Condensate reservoirs are mostly pressure sensitive and keeping the pressure above the dew point pressure in the reservoir is critical to avoid condensate banking in the reservoir. If it occurs, production is highly inhibited and the well may ultimately quit on production under liquid loading. Fluid ratios are important in the management of condensate wells and most critical is the Gas Liquid Ratio (GLR). There is a certain GLR that below it, there will be a liquid loading in the wellbore that could quit the well. Each fluid rate goes with a GLR and the point where there is a reversal of the GLR or CGR trends may present a case of loading scenario and that is taken as the determination reference point. When a condensate well shows an improvement of water cut as the choke bean size is reduced does not necessarily signify a healthy situation and neither a one-point higher water cut with increase in choke bean size mean a water coning situation. When a liquid loading well is beaned up, there is early signs of water coning in the production data but this is just a wellbore production and the BS&W improves as the production rate is further increased. Further investigation is necessary to separate the challenge of water conning from the challenge of too low Gas rate which causes the loading of the liquids in the wellbore. That is the operating envelop to manage condensate well rates: rates too low with a possibility of a liquid loading and rates too high that depicts a case of water conning when water is close to the perforation. This band must be completely exploited to turn the production curve in the positive. This paper provides a strategy to recover a condensate well production with a challenge of liquid loading using a case study. The degree of the severity of the liquid loading can be represented using a power law model with the gradient being the level of severity of the loading. The production improvement is greater than nβ percent where n is the quadratic model number 2 and β is the product of the graphical and Lagrangian-Quadratic alpha parameters. The optimum rate can be determined using the Lagrange Multiplier optimization method to effectively extend the production life of the well.

The oil and gas industry in Nigeria is undergoing rapid change and explosive growth especially for marginal oil fields. Marginal oil fields operators are indigenous companies with limited profitability and some operators embrace outsourcing in their operations. Furthermore, outsourcing is process in which a company contract with another company to manage service that it does not want to provide by itself. The study examined the effect of outsourcing on marginal field operations. Using literature review and case study in India, Egypt and Malaysia by marginal field operators it is observed that outsourcing has positively contributed to delivery of marginal field project. Outsourcing is beneficial because it allows companies to reduce their fixed asset costs. Outsourcing in form of alliance between indigenous and foreign companies would enhance the credibility of the indigenous companies and stimulate capacity building in terms of knowledge and technology transfer. It is recommended that for effective outsourcing there should be a clear legal frame work.

Extant literature strongly suggest that marginal oil field operators are vital to economic growth and social development. The conjecture is that marginal field operators need to be nimble and innovative in order to survive, and this form the basic premise for this study. The objective of the study is to investigate the role of innovation as one of the success factors formarginal oil field development in Niger Delta region. The study methodology involved literature review and multiple level case study of operating marginal fields which demonstrated that innovation can bring about efficiency and cost reduction. The innovation facilitates the utilization of competitiveness and cluster system to transform the marginal field development to wealth creation. The study among other recommends that the Niger Delta region should be given urgent attention for the development of comprehensive infrastructure in order to transform the marginal field development into competitive oil and gas business.

