bluuebunny/crossref_metadata_2025 huggingface dataset:
Cost Effective Approach for the Recertification of Open-Water Intervention Riser Systems in Nigeria using Asset Integrity Management Tools
Authors: Ademoyegun Adedayo C. , Andrawus Jesse , McCullagh Cathy
Published: July 2023

This paper details the risk-based approach to optimize the recertification cost of Open-water intervention riser systems (OWIRS) in Nigeria. The recertification of Open-water intervention riser systems (OWIRS) is a conservative maintenance program that occurs every fifth year according to recommended practice and client requirements (1) (2) (3).

Reliability and Integrity assurance are critical during any intervention activity because a runaway failure effect could escalate to an unwanted event, potentially impacting HSE, cost, and even reputation (4).

The recertification of the Open-water intervention riser systems (OWIRS) has always been a capital-intensive activity due to the conventional approach deployed by various organizations resulting in a long period of asset unavailability and high cost. Although some notable recommended practices (1) (3) provide guidance but the approach for execution remains with the stakeholders. Due to the current Russia-Ukraine War and continuous drive to stay agile and lean for the removal of wastages, this paper has reviewed the cost element of typical recertification, adopted the hybrid technique comprising Failure Mode, Effect and Criticality Analysis (FMECA), and Reliability Centered Maintenance (RCM) decision tree (5) to develop a cost-effective approach to recertification for OWIRS.

The results showed that specific and value-focused scopes driven through the aggregation of maintenance strategies are efficient. Engrafting an established and critical recertification maintenance scope into existing maintenance programs on Computerized Maintenance Management System (CMMS) that is driven more by a condition-based approach, condition monitoring and proactive tasks from lessons learned from field non-conformances reports and corrective actions provided a significant reduction to waste generated during the planning and execution of recertification project. The integration of recertification as part of the maintenance program is a pathway to saving great cost values of recertification whilst ensuring asset availability and Integrity (4).
Green Technological Approach for Sustainable Operations of Oil and Gas Industry
Authors: Oruwari Humphrey Otombosoba
Published: July 2023

Green technology encompasses evolving group of methods and materials for the production of essential nontoxic products by oil and gas operators. Oil and gas are very important drivers for job creation and a pillar of economic growth in many oil and gas producing countries. They play a prominent role in the development of the developing countries in terms of creating employment opportunities. The oil and gas companies also generate waste and pollution from their practices and businesses because of their informal nature, lack of adequate regulation and supervision. The pollution produced by the oil and gas has contributed immensely to the global warming and natural resource depletion leading to many econonmic, environmental and social problems from climate change to local waste. The methodological framework for the study involved the use of literature review and document analysis. The study articulated the contribution of green technologies to sustainable development of oil and gas. Advantages and disadvantages of eco-friendly technology, policy requirement for oil and gas development and eco-friendly small business ideas are discussed extensively. It highlights some of the benefits of green technology such as drastic reduction in waste and pollution, high level job creation, reduction in the effect of global warming and less material requirements. It also outlines the environmental and economic sustainability of green technology. The study advocates for collaborative effort of government, industries, and individual for its implementation.
Strategies for Decarbonizing the Oil and Gas Industries
Authors: Oruwari Humphrey Otombosoba , Itsekor Lucky
Published: July 2023

The objective of the study is to investigate the strategies for the decarbonization of the oil and gas industry. Strategies are general programmes of action with an implied commitment of emphasis and resources to achieve a basic mission. The greatest problem facing humanity is to transit from fuel-based energy system to a sustainable and decarbonized system. There is no industry with the greatest sustainability challenges than the oil and gas industry because they are known to be among the most polluting industries in the world. The research methodology involved the use of literature review and case study of some companies, data was collected and thematically analyzed. The study findings revealed that oil and gas company can decarbonize the industry by various strategies such as changing power sources, implementing improved technologies and adopting energy efficiency in their operations, flaring through improved additional gas processing and infrastructure, reducing routine flaring through improved reliability of equipment, rebalancing portfolio, the use of renewables, electrifying operations, increasing the use of carbon capture and storage. transformation of carbon dioxide into useful product for example, the use of Carbon dioxide for enhanced oil recovery. In summary it is recommended that the oil and gas industry should diversify by incorporating other forms of energy and technologies with less polluting carbon dioxide and other green gas emission to decarbonize the system. Capacity building and training of personnel is very necessary to cope with these transition strategies in order to meet the Paris climate change target.
Environmental Impact Assessment of Current Synthetic Drilling Fluids in Offshore Oil Fields Using Modified CO2 Evolution Respirometry Technique
Authors: Johnson Folayan Adewale , Dosunmu Adewale , Aleruchi Oriji Boniface
Published: July 2023

Synthetic fluid biodegradation test is one of the essential requirements by environmental regulatory agencies before an approval for offshore cuttings disposal can be granted.

