Multi-functional oilfield production chemicals: maleic-based polymers for gas hydrate and corrosion inhibition

Abstract

Several chemical problems can occur during the production of oil and gas through flow lines. This includes corrosion, scale deposition and gas hydrate plugging. Three separate chemicals may be needed to treat these issues. Kinetic hydrate inhibitors (KHIs) are used in cold oil or natural gas production flow lines to prevent the formation and plugging of the line with gas hydrates. They are often injected concomitantly with other production chemicals such as corrosion and scale inhibitors. KHIs are specific low molecular weight water-soluble polymers with amphiphilic groups formulated with synergists and solvents. However, many corrosion inhibitors (CIs) are antagonistic to the KHI polymer, severely reducing the KHI performance. It would be preferable and economic if the KHI also could act as a CI. We have explored the use of maleic-based copolymers as KHIs as well as their use as film-forming CIs. KHIs were tested using a natural gas mixture in high pressure rocking cells using the slow constant cooling test method. A terpolymer from reaction of vinyl acetate:maleic anhydride copolymer with cyclohexy lamine and 3,3-di-n-butylaminopropylamine (VA:MA-60% cHex-40% DBAPA), gave excellent performance as a KHI, better than the commercially available poly(N-vinyl caprolactam) (PVCap). CO2 corrosion inhibition was measured by Linear Polarization Resistance (LPR) in a 1 litre CO2 bubble test equipment using C1018 steel coupons. The new terpolymer gave good CO2 corrosion inhibition in 3.6 wt% brine, significantly better than PVCap, but not as good as a commercial imidazoline-based surfactant corrosion inhibitor. The terpolymer also showed good corrosion inhibition efficiency at high salinity conditions, (density 1.12 g/cm3). VA:MA-60% cHex-40% DBAPA shifted the open-circuit potential to more positive values and significantly decreased the corrosion rate.

Non-Amide Polymers as Kinetic Hydrate Inhibitors─Maleic Acid/Alkyl Acrylate Copolymers and the Effect of pH on Performance

“…Knowing that the hydrophobic group in the alkyl acrylate was probably insufficient for good KHI performance, we introduced more hydrophobic groups by reacting the MA units with a readily available diamine, N , N -dibutylaminopropylamine (DBAPA). We had used this before with good success to make VA:MA-60%cHex-40%DBAPA, which also showed good corrosion inhibition properties. , Also, adding monoamines (alkylamines) to ring-open MA units only lowers the water solubility, so we reasoned this was not a good idea with MA:alkyl acrylate copolymers that are only just water soluble. The results in Table show that MA/ i PrA 1:1-DBAPA gave some KHI effect with an average T o of 11.6 °C.…”

N-Vinyl Caprolactam/Maleic-Based Copolymers as Kinetic Hydrate Inhibitors: The Effect of Internal Hydrogen Bonding

“…For example, reaction of the anhydride groups in the VA/MA 1:1 copolymer with a 60:40 mixture of cyclohexylamine:3-di- n -butylaminopropylamine (VA/MA-60%cHex-40%DBAPA, M n = 11 kg/mol, 25 wt % in BGE) gave a significantly better performance than previously reported maleimide polymers (Figure ) and no cloud point at 95 °C in water. This copolymer also showed good CO 2 corrosion inhibition properties …”

“…KHIs were evaluated for performance by the slow constant-cooling (SCC) experimental method, which is summarized as follows: Test chemicals were dissolved to the desired concentration in deionized water (DIW) usually 1 day in advance of the test. 20 mL of test solution was added to each of the five cells. Using repeated vacuum and pressurizing with SNG, the air in the cells was replaced with SNG up to 76 bar. 4.The cells were rocked at a rate of 20 rocks per minute with an angle of 40°, while being cooled at 1.0 °C/h from 20.5 to 2.0 °C. …”

Gas Hydrate in Oil-Dominant Systems: A Review

“…As a result, a fine-tuned EoS fluid model can serve as the foundation for most dissociation hydrate curves. EoS models are often set to match the PVT data at reservoir temperatures over 65 °C. − There is an argument made regarding an error during the crucial stage that could be developed; such fluid models might not indicate accurate fugacity predictions over the range of temperatures encountered, causing errors in hydrate predictions as well as the prediction of the temperature that depends on the fugacities in a typical production system . According to the previous research by Golsanami et al, using bubble point data at low temperatures to tune the EoS fluid model has little effect on hydrate dissociation condition predictions.…”