Clathrate hydrates are non-stoichiometric compounds of water and gas molecules coexisting at relatively low temperatures and high pressures. The gas molecules are trapped in cage-like structures of the water molecules by hydrogen bonds. There are several hydrate deposits in permafrost and oceanic sediments with an enormous amount of energy. The energy content of methane in hydrate reservoirs is considered to be up to 50 times that of conventional petroleum resources, with about 2,500 to 20,000 trillion m 3 of methane gas. More than 220 hydrate deposits in permafrost and oceanic sediments have been identified to date. The exploration and production of these deposits to recover the trapped methane gas could overcome the world energy challenges and create a sustainable energy future. Furthermore, global warming is a major issue facing the world at large and it is caused by greenhouse gas emissions such as carbon dioxide. As a result, researchers and organizations have proposed various methods of reducing the emission of carbon dioxide gas. One of the proposed methods is the geological storage of carbon dioxide in depleted oil and gas reservoirs, oceanic sediments, deep saline aquifers, and depleted hydrate deposits. Studies have shown that there is the possibility of methane gas production and carbon dioxide storage in hydrate reservoirs using the injection of carbon dioxide and nitrogen gas mixture. However, the conventional hydrocarbon production methods cannot be used for the hydrate reservoirs due to the nature of these reservoirs. In addition, thermal stimulation and depressurization are not effective methods for methane gas production and carbon sequestration in hydrate-bearing sediments. Therefore, the gas replacement method for methane production and carbon dioxide storage in clathrate hydrate is investigated in this paper. The research studies (experiments, modeling/simulation, and field tests) on CO 2 /N 2 gas mixture injection for the optimization of methane gas recovery in hydrate reservoirs are reviewed. It was discovered that the injection of the gas mixture enhanced the recovery process by replacing methane gas in the small and large cages of the hydrate. Also, the presence of N 2 molecules significantly increased fluid injectivity and methane recovery rate. In addition, a significant amount of free water was not released and the hydrate phase was stable during the replacement process. It is an effective method for permanent storage of carbon dioxide in the hydrate layer. However, further research studies on the effects of gas composition, particle size, and gas transport on the replacement process and swapping rate are required.

The objective is to design a control agent that will induce fluids flow orientation in a reservoir. The specific objectives are to delineate the minimum volumetric rate of the injecting fluid that will orient and control reservoir fluids flow rate and the recovery efficiency. Next estimate the maximum flooding injection rate for high oil recovery and finally predict reservoir fluids recovery efficiency. This work estimates the minimum volumetric rate of the injecting displacing fluid that will displace and control reservoir fluids flow rate and efficiency using mobility ratio. Next it estimates the maximum injection rate of the displacing agent that will recover high oil using summation of the reservoir thickness. Finally, it predicts reservoir fluids flow rates and cumulative oil recovery using unit floodable pore volume and the daily or yearly floodable volume. A cash flow model is used here to describe and compare the revenue (Recovery bill) and the costs (Capex and Opex). The result shows that it is possible to attain a floodable volumetric sweep efficiency of 70% with a corresponding recovery factor of 66% and a floodable volumetric sweep efficiency of 80 with a corresponding recovery factor of 72%, compared to scenario - C (Oil reservoir producing under water-drive and gas injection) where recovery factor is possibly 25 to 40%. Both recovery efficiency/factor depend on the summation of the volumetric floodable ratio. The novelty in this work is the development of a control agent which can increase recovery factor from 40% to 66% or 72%

Saturation logging tool is one key tool that has been successfully used in the Oil and Gas Industry. As important as the tool is, it should not be mistaken for a decision tool, rather it is a tool that aids decision making. Because the tool aids decision making, the decision process must be undertaken by interdisciplinary team of Engineers with historical knowledge of the tool and the performance trend of the candidate well and reservoir. No expertise is superior to historical data of well and reservoir performance because the duo follows physics and any deviation from it is attributable to a misnomer. The decision to re-enter a well for re-perforation or workover must be supported by historical production and reasonable science which here means that trends are sustained on continuous physics and not abrupt pulses. Any interpretation arising from saturation logging tools without subjecting same to reasonable science could result in wrong action. This paper is providing a methodology to enhance thorough screening of candidates for saturation logging operations. First is to determine if the candidate well is multilevel and historical production above critical gas rate before shut-in to screen-out liquid loading consideration. If any level is plugged below any producing level, investigate for micro-annuli leakage. All historical liquid loading wells should be flowed at rate above critical rate and logged at flow condition. Static condition logging is only good for non-liquid loading wells. The use of any tool and its interpretation must be subjective and there comes the clash between the experienced Sales Engineer and the Production/Reservoir Engineer with the historical evidence. A simple historical trending and analysis results of API gravity and BS&W were used in the failed plug case-study. Further successful investigation was done and the results of the well performance afterwards negated the interpretation arising from the saturation tool which saw the reservoir sand flushed. The lesson learnt from the well logging and interpretation shows that when a well is under any form of liquid loading, interpretation must be subjective with reasonable science and historical production trend is critical. It is recommended that when a well is under historical liquid loading rate, until the rate above the critical rate is determined, no logging should be done and when done, logging should be at flow condition and the interpretation subject to reasonable system physics.

