Adverse effects caused by drilled solids account for a major portion of drilling fluid maintenance expenditures. Drilled solids are the number one contaminant of all drilling fluids. Considering that a 12¼ in. gauge hole drilled to 10,000 ft would result in 1,327,000 lb or more of drilled solids, the above statement is not surprising.

Overall drilling costs can also be severely affected by the quantity of drilled solids incorporated into the system. These effects include the following:

  • Increased drilling fluid maintenance costs.
  • Greater difficulty in maintaining optimum rheological properties.
  • Increased frequency/opportunity of differential sticking.
  • Reduced penetration rate.
  • Decreased bit life and increased rate of wear on pump parts.
  • Increased circulating pressure losses, and consequently increased possibility of lost circulation.
  • Increased tendency for a well to swab on trips, possibly contributing to pressure control problems.

A solids control program should consider the drilling fluid as well as the formations to be drilled prior to selecting equipment for a particular operation. Care should be taken to operate the selected equipment efficiently and in the correct sequence to prevent overloading any individual unit.

It would be desirable in most cases to remove all drilled solids. Although this is possible with the use of chemical enhancement prior to separation, it is not always the most economical approach. The goal of a solids control system is to achieve the balance between mechanical solids separation and dilution that will result in drilled solids being maintained at an acceptable level with minimum cost, while maintaining property specifications. This is achieved when the cost of the required dilution fluid is at a minimum.

Classification of Solids

Solids can be classified into categories based on specific gravity and particle size.

Figure 1. Average solids range of water-base drilling fluids (freshwater)
  • Specific Gravity (S.G.) – Solids in drilling fluids can be separated essentially into two density groups, high and low specific gravities. High specific gravity will refer to those solids with a specific gravity of 4.2 and above. High specific gravity materials are used for drilling fluid density increases, the most commonly used of which are barite (4.2 s.g.), and hematite (5.0 s.g.). Low specific gravity solids may range from a low of 1.6 to 2.9 for dense lime. Drilled solids have a specific gravity in the range of 2.1 to 2.8. Most solids analysis calculations use 2.6 as the assumed S.G. of all drilled solids.
  • In a drilling fluid containing only low-gravity solids and fresh water, the concentration of solids will be a function of fluid density. The same relationship exists if a drilling fluid is composed only of barite and water. If a drilling fluid contains low-gravity and high-gravity solids, then the solids content will vary between the two ranges at a particular density. Figure 1 illustrates the effect of specific gravity and solids concentration on fluid density.
  • Particle Size – Fluid solids are measured in microns because of their small size. A micron (μ) is a unit of measure in the metric system and is 1/1000 of a millimeter. To better illustrate the relative size of a micron, there are 25,400 microns to the inch. API classification of solids by size range is listed in Table 1. Commercial clays such as MILGEL® contain predominantly particles which are smaller than 2 microns, or colloidal in size.
Particle Size, microns(μ) Particle Classification Sieve Size
Greater than 2000 Coarse 10
2000 to 250 Intermediate 60
250 to 74 Medium 200
74 to 44 Fine 325
44 to 2 Ultra-Fine 400
Less than 2 Colloidal

Table 1. API Classification by Particle Size

Even though drilled solids initially may be relatively coarse, they rapidly disintegrate into smaller particles due to chemical dispersion and mechanical action of the bit and drillstring. The rate of disintegration will vary with formation, type of drilling fluid, bit exposure time, annular transport time, annular circulating rate, degree of deviation, and mechanical abrasion from the drillstring. Disintegration can be shear dependent. It is extremely important to remove as many of the drilled solids as possible on the first circulation.

Low Gravity Solids Concentration

Most fresh water-base drilling fluids use bentonite for viscosity and filtration control. Low density fresh water drilling fluids may contain approximately two (2) volume % bentonite or about 18 lbs/bbl to achieve desirable properties. As mud density increases, the concentration of bentonite required decreases. Polymer based fluids may not use bentonite for this purpose by the substitution of other synthetic materials to achieve similar controls.

