Environmental pollution is one of the major consequences of gas flaring. In the rural oil producing communities of the Niger Delta where this age long practice is common and a large portion of the population use rain water for domestic activities, it is imperative to evaluate the rain water quality in these environments. In this work, a hundred samples of rain water were collected within a period of two years from a typical community where gas flaring has been dominant for several decades. The samples were analyzed in the laboratory for pH value, turbidity and nitrite content, and the results were compared against the World Health Organization (WHO) standard for water quality. The study shows that the rainwater samples collected from the gas flaring zone had an average turbidity value of 22.58NTU, an average pH value of 6.75 and contained an average of 2.6mg/l of nitrite. However, when considered separately, some rain water samples met the WHO standard while others did not. It was observed that about 61% of the samples considered met the WHO standard on turbidity of 15NTU for rain water and 17% of the samples met the standard for drinking water which is 5NTU. 26% met the lower pH standard of 7.0 for drinking water while 64% met the pH standard of 6.5 for rain water. 60% met the WHO requirement for nitrite content of 3mg/l but generally, about 39% of the samples did not meet the WHO standard for rain water quality. These test parameters indicate that the level of rain water pollution in this gas flaring environment is high and unhealthy especially for the ecosystem system. Thus, drastic measures need to be taken to stall gas flaring in the Niger Delta.

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.

Crude oil fingerprinting is a term applied to techniques that utilize geochemical analysis of hydrocarbon fluids composition to provide valuable information for well, reservoir and spill management. Analysis of crude oil fingerprints reveals a typical oil profile. Such a profile can provide information on formation history, type of carbon number preference during formation and route of migration. This study was undertaken using whole oil fingerprint and biomarkers of oils from twenty well strings from an onshore field in the Niger Delta Region. The aim was to evaluate light crude oils and determine thermal maturity, source rock quality, depositional environment and condensate correlation. The crude oil samples were analyzed using two major analytical techniques namely Gas Chromatography-Flame Ionization Detector (GC-FID) and Gas Chromatography-Mass Spectrometry (GC-MS). Evaluation of light hydrocarbon components was done using Mango parameters K1, K2, P2, P3 and N2 and the results revealed terrigenous organic matter input. Biomarker composition and pristane/phytane ratios in the range of 3.51 to 6.83 derived from GC results show that the source rock of the oils is made up of majorly terrestrial (type III) organic matter, deposited in a deltaic setting with prevailing oxic conditions. Maturity parameters calculated from Carbon Preference Indices between the range of 0.87 and 1.44 indicate the source is matured. The study provides key information on source characteristics that are applied to describe the type of petroleum prospects of a region. This study also provides information on condensate correlation, which has production implications such as application to production allocation.