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Principles of HDD Solids Management

Principles of HDD Solids Management

The utilization of drilling fluids by the oil and gas industry is by no means a recent development. However, using such fluids for horizontal directional drilling ("HDD") is only just becoming popular. While HDD technology existed for many years prior, it did not attain mainstream popularity until the 1980s. It took another decade before drillers commonly accepted the use of basic drilling fluids. Given the massive amount of research and development and funding being poured into HDD drilling fluids by manufacturers of these products, it is expected that HDD drilling will follow a similar trajectory to that of the traditional gas and oil industry in years to come. With that said, it is anticipated that the HDD industry can expect a variety of customized and carefully engineered drilling fluids to make their way to market soon.

The evolution of drilling fluids paired with the ever-increasing cost of waste management and disposal allows for an easy conclusion to be drawn in connection with the economic practicality of including drilling fluids in the HDD process. The economic feasibility is highly dependent on the ability to recover and recycle the products. There is no question—the cost of the HDD business is rising. While barite and bentonite have become considerably commoditized over time, critical additives continue to rise in price, impacting overall costs. Additionally, the cost of qualified talent has escalated dramatically, leaving HDD rig operators with a difficult question: How can they continue to generate profits when business costs are rising exponentially?

When evaluating and choosing a package mud reclamation system, many important considerations must be kept in mind. The following guide offers a high-level overview of the critical components of HDD solids control and drilling fluid management. Of course, this guide is not all-encompassing to every set of circumstances. Therefore, it is essential to discuss your individual needs with the supplier of the drilling fluid and the original equipment manufacturer of your solids control and waste management equipment. That discussion, paired with an understanding of the content below, will help guide your business decisions effectively and strategically in the right direction.

Particle Size & Effects

The oil and gas industry is unique to the HDD industry. While the former uses both oil- and water-based drilling fluids, HDD drilling fluids are expected to remain water-based due to local laws and regulations that make oil-based drilling fluids impractical—especially when drilling near the surface.

As indicated by their name, water-based drilling fluids rely upon water as the liquid solute (or the media the additives are mixed into). The solid component of any drilling fluid is either commercial solids or drilled solids. Commercial solids, like bentonite, which is used as a thickening agent to increase the fluid's viscosity, typically have a relative particle size between less than one micron—or 0.000039 inches—to ten microns—or 0.00039 inches. A commonly utilized weighting agent, barite ranges from one micron to one-hundred microns. In examining Figure 1, which highlights particle size distribution from four different barite suppliers, please remember that a micron is 1/1000 of a millimeter—and there are 24 millimeters in one inch.

In contrast to commercial solids, drilled solids are the particles brought into the mud system during the drilling process, including cuttings from the drilling bit, back reamer, or borehole debris. They can vary significantly in size based on the carrying capacity of the drilling fluid—from less than one micron or larger. Several factors play a role in the particle size, such as the spindle speed and the amount of push/pull force necessary to drill. For example, smaller holes or slower drilling/reaming rates typically generate smaller drilled solids.

One of the primary goals of solids control is to ensure that as many large drilled solid particles as possible are removed the first time these solids are pumped out of the borehole. Of course, this must be done without any major impact on the commercial drilling solids, which necessitates properly designed and installed solids removal and treating equipment. Additionally, this equipment should be sized to process 100-125% of the mud circulation rate. Any solids that are not removed during the first circulation through the surface equipment will be mechanically degraded by the drill, reamers, and mud pumps. Eventually, they will be too fine to remove by traditional mechanical means using primary cleaning systems that rely on shaker and hydroclone technology.

To effectively evaluate the removal capabilities of the various pieces of mechanical treating equipment, it is necessary to consider the source of the solids and classify them according to the following sizes.

Benefits of Low Solids in Drilling Mud

There are several benefits to relying on engineered drilling fluids, including but not limited to:

  1. Improved drilling penetration.
  2. Longer bit or back reamer life.
  3. Lowered mud cost.
  4. Reduction in maintenance costs for triplex mud pump, mud motor, and surface equipment.
  5. Reduction in clean-up and disposal costs.

