Sunday, 8 December 2019

OIL & GAS CASING DESIGN - CORROSION

CORROSION 

Casing Design - oilfield - corrosion - drilling
Casing Corrosion



The presence of CO2 and H2S accompanied by water, can cause corrosion of the exposed tubulars. In addition, H2S can cause stress corrosion cracking.

Corrosion Mitigation 

When CO2 or H2S are dissolved in water, they will create an acidic solution. These solutions react with the iron in the pipe causing local pitting which can eventually eat a  hole in the pipe. Some of the ways of combating this corrosion are as follows:

1. Plastic Coatings 

There are a variety of coating materials and thicknesses for the different chemical components and temperatures of the produced fluid.

The inside coating can reduce its effective drift diameter. So it is necessary to coordinate the plastic coating thickness with the proposed through tubing work.

Some disadvantages of internal plastic coating, IPC, is that it is difficult to apply to all exposed surfaces. This is particularly true of coupling recesses and accessories such as packers, seating nipples and safety valves. In order to maintain continuity of the plastic coating's corrosion barrier, some connections provide a Teflon ring on the ID between the pin end and the box recess. It is difficult to ensure that there are no holidays in the coating. Also IPC can be damaged by wireline tools.

2.  Fiberglass Lined Pipe 

Where the corrosion is very high, it is cost effective to have fiberglass lined tubing. Fiberglass lined tubing is constructed by inserting a fiberglass tube of ±0.1 in. wall thickness into the steel tubing. The small annulus between the fiberglass tube and steel tubing is filled with cement.

This lining results in a longer lasting corrosion barrier that plastic coating does not provide. In addition, there are no holidays or interruptions in the lining, the fiberglass is continuous the entire length of the joint.

Fiberglass is more resistant to wireline damage than plastic coatings.

3. High Alloy Carbon, Stainless Steel or Chromium Tubulars 

Where plastic coating is impractical, corrosion control can be achieved through these alloy steels.

This is not a common method since alloy steel tubulars usually cost much more than a conventional steel string.

4. Chemical Inhibition 

An inhibitor may periodically be pumped into a well to form a film on the pipe. If there is no means to circulate down the inhibitor while producing the well, it will be necessary to shut in the well and pump down the tubing.

In a gas lift installation, the inhibitor may be pumped into the gas system. Where wells are completed with concentric strings, the inhibitor can be continuously pumped down one string, with the produced fluid carrying the inhibitor into the other string.

Sulfide Stress Cracking

A type of corrosion caused by H2S can be a severe condition because it can lead to gross failure of steel equipment. Stress corrosion cracking attacks points subjected to a high tension stress. Once the stress crack is initiated, the tensile stress may increase due to the reduced area, thus leading to accelerated stress cracking. This process continues until the stress increases to the ultimate strength of the steel, at which point failure occurs.

In order to prevent stress corrosion cracking in tubulars due to the presence of H2S, certain design criteria can be applied.

1. Steel Properties

One of the principal factors governing the resistance of tubulars to stress corrosion cracking is the physical properties of the steel. Through extensive testing it has been determined that the higher strength carbon steels are more susceptible to sulfide stress cracking.

The API Specification 5CT lists two steel grades, L-80, and C-95 which have a restricted yield strength range of 15,000 psi. This restricted range has the net effect of holding down the maximum strength of the steel while maintaining an adequate minimum yield strength. In addition to the narrower yield strength range, these grades have additional chemical and heat treatment controls not
required on other API steel grades. These three have been widely used in H2S environments. With experimental work on the effect of the heat treatment methods on resistance to sulfide stress cracking, there has been an increased use of the quenched and tempered L-80 grade.

In addition to the API grades, there are proprietary grades used in H2S service. Most of these have a minimum yield strength from 80,000 psi to 90,000 psi, with  a controlled yield strength range of 15,000 psi. This is the same range as API restricted yield grades.

2. Temperature Susceptibility

Another factor in susceptibility of tubulars to sulfide stress cracking is the temperature of the steel when it is exposed. It has been shown that at elevated temperatures, the higher strength steels are not susceptible to sulfide stress cracking. NACE Specification MR-10-75 refers to the use of API grade, P-110 and proprietary grades to a maximum 140,000 psi yield strength in an H2S environment where the temperature during exposure is not less than 175° F. The use of API grades N-80, C-95 and proprietary grades up to a maximum yield strength of 110,000 psi can be used in temperatures above 150° F.

3. Other Factors

Other factors effecting sulfide stress cracking are the level of stress in the steel and the time of exposure. Lower stress levels reduce the chance of sulfide cracking. The steel chemical and mechanical properties, in addition to the time and temperature at exposure and the tensile stress level, determine the susceptibility of the steel to sulfide stress cracking.

4. Design Considerations

In deep, high pressure gas wells where both internal pressure and tension would normally require high strength steels, design of casing and tubing strings becomes difficult with the restriction of the minimum yield strength to 90,000-95,000 psi in an H2S environment. Application of restricted yield strength steel grades dictates thicker-wall pipe in order to handle the high tension and internal pressure loads. A well with a high bottom hole temperature can use P-110 and/or X-125 casing and  P-105 tubing in the lower section of the hole up to a point where the static temperature is no longer high enough. At this crossover temperature, it is then necessary to run the sulfide stress cracking resistant grades to the surface.

By using high strength steel on the bottom, the wall thickness can generally be reduced, thus decreasing the total weight of the string. This is particularly important with the upper section of the string requiring lower strength steel, the reduced weight on the bottom sections will further reduce the weight required at the surface.



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