Hydrate Inhibition in Gas Wells Treated With Two Low Dosage Hydrate Inhibitors

Hydrate Inhibition in Gas Wells Treated With Two Low Dosage Hydrate Inhibitors Dean Lovell; Dean Lovell Conoco Canada Search for other works by this author on: This Site Google Scholar Marek Pakulski Marek Pakulski BJ Unichem Chemical Services Search for other works by this author on: This Site Google Scholar Paper presented at the SPE Gas Technology Symposium, Calgary, Alberta, Canada, April 2002. Paper Number: SPE-75668-MS https://doi.org/10.2118/75668-MS Published: April 30 2002 Connected Content Related to: Two Low-Dosage Hydrate Inhibitors Cite View This Citation Add to Citation Manager Share Icon Share Twitter LinkedIn Get Permissions Search Site Citation Lovell, Dean, and Marek Pakulski. "Hydrate Inhibition in Gas Wells Treated With Two Low Dosage Hydrate Inhibitors." Paper presented at the SPE Gas Technology Symposium, Calgary, Alberta, Canada, April 2002. doi: https://doi.org/10.2118/75668-MS Download citation file: Ris (Zotero) Reference Manager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex Search Dropdown Menu nav search search input Search input auto suggest search filter All ContentAll ProceedingsSociety of Petroleum Engineers (SPE)SPE Unconventional Resources Conference / Gas Technology Symposium Search Advanced Search AbstractTwo low dosage gas hydrate inhibitors, antiagglomerant type and a combination antiagglomerant/kinetic polymeric inhibitor have been successfully field tested in a gas producing well. The well located in Canadian foothills posed challenges for the operators. High pressure, low bottomhole temperature and Joule-Thomson gas decompression cooling effect created favorable conditions for gas hydrates at depths below 300 meters. The well would plug-up with hydrates daily in spite of being treated with 400–500 L of methanol. The operator experienced significant monetary losses due to lost production and had to use considerable amounts of chemicals and time to clean-up hydrates from plugged tubings.The inhibitors were applied downhole in 20% to 10% methanol solution. This novel approach allowed utilization of existing solvent storage and pumping equipment so that no capital spending was required when converting the hydrate prevention program from methanol to LDHI treatment.The combination inhibitor was diluted to 20% in methanol in a stock tank and pumped into the well at the approximate rate 30 L/day. Similarly, the antiagglomerant was initially used at 20% solution in methanol and later its concentration was lowered to 10%. The daily inhibitor treatment rate was established at 45 L.Laboratory results indicate the combination product is a better hydrate inhibitor than the antiagglomerant. However, the cost analysis favors the usage of less expensive antiagglomerant in this application.Following the successful treatment of one well, several more similar gas wells throughout the field were identified and converted from methanol hydrate prevention method to antiagglomerant treatment.IntroductionGas hydrates form when water molecules crystallize around guest molecules. The water/guest crystallization process has been recognized for several years, is well characterized and occurs with sufficient combinations of temperature and pressure.1Light hydrocarbons, methane-to-heptanes, nitrogen, carbon dioxide and hydrogen sulfide are the guest molecules of interest to the natural gas industry. Depending on the pressure and gas composition, gas hydrates may build up at any place where water coexists with natural gas at temperatures as high as 80°F (~30°C). Gas transmission lines and gas wells are particularly vulnerable to being blocked with hydrates.Formation of gas hydrates can be eliminated or hindered by several methods. The thermodynamic prevention methods control or eliminate elements necessary for hydrate formation: the presence of hydrate forming guest molecules, the presence of water, high pressure and low temperature. The elimination of any one of these four factors from a system would preclude the formation of hydrates. Unfortunately, elimination of these hydrate elements is often impractical or even impossible. This is especially true in gas production wells where one has no control over the composition of produced fluids and bottomhole pressure and temperature. The well operator has only limited control over the wellhead pressure. The formation temperature and Joule-Thomson gas cooling effect upon decompression are the factors determining whether the particular well or any part of it is at hydrates conditions. Further downstream, the gas is normally processed to make the stream more resistant to hydrate build-up. The gas conditioning includes sweetening, dehydration and pressure control in transmission lines.There are reported solutions to hydrates problems in production wells. For example Hale, et al.2 patented a method of preventing hydrates formation in such wells with addition of polycyclicpolyether polyols. However, the most prevailing practical approach of preventing gas hydrates formation is the addition of massive amounts of alcohols, glycols or salts to the gas/water stream. These chemicals being thermodynamic hydrate inhibitors shift the operating conditions outside of the hydrate formation region. These additives shift the hydrate equilibrium curve toward higher pressure and lower temperature conditions. They destabilize hydrates and effectively lower the temperature of hydrate formation. Keywords: gas hydrate, upstream oil & gas, pressure cell hydrate experiment, pakulski, hydrate inhibitor, composition, flow assurance, combination product, gas well, hydrate Subjects: Flow Assurance, Hydrates This content is only available via PDF. 2002. Society of Petroleum Engineers You can access this article if you purchase or spend a download.

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