Aggressive moves counter SRB in flooded subsea pipeline

May 3, 2010
Aggressive applications of biocide, use of hydrogen sulfide scavengers, and multiple pig runs can quickly eradicate even major infestations of sulfate-reducing bacteria in a repaired subsea natural gas pipeline following seawater incursion.

Based on presentation to NACE Corrosion 2010 conference, San Antonio, Mar. 14-18, 2010.

Aggressive applications of biocide, use of hydrogen sulfide scavengers, and multiple pig runs can quickly eradicate even major infestations of sulfate-reducing bacteria in a repaired subsea natural gas pipeline following seawater incursion.

Sample analysis made it possible to understand conditions within the pipeline and measure the treatment's effectiveness, allowing Williams Midstream to regain control of internal corrosion mechanisms and quickly eradicate microbial populations, minimizing their threat to pipeline integrity.

The inefficiencies of multicup pigs in removing seawater from pipelines became apparent, particularly when there are major differences in elevation. Injecting biocide at the upstream end of the trunkline required six pig runs before expected concentrations were observed near the downstream end of the pipeline.

Theory holds that as the cup pigs pass over each girth weld, they flex and leave a small quantity of water, which runs down and pools at a low point, meaning numerous pig runs may be necessary to displace chemical products through pipelines, particularly if there are large elevation changes.


Hurricane Ike made landfall at Galveston, Tex., at 2:10 a.m. on Sept. 13, 2008. As the hurricane crossed the Gulf of Mexico it ripped one of the major laterals from the central trunkline in an offshore pipeline system. The breach allowed about 75,000 bbl of seawater to enter the trunkline and about 40,000 bbl of seawater to enter the lateral.

The trunkline was repaired about 100 days after the breach, and dewatering operations commenced. Dewatering detected 90-ppm H2S ahead of the pig. During dewatering of the lateral 2 months later, dissolved H2S spiked to 10,000 ppm. Since normal gas production contained at most traces of H2S, the observed concentrations of hydrogen sulfide were attributed to microbiological activities occurring after seawater entered the pipelines.

This article provides an overview of the pipeline repairs, initiatives to dewater the pipelines, biocide and hydrogen sulfide scavenger treatments, and the pigging program, all of which were implemented to reestablish control over sulfate-reducing bacteria, and the H2S they generated.

Post-Ike repairs

Fig. 1 depicts the affected offshore gas pipeline system in the Gulf of Mexico. A pressure drop on the blocked pipeline during Hurricane Ike indicated a leak. Investigation determined an 18-in. OD lateral had broken free from the 30-in. OD trunkline and the connecting end of the lateral now lay about 572 ft to the west of the previous connection point.

A 90° elbow had previously connected the lateral to the top of the trunkline. Williams decided to replace the section of the trunkline at the location of the breach with a specially designed horizontal spool piece, which provided a T connection to the lateral at 3:00 o'clock. New pipe was laid from the breached end of the lateral to the spool piece.

The connection to the breached 18-in. OD lateral showed no signs of corrosion or mechanical damage in these two photos (Fig. 2).

Fig. 2 shows the breached section of the trunkline, after it was removed from the Gulf of Mexico. Removal occurred about 45 days after passage of Hurricane Ike. Careful examination of the section sought indications of internal and external corrosion or of other mechanical damage that would affect pipeline integrity. The visual appearance of the interior surface of the pipeline was like new, fresh metal, with no indications of pitting or general corrosion.

Divers walked the pipeline to assess damage. Replacement spools and connectors-grippers were designed, built, and pressure tested, enabling the trunkline and lateral to be repaired and returned to production.

Design of the new spool piece for the trunkline and connection lateral included a 3:00 o'clock connection between them, replacing the 90° connection, which had previously been in place (Fig. 3).

Fig. 3 depicts design of the new spool pieces for the trunkline and the connection to the lateral.

Initial dewatering

Knowledge of the length and ID of pipelines, subsea topography, and gas pressure—measured at the offshore platforms and the onshore plant receiving the natural gas—allowed estimation of the volume of seawater that had entered the trunkline and lateral. Williams's first inclination was to pig the trunkline from deepwater to shore to remove the seawater after repairs. The volume of seawater in the trunkline, however, far exceeded the capacity of the onshore slug catchers, which were designed to accommodate condensates and limited volumes of produced water.

Williams instead decided to pig from shore to deepwater. Routine processing of onshore production at the gas plant made an onshore source of gas available.

