45

Typical Fatigue Failure Curves

Curve 1 - Steel in air Curve 2 - Notched steel in air Curve 3 - Steel in salt water

23456789 Number of Cycles to Failure (millions)

Figure 9-55. Typical fatigue failure curves.

Figure 9-58. Effect of concentration of hydrogen sulfide on failure time of highly stressed steel. (From the 1970 issue of Petroleum Engineer International. Publisher retains copyright.)

Time to failure, hr

Figure 9-58. Effect of concentration of hydrogen sulfide on failure time of highly stressed steel. (From the 1970 issue of Petroleum Engineer International. Publisher retains copyright.)

Control of Corrosion

The simplest and most common method of corrosion control is to use a highly alkaline mud. There are, however, limits to this practice: Notably, degradation of clay minerals by the hydroxy! ion starts at temperatures above 200°F (93°C) when the pH of the mud is above 10. As mentioned in Chapter 5, calcium hydroxide can cause solidification of the mud at temperatures above 300°F (149°C), and all hydroxides cause significant degradation and thickening at such temperatures. The wisest policy is to maintain the pH between 9 and 10, which, in many wells, will keep corrosion within acceptable limits, and at the same time allow tannate and lignosulfonate thinners to operate most efficiently. If previous experience in the locality has shown this procedure to be inadequate for corrosion control, or if excessive corrosion is detected by examination of the steel-ring coupons (which should be included in every drill string) (see the section on corrosion tests, in Chapter 3), then treatments appropriate to the particular type of corrosion involved must be applied. Table 9-1475 summarizes the common types of corrosion, their identification in the field, and suggested treatments. Details of the action and control of the various contaminants are as follows:

Carbon Dioxide. Carbon dioxide dissolves in water and lowers the pH by forming carbonic acid. Corrosion is best controlled by maintaining the pH between 9 and 10 with sodium hydroxide, but, when the inflow of the gas is large.

Table 9-14

Trouble Shooting Chart to Combat Drilling Fluid Corrosion*

Identification

Cause

Oxygen

Air entrapment

Mineral scale deposits

Primary source

Visual form of attack

Corrosion by-product

Test

Water additions

Mixing and solids control equipment

Formation and mud materials

Concentration cell.

Pitting under barrier or deposits Pits filled with black magnetic corrosion byproducts

Corrosion cell pits below deposit

Primarily magnetite

Fe304

Iron products below mineral deposit

Aerated Injected air Severe pilling Oxides of drilling fluid iron

Black to riiNi red

Treatment

Not acid soluble 1 HC1

By-product attracted to magnet

White mineral scale; calcium, barium and/or magnesium compounds

Oxygen scavenger: Initial treating range equivalent of 2.5 to 10 lb/hr of sodium sulfite. Maintain 20 to 300 mg/1 sulfite residual. Engineer to reduce air entrapment in pits. Defoam drilling fluid.

Coat pipe with film forming inhibitors during trips to reduce atmospheric attack and cover concentration cell deposits.

If mineral scale deposits on drill pipe, treat with tscale inhibitor at 5 to 15 mg/1 or approximately 25 to 75 lb/day added slowly and continuously. Treatment of scale inhibitor may be reduced after phosphate residual exceeds 15 mg/1. Treatments of 1 gal 1000 bbl mud day can be used for maintenance treatment under normal drilling conditions.

fOrganic phosphorous compounds

Maintain chromale concentration at 500 to 1000 ing/l with chromate compounds or ¿inc chromale compounds. Maintain hieh pH.

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