns on the geology of the formations we are drilling—if it were only that simple. Sometimes we must take the blame for operator-induced errors that lead to loss of returns.

Drilling fluid properties and drilling practices can contribute to loss of circulation. The pressure formulas use mud weight in the calculations. Water weighs 8.34 pounds per gallon (ppg), so this would be the minimum mud weight used to calculate pressures. As we add solids to water—either as beneficial drilling fluid additives to create our desired drilling fluid properties or non-beneficial solids such as drill cuttings— the mud weight increases.

As mud weight increases above 8.34 ppg, the hydrostatic pressure increases and the equivalent circulating density increases. High viscosity or thicker drilling fluids require more pump pressure to initiate circulation and maintain flow and therefore increase equivalent circulating density as well. This also holds true for drilling fluids with high gel strengths.

Maintaining good drilling fluid properties and controlling the buildup of drilled solids in the fluid by effective solids control methods, all within our control, minimizes the chances of loss of returns.

This would be a good time to introduce fracture gradient. Fracture gradient is the pressure gradient at which the formation breaks. If the pressure applied by the drilling fluid is higher than the formation’s fracture gradient, the formation will break and create a potential loss of returns.

How we break circulation and pull and run pipe can lead to fluid losses. If we put the mud pump immediately full on when we are ready to circulate, we send a pressure surge through the circulating system. This can have either of two effects: We could possibly exceed the formation’s fracture gradient and fracture the formation, or the pressure could be higher than the formation fluid pressure, resulting in loss of returns.

To minimize pressure surges, bring the pump on slowly until it is at your desired flow rate. Running drill pipe into the hole can have the same effect. Since the drill bit is only slightly smaller than the hole diameter, it acts as a piston in a cylinder, pressurizing the fluid in front of it. If the surge pressure is higher than the formation fracture gradient or the formation fluid pressure, we could induce loss of returns. To control this, do not let the drill pipe free-fall into the hole but run in at a rate that allows the drilling fluid to flow around the bit, minimizing the pressure surge.

Working with Pressure

Even when we do everything within our control to prevent loss of returns, we can still have lost circulation troubles. What do we do to correct them at this point?

There are two directions we can go. Since loss of returns is directly pressure-related, we could find a way to lower the fluid pressure exerted against the formation by the drilling fluid. This might mean changing from conventional circulation to reverse circulation, and may not be practical.

Or it could be changing from a liquid circulating fluid to drilling with air or foam. Again, maybe not practical, and I’ll leave the air and foam drilling discussion for another day.

The only other direction to follow is adding a loss of circulation material (LCM) to our drilling fluid to plug up the loss zones and keep the drilling fluid in the borehole.

A big misconception is the plugging material needs to make a rigid plug, setting up like concrete. The plug only needs to be strong enough to redirect the direction of fluid flow. In other words, it would take more pressure to push the drilling fluid through the plug and into the formation than to flow up the annulus.

Almost anything imaginable has been used as LCM. Cottonseed hulls were used extensively early in my career. Also used were ground-up paper, mica, cellophane, cedar fiber, ground-up nut shells, fiberglass insulation, sage brush, sand, bentonite chips, horse apples, cement, and even elephant dung. You get the picture.

Now would you really want some of these things in a water well? No, not really, because they are organic materials that biodegrade and can pollute the groundwater. We are more enlightened today and search out inert and nonhazardous materials that will not be harmful to the environment or human health.

Two types of acceptable LCM in water wells are spun mineral fiber products and water-swellable polymers. See your supplier of choice for specific products and trade names.

The choice of LCM depends on the severity of the loss. To cure a seepage loss, increasing the concentration of bentonite in the drilling fluid may be sufficient. The increased concentration of bentonite platelets can build a better mat to plug small openings. To plug a large void, chipped bentonite and gravel may need to be poured into the wellbore.

Any loss between these extremes will require varying concentrations of materials and material sizes and shapes. It is best to consult your drilling fluids supplier or local mud engineer for advice on products and concentrations.


Here are some final thoughts on lost circulation. Prevent it if possible by maintaining a good drilling fluid with low mud weight. Do not let your drilled solids concentration build up in the fluid system by utilizing effective solids control.

Follow good drilling practices and pay attention to surge pressures created by the mud pump or when running pipe. Use adequate LCM concentrations during early stages of treating the loss; the problem usually gets worse with time. When possible, combine different sizes and shapes of materials to achieve a matting effect to form a plug.

Finally, I think of combating lost returns this way: I don’t know where that lost drilling fluid is going, so hit it hard and stop it because it might end up in the neighbor’s water well or basement!

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.