Single-pass friction stir processing (FSP) was used to increase the mechanical properties of a cast Mg-Zn-Zr-rare earth (RE) alloy, Elektron 21. A fine grain size was achieved through intense plastic deformation and the control of heat input during processing. The effects of processing and heat treatment on the mechanical and microstructural properties were evaluated. An aging treatment of 16 hours at 200°C resulted in a 0.2 pct proof stress of 275 MPa in the FSP material, a 61 pct improvement over the cast + T6 condition.

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The use of coiled tubing (CT) in wells containing hydrogen sulfide gas (H 2 S) has associated problems because of the potential for sulfide stress cracking (SSC) of the CT material. Carbon dioxide (CO 2 ) can also contribute to general corrosion or intensify any H 2 S-related corrosion because of chemical reactions resulting in acid. However, with the right precautions, equipment, and procedures, this type of operation can be carried out safely and successfully.The various problems associated with working with CT in H 2 S and CO 2 wells are discussed and a general best practice taken from locations working regularly with H 2 S and CO 2 is presented. This paper shows the equipment, chemical inhibitor, quantity and method of inhibitor application, and other precautions taken to carry out the work safely and successfully. An alternative approach is also highlighted for some situations whereby any H 2 S is bullheaded into the well before coiled-tubing intervention. This alternative approach avoids any contact of H 2 S with CT to prevent corrosion. A number of case histories are shown for different H 2 S and/or CO 2 locations around the world, which detail the type of operations, quantity of H 2 S and CO 2 , procedures used, frequency of operations, and the overall success of these methods in ongoing operations.This paper presents a review of methods and equipment currently being used around the world to work in potentially corrosive and dangerous H 2 S and/or CO 2 wells. Coiled Tubing Corrosion in Acid and Sour EnvironmentsOilfield production fluids containing the acid gases H 2 S and/or CO 2 can be corrosive to CT because of the resultant lowering of the pH of the aqueous phase. Low-pH aqueous fluids accelerate corrosion by providing a plentiful supply of hydrogen ions. Any brines in the production fluid will also increase the overall corrosivity to the CT, as well as provide an aqueous medium for contamination. Thus, H 2 S and/or CO 2 in brine is more corrosive than the same gasses present in oil. Alternatively, because an aqueous phase is necessary, the risk of corrosion or cracking in dry gas wells containing these gases is low.Basically, H 2 S mixed with water will produce sulphuric acid when oxidized or a weaker acid when no oxidizer is present. CO 2 produces Carbonic acid when mixed with water. H 2 S is noncorrosive in the absence of moisture.Other than wall thinning from general corrosion, there are several failure modes that can occur when CT is exposed to H 2 S-containing fluids. These are detailed in Appendix A and can all be directly related to hydrogen entry into the tubing metal structure. Unless otherwise stated, this paper will concentrate on the issues associated with SSC-type failures. Suitable Coiled Tubing SelectionGrade 80 CT will tend to show less susceptibility to SSC as compared to higher-strength grades but is not immune to problems in H 2 S-containing environments. Halliburton individuals:

Coiled tubing (CT) is routinely exposed to different concentrations of acid in stimulation and cleanout jobs. Routine maintenance measures are generally taken, such as the use of inhibitors and proper cleanup and storage practices. However, a large number of CT strings suffer from corrosion and corrosion-fatigue related damage. Though it is difficult to isolate string damage solely from corrosion fatigue, this paper addresses the effect of acid with and without inhibitors on corrosion-fatigue properties of the grade-90 pipe through experimental testing. The results of testing demonstrate that exposure to acid without an inhibitor and during fatigue had the most pronounced effect on fatigue life. The simultaneous action of corrosion and fatigue produced more pits and cracks than would have occurred by corrosion or fatigue separately. CT exposure to acid before, during, and after bending can have different effects on fatigue life. This paper describes an experimental study that was conducted to observe these effects. A strip of metal, 1-in. wide and 6-in. long, was cut from a round 1.75-in. OD, 1.56-in. wall thickness of 90-ksi yield CT and underwent one-way, bent-beam fatigue testing. This paper will present S-N curves generated for samples in three environments: air, acid, and acid with inhibitor at deflection levels ranging from 0 to 40 mm. Finite element analysis (FEA) was used to correlate deflection to strain range levels of 0.5 to 4.0%. Introduction Acidizing is one of the oldest stimulation techniques that is still used today. Often, when petroleum exists in a formation but is unable to flow readily into the well because the formation has very-low permeability, acidizing can be performed to increase production. This treatment is most effective if the formation is composed of rocks, such as limestone or dolomite that dissolve readily in acid. Acidizing is usually performed by an acidizing service company and can be done before the rig is moved off of the well after drilling. Acidizing can also be performed after the rig is moved away. Conventional acid treatments involve pumping 50 to 1,000 gal of acid into the well. The acid travels down the tubing, enters the perforations, and contacts the formation. Continued pumping forces the acid into the formation, where it dissolves channels that provide a way for the formation's oil or gas to enter the well through the perforations. The use of CT for remedial well stimulation (including acidizing) is one of the more popular uses of CT today and offers several advantages over conventional acidizing techniques:○Live well-interventions can be performed without killing the well, reducing additional formation damage.○Additional operations, such as a wellbore cleanout and well-unloading, can be performed immediately before and after a stimulation treatment.○The wellbore tubulars and wellhead equipment are protected from coming into contact with corrosive treatment fluids.○Enhanced placement of the treatment can be achieved, greatly improving uniform injection coverage in the zone or areas of interest.○Pickling and flushing of the CT and wellbore can be performed before treatments, reducing the risk of formation damage caused by contaminants. Major acids used in chemical stimulation include hydrochloric (HCl) acid, hydrofluoric (HF)-HCl acid mixtures, and organic acids. The following is an explanation of the main differences between these acids.