DEPARTMENT OF PETROLEUM ENGINEERING

Drilling mud , otherwise known as drilling fluid, is a vital component in the oil and gas industry. As the primary medium for drilling oil and gas wells, its importance cannot be overstated. However, in Nigeria, the procurement of drilling mud is often costly, as bentonite clay, the conventional material used in its formulation is largely imported. This project investigates the suitability of a locally sourced clay, Okuaghe, obtained from one of the countries numerous clay deposits, as a potential substitute for imported bentonite in drilling mud formulation. The study aims to promote local material utilization, reduce import dependency, and minimize overall operational costs. The clay sample was collected from Uhunmwonde local government area in Edo State, then prepared through drying, crushing, and sieving. Portions of the total sample were activated using soda ash (sodium carbonate) to enable comparative analysis. Guided by API specifications, rheological properties such as plastic viscosity, apparent viscosity, yield point and gel strength were determined using standard procedures. Additionally, carboxymethyl cellukose (CMC) was incorporated in some samples to enhance performance toward API standards. The results indicates that the local clay possesses promising potential for drilling mud formulation, provided adequate beneficiation and optimization of activation conditions are applied. The findings also emphasize the importance of maintaining optimal base concentration during chemical activation, as excessive amounts may yield adverse effects. Overall, this laboratory-based study demonstrates that certain local clays, when properly treated and modified with suitable additives, can perform comparably to imported bentonite. It further underscores the need for field-scale evaluation to validate laboratory results and support the wider adoption of local materials in drilling fluid formulation.

The oil and gas industry is extremely risky and difficult, necessitating the safe and cost-effective execution of all operations. A drilling operation's success depends on the careful selection and application of drilling fluid. Investigating how contaminants affect the properties of water-based drilling fluids is the main goal of this study. This experiment revealed that the fluid loss into the formation was enhanced when sodium salt was present in the mud system. Additionally, as the mass of the mud sample increased from 1g to 5g, the apparent viscosity and gel strength increased, but the plastic viscosity and pH stayed constant. On the other hand, the yield point showed minimal growth. Since the amount of cement sample used was increased from 1g to 5g while the pH remained constant, all rheological properties of the mud increased significantly when cement was used as a contaminant. The carbonate effect is largely on the Gel strength which decreased as the amount of added carbonate increased. The pH had no charges, which also meant carbonate kept the mud in its alkaline state, as it was the case with cement. In conclusion, the presence of a contaminant on the drilling mud either reduces or increases the rheological properties of the mud sample. This in turn affects the rate of penetration, its performance and also could pose serious drilling problems.

With a variety of EOR methods explored, the discovery is in tune with Low-salinity water Injection (LSW) as a promising enhancement of the rate at which oil is recoverable from the reservoir. However, the comprehensive understanding of the principal mechanism directing this technique, has not been fully harnessed, causing the difficulty of creating the most favourable salinity condition, and the ionic formation, required for the injected solution. However, a wider school of thought holds that, the driving mechanism in LSWI of the carbonate’s reservoir, is vast. Though, the modification in wettability is seen as the primary mechanism driving oil to a more recoverable state, with most literature review proving this, how it works is up for a good intelligent discuss. This literature attempts to reviews a variety of working states of LSWI, from studies, field investigations, as well as individual recommended mechanisms affecting the oil–rock–brine contact interfaces. Furthermore, the uniqueness of this project, is to provides an extensive evaluation of previous treatises, on LSWI in carbonate reservoirs, the analyses, applications, as well as achievements that have given ground for a mastery of the difficulty of the multicomponent systems and the potential benefits it has on the oil production industry.

The production optimization of oil and gas wells using computerized well model has becomeasuccessful technique contributing towards the better efficiency and higher production of manywells. This study focuses on designing optimum production strategies in mature oil field, well modelling using prosper, one of the components of the integrated production modelling (IPM) was implemented in field X which is located in peninsular Malaysia. The model carries all theproperties of the well with detailed description of the reservoir and vertical lift performance. The process includes four phases: first phase was building well model using PVT, IPR, surfaceand equipment data. Second phase was constructing well matching based on the monthlywell test data. This helps to ensure that the model is well calibrated. Third phase was performingwell analysis based on the well matching results. Well analysis can be performed by evaluatingeachcomponent of the producing well. Often this procedure will identify possible problems occurredin the production components which restrict flow and cause the well to produce in a manner that the maximum potential rate is not achieved. From the results and findings achieved fromtheIPR-VLP curves/trend, the optimum operating point takes place at a flow rate of 900STB/Dat Bottom hole pressure of 2500psia, so increasing tubing size beyond 3.96-inches offers minimal benefits and can lead to liquid loading issues. Also, maintaining a moderate wellhead pressureof350psig achieves a stable production and prevents drawdown. Also, from my findings, the IPR- VLP intersection in the graphical trend above shows the natural equilibriumof the system, satisfying the certainty and accuracy of prosper modeling software tool. Overall, this productiontechnique permits engineer to come with some modification which is expected to increase theproduction.

