bluuebunny/crossref_metadata_2025_split huggingface dataset:
Assessment of Aquifer Susceptibility using Artificial Intelligence: A Case Study of the Warri-Sombreiro Deposits, Niger Delta
Authors: Ojoboh Emuobosa Patience , Ochie Karen Ifeoma , Nwosu Chinedu Joseph 
Published: August 2020

Abstract
An aquifer is a very paramount aspect of the petroleum system and its susceptibility is a function of its ability to be vulnerable to factors such as contaminants, land pollution, subsidence, groundwater quality degradation due to movement of saltwater and so on. The Warri-Sombreiro deposits in the Niger Delta are characterized with unconfined aquifers as part of its petroleum system and studies have been carried out to determine the aquifer vulnerability using the Aquifer Vulnerability Index (AVI) which only considers the thickness and resistivity of the layers, hence, the susceptibility score is not entirely representative of the innate aquifer properties. The thickness and resistivity values in this study were obtained from ten (10) Vertical Electrical Sounding (VES) stations using the Schlumberger configuration. This methodology utilized a database containing the resistivity, conductivity, hydraulic resistance, longitudinal conductance and corresponding acquifer susceptibility rating of the stations. Linear transformation was used to normalize data with high deviations to values between 0.2 and 1, in a bid to prevent perturbation conditions. The transformed data was then trained using the Levenberg-Marquardt training algorithm to build a neural network that estimates the Aquifer Susceptibity Rating. The acquifer was further classified using the Acquifer Susceptibility Rating (ASR) to determine the level of susceptibility. The acquifer susceptibility map was then plotted using the RESIST software and it was determined that 25% of the area had low susceptibility with a clay overburden between 2.0m to 33.9m above the aquifer, 25% of the area had moderate susceptibility with clay overburden of 1.1m and the remaining 50% had high susceptibility and a lower clay overburden. The Neural Network model proved to be statistically efficient in the prediction of the Acquifer Susceptibility Rating as it gave a correlation coefficient of 1 and mean square error of 5.6246 × 10−24.
Geosteering in a Turbidite Lobe Deposit in Deepwater Niger Delta
Authors: Ndokwu Chidi , Okowi Victor , Brock Philip , Imomoh Victor , Amadi Kenneth , Berry Timothy , Osita Humphrey , Ozioko Raphael , Chizea Chukwuka , Agbejule Adekunle , Oteh Benneth , Olagundoye Olatunbosun , Okengwu Kingsley , Acra Jones 
Published: August 2020

Abstract
The knowledge of structural geology and depositional environment plays an important role in the success of any geosteering job. The bedding type, bedding dip and dip direction, faulting, localized folding, lateral facies change and continuity of sand bodies, sand-shale ratio of the deposits are some critical factors to consider in the planning of a geosteering job. These factors determine the predrill geosteering strategy and the real-time decision-making steps. The resolution of seismic data, the limited number of offset wells and their lack of proximity to the planned well, contribute uncertainty to the knowledge of these factors before drilling commences.
This is a case study describing the geosteering of a complex deepwater turbidite reservoir in the Niger Delta. The reservoir is a sandy lobe deposit and is faulted. The well objective was to drain the required intervals in the sand compartments and geosteering was needed to support real-time decision making by estimating the throw of major faults, determining the presence of sub-seismic faults, interpreting near-wellbore structural geology, stating the proximity of conductive boundaries and describing reservoir heterogeneity. The geosteering was successful with the trajectory draining all planned sand bodies, providing improved structural interpretation of the reservoir geology in real time and achieving over 500m of net sand.
The aim of this paper is to review the real-time decisions taken to achieve the well objective of placing a drain section in a sandy lobe deposit, describe the near-wellbore structural geology of a turbidite reservoir in the Niger Delta, and review some geological factors to consider while geosteering in deepwater Niger Delta reservoirs.
Assessing the Impact of Deep Offshore and Inland Basin Production Sharing Contract Ammendments on the Economics of Deep Offshore E&P Assets in Nigeria
Authors: Ogolo Oghenerume , Iledare Omowumi O. , Nzerem Petrus , Okafor Ikechukwu S. , Iloegbunam Emeka , Ekeoma Isaac P. 
Published: August 2020

