Handling Jurassic Field Sour Gas Creates Challenges Upstream and Downstream
- Adam Wilson (JPT Editorial Manager)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- April 2013
- Document Type
- Journal Paper
- 104 - 105
- 2013. Society of Petroleum Engineers
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This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 154452, "Challenges in Sour-Gas Handling for Kuwait Jurassic Sour Gas," by Bader Nasser Al Qaoud, SPE, Kuwait Oil Company, prepared for the 2012 SPE Middle East Unconventional Gas Conference and Exhibition, Abu Dhabi, 23-25 January. The paper has not been peer reviewed.
Kuwait Oil Company started free gas production from its Jurassic sour-gas field in May 2008 with the commissioning of Early Production Facility (EPF) 50. The field produces sour gas and light crude from a deep high-pressure/high-temperature naturally fractured carbonate reservoir with low permeability and low porosity. The well fluid is characterized by high hydrogen sulfide (H2S) (5%) and carbon dioxide (CO2) (5%) content. Handling such highly corrosive well fluid creates a wide range of challenges, from upstream at the wellhead to downstream at the processing facility.
Upstream challenges for the Jurassic gas field have been related mostly to subsurface corrosion of tubing, unplanned well downtime because of hydrate formation during winter, and failure of automated chokes for some wells.
Subsurface Tubing Corrosion. A moderate to severe corrosion rate has been indicated by corrosion logs in the production tubing because of the high H2S and CO2 content of the well fluid. Plans exist for existing carbon-steel tubing for four wells to be replaced by corrosion-resistant alloy material, and regular corrosion logs are being run for other suspect wells.
Hydrate Formation in Flowlines. Hydrate formation has been observed in flowlines during winter for 11 wells when flowline temperature drops to 65°F. This has resulted in unplanned production loss and substantial well downtime. The best mitigation option implemented was the injection of kinetic hydrate inhibitor (KHI) at the wellhead at the onset of winter for the identified wells, and a good degree of success has been achieved. However, KHI is not very effective in controlling hydrates at temperatures below 4°C, and this is a problem that needs to be addressed as a priority.
Flowline insulation at the point of restriction and heat tracing also have been implemented for four wells, with a fair amount of success.
Challenges With Automated Chokes. Automated chokes were first installed in the field in April 2011. The purpose of automation was to improve control of remotely located wells, enhance safety, and ensure better control of field production. Sixteen Jurassic wells are currently on automated chokes of three different makes—M1, M2, and M3.
Challenges With Make M1. The factory-set choke opening did not match actual choke opening. Choke adjustments had to be made with flowing wellhead pressure (FWHP) as a reference, and this leads to inaccurate settings. Scale formation also has been observed in-side the choke body, causing restricted flow and inaccurate FWHP readings and, therefore, poor monitoring of well performance.
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