The extraction of crude oil in the Niger Delta generates vast quantities of produced water (PW), a complex, highly saline wastewater containing hazardous heavy metals. Conventional treatment
methods are often prohibitively expensive and inefficient, necessitating the development of lowcost, sustainable alternatives. This research investigates the efficacy of two locally abundant waste
materials, thermally-chemically activated sawdust and thermally activated eggshell, as bioadsorbents for removing iron (Fe) and zinc (Zn) from real produced water sourced from an oil field within the Niger Delta. The study involved preparation and activation of adsorbents, followed by batch adsorption experiments under varying contact times. The produced water was characterized, and experimental data were analyzed using kinetic and isotherm models. Results demonstrated that both adsorbents effectively removed metals. Activated sawdust achieved removal efficiencies of 70.6% for Fe and 95.5% for Zn, while thermally activated eggshell removed 61.4% of Fe and 79.8% of Zn. Kinetic studies revealed that iron adsorption onto sawdust followed a physisorption-driven Pseudo-First-Order model, whereas adsorption onto eggshell followed a chemisorption-driven Pseudo-Second-Order model, indicative of ion exchange with calcium carbonate. Equilibrium isotherm analysis showed that the Freundlich model provided a better fit than Langmuir for both adsorbents, suggesting multilayer adsorption on heterogeneous surfaces. However, anomalous parameters in both models underscored the influence of the complex, multi-component nature of real produced water, causing deviation from ideal model behavior. The study concludes that both sawdust and eggshell are viable, low-cost, and sustainable materials for remediating heavy metals from produced water in the Niger Delta, validating a circular economy approach that transforms local waste into valuable resources for environmental cleanup.

Flow assurance has become one of the most pressing challenges in onshore oil and gas production. It refers to the ability to transport hydrocarbons from the reservoir through pipelines and surface facilities to the point of sale without blockages or interruptions. While the concept first gained traction in offshore systems, onshore operations face their own unique and complex issues. These challenges are linked to aging infrastructure, climatic variations, and the exploitation of marginal and mature fields, which often present high water cuts and unstable emulsions. This study provides a systematic review of the major flow assurance problems in onshore environments, focusing on wax deposition, hydrate formation, asphaltene precipitation, mineral scale, emulsions, and corrosion. Each mechanism was examined in terms of its underlying chemistry and physics, its operational impact, and the mitigation strategies commonly applied. Traditional solutions such as thermal treatments, chemical inhibitors, pigging, and water management remain central, but they are often costly, environmentally intensive, and sometimes unreliable under harsh conditions. The review also highlights the increasing use of innovative technologies, including nanomaterial-based inhibitors, environmentally friendly chemical alternatives, advanced coatings, and digital monitoring supported by artificial intelligence and machine learning. These emerging approaches show promise in reducing chemical volumes, lowering costs, and improving predictive control, although many remain at laboratory or pilot scale. The findings demonstrate that no single strategy is universally effective. Instead, integrated approaches tailored to field-specific conditions provide the best outcomes. For instance, thermal and pigging strategies remain practical in wax-prone pipelines, while low-dosage hydrate inhibitors and AI-based prediction models are more suited for hydrate management in colder climates.

The IZYP field, located in the Niger Delta region, is an oil rim reservoir characterized by a combined drive mechanism involving both an aquifer and solution gas. The field has undergone primary recovery and conventional water injection, achieving a recovery factor of 19% and 28.5%, respectively. However, the late initiation of water injection led to substantial pressure depletion and solution gas liberation, compromising the reservoir's natural energy drive and hindering efficient hydrocarbon recovery. This study aimed to optimize the water injection strategy for the IZYP field to maximize oil recovery and resource utilization. A representative reservoir simulation model was developed through history matching, replicating the field's past production performance. Subsequent simulations evaluated the impact of modifying water injection timings and operational parameters on overall recovery factors. The optimized water injection strategy involved initiating water injection at an earlier stage (3,015 days or 1997), effectively maintaining reservoir pressure above the bubble point. This proactive approach minimized solution gas production and preserved the reservoir's energy potential. The optimized strategy yielded a substantial improvement in the ultimate recovery factor, increasing from 28.5% to 32.6% after 34 years of production. Comparative analyses of average reservoir pressure, gas-oil ratio (GOR), and recovery factor graphs illustrated the significant benefits of the optimized approach