In order to properly meet up with the ever-increasing demand for petroleum products worldwide, it has become increasingly necessary to produce oil and gas fields more economically and efficiently. Waterflooding is currently the most widely used secondary recovery method to improve oil recovery after primary depletion. A crucial component required to conduct an efficient waterflooding operation is an optimal production setting, most especially with respect to the amount of water involved. This research work has been carried out to develop a model that can be used to maximize oil recovery and minimize water production with the least amount and number of waterflood variables in order to minimize the secondary recovery investment cost. The gradient-based approach to optimize the production and net present value (NPV) from a waterflood reservoir using the flow rates or bottom hole pressures of the production wells as the controlling factors with the use of smart well technology was applied. In this approach, a variant of the optimal switching time technique was used in the optimization process to equalize the arrival times of the waterfront at multiple producers, thereby increasing the cumulative oil production. The optimization procedure involved maximizing the objective function (NPV) by adjusting a set of manipulated variables (flow rates). The optimal pressure profile of the waterflood scenario that gave the maximum NPV was obtained as the solution to the waterflood problem. The proposed optimization methodology was applied to a waterflood process carried out on a reservoir field developed by a five-spot recovery design in the Niger Delta area of Nigeria, which was used as a case study. The forward run was carried out with a commercial reservoir oil simulator. The results of the waterflood optimization revealed that an increase in the net present value of up to 9.7% and an increase in cumulative production of up to 30% from the base case could be achieved.

The largest component of operating costs in most matured assets utilizing 3 rd party evacuation infrastructure is crude handling charges. In mature fields with significant water production, water volumes could easily account for over half of crude handling costs. Produced water re-injection for disposal has become a popular strategy for optimizing liquid handling cost as well as supporting environmental responsibility. Injectivity for water disposal wells have been demonstrated to decline with time, the most common factor being permeability reduction arising mostly from fines migration, suspended and dissolved solids in injected water, microbial activities, oil in water and cation concentrations, etc. Thus, Injection wells typically require intermittent stimulation to restore or improve injectivity. Fracturing has been demonstrated to prolong injectivity. However, sustainability is greatly affected by ability to keep fractures open after shut-ins and limited by environmental regulations. Understanding the key mechanisms that lead to injectivity decline will help optimize produced water reinjection systems, enable proactive intervention planning, thus improve injectivity and well availability. In this work we present the development of an injectivity modelling and simulation tool called IDS based on relatively recent injectivity models. Testing and validation of the tool using standard data and an active onshore Niger-Delta Produced Water Reinjection Project as a case study are presented. An outstanding feature of this simulator is its ability to estimate missing parameters or those whose values are not known to high fidelity via history matching. The resulting nonlinear regression problem is solved using a trust-region reflective approach. Decline mechanism regression parameters were similar for a well that had multiple injection periods. Transition time from deep bed to external cake is very sensitive to Total Suspended Solids (TSS) in injected water. Injectivity half-life could increase by as much as 100% for about a 100% drop in mean TSS concentration. The IDS tool was used to predict the injectivity half-life of Well A in the water disposal project.

