Case study: Dissolver/dispersant supports increased production on North Sea asset

By Myles Jordan, Clare Johnston, Brian Bennett and George Cole, ChampionX

The formation and buildup of scale substances can result in loss of production due to issues such as plugging, corrosion, flow restriction and emulsions. Efficient ways to handle oil wet solids during production water reinjection (PWRI) is an inherent challenge for the industry. The use of production chemicals can be applied to recover damage to PWRI systems that would otherwise have required vessel intervention to clean flowlines.

For many years, an operator in the North Sea had been using seawater injection for pressure support, with produced water discharged to sea. However, the operator’s strategy changed, and seawater injection was halted. Instead, all produced water was reinjected via subsea wells, with a subsea flowline transporting the water to these wells from the host platform.

At this time, H₂S and oil levels began rising in the produced water due to problems with separation. Iron sulfide, reservoir silicates, barium sulfate scale and biomass were found within the hydrocyclones. These issues were controlled by the application of flocculants and monthly cleaning of separation equipment. The subsea water injection flowline was also experiencing increased pressure drop because of fouling in the injection line, resulting in lower injection capacity.

The continued capacity reduction of the subsea water injection flowline, and the potential for total occlusion of this line, were considered the most significant threat to the remaining reserves in this field.

ChampionX Corp. was tasked with developing a customized chemical cleaning program to prevent ongoing fouling and generation of H₂S in the operator’s PWRI systems. The typical treatment program would require large volumes of chemical, so the ChampionX team worked to design a solution with fewer logistical hurdles.

Laboratory assessment

Focused on treating the root cause of topside separation and injection line fouling that was causing the biogenic H₂S generation, the ChampionX team assessed whether it was possible to reduce iron sulfide formation and improve oil in water volumes topside through application of an H₂S scavenger to the subsea production wells.

Effective methods for cleaning the water injection line were initially evaluated via batch application of chemicals, such as hydrocarbon solvents, mutual solvents (hydrocarbon removal and water wetting), dilute acid solutions and THPS solutions (iron sulfide dissolver), chelants (barium sulfate dissolvers) and oxidizing agents, such as hypochlorite (biomass dissolvers). While this showed an acceptable degree of performance, there were several challenges to consider:

• A large amount of chemical was required for the treatment due to the flowline volume;
• Logistics of collecting the spent chemical that could not be injected into the well;
• Duration of time over that the injection line would be out of service (resulting in a full field shutdown) to allow pumping and soak periods; and 
• The aggressive nature of some chemical stages with respect to the materials used in construction of the subsea flowline and wells.

This led to an alternative cleaning program being evaluated, which could be continually injected at a lower rate to remove fouling within the produced water line and help prevent additional fouling.

Based on the composition of the fouling material in the injection line, the proposed formulation contained a non-THPS dissolver (near neutral pH) for removal of the iron sulfide (Figure 1), combined with a corrosion inhibitor that would act as a surfactant to reduce interfacial tension. This treatment would ensure trapped oil became mobile to assist the disaggregation of the iron sulfide/hydrocarbon accumulations.

In addition to this cleaning program, a 1,000-ppm glutaraldehyde batch treatment was applied for 90 minutes every five days.

Assessment of the microbiological activity within the produced water was made using molecular methods, including adenosine triphosphate and adenosine monophosphate quantification and quantitative polymerase chain reaction (qPCR). Due to high counts of sessile bacteria, a treatment was recommended that showed good performance.

Field performance

A field trial of the non-THPS dissolver/surfactant was set up, and the restriction “fouling factor” along the water injection flowline was trended to compensate for the variation in frictional pressure drop as a result of variation in flow rate. Fouling material samples were also tested and analyzed prior to and during the trial to determine if the composition of the material had changed due to the application of the chemical. There was a significant reduction in the fouling factor with the onset of the injection during the three-month trial (Figure 2).