In this study, the aerobic biodegradation tendencies of two industry grade, deep-water synthetic hydrocarbon-based fluids (SHBF and SEBF) were investigated using modified carbon-IV-oxide (CO2) evolution respirometry technique. The results were compared with an ester synthetic fluid that was code-named as ternary mixture of synthetic ethyl esters of plants oil (SEEP-Mixture). A known concentration of the test drilling fluids and reference chemicals was inoculated in a mineral medium, pre-conditioned and incubated by the passage of CO2 free air under aerobic condition in the dark for a period of twenty-eight (28) days at the test temperature of 58°C± 2°C in an aerobic digester. The amount of CO2 evolved from the exhaust air of each composting vessel at intermediate time intervals was measured as dissolved inorganic carbon (DIC) by absorption in Ba (OH)2 solution using titration technique. Sodium benzoate (C6H5COONa) was used as reference fluid sample. The tests were conducted under OECD and OSPAR Commission recommended standard protocols for testing chemicals in the offshore oil industry.

The SEEP mixture ester fluid and the sodium benzoate reference fluid sample are inherently and readily biodegradable because more than 60% of their theoretically available carbon IV Oxide (ThCO2) have been converted to CO2 in the presence of activated sludge inoculum during a 10-day window period with ultimate biodegradability extents of 87.60% and 89.10% respectively at the end of the 28-day test duration. Whereas, the synthetic hydrocarbon fluids have longer lag phase before biodegradation began and they were only fairly biodegradable under the aerobic microbial consortium with ultimate biodegradation values of 51.85% and 62.30% at the end of the 28-days test period for SHBF and SEBF respectively.
Maximizing Production through Optimal Wellbore Placement for Energy Accessibility and Affordability
Authors: Onyeji J. A , Olufisayo Fagbowore , Taiwo B. O , Clement Chukwuka , Eddie Agbongiator , Okorie V. N , Olugbenga Abolarin
Published: July 2023

Considering the high cost of drilling wells in recent times, with associated subsurface geological complexities, and brown fields` operating concerns. It becomes challenging on how to properly drain or recover the remaining oil in place to meet and sustain the ever-increasing demand of energy at affordable cost. This paper streamlines an innovative approach applied to delineate the sweetest spot in a target reservoir through optimal wellbore placement and improved production. Methodology deployed involved looking beyond the bright spot in the seismic volume, with a deep dive into petrophysical parameters of the existing wells, reservoir characterization, utilizing high resolution sequence stratigraphical approach, static modeling and reservoir simulation. The systematic approach utilized aided in delineating the rock properties quality of different regions of the reservoir. After a series of sensitivity tests, a lateral length of 1200 feet was selected to accommodate identified structural and drillability constraints. #-82h wellbore was placed at the sweetest portion of the reservoir. The well production performance has been consistent with over 1,700 barrels of oil per day (BOPD) over the past two years. Lessons learned: optimal well placement in the sweet spot of the target reservoir was guided by lithofacies analysis and reliable dynamic modeling. This remains valuable for reservoir management, maximizing reserves to production. One team approach also aided the timely attainment of the project objectives. The best practice would be to integrate reliable datasets, such as pressure information, fluid rates, well logs, 3D/4D seismic volumes and attributes, to generate representative geologic and simulation models that best depict and predict subsurface ‘architectural` behaviours.
Modelling System Failure of a Typical Hydraulic Power Unit within a Subsea Production Control System
Authors: Slimane S. Ben , Andrawus J. , Iyalla I.
Published: July 2023

Hydraulic Power Unit (HPU) is one of the critical subsystems of a Subsea Production Control System (SPCS). HPU is designed to supply clean and regulated control fluid to remotely operate subsea valves. Failures of HPU can potentially lead to loss of control of subsea valves which are often designed to fail-safe. This automatic production shutdown disrupts normal operation with significant downtime cost. Therefore, optimising HPU's performance is critical to maximising production availability. Modelling System Failures (MSF) is a quantitative maintenance optimisation technique. It aims at determining optimum maintenance requirements by investigating equipment failure patterns. MSF helps select the most efficient and cost-effective maintenance strategy. Failure and maintenance data are collected then analysed. MSF permits the creation and simulation of a system's model to set optimum maintenance tasks.

A typical HPU was analysed using MSF methodology. Generic failure rates of HPU components were extracted from the Offshore and Onshore Reliability Data (OREDA) Handbook. HPU Reliability, Availability and Maintainability (RAM) model was designed using ReliaSoft software packages. The designed model was simulated over a period of 25 years design life of a typical HPU. Appropriate maintenance tasks were determined based on the failure characteristics of the HPU. Mean Availability increased from 97.01% to 99.56%. System uptime increased from 24.25 years (212,441.61 hours) to 24.89 years (218,036.81 hrs) and downtime decreased from 0.75 years (6,558.39 hours) to 0.11 years (963.19 hrs).
Modeling the Oil Viscosity of Nigerian Crudes Using Machine Learning
Authors: Adeeyo Y. A. , Osinaike A. A.
Published: July 2023

Oil viscosity is an important parameter for estimating the flow behavior of crude oil under varying pressure and temperature regimes encountered in the subsurface and surface components of the petroleum production system. Although experimental data provides the most accurate characterization of this property, obtaining such data in the laboratory is often time-consuming and expensive. Alternatively, one of several empirical correlations can be used, albeit with often poor generalization to samples from differing thermodynamic systems or crude oil types.