Proper understanding of reservoir producing mechanism forms a backbone for optimal fluid recovery in any reservoir. Such an understanding is usually fostered by a detailed petrophysical evaluation, structural interpretation, geological description and modelling as well as production performance assessment prior to history matching and reservoir simulation. In this study, gravity drainage mechanism was identified as the primary force for production in reservoir X located in Niger Delta province and this required proper model calibration using variation of vertical anisotropic ratio based on identified facies as against a single value method which does not capture heterogeneity properly. Using structural maps generated from interpretation of seismic data, and other petrophysical parameters from available well logs and core data such as porosity, permeability and facies description based on environment of deposition, a geological model capturing the structural dips, facies distribution and well locations was built. Dynamic modeling was conducted on the base case model and also on the low and high case conceptual models to capture different structural dips of the reservoir. The result from history matching of the base case model reveals that variation of vertical anisotropic ratio (i.e. kv/kh) based on identified facies across the system is more effective in capturing heterogeneity than using a deterministic value that is more popular. In addition, gas segregated fastest in the high case model with the steepest dip compared to the base and low case models. An improved dynamic model saturation match was achieved in line with the geological description and the observed reservoir performance. Quick wins scenarios were identified and this led to an additional reserve yield of over 1MMSTB. Therefore, structural control, facies type, reservoir thickness and nature of oil volatility are key forces driving the gravity drainage mechanism.

Production ramp-up can be a tricky exercise, with a repertoire of challenges and surprises, which can threaten the proposed percentage of success. These challenges largely stem from paucity of data, change in reservoir dynamics, impact of unauthorized third-party activities and the compliment of skill sets/experience in the team. In addition, reservoir models are in some cases, ineffective tools for reservoir management and prediction. This is especially true in assets that are heavily bunkered by crude oil thieves and in geologically complex reservoirs with very few wells. Therefore, models must be updated with recent data and new understanding, to remain useful and accurate. Of great importance to a successful production ramp-up effort is assembling an integrated team of experienced sub-surface professionals and field executors. Unfortunately, in some teams and companies, the position and opinions of Geologists are often overlooked, resulting in mixed outcomes. Geologists do not only think in "millions of years" but can add value and contribute significantly to the overall project objective. This paper explores and explains the role of a geologist, as part of an integrated asset management team, in the successful ramp-up of production from 45KOPD to about 80KOPD, without drilling a single well or executing any rig activity. It also showcases some work methodologies adopted in the evaluation of candidate wells and the power inherent in adopting an integrated subsurface approach.

A water injector pilot well - Ughelli East-30, was drilled across high-permeability unconsolidated sandstone aquifers to dispose 30 Mbwpd of produced water in November 1998 and suspended in December 1998 due to lack of injectivity. Review of the failed pilot injection was performed as part of an extensive water management study for a cluster of onshore fields located in the western Niger Delta area. The technical investigation focused on the target disposal aquifer petrophysical parameters, produced water composition analysis, well completion design and injection performance result. Potential impairment mechanisms and failure risk factors for injectors with similar cased-hole, perforated completion design in analogue reservoirs were also investigated. The poor well injectivity performance was attributed to sub-optimal sand control completion design and the ‘water hammer’ effect which resulted in massive sand fill as evidenced by a sand bailing exercise during November 1999 riglessre-entry in the well. The 17-ft rat hole below the bottom aquifer sand perforations was also deemed to be inadequate for the sand fill which apparently bridged the perforations. Optimal completion requirements to prevent water injection failure in unconsolidated sandstone formation has been brought to the fore in this paper which is expected to steer engineers focus to those factors with high impact on water injection system performance.

