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24-hour Turnaround on Inflow Control Device Improves Production with No Downtime
+ Design, manufacture and install flow control device to increase production rates in SAGD operation over three week period.
+ Use multiphase wellbore software to design a device that integrates swellable packers over 15 horizontal zones, and a propriety nozzle design to manage steam.
+ Tripled oil production, near zero subcool and easy well operation.
A major oil sands operator located in Calgary, AB approached RGL with evidence of a SAGD producer well showing uncharacteristically low production rates. The slant well had been in production for approximately two years with increasingly disappointing performance and the customer was under pressure to resolve the issue and improve production. The customer’s well and reservoir data showed three hot spots in the well. In addition to the thin pay, the toe zone was cold and not producing. Data also showed the geology of the reservoir was heterogeneous with variable pay thickness and barriers and baffles along the well.
The operator and RGL discussed used tubing deployed inflow control devices to:
Achieve uniform temperature and pressure along the well
Mitigate any hot spots
Reduce the sub-cool to nearly zero
Optimize production rate
After analyzing the customer’s data, including well trajectory, well logs, temperature fall-off data, lithology and pay thickness, RGL used in-house multiphase wellbore software to design a Flow Control Device (FCD) completion specifically for the well. The design included “swellable” packers to isolate 15 horizontal zones in the producer well and an inflow control device—RGL’s Production Divert Pup (PDP)—in each isolation zone. RGL included a proprietary nozzle design to restrict the steam while maintaining emulsion production rates.
The engineering report was forwarded to the customer for review outlining volumetric flow rate and the nozzle size of the PDP in each zone, the reasons for the design, the engineering calculation and sensitivity analysis of the completion. The entire process, from obtaining the information to finalizing the design, took 3 business days.
RGL’s completion engineer travelled to the field to assist with the install of the devices. Two hundred meters from the toe, the Operator had difficulty pushing the FCD string to the well toe as designed likely due to dogleg severity or sand blockage, which necessitated a re-design of the FCD completion. The Operator attempted numerous methods, including Sil-Glyde without success.
RGL’s applications engineer and the Operator spent 3 hours revising the design, which was sent immediately to RGL’s machine shop in Leduc, AB.
When it became clear that the string would have to be “pulled” through as opposed to “pushed” through, it was clear that the design of the tool would also have to change. RGL’s technical team analyzed the problem and proposed a smaller 3.5” tubing in the last two hundred meter toe zone. The team utilizing in-house wellbore software to redesign the isolation zones and the sizes of nozzles in each zone. In the new design, last two hundred meter end zone was constructed as one isolation zone and the PDP was installed at the end toe of the tubing. The design made the end zone a tail pipe completion which would hele steam to condensate en route to the tubing.
The RGL shop team manufactured and shipped the new tool to the field next day. It took less than 24 hours for RGL to assist with the design revision, manufacture the device, ship the device to the field and assist with the field installation.
Oil production rates tripled in the 2 months following the workover.
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