Several correlations have been developed to predict wellhead pressure–production rate relationship in the Niger Delta region. Regrettably, most of these correlations were developed from field data that are not from the Niger Delta region and with limited field test data ranges, so their predictions are lower than expected field values when applied to the Niger Delta. Additionally, some developed wellhead pressure–production rate correlations based on Niger Delta field data are made using in-house equations by the operating companies in the Niger Delta region. To ameliorate this anomaly, sixty four (64) field test data: choke size (S), production rate (q), gas-liquid ratio (GLR), flowing wellhead pressure (Pwh), flowing temperature (FTHP) and basic sediment and water (BS&W) were collected from oil producing wells in the Niger Delta region to develop wellhead pressure–production rate correlations based on Gilbert correlation and modified Gilbert equations. The developed correlations using Niger Delta field test data were compared with several authors' correlations. The results obtained indicate that the developed correlations resulted in better predictions than earlier correlations. In addition, the statistical analysis of the developed correlations used to ascertain the extent of their predicted values differ from the field test data and resulted in average error, absolute error and standard deviation of −0.1477, 0.4430 and 0.9582 for Gilbert formula and −0.2515, 0.4737 and 1.0997 for modified Gilbert formula, respectively. Furthermore, the developed correlations are comparable with an average correlation coefficient of 0.9869. Therefore, the developed correlations can be used as a quick tool to estimate the wellhead pressure–production rate relationship in Niger Delta oil fields.

In petroleum industry, oil production strategy to circumvent water coning in reservoirs with strong water drive is quit challenging. To ameliorate this oil production related problem, several water coning prediction models and control approaches have been developed by researchers. The prediction approaches include analytical, empirical and numerical approach. The analytical and empirical prediction approaches are qualitative water coning prediction approach with limited field scale application. However, these approaches model predictions can gain field application if upscale. Numerical approach has provided the fulcrum to study the complexity of water coning phenomenon in bottom-water drive reservoirs, and its prediction and sensitivity results have found wide field application. In addition, the various developed water coning control methods: downhole oil-water separation (DOWS), downhole water sink (DWS), downhole water loop (DWL), among others have proved to be effective, as it reduces the water-cut, produced water and water handling

Sanding during oil production causes severe operational problems in the oil and gas industry. Several techniques have been used for sand production control in sandstone reservoirs. Consolidating materials, such as, crude oil coke and nickel plating have been used in the past by researchers. At present, the chemical binders, such as; phenol resin, phenol-formaldehyde, epoxy, and furan or phenol-furfural provides cementation. This work is centered on the laboratory studies of selected sand consolidating resins that would be suitable for application in the Niger Delta (ND) oil fields. Considering the available resins for consolidation process, six types of chemical resins namely; Epoxy (A&B), Novalak Phenol-Formaldehyde, Furan Phenol Acrylic, Furan and Phenol resins were selected for studies. Three other locally made resins: Rubber Latex, Evo Stik and Polystyrene gum were reviewed alongside for comparison and test for their applicability. Different core samples were made by mixing these resins and their hardening agents with sand sample obtained from a sand producing oil field in the Western Niger Delta. The core samples made were subjected to laboratory qualitative and quantitative analysis in order to obtain individual permeability and porosity under different overburden pressures from 500psi through 3500psi. Results from experimental data show that Epoxy A&B resins ranked best followed by Furan resin and then, the local resins. This was adjudged based on minimal variation in the permeability and porosity of the core samples retained in acceptable values after curing and by analytical result from measurements at various overburden pressures.

Sand consolidation as a sand control method has been applied in the oil industry for nearly eight decades. Chemical sand consolidation has evolved since its first application in the early 1940s. Despite the failures recorded and its limitations in application in some oil and gas wells, this method has recorded some remarkable successes both as a primary and a remedial method of sand control in the petroleum industry. This paper presents the operation constraints in sand consolidation since its first use in the industry, the selection criteria and remedy. It also considers the types of resins which have been used over the years: highlights of sand consolidation methods in high clay content formations and the problem of long shut-in time for sufficient consolidation strength in reservoirs with either relatively low or high bottom-hole treatment temperatures. Moreover, recommendations on the way forward to manage these operational problems are elucidated.

There is an increasing need to limit the use of chemical treating agents during oil and gas production and to search for safer and cost effective ones mainly due to environmental constraints. Therefore the use and performance of demulsifiers have to be improved from the application and cost as well as from the environmental issues. This means that new formulations must be less toxic and efficient compared to the general classical chemical families of demulsifiers which contain toxic molecules like phenol groups. This paper is on the performance and the comparison of four chemical demulsifiers (local and foreign) on their demulsification of four crude oil emulsions of different asphaltene contents from different oil wells in the Niger Delta. The chemical families of these demulsifiers were screened with effective separation ability of different surfactants using classical "Bottle test". The Bottle test helped to determine the type of demulsifier that will most effectively break the emulsion of the crude samples. The basic aim of this screening was to compare and rank the efficiency of the various demulsifiers both local and foreign (V4404 of Nigeria, 92LTM174 of USA, EN/82/2 of France and DS 964 of Canada) in terms of percentage (%) volume of water that will be separated out of the samples. The results showed that the viscosity of the emulsions increased as the water content increased with an assumption that only oil and water were present. The nature of the emulsions were subject to changes, therefore no treatment method was conclusively generalized as best for every emulsion problem. Finally from the preliminary screening, the result also revealed that V4404 a local demulsifier exhibited very interesting performance and was also environmentally friendly compared to the imported ones.

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Liquefied Petroleum Gas (LPG) is one of the alternate sources of energy because of its availability and high heating value. As the interest in LPG production in Nigeria and other developing countries increases, it is imperative to study some of the flow assurance issues associated with LPG. Due to the presence of moisture in commercial LPG, hydrates can form during LPG production, transportation and storage. Hence, it is important to predict hydrate forming conditions of LPG and propose a prevention plan if the LPG production, transportation or storage system falls in the hydrate formation zone. This paper examines the mechanism of hydrate formation in LPG and how LPG hydrates can be inhibited using methanol and ethanol. The inhibitor effectiveness was evaluated by the degree of temperature depression effected by equal amounts of these inhibitors. It was discovered that Methanol performed better than Ethanol when 20wt% of methanol and 20wt% of ethanol respectively were used in inhibiting hydrates formed in LPG. The effect of dehydration on LPG hydrate formation was also examined by varying the water content of the LPG from 7wt% water to 2.5wt% water. This simple approach to hydrate inhibition will enable the Engineer reduce the risk of hydrate formation during LPG production, transportation and storage.

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