Why it’s important and how you can prevent fluid loss.
By Jennifer Strawn
When Stewart Krause, senior sales manager with Wyo-Ben Inc. in Billings, Montana, talks about filtrate control in drilling applications, he uses sand in clear plastic cups to demonstrate its importance.
There are two cups in the demo with “pipes” down the middle of the sand to simulate the way fluid is pumped down during drilling. In one cup, water is poured down the pipe. In the other, drilling fluid is poured down.
The water in the first cup fills the voids in the sand quickly. When the pipe is removed, the sand collapses on itself. But when the pipe is removed in the second cup with the drilling fluid, there is dry sand and a discernible borehole left behind.
“It’s a very stark visual,” he says.
The benefits of filtrate control
Krause defines fluid loss as the willingness of drilling fluid to give up its liquid phase when put under pressure. Controlling fluid loss helps keep boreholes stable and in gauge. Without proper filtrate control, the formation tends to slough or fall into the hole as it does in Krause’s demo.
Two things have to happen for drilling fluids to keep the hole open, adds Todd Tannehill, technical sales manager with CETCO Drilling Products. First, you must create an impermeable barrier—or good filter cake—then apply positive pressure with fluids creating hydrostatic downhole pressure.
“A weak or inconsistent filter cake in unconsolidated soils can cause excess fluid loss,” he says. “This causes the borehole to empty or require increased drilling fluids.”
There are more benefits to filtrate control. Less fluid loss also leads to less torque and drag, less development time, and a better grout job.
“Some drillers don’t see the importance because on a day-to-day basis they get by,” Krause says. “When they get into a sensitive formation, they put up with the results.”
Krause says he often hears complaints about how long it took to develop a well after it was drilled, and controlling the filtrate will reduce the well development time substantially.
Take this example: One well was drilled with extremely high filtration—the fluid loss was around 30 milliliters. The resulting filter cake was thick and difficult to remove. Another well was drilled with a fluid loss around 15 milliliters. That filter cake was much thinner.
“The thinner one didn’t allow the fluid to pass into the formation at near the rate that other one did,” Krause says. “The thinner the filter cake, the easier it is to remove during development.”
Controlling fluid loss can even help you take better well samples.
“If you have a hole that’s sloughing in and you’re pulling samples, you really don’t know where that sample is coming from,” Krause says. “That’s why a lot of people don’t take good samples when they’re drilling with mud; they don’t use good mud properties.”
Building a good mud for filtrate control
Besides understanding why filtrate control matters, the key to successfully controlling fluid loss is building a good drilling fluid.
Bentonite is your first line of defense against fluid loss because of its thixotropic properties—meaning it can build gel strengths. It suspends the cuttings that are in the column so they don’t all fall down on top of the bit, and it builds a nice wall cake.
But to make a good bentonite mud, good water is needed. It’s a vital step that some may be missing. The makeup water should be warm, soft water. Otherwise, you risk inhibiting the performance of the bentonite and any polymers you’re adding to it.
You’ll also want to add soda ash to the water to soften it and raise its pH to between 8.5 to 9. Typically, that is anywhere from one-quarter pound of soda ash per 100 gallons to about one-half pound per 100 gallons if you have extremely hard water.
“Not treating makeup water correctly allows for a fragile or nonuniform permeable filter cake that will not keep the hole open,” Tannehill says.
The role of additives
Bentonite is a good fluid loss control agent, but more does not necessarily equal better. Adding more bentonite to your fluid will improve filtrate control but increase the viscosity.
“For everything you put in to get a reaction, there’s probably another reaction not always positive in nature,” Krause says. “When you stop to make that connection, your gel strengths will continue to build. Then when you turn the pump on, you have to shear all those gel strengths, so you build up downhole pressure and create loss circulation. You’ve fixed one problem but created another.”
Increasing the viscosity of the fluid also slows the velocity of the cuttings being removed from the borehole. This reduces drilling speed.
