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

The formation and accumulation of calcareous substances can lead to loss of production due to problems such as clogging, corrosion, flow restriction and emulsions. Effective means of managing wet oil solids during produced water reinjection (PWRI) is an inherent challenge in the industry. The use of production chemicals can be applied to repair damage to PWRI systems that would otherwise require the ship to be involved to clean the flow lines.

For many years an operator in the North Sea had used seawater injection for pressure relief, with the water produced being discharged into the sea. However, the operator’s strategy changed and the seawater injection was stopped. Instead, all produced water was re-injected via subsea wells, with a subsea pipeline carrying water to these wells from the host platform.

At that time, H2S and oil levels began to rise in the produced water due to separation issues. Iron sulphide, reservoir silicates, barium sulphate scale and biomass have been found in the hydrocyclones. These problems were controlled by the application of flocculants and the monthly cleaning of the separation equipment. The underwater water injection line was also experiencing increased pressure drop due to fouling of the injection line, which reduced injection capability.

The continued reduction in the capacity of the subsea water injection pipe and the potential for this pipe to become completely entrapped was considered to be the most significant threat to the remaining reserves in this field.

ChampionX Corp. was tasked with developing a custom chemical cleaning program to prevent continued fouling and the generation of H2S in carrier PWRI systems. The typical treatment schedule would require large volumes of chemicals, so the ChampionX team worked to design a solution with fewer logistical hurdles.

Laboratory evaluation

Focused on addressing the root cause of top surface separation and injection line fouling that was causing biogenic H2Generation S, the ChampionX team assessed whether it was possible to reduce iron sulphide formation and improve oil volumes in water above by the application of an H2Scavenge at underwater production wells.

Effective methods of cleaning the water injection line were initially evaluated via the batch application of chemicals, such as hydrocarbon solvents, mutual solvents (hydrocarbon removal and water wetting) , dilute acid solutions and solutions of THPS (iron sulfide remover), chelators (barium sulfate remover) and oxidizing agents, such as hypochlorite (biomass remover). Although this showed an acceptable degree of performance, several challenges had to be considered:

  • A large amount of chemicals was required for treatment due to the volume of the flowline;
  • Logistics for collecting spent chemical that could not be injected into the well;
  • The length of time the injection line would be out of service (resulting in a complete field shutdown) to allow for periods of pumping and soaking; and
  • The aggressive nature of certain chemical steps with respect to the materials used in the construction of the underwater pipeline and the wells.

This led to the evaluation of an alternative cleaning schedule, which could be continuously injected at a lower rate to remove fouling in the produced water line and help prevent further fouling.

Based on the composition of the fouling material in the injection line, the proposed formulation contained a THPS-free (near neutral pH) solvent for iron sulfide removal (Figure 1), combined with an inhibitor corrosion which would act as a surfactant to reduce interfacial tensions. This treatment would ensure that the trapped oil becomes mobile to aid in the breakdown of iron sulphide/hydrocarbon buildups.

In addition to this cleaning schedule, a batch treatment of 1000 ppm glutaraldehyde was applied for 90 minutes every five days.

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

Field performance

A solvent/surfactant field trial without THPS was set up, and the restricting “fouling factor” along the water injection line tended to compensate for the variation in pressure drop friction due to flow variation. Samples of fouling material were also tested and analyzed before and during the test to determine if the composition of the material had changed due to the application of the chemical. There was a significant reduction in fouling factor with the start of injection over the three month trial (Figure 2).

The performance of the injected chemical from five to 40 ppm is shown in Figure 3. To reduce the risk of displacement of partially dissolved biomass, oil and sulphides into the injector well, the cleaning chemical was injected at a slow rate (5 ppm) with an associated risk of reduced injectivity. This resulted in an almost instantaneous reduction in fouling factor.

Increasing the treat rate from five to 10 and up to 20 ppm showed a consistent reduction in fouling factor as iron sulphides and hydrocarbon were swept from the injection line surfaces. No improvement was observed when the concentration was increased from 20 ppm to 40 ppm. The optimum cleaning action was obtained at 20 ppm, as the fouling factor did not decrease above this rate. Notably, even at 5 ppm, the chemical prevented backflow from the system.

Analysis of the recovered solids after the application of cleaning chemicals showed a reduction in the percentage of iron sulphide in the recovered solids but an increase in barite (barium sulphate = scale). As the proportion of barite in the sampled material increased, the total amount of fouling decreased over time. This is not due to the formation of additional scale but rather to the removal of iron sulfide, which means that unreacted scale solids make up a higher proportion of the remaining deposit.

The hydrocarbon content of the post-chemical application of the recovered solids also showed a significant reduction, suggesting that the surfactant properties of the cleaning chemical above 5 ppm were capable of mobilizing oil from the reservoir.

Over the period of injection of cleaning chemicals, microbiological growth determined from “studs” in a lateral flow unit showed a significant reduction, with evidence of synergy of cleaning chemicals and glutaraldehyde . The cleaner’s surfactant package would help penetrate the biomass and cut channels in it, allowing the biocide to access a larger surface area of ​​the sessile colonies.

Implementation of the new cleaning chemicals program has resulted in the following changes to the PWRI system:

  • The produced water injection rate increased from 729 cu. m per hour at 777 cu. m per hour (an increase of 7%). Although this is not a full recovery of injection potential, it is a significant improvement;
  • Reduction of the injection pressure from ~50 bar to 40 bar (20% decrease, despite the increase in injection rate). Hence a reduction in the energy required for the injection pumps;
  • Increased production, as injection line fouling reduced replacement of tank voids; and
  • Reduced risk because the injection line was able to absorb more of the water produced.

Improvements in H2Managing the S in the produced water will lead to less generation of iron sulphide at the top, which will lead to fewer solids entering the flowline with the produced water. With less solids and less oil in the water, fouling has been reduced in the flow line.

Long term durability

For efficient operations, it is essential to prevent fouling and the generation of H2S and iron sulfide in PWRI systems. Innovative technologies applied to the North Sea asset offer opportunities to improve efficiency and minimize waste by reducing the energy required to operate injection pumps, lowering the total cost of operation, helping to improve production gains and avoiding unbudgeted costs.

By continuously injecting the custom chemical treatment, a significantly lower volume of chemicals (27,000 litres) was required compared to batch treatment (59,476 litres), improving the carbon footprint of the operation by requiring less product chemicals to manufacture and inject and fewer chemical tanks. to ship (12 versus 26).

References available upon request.

Editor’s Note: This article is an abridged version of SPE-209478-MSD presented at the SPE Oilfield Scale International Conference and Exhibition in May 2022 in Aberdeen, Scotland.