DRILLING FLUIDS WITH SCAVENGERS HELP CONTROL H2S

Paul Scott
M I Drilling Fluids Co.
Houston

Maintaining a high pH and using chemical M sulfide scavengers in oil based and water based drilling muds can neutralize hydrogen sulfide (H2S).

Safe, successful drilling of H2S bearing formations requires good drilling practices, extra attention to casing design, and proper drilling fluid formulation, The drilling fluid must be capable of controlling formation pressures, protecting workers, inhibiting corrosion, limiting drilling fluid contamination, maintaining well bore stability, and removing sulfide contamination rapidly.

In drilling operations, hydrogen sulfide is encountered in sour formations, in various make up waters, and in some fluids after bacterial degradation of sulfates.

H2S is soluble in both water and oil. Understanding H2S behavior in drilling fluids is essential to making appropriate fluid decisions. High stability, oil based muds are preferred for performance and corrosion reasons. High pH, dispersed water based muds offer acceptable performance when environmental conditions or uncertain formation pressures are important considerations.

High alkalinity drilling fluids with excess lime are recommended to provide buffering capacity for pH neutralization. Following the detection of soluble sulfides, the fluid should be immediately treated with the applicable scavenger.

In solution, hydrogen sulfide gas ionizes depending on the pH (Fig. 1). H2S dominates in the lower pH range. At higher pH levels, hydrogen sulfide is ionized into less harmful hydrosulfide (HS ) and sulfide (S=) ions.

The conversion of H2S into HS and S= by pH control is referred to as neutralization.

If the pH is kept high with treatments of alkaline additives, such as caustic soda (NaOH) or lime (Ca(OH)2), then the concentration of hydrogen sulfide remains very low.

For instance, at a pH of 11.0, 99.99% of H2S is converted to HS and S= ions.

Neutralization is reversible, however, and a decrease in pH below 11.0 converts these ions back into H2S. Subsequent contamination from H2S, CO2, or brine could cause the pH to drop below a safe level.

At atmospheric pressure, even high pH fluids liberate H2S if the sulfide concentration is excessive.1

Alkalinity, alone should never be relied upon to control sulfides. Any detectable sulfide contamination should always be immediately treated with an appropriate scavenger.

DRILLING FLUIDS

The National Association of Corrosion Engineers (NACE) specifies controlling the drilling environment to prevent sulfide stress cracking by maintaining the hydrostatic head and fluid density to minimize formation fluid inflow and by one or more of the following:

Maintaining a pH of 10 or higher to neutralize H2S in the drilled formation
Using chemical sulfide scavengers
Using a drilling fluid in which oil is the continuous phase.2

The service life of steel equipment is directly related to the concentration of H2S and the exposure time. Corrosion tests indicate that maintaining an alkaline pH will significantly reduce failures (Fig. 2).5 Drillstring failures have occurred during kill procedures with sour gas kicks.

Clearly, every effort should be made to limit the influx of sour gas into the circulating system, to identify any H2S contamination, and then to remove it as soon as possible. Drilling practices such as the use of an overbalanced mud weight and comprehensive sulfide detection and worker protection programs are essential. Once H2S has contaminated the circulating system, mechanical degassing equipment and sulfide scavengers should be used to remove all sulfides.

The solubility of hydrogen sulfide is important to drilling fluid formulations. H2S is highly soluble in oil and oil based muds and slightly soluble in water and water-based muds. H2S is more soluble than carbon dioxide or methane in diesel oil (Fig. 3).

This increased solubility indicates that the expansion of dissolved sour gas in oil-based mud would not occur until the mud is circulated up the annulus near the surface. Under certain conditions, gas flowing into the well bore dissolves in oil-based mud, reducing the normal pit gain volume and making kick detection extremely difficult.4 Particular care should be taken to identify small pit volume increases when sour gas formations are drilled with oil-based mud.

The two fluid systems used most often for drilling sour formations are a high-pH, dispersed water based system and a high stability, oil based system. Each of these fluids is formulated with a sufficient quantity of lime to provide a buffered alkalinity and neutralizing potential.

WATER BASED SYSTEMS

Water based muds are often preferred to oil based muds because of environmental considerations. If formation pressures are not well known, water based muds also have the advantage of improved kick detection.

