Operator saves GBP 13,000 per month in chemical costs and sees a significant reduction in annual onshore H2S removal tariffs.
On producing platforms, chemical solutions are widely used to manage issues such as scale, hydrates and corrosion.
Hydrogen sulphide (H2S), a highly poisonous, flammable and corrosive chemical compound, is often encountered during drilling and production activity. Colourless, H2S gas found in sour wells can form sulfuric acid in the presence of air and moisture, potentially corroding pipeline and wellhead equipment, such as blowout preventors. To ensure everyone’s safety as well as optimal production levels and asset integrity, H2S levels must be carefully monitored and managed.
To counter these issues, H2S scavengers are used to remove sulphide species. The low hazard, specialised chemical compounds have become the standard method for onshore and offshore H2S remediation and are typically injected directly into the sour production. Due to the potentially large volumes required for treatment, scavengers are often transported offshore so they can be injected directly into the liquid or gas phase before entering export lines to refineries or gas processing plants onshore.
Dr Alfred Hase, senior group leader for flow assurance at ChampionX and Laura Crombie, lead chemist for flow assurance at ChampionX, recently worked with a North Sea operator to develop a treatment for both gas hydrate inhibition and H2S mitigation.
“Production had been constrained from the operator’s Normally Unmanned Installation (NUI) to meet export H2S specifications,” Hase says. “The existing product used for topside scavenging on the manned central facility at the separator outlet had limited efficiency, and short residence time and low temperatures were adversely impacting the reaction kinetics.”
“ChampionX was asked to develop a bespoke solution to protect the NUI pipeline against hydrates whilst ensuring efficient scavenging of the H2S.”
Improve scavenging efficiency
The entry specification of the pipeline from the central processing facility to the onshore terminal was 10 ppmv H2S. This gas was treated at the central processing facility with an H2S scavenger to remove the hydrogen sulphide present. However, on arrival at the main platform, low temperatures meant the scavenger had slow reaction kinetics, resulting in poor efficiency. The operator could only achieve export specifications on the gas by choking back the sour well, locking in valuable hydrocarbons. The only way to resume normal production was to improve scavenging efficiency.
The scavenger’s ideal injection point was on the NUI, 20 km from the central facility. No spare injection umbilicals were available for the treatment, but a kinetic hydrate inhibitor (KHI) was being pumped to the NUI to treat wet gas flowing back to the main platform.
“The aim was to develop a combined H2S scavenger / KHI product to enable production under the permanent hydrate conditions found in the pipeline,” Crombie says.
“KHIs were an essential component for this producing asset. They are polymeric compounds used to slow or prevent the formation of gas hydrates, which can occur where gas and water are present. If the hydrates form to the point of blocking a pipeline, remediation can take months, and pipeline replacement is often a necessary last resort. This can cause significant operational downtime, in addition to increased project costs, meaning a robust preventive chemical treatment strategy is vital.”
ChampionX first worked closely with the operator to identify alternative routes for the incumbent scavenger, aware that utilising the chemical solution on the NUI, where temperatures were much higher, would deliver quicker reaction time and a more efficient outcome. This would also provide the scavenger with more time to react with H2S as gas flowed through the pipeline.
However, with the only line available to get the chemical to the NUI already being used by the KHI, testing began to ascertain if the two chemistries could be combined to apply the KHI and H2S scavenger simultaneously.
“Combining KHI with a high-pH product like an H2S scavenger, can cause precipitation or destabilisation of the polymer so compatibility testing was carried out to ensure the combined solution was stable,” Crombie says.
“The highest risk for the operator was formation of gas hydrates, so this was our first priority in creating the new compound. Secondly, the solution had to meet stringent H2S safety and environmental specifications. Modelling was carried out to determine the approximate concentration of H2S scavenger necessary to remove the required 110 kgs of H2S per day.”
Once established, temperature stability cycle testing was performed. The chemical formulation was exposed to 50° C for 20 hours before being cooled to an ambient temperature for 4 hours and placed into a freezer at -10° C for 20 hours. This was repeated five times to ensure the product’s stability during harsh North Sea winters and warmer summer months. Extended tests were carried out following the same cycle but for 4 weeks at a time. The pH was measured throughout to ensure a consistent chemical with no haziness or separation.
“Because the new product would be applied via an umbilical line, essential tests were necessary to confirm stability,” Hase says. “Unstable production chemicals in umbilical lines can cause severe problems, including losses of lines, and replacement can be impossible or incur high costs.”
Cold centrifuge tests were conducted at 4° C and 2,000 rpm for 7 days, and high-pressure viscosity tests at 4° C and 25° C confirmed the product’s stability. Pictures were taken after 24 hours and after 7 days to monitor progress with no gelling or solid formation resulting, which ensured no precipitation was created within the vials, as this could indicate a potential blockage once deployed.
Before field trials, tests were carried out under two different temperatures and pressures to reach 15,000 psi, confirming that once in the pressurised flow line, the product would operate effectively.
With stability confirmed, testing was essential to prove the KHI’s effectiveness. Modelling software calculated the hydrate equilibrium curve based on the gas and water composition to determine the severity of hydrate formation, which is described by the subcooling (how far the system is operating in the hydrate zone). For this project, the subcooling was 7.7° C at system conditions. Kinetic hydrate inhibitors work up to 12° C subcooling.
“To confirm successful prevention of hydrate formation, we used rocking cell equipment with a defined volume of fluids inside each cell,” Hase says. “A stainless-steel ball in the cell rocks left to right, around 10 times per minute, agitating the cell. Gas hydrate formation will be indicated by a pressure drop. If this occurs, the transducer each cell is connected to will show a drop in pressure profile. In this instance, the cell was cooled from ambient temperature to test temperature, around 4° C, and pressurised to around 25 bar.”
“After 9 days’ testing, no hydrate formation or pressure drop was detected.”
Reduction in chemical costs
Following laboratory testing, a combined KHI and H2S scavenger chemistry, HYDT16919A, was successfully developed, which effectively controlled hydrates in the wet gas line while mitigating H2S, allowing the operator to enhance production from the sour well.
“The injection facilities were switched from the incumbent KHI to HYDT16919A and the chemical was pumped to the NUI,” Crombie says. “H2S decreased from the previously measured 14 ppmv, the process limit, to less than 4 ppmv, meaning the well could be fully opened, which increased production by 1.14 mboed.”
“This delivered a GBP 13,000 per month reduction in annual chemical costs for the operator and a significant cut in annual tariffs related to onshore H2S removal.”
“Without our solution, the well could not have been fully opened and installation of tanks and regular interventions to the NUI may have been required. This would have created significant operational expenditure in tank change-outs and increased the operator’s carbon footprint.”
The growing complexity of oilfield challenges requires service companies to collaborate with operators to create solutions which meet constantly evolving issues. The need to maximise production on existing assets means new solutions must help support sustainable hydrocarbon extraction.
Dr Alfred Hase is a ChampionX senior group leader for flow assurance in the Eastern Hemisphere. Having worked in the industry and in research and development for more than 25 years, Alfred has a broad knowledge of oilfield chemical products and applications. He has an MSc in Chemistry from the Technical University in Clausthal-Zellerfeld and a PhD in Petroleum Engineering from the German Petroleum Institute.
Laura Crombie is a lead chemist for flow assurance with ChampionX. She has more than 10 years’ experience in the energy industry, particularly in research, development and engineering. She has a BSc (Hons) in Forensic Science with Chemistry from Robert Gordon University, Aberdeen.