The world is fast changing and so is the energy mix. A global clarion call by scientists inspires an immediate action to circumvent the visible effects of climate change or face the damning consequences in the coming few years. Scientists and environmental lobbyist are campaigning against the consumption of fossil-based fuel and mounting more and more pressure on the international financial bodies including calling on government around the world to refrain from further financing of fossil fuel projects. This is surprisingly gathering momentum on regular basis, thereby posing existential threat to third-world oil producers, which are largely dependent on royalties and tax revenues from crude oil and other natural resources in order to sustain their economies. The future trends warn of a looming dooms day when these remaining reserves may no longer be able to attract the requisite funding necessary to develop them, let alone explore them. Besides Niger Delta, most other petroleum basins in Nigeria are highly under-explored but presumed to have significant hydrocarbon resources, albeit mainly gas. For that reason, these basins and their resources do not yet count in the nation's wealth of booked resources. It is believed the country can also benefit from significant amounts of oil discoveries that are invisible to conventional technologies or intentionally bypassed in natural recovery methods. These could present less costly alternatives to uplift the nation's reserves booking and in so doing minimize uncertainty involved in deep water or frontier explorations. Nigeria should therefore aim to ramp up its capital investment to boost oil & gas production in the next couple of years so as to harness th abundant discovered resources whilst there is still time to do so. To take advantage of Nigeria's vast portfolio of hydrocarbon resources, the nation must explore strategic policies aimed to enhancing exploration and production interests while simultaneously expanding other value chains and promoting the investment in alternative or renewable energy. It must expediently exploit the remaining reserves so as to make the most of what it has. Then the wind fall from that exploitation can be ploughed back into the economy to facilitate the implementation of large-scale alternative energy projects as it plans to eventually substitute the fossil fuel energy. This paper presents some thought-provoking but radical ideas of how this can be achieved in the near term.

This paper examines an optimized strategy and approach for executing a marginal field re-entry in the face of harsh global economic realities in the oil and gas sector. With dwindling and depressing oil prices driven by demand & supply volatility with root causes traceable to some factors such as the prevalent health pandemic, clamor for green energy, climate change discussions, geopolitics etc, the operating model for oil companies will need to drastically change to reflect current realities. Due to rapid global urbanization and increasing population amongst other factors, there is a corresponding huge appetite for oil to meet energy demands. This has led to exploration in unconventional terrains, utilization of the full extent of primary and secondary recovery mechanisms to attain high RFs in already producing fields and in some extreme cases, the development of marginal fields. In the Niger Delta area of Nigeria, marginal fields usually given up by Oil majors or abandoned following production exigencies and government laws are acquired and operated by indeginous companies. These indigenous players look for the most cost-effective means to produce these assets as it becomes the only way to make profit. A case study for field re-entry in the Niger Delta, which emphasized relatively/comparatively reduced capital outlay dependent on the technical approach is examined. Lessons learnt are drawn to aid enlightened go-forward actions and that will ensure a go-to template for similar future marginal field re-entry projects.

Enhanced oil recovery has been gaining relevance over the years following success stories from already executed projects from various parts of the globe. The recoveries from such successful projects have tremendously increased the terminal life cycle recoveries from the subject reservoirs and subsequently the project Net Present Value and Value to Investment Ratio. More than 90% of Field Development Plans in the Niger Delta have not considered Enhanced Recovery Mechanism as part of the field development options and as such Top Quartile Recovery Factors are never achieved. In this study, the effectiveness of Enhanced Oil Recovery within the Niger-Delta reservoir sands via 3-Dimentional Dynamic Simulation, Economic models and Experimental investigations (temperature and pressure effects on polymer effectiveness) was done. The GN7000 reservoir was used as a case study for this work. This reservoir is the largest gas cap reservoir in the N-Onshore field within the Niger Delta area and it is at the mid-life stage. This study tested the effectiveness of three Recovery mechanisms (Water Flood, Polymer Flood and Polymer Alternating Gas). Simulated and Experimental result suggests that Polymer flooding and Polymer Alternating Gas (PAG) yields greater Technical Ultimate Recovery, better economic indices but greater complexity in polymer selection due to inherent high reservoir temperature and low salinity that make the use of synthetic polymers inadequate. Experimental investigation showed that biopolymers are most suitable for this sand. The suitability of some biopolymers (Xanthan and copolymers containing high level of 2-acrylamido2-methyl propane sulfonate (AMPS) showed good results. Study results shows that with the deployment of biopolymers with high viscosifying power and high resistance to thermal degradation an incremental recovery of 8% from the natural flow could be achieved. Research findings indicate that biopolymers could yield good results for Niger Delta sands within the pressure and temperature ranges of 93°C and 290 Bar.

