The Greater Burgan Field, first discovered in 1938, is the second largest oilfield in the world. Production from the Greater Burgan began in 1946 from the Wara reservoir via primary recovery. Recently, field-wide waterflood as a secondary recovery mechanism has been implemented. The current insight on the potential of hybrid low salinity water and polymer flooding in the Greater Burgan is presented.

The goal of the Greater Burgan Study team in this enhanced oil recovery (EOR) evaluation program was to compare the benefits of using low salinity waterflood (LSW) and low salinity polymer (LSP) injection as tertiary oil recovery methods in the Wara sandstone reservoir of the Greater Burgan field. The efficacy of low salinity and low salinity polymer injection has been investigated in the laboratory and by conducting a series of single-well chemical tracer (SWCT) tests in one Wara producer.

In the field trial carried out on Well A, three separate determinations of residual oil saturation (Sor) were made. The first SWCT test measured waterflood Sor after injecting a slug of high salinity water (HSW) that is compositionally comparable to the produced water utilized field-wide for waterflooding operations. The second and third SWCT tests measured the remaining oil saturation after LSW and LSP, respectively. Laboratory corefloods were also performed to evaluate LSW and LSP recoveries and their impacts on injectivity. The injection water salinity, injection design, oil viscosity, and polymer viscosity used in the laboratory experiments were identical to those used in the field SWCT tests.

These SWCT test trial results establish a baseline waterflood Sor (i.e., after high salinity water injection) and show that further reductions in Sor may be achieved with low salinity waterflooding and low salinity polymer injection. The laboratory results showed no plugging or injectivity issues during LSW or LSP corefloods. Overall, LSW and LSP were shown to be technically workable tertiary processes in the Greater Burgan.

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