That’s where additives come into play. A good option that will lower your fluid loss without building too much viscosity is a polyanionic cellulose (PAC) polymer. PACs are available in low-viscosity blends and regular blends in both dry and liquid formulations.
PAC polymers do a good job of wrapping around the clay particles to lower filtrate so you’re building a low-permeability liner on the borehole wall. The side benefit of a PAC polymer is that it flows well through solids control systems. It goes through the screen and through the system when longer chain polymers won’t.
Short-chain partially hydrated polyacrylate (PHPA) polymers are another option that also won’t build viscosity. They will also lower fluid loss, although not as much as a PAC polymer. On the other hand, they have better shale inhibition and can encapsulate clay better.
“You may choose to use it if you have narrow sand lenses and a lot of clay in a hole,” Krause says. “I may choose to use that product because it’s a better shale inhibitor. We’re not putting it in to facilitate viscosity. Its primary function is to get the fluid loss down or shale inhibition.”
Monitoring and mitigating fluid loss
Fluid loss is something you can’t see, so a low-pressure filter press can help you measure it. It works by using filter paper to simulate a permeable formation. Then the drilling fluid is held under 100 psi to simulate what you would expect to see under a certain hole condition at a certain depth.
A good, low fluid loss is around 10 milliliters and under 15 milliliters.
“It’s just a measurement,” Krause says. “What you’re looking for are trends. You don’t run one test and panic; you run multiple tests. If the fluid loss is climbing, put additives in to bring it down.”
If you’re not using a low-pressure filter press, there are visual cues you can look for. If you have good filtrate control with polymers, there is a sheen on the mud, making it look shiny.
“When you put these polymers in, it will take on a different complexion,” Krause adds. “I know that really doesn’t make much sense, but good drillers can look at the mud and tell you something’s wrong.”
You can also put the fluid in a cup and hold it up to see if there’s a polymer string coming off it. If there is, that tells you that you still have polymer in the system.
“The best way to monitor fluid loss is to pay attention to the returns,” Tannehill says. “Are you getting the same amount or more fluids out as you are pumping downhole? If not, you are losing cuttings to the formations or the bottom of the bore. If spoils go away completely, that is not a fluid loss situation but a loss of circulation issue. The faster it goes away, the less likely you will regain returns.”
The helper shoveling out the mud pit may be the first one to notice if there is too much fluid loss. Any clay in the system will stick to the shovel. If there’s an encapsulation on that clay, the cutting will slide off the shovel.
“The challenge for all drillers is to stay aware of drilling fluid returns and adapt to changing conditions at different depths,” Tannehill says. “Running through unconsolidated and consolidated soils on the same deep bore is very common.”
The easiest way to mitigate fluid loss is to have a maintenance program.
“For every two rods drilled, I would put in three to five ounces of polymer to provide system maintenance,” Krause says. “As you’re drilling you have to increase the volume because you have more hole volume.”
Krause prefers a pre-mix tank rather than adding water to an active system. You’re mixing bentonite and polymer off to the side so when you need volume you can add it to the system.
When he gets to the producing zone, he may even start over with fresh mud.
“I get that ‘you’ve fallen off a turnip truck’ look when they’ve drilled for four, five or six hours, and I make the suggestion that we dump the mud,” Krause says. “We’ve drilled all day to get to the producing zone. Let’s use very good mud properties to do that.”
Filtrate control is important throughout drilling, but most important in the production zone. If you’ve drilled into it with heavy mud and poor mud properties, you’ve already contaminated the producing zone you want to make the well out of.
“Fluid loss—and all the things that come with it—is one of those key factors that we put our faith in a drilling fluid, especially in the production zone,” Krause says. “You only get one opportunity to not screw up that formation.”
Jennifer Strawn was the associate editor of Water Well Journal from 2004 to 2007. She is currently in the internal communications department at Nationwide in Columbus, Ohio. She can be reached at email@example.com.