Slug catchers at the onshore Larose gas processing plant were insufficient to cope with the amount of seawater in the lines, forcing evacuation to barges offshore instead (Fig. 4).

Fig. 4 shows the slug catchers at the onshore plant in Louisiana. The estimated 75,000 bbl of seawater in the trunkline exceeded the slug catcher's 10,000-bbl capacity, even with a fleet of water trucks to assist in the draining and disposal of the seawater.

The first step in dewatering the pipeline was launching a low-density foam pig from the onshore pig receiver-launcher and pushing seawater to the offshore platform, where it would be routed through temporary piping to a large barge stationed next to the offshore platform to receive, process, and store the water and any condensate.

In early January 2009 the operator dropped line pressure to minimize the risk of hydrate formation and launched a soft foam pig from the onshore facilities. This pig proceeded slowly to the offshore platform, propelled by onshore gas. Soft foam offered a balance between flexibility and maintaining a good seal for the first step of dewatering.

The pig moved at about 3-4 mph, or about half the normal pigging speed. Because numerous pigs had previously passed through the trunkline without showing adverse wear from the numerous girth welds, the soft foam pig was expected to pass without being ripped apart.

The trunkline originates at deepwater offshore platform EW-873 and extends to shallow water, and finally onshore Louisiana in a gradual incline (Fig. 5). During the first step of dewatering the foam pig therefore passed in the opposite direction of normal flow, having a gradual downward slope for the first 85 miles, followed by a sharp decline to the base of the riser at EW873.

Once the foam pig reached the riser, the gas that had been pushing the pig began to bypass it, ending that phase of dewatering. The piping on the platform was returned to normal configuration, allowing offshore gas production to push the foam pig back to shore.

The volume of seawater removed from the trunkline during this first pigging run measured about 60,000 bbl. Elevated levels of H2S, however, were found in gas removed from the trunkline ahead of the pig. The gas produced offshore and the gas used to propel the foam pig towards the offshore platform had at most a trace of hydrogen sulfide, but H2S levels spiked to about 90 ppm. Williams attributed the elevated H2S to microbiological activity inside the trunkline after the ingress of the seawater.

The piping and valves at EW-783 were returned to normal configuration, such that offshore production could push the foam pig back. A methanol pill injected into the trunkline helped prevent hydrate formation and a 30-in. cup pig was launched to ensure the foam pig would be successfully returned. The foam and cup pigs arrived at the onshore Larose plant Jan. 12, 2009, with the cup pig in good shape, but the foam pig destroyed.

A 16-in. pig run with a small volume of methanol to prevent hydrate formation quickly followed the 30-in. cup pig run. Injecting additional methanol when the 16-in. pig entered the trunkline ensured hydrates would not form, and a 30-in. pig was launched to distribute-apply the methanol and push both pigs to the onshore receivers. These two runs removed sufficient seawater to make application of biocides at an effective treatment rate (1,000 ppm) practical.

Biocide, monitoring

The primary internal corrosion threat appeared to be from sulfate-reducing bacteria (SRB) based on the observation of 90 ppm H2S in the gas accompanying the seawater pushed to the offshore barge-tankage during the initial foam pig run.

Williams chose to apply Tetra kis Hydroxy Phosphonium Sulfate (THPS) biocide as it is highly effective in controlling SRBs. The first biocide treatment followed the first two pig runs, intended to remove seawater and prevent the formation of hydrates. An initial treatment at 1,000 ppm sought to bring the microbial population under control quickly, factoring in the volume of seawater estimated still in the trunkline. Grab samples collected at the onshore end of the trunkline allowed monitoring of the biocide's efficacy.

The slug catchers in Fig. 4 are self-draining, so that any condensates or liquids removed from the trunkline during pigging will drain out and into separators, leaving the slug catchers empty. Sample points were not available upstream of the slug catcher, requiring fluid samples be collected immediately downstream of the slug catcher to assess the effectiveness of the biocide treatments.

Field and laboratory testing of the seawater samples included measuring pH, chlorides, iron, manganese, magnesium, serial dilution studies to quantify microbiological populations (which take 28 days to complete), adenylyl sulfate (APS) reductase tests, which rapidly check the populations of SRBs and tests to quantify the concentration of THPS biocide. The initial pigging runs produced sediment, as would be expected from the ingress of seawater into pipe on the bottom of the Gulf of Mexico, but the sediments cleared after a few pig runs.

