Drilling Fluid Disposal

Potentially Hazardous Components of Drilling Fluids and Potential Hazards of Complete Drilling Fluids

shale shaker and drilling fluid disposal

A symposium organized by the EPA administrator and the drilling industry in 1980 examined those factors of drilling fluids considered potentially hazardous to the environment. These were oil itself, especially in oil fluids, salts, and soluble trace elements consisting of Zn, Pb, Cu, Cd, Ni, Hg, As, Ba, and Cr (zinc, lead, copper, cadmium, nickel, mercury, arsenic, barium, and chromium) associated with low grades of barite. Many of the papers presented before that symposium were reports of the effects of single components of drilling fluids on aquatic life, indicating a belief on the part of those authors that drilling fluids readily are broken down into their components – a belief not so readily shared by drilling personnel.

Drilling fluid disposal was managed by Aipu solids control equipment

The extreme difficulty in properly defining “hazard,” “component,” and “drilling fluid” has led to a great deal of misunderstanding in past assessments of dangers involved in using and disposing of drilling fluids. Apart from the sheer esthetic appearance of the materials involved – a
factor that bears negligible weight in terms of disposal hazards – the hazards associated with individual components that make up a drilling fluid and those associated with the finished whole fluid are absolutely-and totally different.

The hazards of components that make up a fluid may be great; the hazards of the mixed components that constitute the complete fluid are almost uniformly very small. Caustic soda (NaOH) constitutes a handling problem for rig personnel due to its ability to burn by chemical dehydration and dissolution of fatty tissue. But when mixed into the buffering power of a fluid contammg weak acids such as lignosulfonates and bentonite, the NaOH becomes a salt of a weak acid and/or is absorbed interstitially in the clay and rendered harmless.

Oilfield solids control

The handling of fluid components around the drill rig can be carried out safely by following procedures outlined in material safety data sheets supplied by the manufacturers of all fluid components. These sheets are readily available to contractors and operators alike. The sheets provide all the information needed for safe handling and frequently provide a “hot line” for the solution of unusual problems.

But the problem addressed by this paper is that of completed drilling fluid disposal. And for this, the potential hazards of complete fluids must be addressed.

Several very general studies have been carried out to determine effects on environmental factors. One study prepared by a Tulsa-based independent geological consultant firm studied the impact of oil and gas production on salinity in major freshwater aquifers. This report worked from public water agency records in five major petroleum-producing states covering regions containing thousands of petroleum-producing sites. The conclusion reached was that there was essentially no effect on major freshwater aquifers due to oil and gas well drilling. Miller carried out an outstanding study on the effects of whole drilling fluids and their components on plant growth, conduding that major effects on plant growth were from soluble salts, exchangeable sodium values, and diesel oil phytotoxicity. All these effects were ameliorated greatly by dilution and time. Long-term effects (greater than 3 years) indicated that growth factors become positive; thus, the fluid when diluted became a fertilizer. More recently, Nelson et al. 10 studied plant uptake and accumulation
of metals derived from drilling fluids. Results similar to Miller’s were obtained. Addition of 50 wt% of drilling fluid to fertile soils resulted in
plant yield reductions. But more moderate applications (20 wt%) did not result in yield decreases. An important observation made by many researchers in the case of the most hazardous elements (Pb, Hg, As, etc.) is that residues from worst-case drilling fluids frequently have an associated lower level of the contaminant than the background levels of the original flora and fauna.

oilfield mud tank in drilling pits

A difficulty in arriving at any decision-making consensus regarding toxic effects of trace elements can be illustrated in the case of zinc. Hundreds of
papers have been written representing thousands of experiments carried out to determine (1) the maximum toxic limits of Zn on plants and animals and (2) the minimum level required in plant and animal nutrition. Ambient water quality criteria for Zn were set by the EPA in 1980. 11 A water limit of 5 mg/L is set arbitrarily by many states on the basis of a wide-ranging tolerance for Zn by plants and animals. However, long-term oral administration of zinc sulfate in daily doses of 135 to 150 mg of contained Zn has been well tolerated by patients given the compound to promote wound healing. 11 Further,. the EPA criteria cite the following minimum daily requirements of Zn: adults, 15 mg; pregnant women,
20 mg; and lactating women, 25 mg. The apparent ambiguity of this information concerning Zn translates into a vacuum in terms of yielding
engineering information. What level of zinc is tolerable?

