Thursday, December 6, 2018

Matrix Treatment in Alberta

This case concerns a Suncor Inc. operated gas well, Pine Creek 10-1, in Alberta, Canada. It has a 2493-ft (760-m) horizontal section, drilled through the carbonate reservoir above the water leg to a measured depth of 14,935 ft [4552 m].

Unlike the usual situation, the best porosity of the horizontal section was believed to be at the toe of the well rather than the heel. However, it was also believed that these high-potential zones had been invaded by drilling mud filtrate.To enhance productivity, it was important to ensure that the acid was pumped into the toe of the well to open up fractures and allow the mud to flow out.

To create the required diversion, it was decided to pump a Foam treatment. Foam is pumped into the formation, blocking further entry of the acid and diverting it to unstimulated reservoir. To minimize friction when pumping at the necessary rate, 2 inch coiled tubing was used to deliver the fluids. The relatively large CT diameter also helped avoid lock-up when running into the long horizontal section and offered more pulling potential if the string had become stuck. 

The downhole assembly consisted of a nozzle, two memory gauges separated by a knuckle joint, and a check valve. The knuckle joint added flexibility to an otherwise stiff assembly. Data collected by the gauges were used after the job to analyze the buildup and breakdown of the formation as successive diversion and acid phases were pumped.

A number of factors complicated the choice of acid additives - which is crucial to the success of any matrix treatment. First, as already noted, Suncor suspected that the formation had been invaded by significant quantities of mud filtrate, which contained a strong emulsifier likely to form an emulsion with spent acid. Second, the presence of 25% hydrogen sulfide [ H2S] in the well necessitated the use of corrosion-control additives that may react with other chemicals in the fluid.

 Consequently, extensive compatibility tests were run between the mud and proposed acid systems. The final treatment design included a number of stages:

  • tubing pickle, which is used to clean up the inside of the coiled tubing - 15% hydrochloric acid [HCl] , inhibitor and surfactant. 
  • preflush, to thin the mud in the wellbore - fracturing oil, antisludge agent and nitrogen, creating a foam with a quality of 50%.
  • Mudclean OB solution, to flush out any remaining mud in the well and water-wet the formation  prior to the FoamMAT job - water, surfactant and solvent as a foam of 50% quality.
  • diversion stages - water and surfactant with nitrogen as a 65% quality foam.
  • Squeeze acid - 15% HCl, with inhibitor, surfactant, de-emulsifier, antisludge agent, miscible solvent and H2S scavenger. The total volume of the acid, some 33,025 gal, was determined by a rule of thumb and past experience of a FoamMAT job carried out on a nearby oil well.
  • postjob flush - fracturing oil and nitrogen. Having pickled the CT and negotiated some problems running in hole caused by a hydrate plug, the preflush was pumped with the CT on bottom- at the end of the toe. Once all the preflush had been displaced across the open hole, the well was shut in for about 15 minutes to allow it to soak and then flowed back to recover any mud filtrate. Next the mudclean OB stage was pumped downhole and displaced using nitrogen. The well was then allowed to flow to clean up and another stage was pumped.
 When this had been displaced out of the well, the main treatment commenced. A series of 15 alternating acid - 1585 gal- and diverter 400 gal -stages were pumped at 25 to 80 gal/min. At the same time , the coiled tubing was gradually pulled out of the hole at about 10 ft/ min from the toe to the heel of the well. After pumping a diverter stage, the pumps were shut down for 10 minutes before the next acid was pumped. 

Midway through the job, the well went on a vacuum. To maintain a positive surface pressure and gain maximum information about the treatment, it was necessary to reduce the bottomhole hydrostatic pressure. The foam qualities of the two fluids were adjusted so that the diverter was 70% and the acid 25%. 

Surface pressure was plotted throughout the job to assess the success of the diversion stages. Once all the acid was pumped, the CT was run back to the toe of the well and postjob flush was pumped to break up the foam in the wellbore and hasten the cleanup.

The well was opened up to flow with the gauges still on bottom. During cleanup, the well flowed spent acid and estimated 21,000 gal of mud filtrate. Suncor believes that this mud came out of the natural fractures of the formation. Once the well was cleaned up, the well pressure and temperature were logged using the memory gauges.

The well is currently waiting to be brought into the production, but Suncor estimates that the acid treatment reduced the pressure drop across the reservoir by 435 to 725 psi. By comparing this to pretreatment pressure and rate information, additional gas deliverability due to the treatment is likely to be 2 to 6 million scf/D.

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