Measuring chlorides and magnesium provides a perspective on the seawater. Iron and manganese provide a perspective on potential metal loss from the steel pipes, particularly manganese. A decrease in iron concentrations indicates corrosion is being controlled. Some iron, however, may come from natural sources.

The APS reductase test is a rapid check of SRB populations. Results provide preliminary indications of microbial populations and whether populations were being brought under control. APS reductase is an enzyme specific to SRB. The amount of this enzyme in each bacterium is fairly constant. The test captures the enzyme from each bacterium, thereby allowing the total population of SRB to be quantified. Although the APS reductase tests were used as indicators, Williams relied on several dilution tests to provide definitive quantification of SRB microbial populations.

Measurement of pH and concentration of H2S within the seawater occurred once the lateral was brought on line.

Lateral repair

Once the trunkline returned to normal operations, attention switched to the repair of the 18-in. OD lateral. New pipe was laid between the ripped end of the lateral and the spool piece on the trunkline. Loading of a multidisc foam pig into the valve and pipe pup occurred before it was transported offshore and connected to the spool piece.

Once all connections were completed a barge with large nitrogen tanks staged above the spool piece at the connection of the two pipelines. A second barge staged at the upstream end of the lateral, immediately adjacent to the ST-200 platform. This second barge included appropriate vessels for processing the seawater removed from the lateral. With the valve between the lateral and trunkline closed, nitrogen was slowly fed into the lateral and propelled a multidisc foam pig towards S-200, displacing the raw seawater to the waiting barge.

This pig dewatered the 18-in. lateral before retrieval at the upstream end (Fig. 6).

Fig. 6 shows the multidisc foam pig once it was recovered at the platform at the end of the lateral on Mar. 10, 2009.

When the trunkline was first dewatered, the gas accompanying the foam pig to offshore platform EW-873 spiked to 90 ppm H2S, raising concerns regarding dewatering the lateral to the ST-200 platform. Dewatering of the lateral occurred about 2 months after dewatering the trunkline. Microbes grow at exponential rates, making it natural to assume a large growth in microbial population of SRB and a proportionate increase in the evolution of H2S.

The lateral connects to the trunkline at roughly 240 ft water depth (Fig. 5). It is reasonably flat, varying only 20-30 ft. As opposed to extending to deeper, colder water, conditions in the lateral would be relatively warmer, further promoting microbial growth.

As the multidisc pig moved from the trunkline towards ST-200 at the end of the lateral, seawater removed was directed into tanks on the barge for processing and storage. One measure of H2S concentration dissolved in the seawater reached 10,000 ppm. Most H2S readings, however, were 500-1,200 ppm dissolved in the seawater.

Natural gas production throughout the pipeline system historically had at most only a trace of H2S. The observed H2S therefore was attributed to microbiological activities within the pipeline following its breach due to forces from Hurricane Ike.

Hydrogen scavengers treated the high levels of H2S in the fluids removed from the lateral before they were transported ashore for appropriate disposal. Hydrogen sulfide scavengers were also injected into the lateral ahead of the first pigs routed from ST-200 back to the trunkline. This was to minimize the concentration of H2S that would otherwise flow toward the onshore facility once natural gas production resumed.

Following removal of the bulk of the seawater, piping on the platform at the end of the lateral returned to normal configuration, allowing natural gas production to resume. Natural gas then pushed additional pigs through the lateral back to the trunkline to complete the dewatering.

Fluid assessment

Williams collected liquids samples at the onshore gas processing plant whenever pigs were arriving from offshore. Fig. 7 summarizes results and observed trends. Accurate interpretation of results from analysis of seawater samples collected at the onshore gas processing plant in Larose, La., requires closely tying them to ongoing operational activities.

Fig. 7 also includes notes delineating the timeline related to operational activities associated with reestablishing the integrity of the subsea trunkline and lateral.

Trunkline dewatering

The soft foam pig, which had been pushed offshore to displace the initial charge of seawater to the waiting barge, arrived back at the onshore plant, along with a 30-in. diameter poly pig launched from the EW-873 offshore platform Jan. 12, 2009. Samples collected when these first pigs arrived contained a large amount of sediments.

The greatest volume of sediment observed was 420 ml in a 1,000 ml sample, showing the pigs to have been effective in displacing much of the sediment that entered the pipeline when it was breached. Subsequent runs yielded much lower proportions of sediment.