Experience has shown that the low gravity solids concentration should be controlled and maintained at specific levels for optimum fluid performance. Experience with the economics of solids control has indicated that the specific level for low gravity solids concentration falls between 4 and 6 percent. Since bentonite concentration can be approximately 2 volume %, this leaves room for only 2 – 4 volume % drill solids.

Various publications have addressed the issue of drilling and mud economics. The subjects of “dilution” vs. “displacement” have been considered. Since waste disposal has become a major economic factor in drilling operations today, emphasis has been placed on the proper selection and operation of mechanical solids control equipment. This has resulted in concentrating the volume of “dry” drill solids requiring disposal and therefore has minimized the need for building large volumes of dilution mud to achieve optimum fluid performance.

Dr. Leon Robinson presents an economic analysis that bears repeating. In his article, Robinson states that since drilling fluid costs vary greatly, a particular well situation needs to be analyzed. That involves the cost of fluid associated with each barrel of discarded drill solids which can be calculated. Using the data in Figure 2, if the drilling fluid target solids is 4 volume % and the system has a 60% removal efficiency, 9.6 bbl of drilling fluid will be discarded with each barrel of drilled solids discarded. Assuming a $50/bbl fluid cost, 1000 bbl of drilled solids would require $480,000 for new drilling fluid.

Robinson, L., How to Optimize Solids Control Economics, Efficiency, Handbook by Derrick Equipment Co., “Solids Control Manual for Drilling Personnel”.

If the drilling fluid target solids can be increased to 6 volume % and the removal efficiency increased to 70%, only 4.7 bbl of drilling fluid must be built for each barrel of discarded drill solids. Again, for a $50/bbl fluid, the same 1000 bbl of drilled solids discarded would cost $235,000.

Figure 2 Drilling Fluid Required if Discard Stream From All Solids Processing Equipment Averages 30% by Volume Solids


The Methylene Blue Test (MBT) is used to determine the Cation Exchange Capacity (CEC) of fresh water-base drilling fluid. The test measures the concentration of all active clays present in the drilling fluid. Correcting the test results for commercial bentonite concentration allows the concentration of all other clays to be estimated. Using the MBT test allows the concentration of drilled solids to be estimated and the drilling fluid treated/processed accordingly to achieve a predetermined drilled solids concentration. Efforts to reduce the drill solids concentration to lower levels can result in unnecessary drilling fluid maintenance expense.

Oil or synthetic-based systems, along with certain polymer systems, because of their inherently inhibitive nature, do not experience the same low gravity solids problems particular to fresh water-base drilling fluids.

The API Recommended Practices 13C contains a field method for evaluating the total efficiency of the drilling fluid processing system in water-based fluids. This procedure depends upon accurate dilution volume information. The API procedure uses the dilution volume over a given interval to compute a dilution factor, DF, which is the volume ratio of actual mud dilution required to maintain a desired solids concentration with no solids removal equipment. The dilution factor is used to determine the total solids removal efficiency of the system. The API procedure is as follows:

  • Over a desired interval length, obtain accurate water additions and retort data.
  • From the retort data, calculate:
  1. The average drilled solids concentration in the mud, ks.
  2. The average water fraction of the mud, kw.
  3. Calculate the volume of drilled solids, Vm⇒  Vm=Vw/kw
  4. Calculate the volume of drilled solids, Vc⇒ Vc = 0.000971×D² × L×W
  5. Calculate the dilution volume required if no solids were removed Vd⇒ Vd=Vs/ks
  6. Calculate dilution of factor, DF⇒DF = Vm/Vd
  7. Calculate the total solids removal performance, Et⇒Et = (1− DF) Multiply the result by 100 to calculate a percentage.

The accuracy of the API procedure depends somewhat on a relatively constant solids concentration in the mud, constant surface circulating volume, and consistent averaging techniques over the interval of interest.  The total solids removal performance by this method should be reported at frequent intervals during the course of drilling the well..



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