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.
As oil fields mature, producing more oil out of maturing reservoirs entails more water production. It is essential to have a successful water management process to be introduce, one that can handle substantial volumes of water produced in order to sustain crude oil production. At the early stage of the Greater Burgan Field water management was not a major concern. Most of its crude oil was dry and easy production with little water from Burgan & Wara reservoirs in Greater Burgan Field. With maturing of the field, South & East Kuwait Asset has started experiencing an increase in water production from its maturing reservoirs. Also starting water flooding in Wara reservoir to increase oil recovery increased water cut with oil production as expected. These changes made the production facilities to become constrained that cannot fully handle produced water volume and result in production deferral. To mitigate the high water cut challenges, South East Kuwait set up a multidisciplinary team to review and come up with actions to tackle the produced water handling challenge. The team looked at an operational initiative to maintain the long-term disposal option of disposing produced water into Shuaiba formation. Shuaiba formation is below Burgan reservoir. During drilling the drilling team encountered heavy fluid losses in Shuaiba. This experience led the study team to support the option of disposing effluent water into fractured Shuaiba carbonate. Shuaiba formation is classify as carbonate formation, full of vugs and fractures resulted from dissolution due to ancient underground water movement, the dissolution led to collapse And creation of large vugs and fractures around the collapsed area. The collapsed area and fractures are the main mechanism for storage of effluent water and increasing disposal capacity for the production facility. The plan is to drill Horizontal disposal wells targeting the Karst to intercept those vugs and fractures. The team saw a promising option to drill in Shuaiba, to increase the chance of loss fluid circulation and enhance facility capacity. After drilling few wells and encountering total loss in the horizontal fractured section, along the edge of the karst, and performing injectivity disposing test, the wells showed ability to take up high water rates more than (50,000 BWPD). Based on the success of these disposal wells, Production operations bottlenecks are resolved in disposal well capacity and increasing it to more than (500,000 BWPD). Disposing in Shuaiba, formation will not require any treatment facilities and is an environmentally friendly long-term option
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