Serial dilution studies (a four bottle-vial series) and APS reductase tests estimated microbial populations. Four bottles out of the initial four-bottle serial dilution study turned within the test period, showing high microbial populations for SRB. Results for the APS reductase tests, which take only a few moments to complete, showed populations between 10,000 and 1 million microbes/ml for different samples collected at the onshore facility from the first wave of seawater removed from the trunkline.

Hydrate prevention

Shortly after the first pigs arrived at the onshore plant Jan. 12, 2009, a 16-in. pig was launched from GC-254, a platform upstream of EW-873 and the start of the 30-in. OD pipeline. The purpose was to displace any seawater which may have entered the 16-in. OD pipeline before the valves were closed back into the 30-in. OD trunkline. After the 16-in. pig entered the 30-in. OD pipeline, a new 30-in. diameter pig was launched from the EW-873 offshore platform to sweep the two pigs to the onshore facility. Methanol was injected ahead of each pig to help prevent hydrate formation, which posed a greater short-term threat to pipeline operations, since hydrates could plug the pipelines, stopping flow. The plan was to initiate the biocide treatments once the risk of hydrate formation had been addressed. Williams nevertheless collected fluid samples at the onshore facilities, even from the first pig runs, before biocide treatments were initiated. This helped establish post-Hurricane Ike baseline conditions.

The multicup pig arrived ashore Jan. 15, 2009, and two out of four bottles in the serial-dilution test yielded indications at least 100 microbes/ml. APS reductase methodology showed up to 10,000 microbes/ml. These collective results showed large microbial populations were still within the trunkline and there was a continuing potential for MIC occurrence.

Other laterals

Following Jan. 15 passage of the pig through the damaged lateral, attention shifted to returning other laterals, not damaged by Hurricane Ike, to production. Initial concerns again focused on preventing hydrate formation in either the laterals or the trunkline.

Pigs launched from laterals on Jan. 21 and 27, 2009, traveled to the trunkline and were then pushed to the onshore gas processing plant by a 30-in. multicup pig from EW-873 at the upstream end of the trunkline. Fluid samples were again collected at the onshore facility, and they provided positive indications for SRB, with 100 microbes/ml based on serial dilution studies and 10,000 microbes/ml using APS reductase studies.

THPS treatment

THPS biocide was injected into the upstream end of the trunkline and was first evident in sampling associated with the pig arriving Feb. 5. A sufficient volume of THPS was injected into the trunkline to provide 1,000 ppm of THPS residual at the end of the trunkline based on the estimated volume of seawater remaining in the trunkline at the time. The first measurement, however, yielded only 76 ppm of THPS at the onshore facility.

Biocide treatments and pig runs followed a rotating schedule treating all laterals on the pipeline system, including those unaffected by Hurricane Ike, and the trunkline. Through February 2009 THPS residuals increased to roughly 720-820 ppm. The delay in getting the biocide distributed through the pipeline is undoubtedly related to the frequency of the pigging and the vertical incline of the pipeline.

Serial dilution studies were negative, showing microbial populations of SRB were below detectable levels.

The biocide was effective as APS reductase readings mostly measured zero. Samples collected Feb. 22 and Feb. 27, however, had APS reductase readings as high as 10,000 microbes/ml. The APS reductase test cannot distinguish between live SRBs and those freshly killed by a biocide, explaining how there can be differences in results between the serial dilution and APS reductase techniques. Results from serial dilution studies were taken as the most definitive measure of microbial populations.

Once microbial populations were eradicated, a batch treatment of a tenacious oil-soluble corrosion was applied to the trunkline, quickly reestablishing a protective inhibitor film, helping ensure the trunkline's ongoing integrity.

18-in. lateral

The next major operational change was returning the 18-in. lateral to service. The multidisc pig used to dewater the 18-in. OD lateral arrived at the ST-200 platform Mar. 10, 2009.

During initial dewatering elevated levels of H2S appeared at the receiving barge where liquid was removed from the lateral, showing microbial activity in the pipeline. The H2S required the fluid removed from the lateral be treated with an H2S scavenger before transfer ashore for disposal.

H2S scavenger was therefore injected ahead of the first pig to traverse the lateral back to the trunkline to reduce the concentration of H2S dissolved within any remaining seawater resident in the lateral that would be pushed into the trunkline and transported ashore to Larose.