In this paper, we use a data-driven approach based on machine learning (ML) algorithms to create high-performing models for predicting the dead oil and bubblepoint oil viscosity of Nigerian crudes. Random Forest (RF) and Gradient Boosting (GB) ensembles, as well as Multi-Layer Perceptron (MLP) and Radial Basis Function (RBF) networks, are compared to several widely used correlations, and their performance is evaluated on a large dataset of crude oil samples collected from various Niger Delta oil fields. The ML models are built with minimal and easily accessible input parameters shared by the correlations, allowing for an objective assessment of their superiority to these correlations given the same input framework. These are reservoir temperature and oil API gravity for the dead oil viscosity modeling, and the solution gas-oil ratio and dead oil viscosity for the bubblepoint oil viscosity modeling. Furthermore, the model's reliability is tested by partitioning the dataset into training, validating, and testing sets, and optimal model configurations are achieved through Bayesian Optimization.

On the dead oil viscosity modeling task, we achieve a modest improvement over the best-performing correlation developed by Al-Khafaji (1987). The RF model's R2 and mean absolute error (MAE) scores on the testing data are 0.831 and 3.423, respectively, versus 0.809 and 4.439 for the correlation method. However, for the bubblepoint oil viscosity modeling, the improvement recorded using the RF model over the best-performing correlation developed by Beggs and Robinson (1975) is remarkable. In this case, the R2 and MAE scores for the RF model are 0.924 and 0.441, respectively, compared to 0.574 and 0.813 for the correlation method. As a result, our ML models have outperformed conventional correlations for modeling oil viscosity.

Ultimately, oil viscosity estimates from the developed ML models can provide a much more accurate characterization of the fluid behavior of Niger Delta crudes than the conventional correlations can. Furthermore, the ML models allow for continuous improvement of their generalization ability by introducing new data from various sources to the models.
Reservoir Characterization for Co2 Sequestration and Co2-Enhanced Oil Recovery Techniques in Maje Field, Offshore Niger-Delta, Nigeria.
Authors: Agunbiade T. O. , Oluwadare O. A. , Amusan R. O.
Published: July 2023

The oil and gas industry is a significant contributor to carbon dioxide (CO2) emissions, which have a major impact on climate change. Geoscientists in the industry play a crucial role in mitigating climate change by identifying and evaluating potential CO2 storage sites, monitoring CO2 behavior after injection, and exploring CO2 enhanced oil recovery (EOR) techniques. CO2 -EOR involves injecting CO2 into depleted oil reservoirs to increase oil production. Reservoir characterization using well log and seismic data analysis helps determine storage capacity, containment, and injectivity of reservoirs for CO2 sequestration and EOR. In this study, two sand reservoirs (RES 1 and RES 2) were analyzed, with RES 2 being considered more suitable for CO2 sequestration and CO2 -EOR. The estimated storage capacity of the study area was approximately 40 million metric tons (MT). Assessments of fault sealing capacity and reservoir properties were conducted to validate storage potential. Further investigations and analysis by experts in different fields are necessary. The interpretation of seismic and well log data aids in generating geological and structural models, which provide necessary information for designing injection and production wells and analyzing the compatibility of CO2 -EOR techniques with the reservoir. Direct Air Capture and Rejection (DACR) technology is also highlighted as a beneficial carbon capture solution for developing countries like Nigeria, as it can help reduce carbon emissions from oil and gas operations while enhancing oil recovery in characterized reservoirs.
Enhancing Natural Gas Plant in Niger Delta Region: Using Wireless Sensor
Authors: Oruwari Humphrey Otombosoba , Oruwari Raymond Odum
Published: July 2023

This study evaluates designing and simulating wireless sensor network as a solution to enhance the operations of natural gas plant in a metering station in Niger Delta region. There are several problems in natural gas plants ranging from hydrate formation, condensate carryover to customer's facility, low equipment availability and so on. All the problems enumerated were due to inability of some units of the plant not linked online nor on Realtime basis. To solve these problems requires the use of transmitter to route process parameters in the respective plant units to the control room and display such parameters for online monitoring. As such, there are two basic options. Either the use of wired transmitters or wireless transmitters. Both technologies are great but considering the prevailing circumstances of an existing old gas plant in Niger Delta region, the cost of excavation to lay fresh signal cable will be relatively high. Hence, the choice of wireless transmitters was chosen. The methodology involved using literature review and case study of existing metering station gas plant in Niger Delta. The literature reviewed involved wired sensors network, wireless sensor network, and application of wireless sensor network. There was also comparison between wired fieldbuses, wireless network technologies and wired versus wireless fieldbuses. Matlab software was used to design wireless sensor network. The Matlab code was written such that it can read data from Microsoft Excel sheet into the program for analysis and simulation. K-means algorithm was used to cluster the sensor nodes data and determine the centroids of the clusters. The program when run will create sink node matrix, concatenate the cluster centroid, and sink matrices. The results of the software simulation and discussion show that the proposed wireless sensor network if implemented will solve the identified problems and therefore, enhanced the operations of the gas plant in the metering station.
Uncertainty Management for Well Planning and Execution; Case Study of New Drills in Tom Boy Field in the Swamp Niger Delta
Authors: Taiwo B. O. , Igiri T. Z. , Onyeji J. A. , Ohenhen Oduware , Olufisayo Fagbowore , Zen F. A. , Ayodele Asaolu , Aluba Oragwu , Clement Chukwuka
Published: July 2023