Abstract
Nigeria recently amended the Deep Offshore and Inland Basins Act. The Act seeks to generate aditional annual revenue of over $1 billion for the government. The 2019 Law seems attractive to the government in the short run in terms of early rent extraction; on one hand, the seeminglly attractiveness of the fiscal terms in the Ammended Act, which is to expand output from investment in Nigeria deep offshore in the country is conjectural. The purpose of this paper is to evaluate the impact of the amendments to the PSC Act on value creation and addition to stake holders using systems and economic metrics that include investment earning power and discounted government take. A designed petroleum economic modeling framework applied to the fiscal terms in the new Act show a significant decrease in value addition to contractor portfolio of assets by about 25% but increases government discounted take statistics from 63.70% to 72.64% in comparison to the fiscal and contract terms in PSC 1993. The IRR and FLI obtained using the terms in the new Act were 23.66% and 0.043, respectively.
Effect of Skin Factor on a Pressure Maintenance Project
Authors: Raji Abubakar , Ogolo Oghenerume , Anochie Victor 
Published: August 2020

Abstract
The causes of low oil production from wells includes skin, low permeability and high rate of pressure depletion among other factors. Skin is a major challenge in oil production because it causes additional pressure drop around the wellbore. Hence, there is a drop in oil flow from the resevoir to surface facilities. Skin could be as a result of formation damage, poor production practices, well deviation, and poor well completion. The effect of skin is measured using skin factor which is a dimensionless parameter. A positive value of the skin factor indicates flow restriction while a negative value indicates a stimulated reservoir. Pressure maintenance is a method used to increase oil recovery from the reservoir by maintaining the reservoir pressure above the bubble point pressure of the reservoir. In this study, water injection was used as the method of pressure maintenance. The results showed that skin factor has much effect on oil production despite the pressure maintenance carried out in the reservoir; the rate of oil production was hindered depending on the value of the skin factor for the well. Oil reservoirs are more sensitive to skin despite pressure maintenance and in some scenario the skin even had a greater effect. Also, for wells in a reservoir having high skin factor, it is advisable to reduce the injection pressure and flowrate. The voidage replacement ratio should be recalculated to consider the outflow from the wells. The simulation resuts also showed that for reservoir with wells having high skin factor, pressure maintenance is very risky because this could lead to over pressure in the reservoir and when the reservoir pressure exceeds the fracture pressure of the reservoir rock, the reservoir fractures thus leading to loss of oil from the reservoir.
A Model for Predicting Elemental Sulphur Induced Permeability Damage in a Fractured Sour Gas Reservoir
Authors: Adeyemi Gbadegesin , Fadairo Adesina , Ogunkunle Temitope , Oladepo Adebowale , Alozie Amachree , Vamegh Rasouli , Kegang Ling , Oredeko Olugbenga 
Published: August 2020

Abstract
The complexity and damages that result from the precipitation and deposition of hydrogen sulfide (H2S) in the sour gas reservoirs constitute challenges during modeling of gas production and transportation from such reservoirs. During production from a fractured gas reservoir with high H2S saturation, a continuous drop in the pressure is experienced within the formation. The change in pressure generally leads to a decline in the sulphur solubility and precipitation when it reaches its critical saturation state. Sulphur deposition in the pore spaces and throats of the formation rock eventually leads to porosity and permeability damage. It becomes paramount to have a model that depicts what happens in the formation throughout the life of the reservoir and to show the damage trend of the formation as the production time increases. In this current study, Robert's Sulphur deposition model was modified to account for non-darcy flow and fracture properties in the near-wellbore region. The results show that a decrease in fracture aperture lead to a decrease in the formation permeability. It also shows that higher production rate leads to increase in rate of sulphur deposition, and conclusively fracture aperture has a severe influence on the permeability of the formation as damage done in such reservoirs due to sulphur precipitation are more severe. It is advisable to maintain pressure above the critical pressure at which sulphur precipitation is activated, in order to maximize production and not to induce additional pressure drop caused by sulphur plugging on flow conduits.
Investigating Flow Regimes in High Temperature High Pressure HPHT Gas Subsea Tieback
Authors: Maria Sheilla , Iyalla Ibiye , Okulaja Olubukola 
Published: August 2020

