The complex conditions encountered in the harsh downhole environments of HP/HT wells drive difficult decisions because the scientific data needed to predict tubing/fluid compatibility has not been available until recently. Too often, the operator has had to select more exotic and expensive alloys and fluids just to be sure. Thus, the cost of materials for HP/HT completions has tended to be much higher than it would be if better information was accessible. Yet, despite these safe choices, there have been catastrophic failures.

To fill this information void, TETRA Technologies Inc. and a major oil country tubular goods

Figure 1. The annular environment is complex, and many factors can work together to generate conditions conducive to the development of various types of corrosion. (Figures courtesy of TETRA)
manufacturer have conducted more than 3,700 tests of chrome production tubing and the clear brine fluids most often used with them under real-world conditions. A vast database of these test results enables the prediction of safe tubing/fluid combinations at the lowest possible costs.

TETRA has developed a software program, called the Crack Reducing Fluid Selector (CRF), to access this database. This software allows operators to quickly access empirical data to design completion systems that will withstand the harsh conditions found in HP/HT wells.

The annular environment is complex, and many factors can work together to generate conditions conducive to the development of various types of corrosion: localized corrosion of the metal’s surface, pitting, or the relatively rapid phenomenon of catastrophic cracking due to stress corrosion. Because of these complexities, there have been no simple answers to the question: “How do I prevent stress corrosion cracking when using chrome tubing and clear brine packer fluids?” Surprisingly, after immersing chrome tubing in clear brine fluids for years, very little comprehensive scientific testing has been done to measure these factors or to establish effective guidelines to help operators avoid them. Although chrome tubing was instituted in these harsh environments because of its resistance to general corrosion, the industry had virtually no data or experience to realize that many of the additives that had been effective with carbon tubing could create stress corrosion cracking issues.

Tests have incorporated the harsh parameters (high stress; temperatures ranging from 100ºF to 400ºF (37.74°C to 204°C); contaminating CO2 and H2S gases) found in HP/HT wells. The result is a new body of empirical data.

As the data was generated from this unique testing program, a number of widely held universal truths about stress corrosion cracking and corrosion were found to be baseless. Such widely held beliefs as “chlorides are usually the cause of stress corrosion cracking” or “using bromide fluids will eliminate the chance of failure” have been found to be not always true. Indeed, the testing identified many instances where chloride fluids performed very well and other instances where bromide fluids experienced failure.

Now, the necessary scientific data is available to identify fluids compatible with the metallurgies determined to produce fluids and gases unique to an HP/HT well. This identification is significant because every well has its own fingerprint of corrosive gases, temperature, and other characteristics that contribute to the corrosive potential of the completion system. As Figure 2 illustrates, a given combination of tubing and fluid that works in one instance could fail in another set of well conditions.

New options
The CRF program uses key parameters such as bottomhole temperature, CO2 and H2S concentrations, required fluid densities, specific metallurgy of the tubing, anticipated stresses on the tubing and several other factors. The output is a cracking susceptibility index (CSI) that indicates how well the fluid/metallurgy combination performed under simulated well conditions in the testing phase.

The CSI is provided on a scale of 0 to 100, with values of below 25 indicating combinations that are acceptable for the conditions given. A CSI value of 0 indicates that the fluid/tubing combination experienced no cracking in the research testing, while a CSI of 24 indicates that although no cracking was observed, some localized corrosion or pitting was seen. CSI values of above 25 indicate that for the given well conditions cracks were observed during testing, and the combination would not be recommended for the well conditions.

These evaluations can be done in minutes with a CSI value provided for each combination of materials considered for the well. In this way, a completion design can be evaluated quickly with all options of fluid/tubing combinations being considered technically and economically.
The company also provides quality control during fluid procurement and delivery to assure that the fluid pumped into the well is as ordered. It is the chemistry of the fluid in the annulus that determines the potential for corrosion issues. So it is vital that effective QA/QC measures are taken to ensure that fluid chemistry is not compromised.

South Texas corrosion issues
In 2004, a South Texas gas producer acquired several HP/HT >350ºF (>176.5°C) wells. Initial evaluation of the wells found several to have corroded and cracked production tubing. Completion records indicated that these wells had packer fluids that were not properly matched with the chrome metallurgy in the wells. The company reviewed the completions using its CRF software.

Review of the well data indicated that mismatched fluids and additives had indeed been
Figure 2. A given combination of tubing and fluid that works in one instance could fail in another set of well conditions.
applied to the chrome tubing in some of the wells. These concerns were borne out during workover operations, as the company found numerous instances of stress corrosion cracking of the tubing and couplings. Recompletions were designed for these wells using information generated by the CRF program. Subsequently, the wells were successfully recompleted and restored to production.

Automated well design lowers cost
The company evaluated the completion design of a deep, hot gas well for a Gulf Coast offshore operator. The operator had selected a tubing metallurgy that he believed would require a pure calcium bromide packer fluid given the very harsh conditions of the well. Analysis generated three fluid choices that had an acceptable CSI.

As expected, calcium bromide had a CSI of 0 but calcium chloride, with an appropriate package of inhibitors and at a slightly lower density <.3 ppg, had a CSI of 4, while sodium bromide had a CSI of 7. Given that all three fluids evaluated were acceptable for the well, the operator was able to make a sound economic choice to use calcium chloride with the assurance that it would not create corrosion problems, while saving more than 70% of the cost of calcium bromide.

Changing the design sequence
Operators now have the opportunity to maximize the technical viability of wells while minimizing the cost of materials.

The evaluation can be done in minutes. This capability changes the traditional timing sequence of selecting tubing early in the process and making the fluid decision at much later date. Making the tubing/ fluid choices at this earlier point gives the operator all of the available options to design a technically sound completion at the lowest possible cost.