LNG

Handling Jurassic Field Sour Gas Creates Challenges Upstream and Downstream

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.

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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

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 inside the choke body, causing restricted flow and inaccurate FWHP readings and, therefore, poor monitoring of well performance.

Challenges With Make M2. The carbide trim failed for two chokes within a few months of operation, resulting in well closure and subsequent production loss. Trim failure within such a short period of operation is cause for concern and could be because of poor design, improper metallurgy, or failure to handle the rated differential pressure generated across the choke. The trim was changed with vendor assistance for Make M2. Scale formation was observed inside the choke body, restricting flow and leading to inaccurate FWHP readings.

Challenges With Make M3. The carbide trim failed for one choke within a few months of operation, resulting in unplanned well closure and production loss.

Downstream Challenges

Frequent carryover of condensate from high-pressure dry separators into the amine contactor has been observed, especially at flow rates exceeding 108 MMscf/D. This has resulted in costly plant downtime.

The immediate effect of such carryover has been

  • Amine contamination, foaming, and choking of filters and exchangers of amine system
  • Poor amine regeneration and subsequent off-specification export gas in terms of H2S content
  • Production cutback and revenue loss
  • Costly amine loss
  • Increased flaring from the plant, leading to environmental concerns

Remedial Steps. The following remedial steps were initiated:

  • Installed hydrocyclone separator in the gas line upstream of the amine contactor to capture carryover liquid from high-pressure separators
  • Installed inlet vane pack separation assembly and better designed demisters in separators and amine contactor
  • Installed random packed bed at the bottom of the amine contactor to prevent incoming gas into the vessel to carryover amine from the last tray
  • Lowered rich amine outlet line from the amine contactor to prevent gas cutting into the rich amine outlet line

A probable cause of carryover from the high-pressure separators is an undersized separator.
Other Downstream Challenges at EPF 50. Insufficient Capacity of Amine Unit To Process Acid Gases. The amine unit has been designed to handle 2% H2S content in feed gas, while H2S content in the well fluid flowing to EPF 50 has been observed to be 3.5%. Thus, the sweetening capacity of the amine unit is affected, and the plant must operate at limited capacity if export gas specifications are to be met.

Limited Capacity of the Plant for Treating Wet Crude. The desalter capacity for handling wet crude is 20,000 BOPD. Because most of the wells are wet, wet crude is being processed in a dry train, causing fouling of crude stabilizer trays and causing basic sediment and water to be higher than specifications in export crude. To mitigate this issue, a static mixer was installed in the low-­pressure dry three-phase separator to reduce the salt content in the dry crude.

High Chloride Content of Amine in Circulation. The amine was getting contaminated with high salt content in feed gas and carryover from the high-pressure separators. High chloride content was increasing corrosivity of amine. An increase in foaming tendency caused production cutback and flaring loss.

Frequent Choking of Amine Lean/Rich Exchanger. Backpressure caused by choked exchangers led to flaring from the amine flash tank. A new standby lean/rich exchanger was installed. Existing exchangers were serviced to mitigate this issue, and 40-μ filters in the amine filtration system were replaced with 10-μ filters to improve cleanup.

Implemented Projects and Short-Term Plans

  • Internal modification of high-pressure separators and piping modification were performed in the amine contactor for proper separation of phases. Internal modification in separators involved placing an inlet vane pack assembly for proper phase separation and replacing the existing demister with larger unit.
  • Random packing at amine contactor bottom was installed to reduce flaring.
  • Implementation of intelligent field projects for Jurassic wells is ongoing.
  • Plans are for installation of an ion-exchange-type reclaimer for chloride removal from amine in circulation.
  • Hydrocyclone separator will be modified to increase separation efficiency.
  • Plans call for selecting suitable corrosion inhibitor/KHI/demulsifier on the basis of field trials.

Long-Term Projects

  • A new desalter with a capacity of 50,000 BOPD to treat additional wet crude is planned.
  • A hookup of a new multiphase flowmeter is planned for accurate well testing.
  • Replacement is planned of existing valve trays of the amine contactor.
  • Solvent replacement is planned for enhancing amine contactor capacity.
  • A third sulfur recovery unit train is planned to process an increased acid gas feed rate.

Conclusions

Challenges faced in the operation of the facility have been unique to the company because this is the first time that the company has had to process sour gas. The challenges have been mitigated successfully for most cases, and the lessons learned have been incorporated into the design phase of the future facility, expected to be commissioned soon. The company has ambitious plans for further development of the Jurassic gas field in the near future and plans to increase gas production significantly from its current level.

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.