The Tom Boy field is one of the oldest fields in the Niger Delta Basin with more than 30 wells at the time of initiating infill development drilling campaign. The drilling campaign of 11 wells (10 producers and 1 Water Source) was planned to develop reservoirs that have not been produced and to optimize production from developed reservoirs. Numerous challenges were faced in the planning and execution phases for the infill drilling. Key uncertainties include, Structure, Stratigraphy, wellbore placement issues, current fluid saturation/contacts in the reservoirs, and wellbore instability issues as wells drilled through pressure-depleted reservoirs. Thus, this paper addressed how these uncertainties were managed during planning and execution of the drilling program.

Through integration of detailed Uncertainty Management Plan (UMP) during execution, the team eliminated the need for drilling pilot well in an instance; and in another scenario, successfully landed a horizontal well in a 10ft thick sand. The methodology used include deployment of improved technologies, proper planning, appropriate mud-weight design, history matched reservoir models, optimizing subsurface target locations for data acquisition and proper well sequencing on the drilling schedule was used to understand the current saturation in some target reservoirs and target the sweet spot in the reservoir. Pre-execution decision tree assisted with making quick real time decisions while drilling the landing and lateral hole sections based on the outcome of each uncertainty identified in the UMP signpost. Decision tree incorporated all information (earth model, seismic data, dips, local pre-drill model etc.) integrated with potential outcomes from real-time reservoir navigation data obtained from geosteering tools to aid well placement in an optimal position within clean sand. All wells were successfully drilled and completed in the sweet spot of target reservoirs to meet pre-drill production targets.
Successful Applications of a New Sand Screen Technology to Mitigate Water Injection Challenges, A Case Study for X Field, Nigeria
Authors: Ngerebara Justus , Alawode Olusiji , Hamzat Ismail , Wilson Ross , Anderson James , Moradi Mojtaba , Emifoniye Ejiro , Ugbor Ifeanyi , Okonkwo Ngozi
Published: July 2023

A number of techniques have been applied to improve the integrity and therefore long-term performance of injection wells to eventually enhance oil recovery in one of the fields in Nigeria.

Comprehensive data analysis suggested formation solids due to the phenomena of water hammer, backflow and crossflow are major integrity problems in several injection wells in the targeted field, especially with fines migration and accumulation inside the lower completion during sudden or prolonged well shut-in. Formation solids are normally resident in the reservoir during the steady injection but can be mobilized into the wellbore during sudden shut-ins due to powerful transient flow effects such as water Hammer, cross flow and backflow. This would result in high bottom hole injection pressure (BHIP), diminished or loss of injectivity, screen plugging and erosion of downhole equipment which may lead to the inability to maintain pressure support to pair producer. Therefore, an intervention, remediation, side-track or loss of wellbore may be deemed inevitable. Application of other technologies has proven unsuccessful in these wells for various reasons.

A new sand control technology specifically developed for such projects was chosen as the best option among all available alternatives based on a matrix of requirements for the new campaign. This technology which would be installed on the closest point to the sandface was chosen as it isolates the reservoir from wellbore during well shut in, constitute no obstruction to Intervention tools, provides full access to the lower completion sand face during injection and/or intervention without restriction or pressure drop, withstands well conditions for the entire well life, is compatible with SAS, GP completions and direct wrap or metal mesh screens and it is a low CAPEX solution compared to other alternatives.

Rigorous compatibility tests and practices including modelling, backflow, cross flow, erosion and plugging tests were performed to ensure that well completions and operations requirements were met for field X. The results from all studies were positive and successful and therefore the technology was approved to be installed in the wells.

The NRV technology has already been installed in 3 wells to date. In this paper, the pre-qualification studies, the full qualification test results and post-installation well performance would be discussed. Also, the lesson learnt from these installations will be shared.