Again, the fact that we place a certain amount of metal compound into a drilling fluid does not mean that the metal will be available for plant or animal uptake from the whole fluid. The exchangeable sodium ion in bentonite readily may be exchanged for any ions of the so-called pollutant metals (Hg, As, etc.), but the resultant complex may be stable toward further exchange. That is, bentonite has a preferential adsorption order for various metal ions. Potassium, after adsorption, is at least
partially unavailable for plant uptake. Ample evidence exists that most of the so-called pollutantions are removed almost quantitatively from various slurries similar to drilling fluids by clay filtration using bentonite and attapulgites as the filtration media.

Even if individual components of drilling fluids were examined for their potential hazards, the major components would remain nonhazardous. As already pointed out, bentonite itself is used as an absorbent and an absorbent barrier to encapsulate all of the transition metals and the so-called heavy metals. The soluble gums, cellulose and its derivatives, and starch (i.e., the various polysaccharides) all are either edible or useful as fiber in human and animal diets. The synthetic polymers used in drilling fluids – the polyacrylamides and polyacrylates – are biologically nearly inert because of their high molecular weights. (Some recent research indicates that these are biodegradable.) Barite, regularly ingested for
radiology tests, is virtually insoluble to the point of being inert. Lignosulfonates, per se, have relatively low toxicities among organic compounds and probably would constitute about the same element of hazard as an equal weight of peat or wood chips.

Disposal Methods for Spent Fluids

Direct Ejection of Fluids.

Water-based fluids may be spread directly over adjacent agricultural or forest land areas after adjustment of pH and ion content. Circulating with flocculant and alum and filtering through charcoal are typical costs, as is addition of pH-adjustment chemicals. A major consideration is chloride ion content. Several published drinkingwater standards for water quality are in existence; U.S. Public Health Service recommendations, federal mandatory levels, and World Health Organization recommended limits are tabulated in Ref. 15. The maximum recommended limit of 250 mg/L of chlorides for potable water is not mandatory but only recommended at the federal level. (Note: The units ppm, mg/L, and mg/kg all would be equal for a fluid whose density were exactly unity.) For animal watering, the recommended maximum level is 500 ppm. The typical field cost data shown in Table 1 are for spent fluids satisfactory for stock watering.

Table 1

Total Treated (bbl) Fluid Chlorides Contents Chemical Cost ($) Total Cost ($) Cost Per Barrel
14000 492 1120 7346 0.52
10258 210 860 4153 0.40

With higher chlorides, some transport of the fluid to a better disposal site may be necessary. Field cost data in Table 2 reflect this.

Table 2

Total Treated (bbl) Fluid Chlorides Contents (mg/kg) Chemical Cost ($) Total Cost ($) Cost Per Barrel
19000 8610 5999 14918 0.79
37300 2250 10354 25687 0.69
13446 4962 4245 11429 0.88

Pit and Solids Encapsulation.

Pit encapsulation means the procedure of reserve pit construction such that at the end of drilling the contents may be left in place and sealed in. Normal procedure involves slurry trenching or the equivalent for sidewalls, plowing in organic-treated bentonite (usually about 3 to 4 lbm(sq ft) for a bottom base, placing plastic liner in this excavation (20 mil thick), and covering the liner with additional soil containing some organic-treated bentonite for puncture protection. This pit then can be filled with waste drilling fluid. At well completion, the fluid is allowed to evaporate and, when substantially dewatered, can be covered with a top layer of soil filled with organic-treated bentonite. Typical plastic liners are made from PVC, Hypalon, and CPE; they may be fiber reinforced and
are normally available in widths up to 100 ft. Location of the burial should be recorded. This is a highly recommended practice for even extremely hazardous waste disposal; it provides protection second only to complete incineration of wastes. For the average drilling fluids, such protection is more than adequate.

