Corrosion and ‘Schmoo’ in Produced Water Systems a report by Gary E Jenneman,1 David J Blumer2 and Jennifer Busch Harris3 1. Corrosion Management Supervisor; 2. Principal Scientist; 3. Senior Scientist, ConocoPhillips
Definition of Schmoo and Where it is Found ‘Schmoo’ has been defined as oil-coated dust particles or, more precisely, as an organically-coated inorganic scale. Schmoo forms in oil production lines from water-suspended solids such as formation sands, proppant, formation fines and, more typically, iron sulphides. These solids become coated with organic compounds including oil, corrosion inhibitors and biofilms that form a black, sticky, greasy and smelly substance that is now popularly referred to as schmoo by oilfield chemists. Schmoo particles that are coated with oil float in the water phase where they collide and agglomerate with other schmoo particles, forming larger particles that eventually stick tenaciously to metal surfaces (see Figure 1).
Schmoo causes many production-related problems. One of the first accounts of a schmoo-related problem was reported by Martins et al.,1 who linked schmoo to formation damage issues in water injection wells at the Prudhoe Bay field in Alaska. Several years later, Bohon et al.2 recorded a more detailed description of schmoo, including its involvement in corrosion. Besides formation damage and corrosion issues, schmoo can cause plugging/fouling of meters, vessels and production tubing.
The Corrosion Paradox
Paradoxically, schmoo is said to promote corrosion but is non-corrosive. To explain this apparent contradiction one must understand how schmoo forms in pipelines. Schmoo has been found on the inside of water injection lines coating their entire circumference with a layer up to 2.54cm thick (see Figure 2). In this case, the thick layer of schmoo is thought to protect and harbour corrosive bacteria from biocides or inhibitors that are injected to control microbiologically influenced corrosion (MIC). Removing the thick layer of schmoo revealed isolated, round-bottomed pits, characteristic of MIC (see Figure 2).
Pigging of pipelines can remove most of the schmoo, leaving only a thin smear on the surface of the metal. Ironically, this thin layer of schmoo is not corrosive and appears to protect the metal from corrosion. Too much schmoo is therefore not good, but a little seems to be beneficial. Nevertheless, schmoo remains a corrosion problem since many well lines cannot be pigged.
Laboratory Flow Cells
In order to study the corrosion that is promoted by schmoo, a series of laboratory flow cells were recently constructed to simulate pipeline conditions thought to favour schmoo formation and MIC. These flow cells were made of PVC pipe containing as many as 12 x 6.4cm-long, rectangular, metal coupons made from carbon steel.
Each flow cell was injected continuously with a community of bacteria from actual field brine and a synthetic brine representative of the
© TOUCH BRIEFINGS 2010
produced water. The brine contained sulphate and other naturally occurring nutrients for the development of sulphate-reducing bacteria (SRB) and was kept anaerobic by continuous purging with oxygen-free gas (see Figure 3). These nutrients were pumped into a reservoir containing the bacterial inoculum, which was pumped continuously into the flow cells at a velocity of 0.14cm/min, representing a flow-cell residence time of approximately one day (see Figure 3).
The flow cells were operated at atmospheric pressure at a temperature of 40°C. These conditions are favourable for the development of MIC
corrosion but not other forms of corrosion (e.g. CO2 corrosion). In one case, an electrical resistance probe was inserted downstream of the coupon holders to measure the corrosivity of the brine. Syringe pumps were placed immediately upstream of the flow cells to allow for the injection of corrosion inhibitors when needed.
Gary E Jenneman is Supervisor of the Corrosion Management Team within the Production Assurance Technology group at ConocoPhillips. He is an inventor on 11 US patents and has authored or co-authored publications in various areas of petroleum microbiology. He is a member of the National Association of Corrosion Engineers (NACE), the Society of Petroleum Engineers (SPE) and the American Society for Microbiology. He holds a PhD in microbiology from the University of
Oklahoma and has worked as an oilfield microbiologist in the areas of enhanced oil recovery, microbially influenced corrosion and reservoir souring.
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Gary.Jenneman@conocophillips.com
David J Blumer served as a Society of Petroleum Engineers (SPE) Distinguished Lecturer on Produced Water and is author of the ‘Produced Water’ chapter in the SPE Petroleum Engineers Handbook. He is a principal scientist with ConocoPhillips in the Production Assurance Technology group in Bartlesville, Oklahoma. Prior to the merger of Phillips and Conoco, he was a Research Associate in Phillips’ Field Measurement and Corrosion Control group in Bartlesville. Previously, he
spent 10 years in Alaska as a Senior Staff Engineer in Operations, with ARCO Alaska, Inc. and then Phillips Alaska, Inc. after the Phillips acquisition. He was a Chemistry Advisor with Occidental Petroleum for nine years before joining ARCO. Mr Blumer received a PhD in inorganic chemistry from University of Illinois Champaign-Urbana and BS in mineral engineering and chemistry from Colorado School of Mines.
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David.Blumer@conocophillips.com
Jennifer Busch Harris is a Senior Scientist for Production Assurance Technology, an organisation serving ConocoPhillips upstream operations. She has worked at ConocoPhillips for over two years, specialising in the monitoring and mitigation of microbially influenced corrosion. Ms Harris is a member of the National Association of Corrosion Engineers (NACE), American Society of Microbiology, and Society for Petroleum Engineers. She earned a doctorate of
microbiology in 2006 and held a postdoctoral fellowship in chemical engineering at the University of Tulsa.
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Jennifer.Harris@conocophillips.com
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