The wells’ performance data shows that this completion technology has successfully delivered the target rate and desired performance so far and provided the field X team with a robust solution to mitigate the common issues with the injection wells while avoiding costly interventions.
Optimizing the Take-Off Valve Opening of a Self-Lift By-Pass Conduit: A Novel Approach to Severe Slugging Mitigation in Offshore Pipeline-Riser Systems
Authors: Okereke Ndubuisi Uchechukwu , Kara Fuat , Iloani Marcel , Okalla Christian , Kerunwa Anthony , Ogazi Isaac , Elendu Emmanuel , Mcphilemon Chijioke , Udeagbara Stephen Gekwu , Nwogu Ngozi Claribel , Nwanwe Chibuzo
Published: July 2023

Previous numerical simulation studies, suggests that active optimization of the take-off valve on a by-pass pipe connected to a pipeline-riser system, is critical to the effective deployment of the self-lift severe slugging mitigation technique. Hence, there are recommendations for further experimental studies on the effective deployment of the self-lift severe slugging mitigation approach. Generally, severe slugging has adverse effect on multiphase flow transportation along the pipeline-riser system, with a potential 50% drop in production.

Industry mostly relies on gas-lift, topsides choking and aggregation of high pressure wells as a means to manage severe slugging for typical deepwater oil fields. However, these methods have key disadvantages such as high volume of gas required for compression to mitigate severe slugging via gas-lift and the drop in production associated with topsides choking as a result of topsides choking being mainly effective at low valve opening.

This study investigated the deployment of self-lift severe slugging mitigation technique via a 4 feet × 7 feet pipeline-riser section, consisting of a 2 inches by-pass pipe diameter, with the take-off valve designed to operate in such a manner as to tap-off associated gas via the valve and injected via the injection valve until it is able to break liquid slugs within the riser column.

The results obtained from this experimental study indicated that severe slugging was better mitigated at between 50% - 70% valve opening of the take-off valve, while the injection valve was set at 50% valve opening, to compress air flowing as part of associated gas increased by 20%. Mitigation of severe slugging was observed with flow stabilization of the intermittent fluctuation at the outlet nozzle at the topsides of the riser section, which was set at about 30% opening. The results further revealed that self-lift could be adapted to mitigate slugging in a pipeline-riser section and also possibly deployed offshore.
Using Artificial Neural Network to Predict Gas Flare Volume, Gas Composition, and Temperature from Gaseous Emission.
Authors: Omion O. O. , Dosunmu A.
Published: July 2023

Gas emission from gas flaring is known to have deleterious effects on the environment and they constitute a major source of global warming. Flare gas volume, temperature, gas composition and other meteorological factors are major parameters in gas flaring processes. Using Artificial Neural Network, a model was developed to estimate gas flare volume, gas composition and flare temperature from gaseous pollutants using. Data used for the study were from oil prolific Niger-Delta region of Nigeria. Air quality index parameter, gas flared volume, temperature and composition between 2013-2017 were used in developing the ANN model using the Neural Training toolbox (nntool) of the Matrix Laboratory (R2019a MATLAB) mathematical software. An 8-6-3 network architecture was adopted. It consists of eight input parameters (suspended particulate matter, carbon monoxide, sulphur oxide, nitrogen oxide, volatile organic compounds, hydrogen sulphide, methane, and ammonia), six hidden layers and three output parameters (gas flared volume, gas composition and temperature) using 1286 dataset for each input and output parameter. Multiple-input multiple-output (MIMO) neural network using supervised learning algorithm (Levenberg-Marquardt) to train the network was adopted in model development. 75% (880 data points) of the data was set aside for the training of the model at its developmental stage, 10% for test data set and 15% for the validation data set. From the models’ prediction, it was observed that the developed model predicted excellently and performed well when tested with new set of data which was not a part of the developmental dataset with a coefficient of determination of 0.99999918, a root mean square error of 0.009029, an absolute average percentage relative error of 0.0362% for Gas Flare Volume, Composition and Temperature respectively. The outcome of this study presents a reliable and speedy tool for forecasting of gas flare volume, composition, and temperature in the absence of conventional methodologies.
An Integrated Approach for the Geologic Model Construction of a Miocene Turbidite Reservoir in the Akpo Field, Niger Delta.
Authors: O Okonkwo Glory , Chizea Chukwuka , Akhajeme Emmanuel , O Olagundoye Olatunbosun , Ogwogho Momodu , Spina Vincenzo , Onyeanuna Chinedu , Uwerikowe Gabriel , Fashanu Mobolaji , Enuma Christopher
Published: July 2023

Geologic model updates especially when driven by seismic data generally help for better field understanding, and in most cases, aid the targeting of nearby undeveloped prospects or infill opportunities and robust geosteering of infill wells for efficient drainage or sweep and well recovery optimization which help to prolong field life and maximize the returns on investment of mature fields.

The Akpo V & W reservoirs case study lie in the central part of the mature Akpo field. They are characterized by laterally offset stacked turbidite channels with dense network of faults.

This work illustrates the collaborative team effort performed through the integration of geoscience and reservoir engineering data in constructing the static model of the V & W reservoirs. This new model aims to address the uncertainties and limitations of the previous model, re-evaluate the volumes in place, better represent the dynamic behavior of the reservoirs to aid history match, forecast and optimize infill well placements within undrained areas to sustain production. This will in turn, improve the recovery factor and the management of the reservoirs.

