Novel combined chemical product increases production and reduces costs

On producing platforms, chemical solutions are widely used and often an essential element in managing issues that occur during the production process, such as scale, hydrates and corrosion. Hydrogen sulfide (H₂S) is a highly poisonous, flammable and corrosive chemical compound, which is often encountered during drilling and production activity. To ensure optimal production levels and the integrity of an asset, H₂S levels must be monitored and managed carefully. In oil and gas production, the colorless H₂S gas found in sour wells can form sulfuric acid in the presence of air and moisture, which is capable of corroding vital pipeline and wellhead equipment, such as blowout preventors.

Chemical solutions offer a cost-effective method for increasing production without creating additional carbon emissions.

To counter this, H₂S scavengers are used to remove sulfide species. The low-hazard, non-corrosive, specialized chemical compounds have become the standard method for onshore and offshore operations and are typically injected directly into the sour production. Due to the potentially large volumes required, the scavenger is transported offshore in chemical tote tanks, so it can be injected directly or bunkered into facility tanks.

During a recent project in the North Sea, production had been constrained from an operator’s normally unmanned installation (NUI) to meet export H₂S specifications. The incumbent product used for topside scavenging on the manned central facility at the separator outlet had limited efficiency. Short residence time, coupled with low temperatures, were adversely impacting the reaction kinetics. ChampionX, well-versed in upstream oilfield technologies, chemical programs and services, was asked to develop a bespoke solution capable of protecting the NUI pipeline against hydrates whilst ensuring efficient scavenging of the H₂S.

Understanding the problem. The pipeline used to export from the central processing facility to the onshore terminal had an entry specification of 10 ppmv H₂S. This gas was treated at the central processing facility with an H₂S scavenger to remove the hydrogen sulphide present. However, when arriving at the main platform, the temperature was so cold that the H₂S scavenger had low reaction kinetics, resulting in poor scavenging efficiency. This meant 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 ideal injection point for the scavenger was on the NUI, 20 km from the central processing facility. There were no spare injection umbilicals available. However, on this particular asset, a kinetic hydrate inhibitor (KHI) was pumped to the NUI, to treat the wet gas flowing back to the main platform. Therefore, ChampionX and the operator agreed to work together to develop an H₂S scavenger product that could be combined with the KHI, to enable production under the permanent hydrate conditions found in the pipeline.

KHIs can be an essential component for a producing asset, with the synthetic compounds used to slow or prevent the formation of hydrates, which can block pipelines. Hydrates can build up, where hydrocarbons and water are present. Here, the combination of pressure and temperature provided a perfect environment for them to form. If hydrates build up within the inner diameter of a pipeline, it can take weeks or months to remediate the issue, with pipeline replacement often necessary as a last resort. This can create significant operational downtime, in addition to substantial increased project costs. Therefore, a robust preventive chemical treatment strategy is vital.

Devising a combined solution. In the early stages of the project, ChampionX worked closely with the operator to identify alternative routes for the incumbent scavenger. It was determined that utilizing the chemical solution on the NUI, where temperatures were much higher, would result in a quicker reaction time and, therefore, a more efficient outcome. This option also allowed for greater time for the scavenger to take effect, as the gas flowed through the length of the pipeline.

Fig. 1. The company’s laboratory in Aberdeen conduced stability testing during product development.

However, there was only one line available to get the chemical to the NUI, and this already contained the KHI. Therefore, the companies agreed to begin testing, to ascertain if the two chemistries could be combined so the KHI and H₂S scavenger could be applied simultaneously. This was the first time that ChampionX KHI and H₂S scavenger chemical solutions had been combined with testing taking place, so the company’s experts based at its Aberdeen, UK, laboratory set to work evaluating whether the concept was even possible, Fig. 1.

KHI is a polymer, so when combined with a high-pH product like an H₂S scavenger, it can result in precipitation or destabilization of the polymer. Recognizing this potential issue, compatibility testing was first conducted by mixing the chemicals to ensure the solution was stable, with no separation or cloudiness observed.

The formation of hydrates was the highest risk for the operator, so this was the first priority in creating the new compound, as blockages in the flowline could result in costly non-productive time, reduced production, and increased project expenditure. Secondly, the solution had to meet stringent H₂S safety and environmental specifications. Chemists conducted modelling to determine the approximate concentration of H₂S scavenger necessary in the formulation to remove the required 110 kgs of H₂S per day.

Once this was established, temperature stability cycle testing was performed. Initially, the chemical formulation was exposed to 50^oC for 20 hours (hr), before being cooled to an ambient temperature for 4 hr. It was then placed into a freezer at -10^oC for 20 hr. This cycle was repeated five times to ensure the product would remain stable across the harsh winters in the North Sea and equally, the warmer summer months. Following initial success, extended stability tests were carried out, which followed the same cycle but for four weeks at a time. The pH was measured at all stages of the testing to ensure a consistent chemical and no presence of haziness or separation.