Abstract
Flow assurance is of significance importance in the oil and gas industry as the produced fluids are typically multiphase in nature. Multiphase flow is the flow of two or more phase in a conduit. The density and viscosity difference of the phases results in the phase separation and difference in pipe wall shear stresses for each phase. The most characteristic feature of multiphase flow is the flow regime (or flow pattern); which is the variation in the physical distribution of phase in the flow conduit. This work seeks to provide a better understanding of flow regimes in a long-distance high pressure and high temperature (HPHT) gas subsea tiebacks with a view to help predict and mitigate potential flow assurance issues. Computational fluid dynamics (CFD) using volume of fluid (VOF) model was used to identify flow regimes, analyse pressure drop and temperature for various gas to liquid concentrations and varying initial gas velocity for horizontal and vertical pipe. The results show elongated bubble, stratified smooth, stratified wavy, slug and dispersed bubble annular flow regimes for horizontal pipe, and elongated bubble, churn, slug and dispersed bubble annular flow regimes for vertical pipe. The ability to predict the expected flow regimes for a subsea tieback will enable the use of appropriate mitigation technique for potential flow assurance issues.
Experimental Studies on the Performance of Bio Based and Industrial Surfactants in Enhanced Oil Recovery
Authors: Abraham Damilola , Orodu Oyinkepreye , Efeovbokhan Vincent , Okoro Emmanuel , Ojo Temiloluwa , Keshinro Lekan 
Published: August 2020

Abstract
Surfactants are known for their unique property in lowering the interfacial tension (IFT) amid fluids injected and heavy crude oil of 22.3°API. In this present work, an original surfactant was formulated from natural oil (Castor oil) to see its use in enhanced oil recovery. The results from interfacial tension reduction by the castor oil-based surfactant were compared to that of the industrial surfactant (Methyl ester sulfonate). The IFT between the aqueous phases was measured then the effect of the surfactants was studied in core flooding experiments. The IFT was found to be reduced to as low as 12.1 mN/m using the castor-based surfactant and 12.3 mN/m using the industrial surfactant. The influence of brine concentration on IFT was also investigated. Results from core floods showed that the range of oil recovery after waterflood is in the range of 30-40% and the additional recovery from surfactant flooding in the range of 35-46%.
Using Difference Factor Thermodynamics Models in Hydrate Formation Prediction During Surface Production Well Testing
Authors: Green Igoniwari , Wami Emenike , Jimmy Dorcas 
Published: August 2020

Abstract
All oil fields under water-drive, including gas-cap and depletion reservoirs may produce some water along with oil. This co-production of water causes an additional set of challenges: corrosion, scale/salts deposition, disposal of the water itself, and gas-hydrate formation. Hydrates are ice-like solids that form when free water and natural gas combine at high pressure and low temperature. This can exist in gas and gas/condensate wells, as well as in oil wells. Hydrate formationis a very serious challenge and can result in a huge loss especially during production. It's also one of the major challenges encountered during surface production well testing and it is controlled by several factors which include thermodynamics and kinetics of the system. This study presents a thermodynamic model under operating field conditions, which centers on changes in the Langmuir constant of the guest molecule(s) which is an important parameter in the hydrate formation process. In this study, real-time production data acquisition system was used to acquire surface production well testing data such as pressure, temperature, and choke size, from a hydrate well. The acquired real-time data were used to determine the effect of the variation in choke size on Langmuir constant and therefore on hydrate formation. Evaluating the Langmuir constant for large cavity under field conditions using a generalized correlation, the Difference Factor method was developed and expanded to incorporate the choke sizes variation. The correlation shows that Langmuir constant (decreases) is inversely proportional to the choke size (increases) causing a decrease in the rate of hydrate formation. Due to an increase in choke size, Langmuir constant approaches zero, therefore the product of fugacity and Langmuir constant which is the driving force for hydrate formation approaches zero, leading to zero hydrate formation.
Best RM Practices for Managing Drilling Margin: A Deepwater Field Experience
Authors: Adegboye Phillip , Bodunde Williams , Mboto John 
Published: August 2020

