Understanding the concepts can make a huge difference in your drilling results.
By Jeff Blinn
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.
My recommendation to remedy this problem—based on what the drillers told me over the phone—was to have them add an inhibitive polymer (PHPA), a filtration control polymer (PAC), and a detergent to their fluid mix.
As described in previous columns, these products inhibit or minimize the drill cuttings from getting water wet and minimize the stickiness of the cuttings surface so they do not agglomerate or stick together or stick to the drill steel. These recommendations worked to a degree but did not entirely solve the problem.
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.
When any problem occurs while drilling, we need to go into troubleshooting mode. Troubleshooting requires a systems approach to solving the problem.
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.
The mathematics of fluid hydraulics can be quite overwhelming and solving the equations involved in a meaningful way can only be achieved using high-powered computer programs. We are not going to venture that deeply here. We will make some assumptions and simplify some things to make fluid hydraulics useful to you.
It’s in the Design
So back to our problem of bit balling. In softer formations such as clay or shale, a long-tooth roller cone bit or drag bit are commonly used. A balled bit is when the formation being drilled packs off between the teeth or otherwise sticks to the cutting surfaces to prevent them from cutting new hole. In effect, you’re spinning in place.
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.
At this point we need to make the distinction between turbulent and laminar flow. Turbulent flow can be thought of as a raging river: high velocity and haphazard in the way it carries detritus with it. It is very high energy and has a scouring effect on the surfaces it encounters. Laminar flow is a meandering stream: a much more defined flow with little interaction with its environment.
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.
Pump Types and Bit Design
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.
Drag bits are very common in the water well business. Most of the designs have an open center and use flow volume to clean the cutting surface and move the drilled cuttings to the surface. I personally have never seen one with jets unless you consider a PDC bit a sophisticated drag bit.
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 the rig crew with hammer and chisel to clean that drill bit. There were no jets installed and the seats were washed out so no regular bit jets could be installed.
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.
And, yes, it was a lot more comfortable writing about it inside under the air conditioning than baking on location living it that day.
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 firstname.lastname@example.org.