Severe contamination of any water based mud with H2S, CO2, or brine win adversely affect rheology and filtration control, possibly compromising well bore stability.

High pH, dispersed mud systems provide an alkaline environment for neutralization and are moderately resistant to contamination. The capacity of a mud to neutralize H2S is directly related to the mud alkalinity, Pm.5 Field practice is to maintain the following alkalinities:

Pm greater than 3.0 ml using lime
pH greater than 11.0
Pf (filtrate alkalinity) greater than 1.0 ml using caustic soda.

Lime has limited solubility at a higher pH and functions as a very effective pH buffer. Typically, 5 15 lb/bbl insoluble excess lime should be maintained for severe H2S applications.

Contamination resistance is achieved by providing a buffered pH with excess lime, minimizing the reactive solids content, and using a high concentration of deflocculant and lignite-based additives. Minimizing the reactive solids by limiting the bentonite content and methylene blue test to 10 lb/bbl and the low gravity solids to 6% is an effective approach to improved contamination resistance.

Shale inhibition can be increased by using potassium-based additives such as potassium hydroxide and potassium lignite and by using asphaltic additives for improved well bore stability.

Table 1 shows typical additive concentrations for water based mud. Pretreatment with 1 2 lb/bbl of a zinc-based sulfide scavenger, such as zinc oxide, is routine for situations where H2S contamination is anticipated with these systems. Additional corrosion control can be obtained with batch treatments or direct application of a film forming amine to coat tubular goods.

OIL SYSTEMS

Oil based muds have a distinct advantage over water based muds because they oil wet metal surfaces, thereby protecting them from the corrosive effects of H2S. Oil-based muds have better contamination resistance, temperature stability, shale inhibition, and lubricity than water based muds. Sulfide scavenging chemicals react more slowly in oil based muds than in water based muds because of the oil continuous environment. H2S-gas contaminated oil muds can be effectively treated with the combination of degassing equipment and chemical scavengers.

High stability, oil based mud systems use high levels of excess lime for neutralization. Normally, oil/water ratios (OWR) greater than 85:1 5 (to restrict the amount of brine) are used for drilling sour environments. Field practice is to maintain the following properties:

Mud alkalinity (Pom) greater than 10 ml
Electrical emulsion stability greater than 1,500 volts
OWR greater than 85:15.

Table 2 shows typical concentrations for a 16 ppg, 90:10 OWR oil based mud.

High stability, tightly emulsified oil based muds are inherently resistant to contamination and provide the best shale inhibition and corrosion protection. However, low stability, weak emulsion, oil based muds, such as water contaminated, low OWR muds, do not exhibit acceptable corrosion protection.

SYNTHETIC SYSTEMS

Recently developed synthetic based muds perform like oil based muds yet meet the environmental criteria for water based muds in certain applications. The base liquids used in the various commercial systems differ significantly in their composition and properties.

Synthetic based muds that use base liquids that are chemically stable at all pH levels and in the presence of H2S appear well suited for use in sour gas applications.

DETECTION

H2S contamination is often first detected by electronic sensors and continuous monitoring equipment.

The following are drilling fluid related indicators of H2S contamination:

A drop in pH and alkalinity,
An increase in viscosity
An increase in fluid loss
In water based mud, a change in color to green-black
A black color on drill pipe
A positive sulfides test on corrosion coupons.

Indications of sulfide contamination should be immediately quantified using one of the following sulfide test procedures:

Hach test
The Hach test is best used as a qualitative indication of the presence of sulfides. This quick, simple test uses lead acetate paper and a seltzer tablet in combination with a color comparison chart to estimate sulfides concentration. The lead acetate paper changes color from light to dark brown depending on the concentration of sulfides.
Garrett gas train
The Garrett gas train is a more sophisticated method of accurately determining the level of soluble sulfides. This American Petroleum institute procedure uses an acid to convert the soluble sulfides into H2S gas while an inert gas flows through the sample to transfer the H2S to a Drager tube. Separate test procedures are used for water based and oil-based muds.