Abstract
In the buildup to the drilling campaign in Agbami, the field encountered disruption in its gas injection capability due to hydrate formation in one of the gas injection manifolds. In addition to this operational challenge was a delay in the arrival of the rig. The impact of these two major issues was higher depletion in reservoir pressures in the field than originally planned, with the attendant narrow drilling margin. This narrow drilling margin posed a significant challenge to the success of the drilling campaign.
A multidisciplinary team comprising of Reservoir Engineers, Geologists, Drilling and Completion Engineers collaborated to assess the potential impact of these two issues on forthcoming drilling campaign. The team found out that the shallow reservoirs of the field were most impacted. The team then evaluated multiple options for addressing the foreseeable pressure depletion with its attendant drilling margin challenge. Leveraging the stream of downhole surveillance data from the intelligent completions in the field, reservoir simulation model was used to assess the optimal production and injection rates for the reservoirs, in addition to the priority given to the limited available gas and water for injection into the identified reservoirs that will boost pressure adequately prior to commencement of the drilling campaign. Furthermore, rig schedule optimization was carried out to align the well drill dates to those from the reservoir simulation.
This joint effort resulted in improved reservoir pressures in the shallow reservoirs that enabled safe drilling margin during the successful drilling campaign.
Maple Field Rejuvenation: A Practical and Effective Approach for Field Production Increase through Gas Lift
Authors: Kuku Abimbola , Adowei Ebikeme , Jumbo Sandison , Dada Yemi , Ajao Oyekunle , Aina Soji , Okeke Genevieve 
Published: August 2020

Abstract
Maple Field was discovered in 1965 and started production in 1968. Peak production was attained in 1979 but has since been declining due to various factors such as funding challenges, ageing infrastructure, pending waterflood for reservoir pressure maintenance and inadequate artificial lift sources which constitutes a significant challenge with many wells "pre-maturely" quitting production on low tubing head pressure (LTHP) as water cut increases and reservoir pressure declines. The main source of artificial lift in Maple Field and other Chevron JV Fields is "Gas Lift". The Gas Lift capability in the Maple field is essentially based on an unconventional approach of using highly pressured wells with high gas to oil ratio (GOR) to serve as "gas source" wells to gas lift producing wells that have vertical lift performance challenges. It should be noted that this methodology constitutes a "fortuitous" scenario at best given that the gas source wells were not initially planned for such purposes but were producers that experienced early gas breakthrough or gas coning and were later converted to "gas source" wells. This has proven to be a workable solution but inadequate in meeting the overall gas lift demand for the Field largely due to the limited number of highly pressured/ high GOR wells and the usually low volume of gas that they produce. Other challenges to this system include the hydrated nature of the gas injected as the injected gas is essentially untreated off water and tend to reduce the gas lift efficiency. The alternative option of installing a conventional gas lift network system with associated surface equipment such as compressors and dehydration units has proven to be economically challenged due to the huge investment required for the installation and running of such systems when compared to the expected "prize" of marginal reserves development from a matured asset as the Maple Field. These issues provided both a challenge and an opportunity for the Maple Field project team consisting of both subsurface & facilities engineers to come up with cost effective and pragmatic solutions that is geared towards providing a more sustainable and adequate gas supply for the Field for gas lifting purposes. These efforts resulted in the production increase of ~ 2,000 BOPD in the Field.
Agbami Next Generation Frac Pack Equipment Development & Deployment
Authors: Adegbulugbe Kayode , Elendu Chidi , Ugah Ibrahim , Ojukwu Ihechi 
Published: August 2020