Solids encapsulation means the procedure of removing solids from a fluid by some form of polymer coating procedure. One such encapsulation is a novel treatment for the removal of chloride ion by microorganisms. At least one Canadian company provides a microorganism “cocktail” that, along with nutrients, is added to a fluid containing suspended solids and high chloride ion content. The microorganisms utilize chloride during growth and coagulate solids. After sufficient aging, clean water can be pumped off, leaving the coagulated solids residue, which simply is buried. Chloride ion concentration is normally below 200 ppm following aging. Again, the burial site should be recorded. This treatment can be more economic because of lower handling costs than normal chemical treatment.

Pumping Into Safe Formations

Deep well injection of spent fluids is another possible alternative. (A modification of this would be to dispose of fluid between casing strings.) Location of a suitable lowfracture- gradient formation bounded by lmpermeable formations is all that is necessary. A very rough estimate of costs is $0.01/lbm.

Removal to Designated Disposal Sites

A current practice is haulage by vacuum trucks to designated disposal sites. Charges for the pickup will vary; a current figure for just the pickup is from $0.50 to $1.35/bbl. Alternatively, vacuum trucks are leased at $60/hr plus fuel. In addition to the pickup or lease charge, there may be a disposal site fee and mileage charges on the trucks. Overall, this kind of disposal has associated costs of about $1 to $1.50/bbl.

Were the state or local agencies to determine that a fluid would have to be disposed of into a hazardous waste “secured” landfill, the fees at the landfill could run as high as $80 to $100/bbl.! A state-bystate list of secured hazardous waste management facilities is given in Ref.

Separation of Clean Liquid From Clean Solids With Reuse of Liquid

Current solids separation equipment capable of operating on both water- and oilbased fluids is described later. One commercial process available for water-based fluids uses a special equipment unit in which chemical· treatment specifically designed for a given fluid essentially coagulates all solids into a tractable material that is separated from the bulk of the fluid. This nontacky solid is dewatered to an extent beyond most polymerflocculated drill solids separable by the conventional shale shaker, desander, desilter, mud cleaner, decanter centrifuge solids control train. The recovered fluid from this new commercial process also is said to be useful for makeup water without further treatment. By alteration of the chemistry of the special coagulation procedure, commercial bentonite may be retained in the recovered fluid.

Hourly rates for one processing unit capable of handling three wells were estimated to be (1) travel charges, $60.00/hr, (2) standby charges, $87 .50/hr, (3) rig-up charges, $98.00/hr, and (4) operating charges, $175.00/hr.


Incineration might be considered in an extreme case for oil-based drilling fluids but is not considered seriously because of costs. Hazardous chemical wastes now being incinerated for disposal cost from $0.10 to $0.15/Ibm. If incineration can be carried out without air pollution, it offers the advantage for so-called hazardous wastes that ash produced is disposed of readily in any landfill. For drilling fluids that are not hazardous, there seem to be no advantages in incineration.

Microorganism Processing

Aside from the novel process described earlier in the section on encapsulation, there does not seem to be any extensive development of microorganism processing. This is somewhat surprising in view of the intense interest in bioengineering and the ancient processes of fermentation and sewage treatment.

Two oilfield-related processes using microorganisms are reported in Ref. 16 where oilfieldproduced water is treated by lagoon aeration or by a “biodisk” mechanism to eliminate undesirable organics.

The obvious advantages of microorganism processing are the potential of obtaining free chemicals from waste material and having a process that is self-sustaining. Obvious disadvantages are the difficulty of keeping the process alive, avoiding strain contamination, and the possibility that a strain that digests various organics also will digest metals.

Distillation, Liquid Extraction, and Chemical Treatment

One process being tested in Europe involves the use of an electrically fired distillation kiln to break down solids-laden oil-based muds. It is not’ known what costs might be involved; however, as a result of added heating costs, distillation units are expensive.

An interesting proposed process involving liquid extraction would use permanent gases near critical conditions as “super solvents” to take apart oilbased fluids.

However, the main piece of equipment required in this liquid extraction unit is a high-pressure compressor operating at pressures up to 2,000 psi or higher. Capital irivestment of around $500,000 would be required for this process. Perhaps the time will come when such a unit is economically feasible.