H2S levels

The concentration of H2S dissolved in the fluids arriving at the onshore facility was measured for each pig run after the 18-in. lateral was brought on line. Analysis of the concentration of H2S dissolved in the fluids arriving at the plant following each pig run showed a gradual increase from 50 ppm to about 650 ppm from mid-March through mid-June 2009 and then a decline to roughly 20 ppm.

Throughout this period, each of the laterals received biocide treatments on a regular rotation, and H2S scavengers were applied. Corrosion inhibitors also continued to be injected into the gathering system at the producing platforms at the same rates used before Hurricane Ike.

As the pH slowly increased to 7.3 from 6.5, concentrations of iron and manganese in the water samples gathered at Larose continued to slowly drop, suggesting corrosion was abating. Serial dilution studies throughout this period also showed microbial populations of SRB as below detectable limits; the microbiological processes were now being kept in check.

Continuing trend

Through the rest of 2009 and early 2010, continued serial dilution and APS reductase studies show microbial populations have remained below detectable levels, even after biocide residuals approached zero. The pH of the water removed from the system continues to be in the range 7.1-7.2, and the concentration of dissolved H2S has dropped to about 10 ppm. Excellent corrosion inhibitor residuals likewise indicate the system is properly treated. A spike in the amount of sand-quartz and iron particles removed during pigging runs in late 2009-early 2010 showed the need for a continuous pigging program to displace these denser particles through the gradual incline of the pipeline. These favorable results show the benefits of having implemented an aggressive chemical treatment and pigging program to regain control of internal corrosion mechanisms and thereby maintain pipeline integrity. ✦

The authors

Daniel Powell ([email protected]) is an internal corrosion and chemical applications specialist for Williams Midstream, based in Tulsa. He has also served as a principal engineer for DNV, director of internal corrosion engineering for Corrpro Cos., and senior corrosion engineer for ARCO Alaska. He has a BS in physics (1969) and an MS in engineering (1976) from Arizona State University. He is a certified PE, has been a member of NACE for over 33 years, including serving on the NACE Northern Area Board, and is also a member of the Association of Professional Engineers, Geologists, and Geophysicists of Alberta.

Rodney Einer ([email protected]) is manager of fixed structures at Williams Midstream. He has also served as manager of asset integrity-team lead fixed structures at Williams Midstream, pipeline integrity supervisor and risk management engineer for Williams Energy, principal engineer and senior corrosion engineer for Williams Natural Gas and senior design engineer for Questar Pipeline Co. Einer holds a BS in mechanical engineering (1981) from the University of Wyoming. He is a certified PE and a member of ASME, with NACE certifications of cathodic protection and corrosion specialist.

Joe Cheek ([email protected]) is team lead pipeline integrity at Williams Midstream. He holds a BS in mechanical engineering (1984) from University of South Alabama. He is a certified PE and a member of ASME.

Dale Fincher ([email protected]) is the supervisor of operations for the Williams Midstream Discovery pipeline system, based in Larose, La. He has over 20 years' experience in pipeline operations, including measurements, and has been with the Discovery system since construction and start-up in 1997. He has also worked for both Texaco and Chevron.

Raymond Gonzales (Raymond.Gonzales@ is the Williams Midstream operations and maintenance coordinator for the Discovery pipeline system, based in Larose. He has over 37 years' experience in pipeline and pigging operations, and has been with the Discovery system since the construction and start-up in 1997. He has also worked for Tennessee Gas.

Robert H. Winters (Bob.Winters@ is the senior pipeline specialist for Champion Technologies' pipeline integrity group in Lafayette, La. He has more than 33 years of pipeline experience in the design, construction, operation, and maintenance of oil and gas pipelines. For more than 20 years he served as division corrosion control supervisor for El Paso/Tenneco Gas/Tennessee Gas Pipeline Cos. in Houston. He holds BS and MS degrees in microbiology-biochemistry from the University of Louisiana at Lafayette. He is a member of NACE International, SPE, and is a technical advisor to the SGA for black powder problems in gas transmission pipelines.

Brad Rodrigue ([email protected]) is the Gulf Coast area manager for Champion Technologies. He has more than 15 years' experience in oil field operations and chemical applications.

Brock Means ([email protected]) is an account representative for Champion Technologies and has been providing field support for chemical operations on the Gulf Coast for the last 3 years. He is presently completing a degree in Petroleum Technology at Nichols State University in Thibodaux, La. (2010).

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