Predicting the temperature profile along a tubing string and production flowline of any high GOR oil or gas well is the key element to assess its operating condition and to predict possible flow assurance or other issues that may impact plant integrity. Issues could be elevated, as system operating constraints may restrict production potential of the well. This article presents one of the Azeri-Chirag-Gunashli (ACG) high GOR oil producers that was used to develop a temperature modelling and hydrate formation assessment strategy, based on dynamic and steady-state models. The well was drilled to the gas cap section of the reservoir where more than 100 MMscf/D gas rate was expected to be produced. But due to the production separator gas handling limitations, the well had to be operated at a restricted condition. This condition created concerns for the platform and stable well operation:

  • Operating in the hydrate formation zone: high dP across the choke resulting in high cooling downstream

  • Exceeding the flowline design limit (or "embrittlement" limit) during restarts of the well: the well was expected to have a Shut-in Tubing Head Pressure (SITHP) of 165 barg, and restarting it against 32 barg system pressure at low ambient temperature conditions (0°C and below) during the winter season, would drop the temperature downstream of the choke below the flowline design limit, risking platform integrity

  • Exceeding separator normal operating temperature limit: a high volume of gas cooling down due to Joule-Thomson (J-T) effects (both during restart and normal operating conditions) would reduce the temperature of the separator below its normal operating conditions, causing automatic shutdown, hence upset of the production system

The study consisted of three main parts (a) to estimate the flowing well head temperature (FWHT) based on the expected production profile, lithology, piping and other key elements that impact temperature, (b) to assess the J-T cooling effect based on the restricted production which is driven by the separator gas handling capacity constraint, (c) to understand the alternatives and supplementary methods that will help to safely operate the platform and well during restart and normal operating conditions.

All of the assessments described in the article were conducted using PROSPER as steady-state well simulator, HYSYS as process simulation software and OLGA as dynamic flow simulator. The assessment concluded that the well will be operating in the hydrate formation zone; the separator operating temperature will reduce below its normal operating temperature and the temperature downstream of the choke will drop below the flowline temperature design limit. Several mitigation actions were put in place in order to eliminate the aforementioned issues, such as injecting methanol from the X-mas tree, injecting hot nitrogen from upstream of the choke and increasing the separator operating pressure.

Start-up of the well showed a perfect match between actual performance of the well and predicted results. Based on the overall assessment results, the modelling-based approach has been recommended for future ACG producers with expected high GOR values.

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