Chemical fixation of water-based fluids is a current possibility. A typical proposed process uses a mixture of something like a potassium or sodium silicate with portland cement to turn a drilling fluid into a soil-like solid that may be left in place, used as a landfill, or even used as a material of construction. This kind of solidification process has been suggested
for radioactive wastes, and while it appears to be economically unfeasible for drilling fluids, it has the definite technical advantage that literally all the transition and heavy metals considered ecologically suspect in the worst-case drilling fluids (i.e., Hg, Pb, As, Cd, Cr, Zn, etc.) would be converted to (physiologically) extremely inert silicates or hydrous oxides.

An estimate of the cost of chemical fixation is at the level of $0.08/lbm. In terms of rig fluid handling, one additional lagoon would be required, as well as a special mixing unit. Depending on the volume of fluid treated, an aging period of from 3 to 19 days is necessary to develop the appropriate degree of solidification. Table 3 is a cost summary.


Method Water-based Oil-based Cost Range ($/bbl of fluid)
A X 0.40 to 0.90
B X X 1.50 to 6.00
C X X 3.00 to 4.00
D X X 1.00 to 1.50
F X 35.00 to 50.00
G X X not available
H X X 20.00 and more

Current Solids Control

There may be additional methods of disposal based on physical processing for fluid disposal; if so, these and the preceding processes should be coupled to the costs of current conventional solids control systems. The current systems are essentially a degasser, shale shaker, desander, desilter, and centrifuge.

Some typical recent daily rates for some of these units are degasser, $50 to $90/D; shale shaker, $80 to $100/D; desanders and desilters, $100 to $150/day; and centrifuges, $160 to $370/D.

There are many combinations of solids control equipment in addition to this suggested train.

At least some of the solids control equipment costs must be attributed to satisfying environmental considerations.

In addition to the choices and costs of the processes discussed here, the cost of site restoration must be tabulated. Currently, about the lowest cost
for site restoration is on the order of $5,000/acre. If extensive earth movement is involved, this cost can skyrocket.

Disposal Discussion

Our major concerns are with safety of rig personnel, conservation of rig equipment and materials, and the integrity of the environment.

Considering the low level of hazard associated with contacts of the environment with whole drilling fluids and the safeguards (buffering effects) built into the fluids, sale of many fluids for forest or agricultural development should be considered before disposal. Reuse of fluids would be recommended where development drilling continues.

Where disposal of the fluids into the environment is necessary, all the previously described methods could be considered. All the methods are environmentally sound when properly managed, and anyone might have local availability or advantages.

Specific rig practices that can be applied are (1) conforming to manufacturers’ material safety data sheets, (2) segregation of different fluids in separate storage, and (3) minimization of all fluid volumes.

An API-managed data base to supply industry with environmental management details (state regulations, etc.) is recommended highly.

In areas where regulatory processes increase, more costly drilling will result. The industry has moved toward more costly closed-fluid systems; increased regulation would accelerate that movement. One could predict several trends: highly inhibited polymer fluids would be used earlier in the drilling systems, oil-based fluids with specially developed diamond bits as well as turbodrill systems also would be encouraged, and more rig automation with microprocessor controls would be encouraged.

The disposal system discussion in this paper is intended to serve only as a guide to the hard details that still are needed to evaluate and optimize the
disposal of fluids properly. We need more engineering details. It is hoped that these· can be developed in a logical process without the artificiality of unnecessary restrictions.

Conclusions and Recommendations

  1. Safety of rig personnel and integrity of the environment must be maintained as paramount features of drilling fluid management.
  2. Rig practice would include safe handling of materials conforming to manufacturers’ material safety data sheets, minimization of fluid volumes, and segregation of different fluids.
  3. The drilling industry must continue its research and development, incorporating the best environmental practice with drilling optimization and emphasizing research on whole drilling fluids rather than partial fluids or single components. This information should be shared with state agencies for best disposal management, and it is recommended highly that an API -managed data base be set up to accumulate and dispense drilling fluid disposal management information.

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