There are also, however, limitations and several problems with engineered drilling fluids, such as:

  1. Decreased penetration rate.
  2. Shorter bit, and reamer life.
  3. Increased mud cost.
  4. Increased wear and tear on triplex mud pump, mud motor, and surface equipment.
  5. Increased clean-up and haul-off costs.

The benefits of using engineered drilling fluids require effective solids controls to be planned and implemented. To achieve these benefits, extensive planning must be done prior to boring to ensure appropriately sized, designed, and operated equipment. The boring crew must be well-versed in the effective and efficient use of the equipment, or the potential benefits may decrease dramatically. Figure 3 illustrates the advantages of choosing the proper mud system and maximizing the effectiveness of the solids control system.

 

Solids Control System Methodologies

Currently, many different methods can be utilized to control formation solids build-up. Historical methods such as diluting the drilling fluid with water or disposing of unused drilling fluid are rapidly becoming outdated. As disposal costs and market expectations have evolved, relying upon these antiquated methods is no longer cost-effective. Instead, the preferred method for solids control has shifted to mechanical treatment. Using chemically-enhanced mechanical separation has become a financially solid option in a rapidly changing market.

Primary Solids Control System Elements

By utilizing linear motion shakers or hydrocyclone devices, including desanders and desilters, primary mechanical treatment systems can remove formation solids effectively, with each piece of equipment limited to a particular range of particle removal.

When implemented correctly, each piece of mechanical equipment can effectively remove particles of a specific size. By utilizing the appropriate combination of equipment, maximum benefits and cost-effective solids control can be achieved affordably. It is critical to be aware of the maximum capabilities of each technology to choose the correct system for each set of circumstances.

Mechanical separation equipment uses differences in mass (using specific gravity), size (using particle size distribution), or both to determine which undesirable formation solids should be rejected while retaining the drilling fluid. Desanders and desilters employ centrifugal force and assess mass differences between solids and liquids to remove solids. Shale shakers manipulate micron-sized differences using a vibrating screen to differentiate between solids and liquids.

Solids Control System Application

100% of the mud returning from the starting pit should be processed by a standard or fine screen shaker before it is released to be processed by additional equipment you've opted to include in your solids control system further downstream. For example, after leaving the shale shaker phase, mud will move onto one or more hydrocyclone devices for further processing. This equipment may include desilters, desander, or both, in their efforts to manage solids. Several industrial claims have stated that hydrocyclones can lead to solid cuts of less than twenty-five microns, but this cannot be guaranteed. Instead, operators should conservatively expect that this is the performance limit rather than the standard. The hydraulic design criteria and cut point expected with each primary solid control device are illustrated in Table 4. It is critical to ensure that each instrument meets the standards below to achieve and maintain a high level of operational success.

When deploying a solids control system, buyers must consider several essential hydraulic design factors. The system must be hydraulically balanced, but it is also necessary to consider the dependability, durability, and potential return on investment of a specific system.

Summary of Effective Solids Control System:

Effective solids control necessitates the following critical steps:

  1. Researching and obtaining an effective, dependable, and durable solids control system
  2. Carefully considering whether the solids control system is:
  3. Hydraulically Balanced
  4. Capable of making both scalp cuts and fine cuts
  5. Has an appropriate capacity for drilling fluid mixing and re-circulating
  6. Avoiding intended or unintended by-pass of the shale shaker or any other solid control equipment while drilling
  7. Using the smallest mesh screen possible on the shale shaker—Note: Operators must keep several screens on hand, as the best option will change from formation to formation.
  8. Keeping an adequate inventory of frequently-used spare parts and screens on hand.
  9. Assigning and certifying rig personnel for equipment operation and maintenance by:
  10. Requesting training and equipment commissioning for your OEM.
  11. Researching and sharing appropriate training programs that may be available with your OEM and implementing a way for your OEM to share that knowledge through additional written training initiatives.
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