Hydrogen-Induced Damage in Sour, Wet Crude Pipelines

Abstract

Summary Hydrogen-induced cracking (HIC) and blistering have been documented in eight sour crude oil pipelines with water cuts (WC's) known or believed to be less than 1 vol %. In some cases the damage has taken the form of blistering pre-existing mill laminations in the pipe. In other cases, however, blisters and cracks have been generated in originally sound pipe. In one case the damage was extensive, necessitating a 920-m [3,000-ft] replacement in an offshore trunkline. This paper describes these instances of damage, discusses when they may be occurring, and recommends steps to mitigate the damage. Introduction Since 1974 I have investigated or documented 25 instances of HIC-type damage in producing facilities: 8 sour crude oil lines, 8 sour gas lines, 1 mixed-service line (originally gas, then converted to crude oil), and 8 gas/oil/water separating vessels. All the HIC damage in pipelines has occurred in welded pipe. To date no damage has been documented in seamless pipe. Table 1 shows the categories of hydrogen damage in the sour crude oil lines:generation of blisters and cracks in originally sound pipe,puffing up (i.e., blistering) of pre-existing mill laminations in the pipe, andinstances in which it has not been possible to verify metallurgically the nature of the blistering. Table l also compares the results of the standard HIC-susceptibility test to the actual service damage for three lines. Previous work by the author has shown very good agreement between HIC-susceptibility test results and actual service experience for wet, sour gas lines and for gas/oil/water separating vessels. The table shows that the agreement is also good for the cases of known service-generated damage in crude oil lines. The agreement is not good for the case of the puffed-up mill lamination, but this is not surprising since the HIC test involves the generation of defects in originally sound steel. The standard HIC-susceptibility test has been described extensively in the literature and is not reviewed in this paper. These references also discuss the effects of various metallurgical and operational factors on HIC damage of steel linepipe in wet, sour environments. Ref. 8 is a particularly good summary article. In most cases of HIC damage in crude oil lines known to me it was not possible to obtain samples of the damaged pipe for metallurgical study. The damage was documented as visible blistering and/or ultrasonic indications and then sleeved; hence the many cases listed in Table 1 under Category 3. In four cases, however, damaged pipe was available for study, and these cases are discussed in the following. Case History 1 An offshore trunkline 610 mm [24 in.] in diameter built in 1970 and transporting pressure crude was discovered to be extensively blistered and cracked in Dec. 1981 when it leaked during revalidation hydrotest. Service details are given in Table 1. A large hydrogen blister had cracked in the center of the bulge on the pipe ID and stepwise cracked between the periphery of the blister and the pipe OD, resulting in a weep leak. As the investigation proceeded, many areas of oil-soaked sand were found adjacent to the pipe in the shoreline area where the initial damage was discovered, indicating the presence of additional leak sites. Eventually 920 m [3,000 ft] of pipe were replaced. Fig. 1 shows a cross section through the center of the blister that leaked during hydrotest. The stepwise crack to the OD surface is shown at Location A. The ID surface crack in the center of the blister is shown at Location B. The offset nature of the crack was not realized when a coupon containing the failure area was torch-cut out of the pipe. Unfortunately, the torch cut partly coincided with the ID crack. A blister that was located near the hydrotest leak was sawed open with a power hacksaw. When the hacksaw cut into the blister, the contained hydrogen gas exploded with a loud pop. This incident provided graphic-if momentarily startling-verification that hydrogen was responsible for the blister formation. Fig. 2 shows some typical stepwise cracking associated with the periphery of blisters examined from the damaged pipe, confirming that HIC was the damage mechanism. Fig. 3 shows an example of blistering on the ID of one of the pipe joints removed from the line. A total of 220 such blisters were counted on the ID of 7 joints of pipe removed from the line near the site of the original hydrotest leak. The axial and circumferential locations of these blisters were recorded and are summarized in Table 2. A statistical analysis using the chi-square method was performed on the circumferential position data. JPT P. 613^