Abstract
Agbami producer wells are mostly installed with stacked Frac Pack completions9,10,11 with IWC capability to adequately control and monitor production intervals. The first completions were installed in 2007, while production commenced in 20081,2. By 2015, when Agbami phase 3 completions were being installed, the reservoirs had been significantly depleted and the wells were more directionally complex thus leading to a relatively more challenging completions design and execution. The depletion led to severe post-frac fluid losses with attendant significant time required to cure such losses often by pumping LCMs which further impacts the well productivity. There were also substantial operational challenges in locating tool positions and activating the ball check (RABC) which worsened due to the more directionally challenging profile.
However, there has not been a major change in the Agbami completion equipment and service tools to manage these challenges since the first completions were installed. Significant completion installation Non-Productive times were incurred during the phase 3 completions installations which are directly attributable to these challenges.
The Agbami drilling team and service providers identified and successfully implemented opportunities to upgrade the Agbami frac pack service tools to mitigate against the frac pack execution challenges. These upgrades effectively addressed the challenges of the older generation service tool configuration and resulted in much improved completion execution and post-completion productivity for the AIDP wells.
Comparative Analysis of Local and Conventional EOR Agents
Authors: Uzoho Chidinma Uzoamaka , Onyekonwu Mike Obi , Akaranta Onyewuchi 
Published: August 2020

Abstract
Latest research in Nigeria, West Africa had shown the possibility of sourcing for low cost chemicals for enhancing oil recovery. In this work, a comparative study was done using local and conventional chemicals for Core Flooding experiment under same conditions. These chemicals are NaOH, KOH, Na2CO3, Polyacrylamide, Sodium Dodecyl Sulphate and Akanwu, Palm Bunch Ash, Plantain Peel Ash, Xero-Detergent, Okro as conventional and local EOR agents respectively. The results showed that local chemicals performed as good as the conventional chemical giving an additional recovery of 11.54%, 21.43%, 17.86%, 12.73%, 17.39% and 17.25%, 12.50%, 9.60%, 20.69%, 18.70% for conventional and local EOR agents respectively. These local materials were characterized using EDXRF and its results verified that the local materials actually contained some chemical components responsible for their performance. The significance of this research work is economic boom to the oil and gas industries, job creation, and increase in the Nation's GDP.
Assessment of Natural Gas Infrastructure Development in Ghana
Authors: Yaw Boahen Kenneth , Oppong Riverson 
Published: August 2020

Abstract
Natural Gas Infrastructure is an integral component of our economic and societal development. This in recent times, has drawn global investments and continues to be a major backbone to the world energy mix. Analysis of the data shows a financial and knowledge gap in the development of gas infrastructures in Ghana. In addition, there is limited private sector participation in gas infrastructure development due to a government policy framework. Further assessment shows that natural gas was mainly being used for power generation, industrial heating applications with Liquefied Petroleum Gas as its by-product used for domestic cooking.
In conclusion, a gas infrastructural development fund needs to be established to support activities within the sector for the full realization of the Gas Master Plan. Also, human resources training within the various technical universities on natural gas development must be enhanced. There is a need for a review of the policy framework to factor in private sector participation through public-private partnership in gas infrastructure development as well as improvement in fiscal regime to mitigate risk and create a friendly environment for investors. The study unearthed other economic benefits that could fully be utilized for the economic and sustainability of society. In agriculture, it was realized that natural gas can be used for making protein-rich animal feed and also in fertilizer for crop production. In transportation, compressed natural gas can be fully utilized as fuel for vehicles resulting in reduced emissions to the environment. Natural gas could also play a key role in cement manufacturing, methanol production, fabrics, and paint manufacturing.