Residual oxygen in membrane generated nitrogen, when commingled with potassium or sodium chloride drilling brines for underbalanced drilling (UBD) applications, is known to be very corrosive to drill pipe, casing and tubing. Commercial chemical inhibitors are routinely applied in such applications but supporting laboratory test data in the literature often fail to represent actual downhole environments.The corrosion rate data from case study wells has limited value due to available locations and technology for measurement within drilling process flow loops. The test protocol discussed here and corresponding results provide for more realistic evaluation of inhibitor effectiveness and suggest a mechanism for corrosion inhibition.The tests were conducted in stages intended to first establish the baseline corrosive behavior of low alloy steel in oxygenated brine with and without pH control by means of buffering agents. Subsequent tests focused on the effect of corrosion inhibitor concentrations and other additives. The results of the test program indicated that a combination of conditions resulted in significant inhibition of low alloy steel against oxygen corrosion, and is associated with the formation of surface film containing phosphorus. Corrosion rates as low as 50mpy without pitting were achieved, compared with 900mpy with significant scaling for uninhibited oxygenated brine. This paper describes the development of conditions necessary to create a stable protective film in oxygenated brine without the formation of copious corrosion products known to present problems in UBD operations. The test protocol used herein suggests a method for qualifying the performance of candidate inhibitor formulations for specific UBD design conditions.

This paper discusses a method based on Bayes’ Theorem to estimate the probability that performance of an In-Line-Inspection tool satisfies stated sizing accuracy specifications. This leads to a new method for accepting or rejecting tool performance that is entirely different from methods based on confidence intervals.

In-Line Inspection (ILI) is used to prioritize metal loss conditions based on predicted failure pressure in accordance with methods prescribed in industry standards such as ASME B31G-2009. Corrosion may occur in multiple areas of metal loss that interact and may result in a lower failure pressure than if flaws were analyzed separately. The B31G standard recommends a flaw interaction criterion for ILI metal loss predictions within a longitudinal and circumferential spacing of 3 times wall thickness, but cautions that methods employed for clustering of ILI anomalies should be validated with results from direct measurements in the ditch. Recent advances in non-destructive examination (NDE) and data correlation software have enabled reliable comparisons of ILI burst pressure predictions with the results from in-ditch examination. Data correlation using pattern matching algorithms allows the consideration of detection and reporting thresholds for both ILI and field measurements, and determination of error in the calculated failure pressure prediction attributable to the flaw interaction criterion. This paper presents a case study of magnetic flux leakage ILI failure pressure predictions compared with field results obtained during excavations. The effect of interaction criterion on calculated failure pressure and the probability of an ILI measurement underestimating failure pressure have been studied. We concluded a reason failure pressure specifications do not exist for ILI measurements is because of the variety of possible interaction criteria and data thresholds that can be employed, and demonstrate herein a method for their validation.

When compared with the previous, more conservative methods of ASME B31G, failure pressure prediction of corroded pipelines using the effective area method (RSTRENG) has been demonstrated over time to be safe and has provided substantial economic benefit through the reduction of un-necessary repairs. In-Line Inspection technology has now developed to the point where approximations to effective area assessment can be provided based on in-line inspection data. This paper presents a method for determining if inspection performance is adequate to justify the use of effective area method based on in-line inspection data. Validation tests for the accuracy of effective area method in prediction of failure pressure from the original development work are cited and compared with the validated performance of effective area approximated from in-line inspection data.

Direct Assessment is allowed under the new Gas Pipeline Integrity Management Rules published by the Office of Pipeline Safety as an assessment method subject to specific applicability restrictions, direct examination criteria and restrictions to re-inspection intervals. The final developed costs for implementing direct assessment is largely dependent upon the extent of direct examination that in turn is a function of the pipeline condition and actual threats discovered and validated. Effective utilization of Direct Assessment within an Integrity Management Program is dependent upon the recognition of the value inherent in the Pre-Assessment Stage of the Direct Assessment Process as defined by the Rule, in which, threats are predicted, applicability confirmed and as a result of data and risk analysis, it is possible to estimate the condition of the pipeline to determine if the use of Direct Assessment is a practical consideration as well as permitted under the Gas Pipeline Integrity Management Rule.