Life Cycle of a Vertical Drilling Fluid

In this article, Brock Yordy, columnist for National Driller, outlines the life cycle of drilling fluids from creation to disposal. Brock teaches Drilling Fluids Management, a 6-week master class for industrial drilling companies.

Drilling fluids management is a term interpreted differently depending on the drilling project and local regulations. The proper interpretation of drilling fluids management is the life cycle of drilling fluids from creation to disposal. The life cycle changes with the following factors:

• Drilling fluids package
• Incorporation of drill solids
• Solids control
• Requirements for disposal

The goal of a good drilling fluid management plan should be to set a fluid volume limit that adequately supports the total circulating volume of the drill from start to total depth. At the end of the project, fluid volume will need to be reused or disposed.

Drilling Fluids Package

My mentors at Baroid IDP taught me that “drilling fluids management starts before the first turn of the bit.” The drilling phase is a disruptive process and the incorporation of reactive and non-reactive drill solids changes a drilling fluid. A drilling fluid is 98 percent water, and that other 2 percent is made of NSF-approved bentonites and specialty polymers. (For the rest of this discussion I am going to make the assumption that, as an environmentally responsible drilling company, you are using NSF standard 60 drilling fluid. If my assumption is wrong, I hope Mother Nature strikes you with a lightning bolt.)

Proper drilling fluids design will stabilize the hole in porous conditions and inhibit reactive clay and shale. Contact your local mud engineer and work up a drilling fluids package that fits your drilling requirement. The fluids package should include sodium bentonite drilling gel, filtration control additives, clay inhibitors, surfactants and loss circulation material that will best suit the anticipated downhole conditions. Consult your mud engineer about water quality/chemistry, mix requirements and environmental impact. Many of these mud engineers still make house calls and can give area insight. Drilling fluids are only as good as the driller’s capability to maintain the required drilling fluid functions and properties. As the drilling phase incorporates solids, the drilling fluid is used up by coating the borehole wall, inhibiting reactive solids and shear degradation. Drilling fluids require maintenance to continue at 100 percent efficacy.

Incorporation of Drill Solids

Drilling fluids become contaminated with the incorporation of solids. An environmental regulator can pull material data safety sheets and understand 100 percent of neat drilling fluid contents. Drilling fluids get classified as hazardous because drill solids could have heavy metals, chemical contaminants and other unknown variables that are now mixed into one fluid. If we consider controlling drill solids incorporation in the beginning, when the bit’s cutting action first creates the solids, the task of managing the drilling fluid becomes much easier. The process starts with the bit rotating and making a cutting action that creates a solid that is the size of a quarter. The goal is to create the largest cutting possible that can move uphole. At the same time, the mud pump pushes the drilling fluid through the bit face and carries the solid to surface. Finally, the solid is adequately removed intact by a method of solids control. The process is simple and foolproof.

The problem starts when the bit produces a 1-inch sized cutting that slowly tumbles uphole breaking apart into numerous smaller cuttings. Proper uphole velocity is required to carry the cutting intact to the surface. A drill solid should move uphole at 60 to 100 feet per minute. In order to achieve 1-inch solids traveling at 60 feet per minute, a drilling fluid’s uphole velocity must be greater than 100 feet per minute. The goal is to keep the solids intact from the bit face to removal of the solids from the mud.

When drill solids deteriorate, they create several issues:

1. The solids break apart into more surface areas that require the drilling fluid to coat and lift.
2. The density and viscosity of the drilling fluid increase. This increase causes the pumps to work harder to remove solids from the bit face, thus creating more solids downhole. This causes the breakdown of the drilling fluid’s properties and functions.

It would be way too convenient if all drill cuttings stayed at that magic 1-inch size and were quickly removed at the surface. However, that is never the case; a good drilling fluids management plan must have a proper solids removal method.

Solids Control

Solids control is any method that removes drill solids at the surface before the solids can be recirculated downhole. Physical solids control, like my Uncle Karl with a shovel, can be an effective way to remove solids from a mud pan. An earthen pit or passive solids control requires the fluid to flow in a way that will facilitate the settling of solids. Both physical and passive solids control can work efficiently for large solids as long as enough time is allowed to remove those solids. Once the large drill solids are recirculated through the mud pump and pumped downhole, it is nearly impossible to remove those solids a second time without mechanical solids control. Passive and physical solids controls are only satisfied with a controlled rate of penetration that allows time for the cutting to settle or be removed.

Mechanical solids control is the most efficient way to remove drill solids if set up correctly.
1. The pickup pump that moves the 1-inch size solid from the pit to the scalping screen must be low impact. If the pump creates 100 smaller solids, the solids control unit will have to work twice as hard to remove them. The goal is to remove the largest solid possible the first time. 2. The scalping screen has to be sized to remove the smallest solids possible and allow 100 percent of the recirculating volume through the screen. Linear shakers allow the use of smaller micron scalping screens, as opposed to elliptical ones.
3. Hydrocyclones need to be sized and operated to manufacturer specifications. The underflow of a hydrocyclone is highly concentrated fine solids. If the underflow is pumped over a shaker screen, the screen needs to be sized to remove those ultra-fines. Regardless of the method of solids control the goal is to maintain a low-solids drilling fluid of 8.8 pounds per gallon and a sand content of .5 percent.

Disposal

Disposing of a drilling fluid can be a slippery slope. No, literally. If you are core driller you often allow the spent fluid to run down a hill or off a slope of a mountain. Another commonly used practice forces the fluid out of the borehole through a fractured zone. These practices can negatively impact the environment and are not a responsible way to dispose of spent drilling fluids.

There are several proper ways to dispose of drilling fluid such as a Toxicity Characteristic Leaching Procedure (TCLP), an analytical test to determine if any part of the fluid is considered hazardous. A TCLP test will help determine what type of landfill the liquid can be stored. Drilling fluid in liquid form is the hardest way of disposal, depending on how the fluid is classified. Turning a spent fluid into a solid or semi-solid state creates many other forms of disposal. Many companies have products that can solidify, dehydrate, flocculate or coagulate the drilling fluid into a semi-solid or solid state. Be sure to check the toxicity of the additives being used to change the fluid from a solid to a liquid. It is counterproductive to create a toxic non-disposable waste stream.

Proper drilling fluid disposal takes time, additives need time to react, and mechanical solids removal such as centrifuge or filter press need time to process. Flocculation or coagulations methods that allow removal of water, or effluent, to be reused as a new drilling fluid help decrease the fluid volumes required to complete a hole. Check out an article I wrote for National Driller in July of 2013 titled System Helps Fluids Impact on Job sites for more information.

The key to success is to implement a drilling fluids management plan that works for your company. The plan should include:

1. Total circulating volume required to finish the project
2. Drilling fluids package
3. Solids control
4. Disposal
5. Environmental impact

The goal is to use the right amount of drilling fluid required to finish the hole and dispose of that fluid. If the project involves multiple holes, try to create a drilling fluids plan that allows for 60 percent reuse on the next hole. Recycled drilling fluid will need to be rebuilt with new bentonite and polymers to maintain proper drilling fluid characteristics. In the next 10 years, we will see tighter regulations for drilling fluid reuse and disposal. The days of using 30,000 gallons to drill a hole that should have used 3,000 are numbered. We have to understand where that fluid has gone and what it could impact. NSF-approved drilling fluids are safe for use in freshwater zones, but that does not mean they are safe to pump into natural waterways or wildlife environments.

Become an expert in the area you drill and understand the essential elements required to be successful.