Because the new product would be applied via an umbilical line, it was agreed with the operator that additional tests must be performed to confirm the stability of the solution in the line. Instability of production chemicals in vital umbilical lines can lead to severe problems, to the point of losses of lines. Replacement of such a key piece of equipment can create high project expenditure and, in some cases, due to complex field layouts, is not always possible.

As part of the testing, cold centrifuge tests were conducted at 4°C and 2,000 rpm for seven days, and high-pressure viscosity tests at 4°C and 25°C were carried out to confirm the stability of the new product. During the cold centrifuge test, observations were made, and pictures were taken after 24 hr and again, after seven days, to monitor progress. The result showed no gelling or solid formation, which ensured no precipitation was created within the vials, as this could indicate a potential blockage once deployed. Before deploying for field trials, further viscosity tests were also performed under two different temperatures and pressures to reach 15,000 psi. This would confirm that once in the pressurized flowline, the product would continue to operate effectively with no change in consistency, which may affect the production flow.

Performance testing for optimum results. With stability confirmed, it was vital to conduct performance testing to prove the KHI was working effectively. Modelling software was used to calculate the hydrate equilibrium curve, based on the provided gas and water composition to determine the severity of hydrate formation. The severity of hydrate formation is described by the subcooling (how far the system is operating in the hydrate zone). For this project, the sub-cooling was 7.7°C at system conditions. Kinetic hydrate inhibitors work up to 12°C sub-cooling.

Fig. 2. Rocking cell equipment was utilized to confirm product performance before deployment.

To confirm the performance of the new product in terms of preventing hydrate formation, rocking cell equipment was utilized with 15 ml of fluids placed inside each cell, Fig. 2. This device uses a stainless-steel ball, which sits inside the cell and rocks left to right, at around 10 times per minute, with the ball providing agitation in the cell. As a closed system, gas hydrate formation will be indicated by a pressure drop, because the gas will be used to form gas hydrate. If this occurs, the transducer that each cell is connected to will show a drop in pressure profile. In this instance, the cell was cooled down from ambient temperature to test temperature, around 4^oC and pressurized to around 25 bar.

It was then agreed that the test would include one day of flowing conditions, rocking left to right. The cells were subsequently shut in for seven days in a horizontal position before the test was restarted for a further 24 hr. After a total of 216 hr (nine days) in testing conditions, no hydrate formation or pressure drop was detected, confirming the product worked.

Field deployment. Following all laboratory testing, a novel, combined chemical, HYDT16919A, was created successfully. The first-of-its-kind solution was able to control hydrates in the wet gas line while scavenging increased levels of H₂S to allow the operator to enhance production from the sour well. After careful planning, the injection facilities were switched from the incumbent KHI to HYDT16919A. The chemical was then pumped along the umbilical to the NUI. Following implementation of the solution, the operator saw a decrease of H₂S from the previously measured 14 ppmv, the process limit, down to less than 8 ppmv. This, in turn, meant the well could be fully opened, increasing production by 1.14 MMboed.

Increased efficiency of the H₂S scavenger also resulted in a £13,000-per-month reduction in annual chemical costs for the operator. Additionally, the operator saw a significant reduction in annual tariffs related to onshore H₂S removal at the refinery.

Had ChampionX’s solution not been developed, the operator would not have been able to fully open the choked-back well and may have needed to either explore the option of installing tanks and regular interventions to the NUI to meet scavenger requirements or accept the production losses. This, in turn, would have created significant operational expenditure in tank change-outs, in addition to increasing the operator’s carbon footprint with the associated logistics required for this activity.

Cost-effective solution. As oilfield challenges continue to grow in complexity, it’s essential that service companies collaborate closely with operators to adapt and develop solutions to meet ever-changing requirements. With increasing emphasis on sustainably enhancing production on existing assets, it is also vital that new solutions directly support net zero goals, ensuring that hydrocarbons are extracted in the most sustainable way possible. Chemical solutions are a low-cost and efficient method of increasing production without creating additional carbon emissions, ensuring that greater recovery can be achieved within existing and mature assets. 

About the Authors

Dr. Alfred Hase

ChampionX

Dr. Alfred Hase is senior group leader, flow assurance for ChampionX, filling that role since mid-2014. Previously, he was section manager for flow assurance for two-and-a-half years. Before that, Dr. Hase was team leader for gas treatment at Champion Technologies from late 2002 to early 2012. Additional early roles include senior chemist at Clariant, and senior research chemist at Institute for Energy Process Engineering and Fuel Technology, as well as at German Petroleum Institute. Dr. Hase earned an MSc degree in chemistry and a Dr.-Ing. degree, both from Clausthal University of Technology.

Laura Crombie

ChampionX

Laura Crombie is principal chemist, flow assurance, for ChampionX. She has served in that role since November 2015. From early 2011 through October 2015, Ms. Crombie was a development chemist/principal chemist for scale at NALCO Champion. She earned a BS degree (with honours) in forensic science with chemistry from The Robert Gordon University.