The new model incorporates new petrophysical synthesis for all development wells, re-interpreted faults, horizons and AEs on a new seismic dataset (2018 4D M3 B98), Lithofacies trends from seismic reservoir characterization study, amongst others. Structural and property modelling results with QCs shows better respect of well, seismic data/trends and facies heterogeneities; giving rise to a more robust model that meets the specified objectives.
Extending the Frontiers of Well Clean-Up Through Microemulsion Fluids-Based Technology Application
Authors: Okoro Felix , Ayodele Bunmi , Anioke Chidiebere , Okolomma Emmanuel , Ibrahim Yahaya , Joseph Victor , Mohammed Olufemi , Mietei-Ileberi Catherine
Published: July 2023

In oil & gas development projects, the target is to clean-up and put well onstream as quickly as possible. Apart from the economic benefits of early production, timely clean-up and well kick-off ensures that drill-in fluids and other materials used during drilling and completions do not create irreversible damage to the near wellbore region of the reservoir. In the FENE field there were 12 wells completed but not on production for over 20 years due to security and contractual challenges. These wells were drilled with water-based mud and left with filtered Seawater post completion. Given that the drill-in fluids, Seawater, and other materials were left in the wells for a long time, significant damage was suspected for the wells. These damage mechanisms include mud invasion, in-situ emulsion and water or emulsion blockage in the production interval.

These identified damage mechanisms meant that the 12 wells require a dedicated clean-up with an optimal recipe to remove emulsion and other damages in the near wellbore. Conventional acid stimulation was initially proposed but was not endorsed due to suspected performance inefficiency and possible fluids-fluids incompatibility that could lead to further formation damage. After a comprehensive integrated review evaluating the potential damage mechanisms, a novel solution was identified which involves the use of a high-definition remediation fluid solution "a Micro-emulsion Fluid (MEF) Based Technology" to remove identified near wellbore damage. Prior to field execution, a rigorous laboratory test was performed with fluid samples from the wells and the result indicated good near-wellbore damage removal, reservoir fluids and Seawater compatibility.

The MEF based technology has so far been successfully deployed in 9 wells (with the remaining 3 wells in plan) and has effectively removed suspected near wellbore and formation damage. The wells are currently on production with a 33% increase in performance above plan. This technical paper explains the process of candidate treatment selection, solution design, job execution, and production gains from deploying MEF based solution on these 9 wells executed till date.
A Successful Foam Assisted Gas Lift Trial in a Matured Niger Delta Field
Authors: Okoro Felix , Arochukwu Elias , Abuah Nnamdi , Marcus Imowo , Nnanna Erasmus , Onuigbo-Nweze Chy , Eke Iheanyi
Published: July 2023

In the oil and gas business, continuous production optimization and enhancement is key for optimal field management. As a field depletes, water cut increases and oil rates decline. To maintain production, there is need to deploy artificial lift systems. The onshore FENE field is a matured Niger Delta field that has been in production for over 50 years. The field has wells that produces on natural flow and on gas lift. To improve field production, often requires optimization of the limited lift gas available to the gas lifted wells.

Foam Assisted gas lift (FAGL) technology involves the downhole injection of a liquid foamer to lighten the fluid column and reduce slippage, thus improving well vertical lift performance. The foamer can be delivered downhole via a pre-installed downhole chemical injection line where available or into a lift gas stream on surface. The application is expected to increase oil production and / or decrease gas lift requirement.

In Nigeria, a field trial was successfully carried out on two wells (Well-X and Well-Y) with water cuts greater than 60% in the onshore FENE field. The foaming agent was injected along with the lift gas via the A annulus of the wells. The field trial resulted in 280 bopd incremental net oil gain and a cumulative gain of 2510 bbls of oil for well-X and 120 bopd net oil gain and a cumulative gain of 832 bbls of oil for well-Y over the trial period of 9 and 7 days for well-X and well-Y respectively. There was also a significant reduction of water cut from an average of 76% to 66% and an estimated 25 - 35% savings in lift gas consumption. This paper details the candidate wells selection criteria, modelling details, foamers qualification, trial execution and post treatment results.
Optimizing Production, Increasing Reserves and Resources; Reviving the Potential of Field A in the Niger Delta Basin
Authors: Dada Y. N. , Zen F. A. , Aina S. , Vincent P. , Ogofa M. , Adowei E. , Toumelin E.
Published: July 2023

Field A is a shallow offshore field, located in the Niger Delta Basin. It is a 2-well field which has an Original Oil In Place (OOIP) of 41 MMSTBO, Estimated Ultimate Recovery of 15.9 MMSTBO, cumulative production of about 50 percent of the EUR. Due to recent suboptimal production from a single completion, a redevelopment effort was thereby initiated, aimed at production optimization, improving the robustness of the new drill opportunity queue for the ongoing new drill development campaign, while increasing resources and reserves by leveraging more recent technology for re-evaluating previously underestimated reservoirs in the field. A detailed Reservoir Characterization (RC) and static modelling efforts concluded for 2 prioritized reservoirs indicated a base case estimate of Current Oil In Place (COIP) of 10.0 MMBO and 11.3 MMBO for reservoirs A and B. A non-rig workover (NRWO) and 2 new drills were identified with potential Estimated Ultimate Recovery of about 6.67 MMBO. A pilot well from one of the proposed new drills is aimed at proving up additional up-dip reserves in stacked reservoir intervals.