The production of oil and gas globally can only be made possible with the aid of drilling technology. However, after well completion, that is making a well ready for production, the surface equipment such as wellhead and Christmas tree is required to flow in the well. The production Choke is precisely regulating the flow of oil or gas to achieve a carefully calculated rate of
recovery. By maintaining the correct backpressure, chokes can increase the ultimate recovery of hydrocarbons from a formation pressure decline, reduce sand production and the migration of fines, possibly control water coning and gas fingering, and minimize tree damage from erosion caused by turbulence and cavitations. Two wells were discussed, Well No (SELE 01) and (SELE
02), the effect of increase in the choke sizes were seen to affect the reservoir characteristics, i.e. Pressure decline, API, Flow rates, Sand Control, Water cut, etc. The results and analysis has shown that as the choke size increased, the flow rate increased, the rate of decline of the FTP increased, the API increased and the Water cut also increased. The choke size was later adjusted to a value of 16/64’’ for well NO (SELE 01) and 30/64’’ for well NO (SELE 02) in order for the well to flow at an optimum rate. At this rate, the pressure decline was also maintained, little or no water cut, and traces of sand. Conclusively, to maintain optimum flow rate, the choke size was carefully chosen so that the pressure in the reservoir is maintaine

The oil and gas industry in the Niger Delta faces a significant challenge with heterogeneous datasets fragmented across multiple platforms and stored in diverse file formats, a situation that impedes efficient research and operational optimization. To address this problem, this study develops a Unified Field Model (UFM) designed to aggregate, harmonize, and standardize these varied petroleum engineering datasets, including well logs, seismic data, and production logs, using scalable cloud storage and data processing pipelines. The core of the research involves creating a durable and adaptable data structure capable of handling both structured and unstructured data while preserving relational attributes. This process is supported by rigorous data quality assurance techniques, such as feature engineering, anomaly detection, and petroleum engineering domain-specific imputation strategies. This UFM then serves as the foundation for a web-based data brokerage platform, known as Petroleum Engineering Research Datasets (PERD), which enables researchers and industry operators in the Niger Delta to efficiently access high-quality petroleum datasets. This study provides a foundational improvement for the sector, enhancing operational efficiency, improving data interoperability, and allowing for the better use of computational tools to tackle complex Petroleum engineering challenges, thereby improving study reproducibility and performance in the region.

This research examines how Sodium Hydroxide (NaOH) influences the flow characteristics of purified gum Arabic-based drilling mud formulations, positioning them as eco-friendly substitutes for conventional synthetic additives. The experiment involved developing seven initial formulations combining bentonite with different polymer systems: xanthan gum, gum Arabic, and mixtures of gum Arabic with either cocoyam starch or ginger extract in proportions of 50/50 and 75/25. Subsequently, selected formulations underwent alkaline modification using NaOH at measurements of 3.0g, 7.5g, and 15.0g to replicate varying pH environments. Flow behavior parameters encompassing plastic viscosity (PV), yield point (YP), gel strength, and mud weight were determined through Fann viscometer measurements and evaluated against three mathematical model frameworks: Bingham Plastic, Power Law, and Herschel- Bulkley models. Experimental findings demonstrated that 50g of gum Arabic delivered comparable rheological characteristics to 1g of xanthan gum under neutral conditions. The introduction of alkaline treatment produced substantial modifications in fluid behavior, with response patterns dependent on both the specific polymer-starch pairing and alkalinity level. The most remarkable transformation occurred in the gum Arabic-cocoyam (50/50) formulation treated with 7.5g NaOH, which demonstrated PV of 65 cp and YP of 180 lb/100ft² corresponding to increases of 261% and 1025% respectively relative to the 3.0g NaOH variant. The gum Arabic-ginger combination displayed considerable viscosity nhancement (PV = 108 cp with 7.5g NaOH) yet revealed temporal degradation of gel structure at elevated alkalinity levels. Every alkaline-treated system manifested pseudoplastic (shear-thinning) characteristics with flow behavior indices (n) spanning 0.3 to 0.948, validating their appropriateness for drilling fluid applications. Comparative model analysis indicated that the Herschel-Bulkley model most accurately characterized the behavior of alkaline-modified natural polymer systems, whereas both Bingham Plastic and Power Law models exhibited substantial prediction errors, especially under high-alkalinity conditions. These results established that purified gum Arabic, when strategically combined with indigenous starches, (cocoyam & ginger) and subjected to pH optimization, represents a viable, environmentally degradable, and economically advantageous alternative to synthetic drilling fluid components, delivering ecological v advantages while preserving operational performance standards required for petroleum drilling activities.