On-site coreflood experiments were conducted at Prudhoe Bay field, Alaska using side streams of produced water taken directly from produced water injection (PWI) lines. The objectives were to determine how rapidly the formation injection face is plugged by produced water reinjection, the location and mechanism of damage, and the impacts of bacterial growth on the extent and rate of damage.

In core tests where produced water was not filtered prior to injection, 90% permeability damage occurred within 24 hours of injection startup. This is inconsistent with field observations where injection well decline is observed to occur over weeks or months, when seen at all. Field observations are consistent with previously-described (growing) thermal fractures that dominate injection performance, thereby minimizing deleterious effects of sand face plugging.

In core tests where produced water was filtered, little damage was observed; this demonstrates that removable components in produced water are responsible for face damage. However, when cores were first inoculated with bacteria-laden water and then flooded for several days with filtered produced water, deep damage (inches) was seen. This suggests PWI wells can suffer injectivity damage over time due to bacterial growth.

Once damage had occurred, addition of biocide did not restore permeability.


Produced water handling has become a major effort of all waterflood operations. With increasing environmental regulations, more and more produced water is being re-injected. Injectivity decline in PWI wells is a major concern; many studies are ongoing to try to understand the damage mechanisms.

Prudhoe Bay (PB) produced water contains a large number of suspended solid and oil droplets and was found to be more difficult to reinject than filtered sea water1.

Bacterial growth in PB PWI systems was suspected to cause further problems. Bacteria can produce exopolysaccarides which coalesce to form a confluent biofilm2. Oil and solid partides entrained in the PWI water can also be trapped by the developing bacterial biofilm to significantly accelerate water injectivity decline rates3. Furthermore, biofilm growth in surface facilities can interfere with separator and gas flotation cell performance, resulting in increased oil-in-water carryovers. The SRB growth in biofilm can also generate H2S gas which reacts with dissolved iron to precipitate iron sulfide, increasing solid particle loading in the injection water.

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