H2S SCAVENGERS

Sulfide scavengers must react with soluble sulfides to form an insoluble metal sulfide precipitate. Effective scavengers must have rapid and complete reactions with H2S, HS , and S= in the chemical and physical environment of the circulating system with minimal side effects. Currently, three zinc-based additives and one iron oxide compound are the most widely used scavengers.

Zinc based scavengers include zinc oxide, basic zinc carbonate, and zinc chelate. Zinc is a divalent cation which may adversely affect lightly treated high solids muds. The chemical reaction of zinc based scavengers with the sulfide ion forms zinc sulfide (ZnS), which is insoluble at a pH greater than 3:

Zn + S= ZnS (pH 3)

* Zinc oxide

Zinc oxide (ZnO) is a widely available, economical additive and is the preferred scavenger for most applications. Zinc oxide has a very high zinc content and can be used in either water based or oil based muds. A 1 lb/bbl treatment of zinc oxide can theoretically remove 1,100 mg/l. sulfide and has minimal effect on high ph, dispersed water based muds. The actual removal is less typically in the 200 800 mg/l. range,

* Basic zinc carbonate

Basic zinc carbonate is a complex compound containing both zinc carbonate and zinc hydroxide (3 Zn(OH)2 2 ZnCO3). Treatments of 1 lb/bbl can remove about 500 mg/l. sulfide. Although basic zinc carbonate has a high zinc content, it also contains 20 wt % carbonate (CO3=) which can flocculate lightly treated, high solids muds. Lime must be added to precipitate the carbonate ions. Pretreatment in water based systems should be limited to lb/bbl.

* Zinc chelate

Zinc chelates are water-soluble additives with the zinc ion chelated, or loosely bonded, to an organic molecule. The primary application for zinc chelates is in brines and low viscosity muds where the insoluble zinc additives would settle. Zinc chelates have relatively low zinc concentrations. Although products differ, a 1 lb/bbl treatment of one commercially available liquid zinc chelate removes about 220 mg/l. sulfide.

* Iron oxide

Iron oxide (Fe3O4) scavenger is a specially reacted, high surface area product. It is insoluble in water and reacts with soluble sulfides to form several stable iron sulfur compounds. Iron oxide is most effective at low pH levels where H2S is the predominant sulfide species.6 The rate of reaction is highly dependent on temperature, pressure, and mixing intensity. The recommended treatment is 10 20 lb/bbl of iron oxide. Because of the treatment's pH sensitivity, it is advisable to use a zinc-based scavenger in combination with iron oxide if soluble sulfides are identified in an iron oxide treated system, especially during difficult H2S contamination situations.

Zinc oxide, basic zinc carbonate, and iron oxide are sparingly soluble to insoluble and exist as solid particles. Special high surface-area grades of these materials are recommended for maximum efficiency in sulfide removal. These high-density solids require the mud properties to provide suspension. Note that a suspended solids, these additives can be rejected by solids control equipment.

REFERENCES

Wendt, R.P., "Generalized Theory for Evolution and Dispersion of H2S from Alkaline Muds," Society of Petroleum Engineers Journal, April 1983, p. 365.
National Association of Corrosion Engineers Standard MR0175 91, Material Requirements Sulfide Stress Cracking Resistant Metallic Materials for Oil Field Equipment, NACE, 1991.
Hudgins, C.M., et al., "Hydrogen Sulfide Cracking of Carbon and Alloy Steels," Corrosion, August 1966, p. 238.
Thomas, D.C., Lea, J.F. Jr., and Turek, E.A., "Gas Solubility in Oil Based Drilling Fluids: Effects on Kick Detection," Journal of Petroleum Technology, June 1984, p. 959.
Whitfill, D.L., "Calculate the Amount of H2S a Drilling Mud Can Neutralize," World Oil, December 1975, p. 74.
Garrett, R.L., et al., "Chemical Scavengers for Sulfides in Water-Base Drilling Fluids," Journal of Petroleum Technology, June 1979, p. 787.
American Petroleum Institute RP49, "Recommended Practices for Safe Drilling of Wells Containing Hydrogen Sulfide," second edition, Apr. 15, 1987.
American Conference of Governmental Industrial Hygienists, "Threshold Limit Values for Chemical Substances and Physical Agents and Biological Exposure Indices," 1992 93.