Flat spots, amplitude conformance and structural highs in untested areas present additional resource potential for the field. Early turnover of geophysical results helped in identifying key seismic angle stack to use for interpretation and amplitude analysis. Structural uncertainty away from well control, canyon edge definition in the up-dip limits of the deeper reservoirs, fluid type identification, are key uncertainties and challenges highlighted during this effort. A best practice employed in achieving timely project milestones was by using an iterative workflow approach between the project team members.
Reservoir Shear Failure Analysis: A Produced Water Disposal Case Study
Authors: Imorame. J Imonitie , Obakhena Femi , Iyowu Olakunle , Arogun Olubunmi , Amuboh Okiemute , Maxwell-Amgbaduba Sunday
Published: July 2023

Injection of water, gas, or steam, into subsurface reservoirs causes an increase in the reservoir pore pressure, with a corresponding impact on the in-situ reservoir stress state. This can lead to tensile fracturing, shear failure or a combination of complex failure mechanisms, depending on factors such as rock mechanical strength, elastic properties, pore pressure & magnitude of total stresses. Reservoir shear failure due to water injection/disposal can result in faulting or fault re-activation, which may present a containment risk if propagated into the caprock or under burden. A robust assessment of shear failure is usually challenged due to limited or unavailable geomechanical core measurements that fully assess lifecycle impact of stress and pressure changes.

This paper demonstrates a deterministic and probabilistic methodology in the assessment of formation shear failure due to water disposal, that manages the uncertainty and constraints posed by limited geomechanical data. This approach employs the Mohr-Coulomb failure criterion in evaluating the tendency for shear failure in two water-bearing reservoirs A1 and A2, identified as Produced Water Disposal/Re-injection reservoirs in X-field, a brown field Onshore Nigeria. It integrates offset LOT data, log data, formation pressure data and empirical relationships between geomechanical and petrophysical rock properties, to establish rock strength parameters, the associated uncertainties, and combining them probabilistically through Monte Carlo simulation to determine the probability of shear failure in reservoirs selected for produced water disposal.

Results indicated the key uncertain parameters impacting this assessment and also showed minimal probability of shear failure in both reservoirs; however, recommendations were provided to maintain a safe operating window and why an integrated approach to optimization is key to success.
Estimation and Sizing Analysis of Renewable Energy System
Authors: Inuwa Haruna Muhd , Abubakar Auwal Sani
Published: July 2023

The primary research objective of this study is to estimate and size a renewable energy system, focusing on a residential building in one of the 36 states of Nigeria. A comparative analysis is employed to assess the estimation, sizing, and cost-benefit analysis of an integrated renewable energy system for the XX residential building in Kano, Nigeria, in comparison to uneconomical electricity tariffs. Kano, a rapidly developing city and commercial hub, has the largest population in northern Nigeria, with over 15 million residents. The data used in this study, including market information and item costs, were obtained from an e-commerce trading company and renewable energy experts with research and field experience.

This research opens doors to identify the costs associated with installing solar energy systems in homes, thereby creating opportunities for oceanic growth. The study systematically enhances social productivity by providing uninterrupted backup power from an integrated renewable energy system. Economically, as discussed in the analysis, the costs of solar installation and maintenance are lower than the annual expenses incurred through electricity tariffs. However, it is important to note limitations within this study, such as the variability of primary and secondary data sources based on location and the projected costs of items used in the estimation and sizing analysis, which may differ across countries. Additionally, the costs of solar installation in homes are influenced by the types of loads, necessitating a comprehensive system analysis of both critical and non-critical loads to assess the economic viability and benefits of adopting an integrated renewable energy system to address the energy crisis.
Simulation Study of the Effect of Various Water Alternating Gas Injection Schemes on Recovery in a Gas Condensate Reservoir
Authors: Jakada K. , Gimba A. S. B. , Okafor I. , Nzerem P. , Abdulfatah H. K. , Oluogun M.
Published: July 2023