Ineffective methods of increasing oil recovery have been one of the challenges, whose solutions are constantly sought after in the oil and gas industry as the number of under-produced reservoirs increases daily. Water injection is the most extended technology to increase oil recovery, although excessive water production can pose huge damage ranging from the loss of the well to an increase in cost and capital investment requirement of surface facilities to handle the produced water. To mitigate these challenges and encourage the utilization of local contents, locally produced polymers were used in polymer flooding as an Enhanced Oil Recovery approach to increase the viscosity of the injected fluids for better profile control and reduce cost when compared with foreign polymers as floppan. Hence this experimental research was geared towards increasing the efficiency of oil displacement in sandstone reservoirs using locally sourced polymers in Nigeria and also compared the various polymers for optimum efficiency. Starch, Ewedu, and Gum Arabic were used in flooding an already obtained core samples and comparative analysis of this shows that starch yielded the highest recovery due to higher viscosity value as compared to Ewedu with the lowest mobility ratio to Gum Arabic. Finally, the concentration of Starch or Gum Arabic should be increased for optimum recovery.

Produced water reinjection (PWRI) is one of the methods employed by oilfield operators to optimize production while conforming to increasingly stringent produced water disposal policies. Different produced water species from different facilities also have different salinities as a result of entrainment of treatment fluids, precipitation of salts at surface conditions, etc. During re-injection operations, the salinity of the injection fluid has to be accounted for as it affects the production. Previous studies have focused on laboratory analysis by core flooding. While this approach is indeed reasonable and offers a first-hand impression of the reservoir conditions, it presents a problem of cost and the age-old opinion that the core sample may not be representative of the entire reservoir. Therefore, I have employed a computer modeling approach using a commercial simulator to analyze the influence of salinity on production during produced water re-injection. It was found that the salinity truly affects production. Re-injection of produced water with salinity equal to the reservoir salinity of 1000 ppm was compared to three cases of re-injection of produced water from extraneous sources having salinities of 100 ppm, 500 ppm and 10000 ppm. It was found that salinity of 10000 ppm gave the best oil production performance for the reservoir model; a daily rate of 40 STB/DAY and an oil cumulative production of 40,000 STB. Incremental salinity of injected produced water led to incremental oil recovery. The mechanism resulting in incremental recovery was attributed to the increase in viscosity and decrease in mobility as the salinity increases.

After the primary and secondary oil recoveries, a substantial amount of oil is left in the reservoir which can be recovered by tertiary methods like the Alkaline-Surfactant Flood. Reasons for having some unproduced hydrocarbon in the reservoir include and not limited to the following; forces of attraction fluid contacts, low permeability, high viscous fluid, poor swept efficiency, etc. Although, it is possible to commence waterflooding together chemical injection at the start of production. Reservoir simulation with commercial simulator, could guide in selecting the most appropriate period to commence chemical flooding. In this study, the performance of a new synthetic surfactant produced from Jatropha Curcas seed was compared with that of a selected commercial surfactant in the presence of an alkaline and this shows that the non-edible Jatropha oil is a natural, inexpensive and a renewable source of energy for the production of anionic surfactants and a good substitute for commercial surfactants like Sodium Dodecyl Sulphate (SDS). The Methyl Ester Sulfonate (MES) surfactant showed no precipitation or cloudiness during stability test and was able to reduce the Interfacial Tension (IFT) to 0.018 mN/m and 0.020 mN/m in the presence of sodium carbonate and sodium hydroxide respectively as alkaline at low surfactant concentration. The optimum alkaline surfactant formulation in terms of oil recovery performance obtained from the core flooding experiment corresponds to a concentration of sodium carbonate (0.5wt%), sodium hydroxide (0.5wt%) mixed in distilled water and Methyl Ester Sulfonate (MES) surfactant (1wt%). The injection of 0.5 percentage volume of alkaline surfactant slug produced an incremental oil recovery of 26.7% and 29% respectively. With these incremental oil recoveries, increasing demand for hydrocarbons product could be met, and returns on investment portfolio will be improved.

