Reservoir souring most times occurs during secondary recovery, after water injection using seawater or produced water from a different reservoir. Water compatibility studies is thus necessary prior to injection to detect potential for souring and to implement preventive measures since souring poses challenges during production. This work stresses the importance of fluid compatibility studies before undertaking water injection projects. Two cases were considered; in the first case, water injection program was implemented using seawater without conducting fluid compatibility studies and serious souring problem was encountered later in the life of the reservoir. In the second case, fluid compatibility study was conducted where produced water from four sources were proposed to be used for water injection in two reservoirs. One reservoir (RW1) had high sulphate content of 20mg/l but did not have Sulfate Reducing Bacteria (SRB) probably because the reservoir temperature was 103 o C, well above the limit for the existence of most SRB. The second reservoir (RW2) with a temperature of 75 o C had SRB concentration of 845cfu/ml and had a sulfate concentration of less than 0.01mg/l, indicating that souring will only occur if water containing sulfate is injected into it. The study shows that reservoir souring could occur in both reservoirs from external sources. It was concluded that three out of the four proposed produced water cannot be injected into RW1 without treatment since their water samples contain SRB. Reservoir souring and its associated problems were thus prevented from occurring in RW1 due to fluid compatibility studies.

Production of formation water during petroleum exploitation is sometimes inevitable, necessitating disposal strategies. Produced formation water can be re-injected back into the reservoir either for enhanced oil recovery schemes or for the purpose of disposal. In any case, there is a need to prevent scale formation because it leads to permeability impairment. In this work, formation water compatibility tests were conducted to detect scaling potentials using the Langelier Saturation Index (LSI). Six water samples were used; four produced water samples intended for use in water injection schemes and two water samples obtained from reservoirs needing water injection programs. The water composition of scale-forming elements such as barium, strontium and calcium were determined for all the samples. Other determined parameters included pH values, total dissolved solids (TDS) and LSI. The LSI for different ratios of produced and reservoir water mixtures were determined. Laboratory results indicated that all the water samples contained scale-forming elements and compounds, and they all had to scale potential at ambient temperature but especially at higher temperatures. The produced formation waters were incompatible with the reservoir waters in terms of their scale-forming tendency. To prevent scale formation, especially at higher temperatures, it was recommended that scale inhibitors be used with the least scale-forming produced water. It was also recommended that produced formation waters be subjected to fluid compatibility studies before use in water injection schemes to prevent scale formation.