The volatile characteristics of gas condensate reservoirs in the phase envelope makes its temperature and pressure conditions between the critical and cricondentherm points very sensitive to perhaps only rely on one source of reservoir energy enhancement and puts enormous technical constraints on quality decision making on effective reservoir management. Non adequate oil production simulation performance interpretation for high, base and low case scenarios based on critical high quality input data is definitely the technical missing link which severely hampers effective design, development, planning, optimization and prediction of gas condensate reservoir performance. The aim of this study was to evaluate the recovery performance of a rapidly declining reservoir flow rates of a gas condensate reservoir through the water alternating gas (WAG) injection technique using the Schlumberger Eclipse simulator. Five different case scenarios were used which include cases of no-injection wells (which is the control case), gas injection, water injection, water alternating gas (for 7, 5, and 3-spot patterns) and flow rate alterations with a seven spot pattern-WAG technique. A total of 13 simulation runs were done with one control and 12 other runs with high, base and low cases. The sensitized water and gas injection rates used ranges from 12,000STB/day to 2,000STB/day and 12,000MSCF/day to 1,000MSCF/day. All results showed increase in oil flow rates with appreciable pressure response and subsequently, the viable option would be to consider in the short term water and gas injection before considering the more holistic WAG techniques in the long term. This is due to the current economic and technical constraints to boost the viability of the best choice of action. The results of these comprehensive simulation runs is a viable data bank needed for critical decision making for improved recovery from this rapidly declining condensate reservoir.
Analysis of Hydrocarbon Allocation Techniques for Natural Gas Plant Outputs
Authors: Kanshio S. , Lekia P.
Published: July 2023

Hydrocarbon commingling and the utilization of shared production and processing facilities are common practices in the oil and gas industry, serving as economic methods for field development and cost-effective gas monetization. However, the complexity of hydrocarbon commingling presents challenges in achieving accurate, traceable, and equitable allocation. This study explores patented methods, such as the differential and phase behavior model approaches, as well as established techniques like simple proportional and process modeling. Additionally, the newly developed compositional mass balance allocation method is investigated and compared against the benchmarked Unisim Utility Method.

The findings indicate that the phase behavior method exhibits larger allocation deviations, while the differential method tends to over-allocate. The plain allocation method demonstrates a reasonable alignment with the Unisim Utility Method. However, the compositional mass balance method offers precise allocation. This research concludes that the compositional mass balance method serves as a dependable approach for natural gas plant allocation, warranting further consideration as a reference method within the industry.
Evaluation of the Profitability of Marginal Field Investment Using the Fiscal Provisions in the Petroleum Industry Act (PIA) 2021
Authors: Danmadami Amina , Iyalla Ibiye , Oluyemi Gbenga , Ogolo Oghenerume , Andrawus Jesse
Published: July 2023

The passage of the petroleum industry act (PIA) 2021 in Nigeria established a new era in the petroleum sector of the country. Before the passage of the PIA 2021, marginal fields were operating using a separate fiscal arrangement that gave them special consideration. But the passage of the PIA 2021, made them operate like other fields depending on the terrain. The fiscal arrangement that governs marginal field investments is embedded in the PIA 2021. It offers marginal field operators dynamic fiscal terms that may increase their chances of survival during periods of low oil prices. This research considered the evaluation of the profitability of marginal field investments in Nigeria using the fiscal provisions in the PIA 2021. Investment in a typical marginal field in Nigeria was modeled using Excel. The fiscal terms in the PIA 2021 for marginal field investments were embedded into the economic model. The profitability of the marginal field investment was evaluated using profitability indicators such as net cash flow, net present value, government take, and internal rate of return. When the oil price was $80/bbl, the contractor's take was higher than the host government take. The contractor's and host government take when the oil price was $80/bbl were 52.40% and 47.60% respectively. While the contractor's and host government NCF when the oil price was $80/bbl were $247.52 MM and $224.816 MM respectively. This shows that the fiscal provisions for marginal field investment in the PIA 2021 are very attractive compared to other fiscal regimes in Nigeria.
Evaluation of the Ionic Liquid, 1-Butyl-1-Methylpyrrolidinium Bis(Trifluoromethylsulfonyl)imide, as a Sustainable Material for Modern Energy Devices
Authors: Kareem M. O. , Amusa H. K. , Nashef E. M.
Published: July 2023

Sustainable materials are those which satisfy the three sustainability criteria of being environmentally safe, profitable, and acceptable to society. Within a circular economy such material's societal acceptability is linked to the wider and long-term implications of its production and its durable usability, along with the assurance that it does not leave negative environmental footprints. 1-butyl-1-methyl pyrrolidinium bis(trifluoromethylsulfonyl)imide (abbreviated as BMPI) is an ionic liquid (IL), with minimal negative environmental impacts that is applied in different components of energy devices like batteries. Like other ionic liquids (ILs) it is non-volatile and non-flammable. It is additionally non-toxic and not too viscous within practical operating conditions, making it safe and suitable for use in batteries. Such batteries constitute crucial parts of renewable energy systems where they are useful for energy storage, thus enabling a practical alternative for diversifying from fossil energy sources. ILs like BMPI, comprising only ions while being in a liquid state, show superior conductivity and dielectric properties relevant for metal-ion batteries, redox-flow batteries, and even solid-state batteries. The performance of BMPI, as well as the economic viability of its utilization, is assessed by analyzing its performance in different battery systems, including "membraneless" systems, wherein it constitutes an active part of components such as capacitors, electrolytes, and ion-exchange membranes. A focused analysis of its usability and potential acceptability in the energy industry of Nigeria among others in Europe, the Middle East, and Africa (EMEA) is further presented, providing a holistic evaluation of the potential sustainability of BMPI and similar ionic liquids as components of energy devices in a circular economy.