Previous studies on smart water effects have suggested wettability alteration as the most significant mechanism for additional oil recovery during smart water injection. Though many other mechanisms have been observed and proposed in several other studies, much more attention is paid to the detachment of oil films from rock surfaces. It is, however, clear from prevailing understanding that the activities at oil/brine interfaces might require as much attention as given to the brine/rock interfaces. This paper presents diffuse double layer surface complexation modelling of the adsorption of potential determining (Ca 2+ , Mg 2+ and SO 4 2- ) ions on oil carboxylic and carbonate surfaces. Surface complexation models are developed by defining the adsorption sites, surface area and mass of the oil and carbonate surfaces. The chemical reactions involving the surface sites and five different brine solutions are also defined. The brine solutions include formation water, sea water, sea water diluted 20 and 50 times, and sea water with four times SO 4 2- concentration. The amount of the divalent ions adsorbed at pH range of 5 to 8 are determined after the reactions had reached equilibrium. Adsorption of the ions on oil carboxylic and carbonate surfaces at elevated temperature for the sea water is also investigated. Results show that significant number of divalent ions are collected at the oil/brine interfaces just as adsorbed at the brine/rock interfaces. The results suggest that the equilibrium reactions and the dynamics at the two mathematical interfaces in any oil/brine/rock systems are equally important to reach a full understanding of the main mechanisms behind smart water effects. Therefore, the dynamics of ionic reactions at the oil/brine interface can play critical roles in defining smart water effects on residual oil mobilization.

One of the challenges of the petroleum industry is achieving maximum recovery from oil reservoirs. The natural energy of the reservoir, primary recoveries in most cases do not exceed 20%. To improve recovery, secondary recovery techniques are employed. With secondary recovery techniques such as waterflooding, an incremental recovery ranging from 15 to 25% can be achieved. Several theories and methods have been developed for predicting waterflood performance. The Dykstra-Parson technique stands as the most widely used of these methods. The authors developed a discrete, analytical solution from which the vertical coverage, water-oil ratio, cumulative oil produced, cumulative water produced and injected, and the time required for injection was determined. Reznik et al extended the work of Dykstra and Parson to include exact, analytical, continuous solutions, with explicit solutions for time, constant injection pressure, and constant overall injection rate conditions, property time, real or process time, with the assumption of piston-like displacement. This work presents a computer implementation to compare the results of the Dykstra and Parson method, and the Reznik et al extension. A user-friendly graphical user interface executable application has been developed for both methods using Python 3. The application provides an interactive GUI output for graphs and tables with the python matplotlib module, and Pandastable. The GUI was built with Tkinter and converted to an executable desktop application using Pyinstaller and the Nullsoft Scriptable Install System, to serve as a hands-on tool for petroleum engineers and the industry. The results of the program for both methods gave a close match with that obtained from the simulation performed with Flow (Open Porous Media). The results provided more insight into the underlying principles and applications of the methods.

In this paper, the enhanced oil recovery potential of the application of nanoparticles in Niger Delta water-wet reservoir rock was investigated. Core flooding experiments were conducted on the sandstone core samples at 25 °C with the applications of nanoparticles in secondary and tertiary injection modes. The oil production during flooding was used to evaluate the enhanced oil recovery potential of the nanoparticles in the reservoir rock. The results of the study showed that the application of nanoparticles in tertiary mode after the secondary formation brine flooding increased oil production by 16.19% OIIP. Also, a comparison between the oil recoveries from secondary formation brine and nanoparticles flooding showed that higher oil recovery of 81% OIIP was made with secondary nanoparticles flooding against 57% OIIP made with formation brine flooding. Finally, better oil recovery of 7.67% OIIP was achieved with secondary application of nanoparticles relative to the tertiary application of formation brine and nanoparticles flooding. The results of this study are significant for the design of the application of nanoparticles in Niger Delta reservoirs.