bluuebunny/crossref_metadata_2025_split huggingface dataset:
Factorial Design Validation of an Environmentally Benign Water-Based Drilling Fluid from Sweet Potato Peels at Elevated Temperatures
Authors: Ebuzeme Ifeanyichukwu , Olatunji Oladipo , Olufemi Babatope 
Published: August 2021

Abstract
In recent years, several research types have been carried out to produce environmentally-benign drilling fluid additives using locally sourced substances. Still, the formulation of a more effective and cheaper viscosifier for a better hole cleaning ability that lowers risk in lost circulation zones, especially at higher temperatures, remains a critical research subject. This study examines the use of Sweet Potato Peels Extract (PPE), a more readily available by-product, as a drilling fluid additive. A 23 factorial experiment that considers temperature, PPE and Xanthan Gum (X.G.) as factor variables and viscosity as a response variable was conducted for field optimisation.
In this research, the PPE and other commercial polymers were measured at different concentrations and combined in a specified ratio of 1:1 by mass to verify the levels of interaction between the additives on the mud weight, yield point (Y.P.), and plastic viscosity (P.V.) of the formulated drilling mud. The additives’ effects were then recorded using a mud balance, a viscometer, and a heater for temperature variance. The results were then compared with the control mud to ascertain the additives’ effectiveness.
Experimental results revealed that the PPE and X.G. increased the Y.P. and P.V. at 104 °F and 176 °F, respectively. On adding 6 g of X.G. to the control mud (8.97 ppg), at 104 °F and 176 °F, the Y.P. increased by 88% and 11%, respectively, and the 3 g PPE + 3 g X.G. gave a better inference at 104 °F and 176 °F with a 92% and 38% increase respectively. This increase is a result of higher potassium content in the PPE from chemical laboratory analysis. Apart from the optimum ratio by mass of 1:1 above, the combination effects or results are shown using the factorial design experiment. The factor variables were modelled into a mathematical equation that indicates PPE additive as the most significant parameter on the yield point. The second component of viscosity, plastic viscosity (P.V.), followed a similar trend. Furthermore, PPE and X.G.'s effect on plastic viscosity at 176 °F decreased slightly with an increase in the control mud's salinity.
This novel combination offers a more cost-effective and better-performing viscosifier than the conventional X.G. from the above results. The model helps predict downhole conditions better as it shows the interactive effects of the various additives and can help inform decisions at the surface. A better hole cleaning ability, lower risk in lost circulation zones, and reduced Non-Productive Time would be the benefits of using this formulation.
Adulteration Detection of Petroleum Products at Point of Sale POS Terminals
Authors: Ejofodomi O'tega , Ofualagba Godswill , Onyishi Donatus Uchechukwu 
Published: August 2021

Abstract
In the Oil and Gas Industry, price disparity between Premium Motor Spirit (PMS), Automotive Gas Oil (AGO), and Dual Purpose Kerosene (DPK), often leads to adulteration of these petroleum products by marketers for monetary gains. Adulteration is the illegal introduction of a foreign undesirable substance to a substrate which affects the quality of the substrate. Adulteration of petroleum products are difficult to detect at Point of Sale (POS) terminals. Current methods for adulteration detection are time-consuming, require specialized equipment and experienced technicians to operate them, and cannot be used at POS terminals. Gaseous Vapor Technique (GVE) is an innovative adulteration detection technique that can be employed at POS terminals and the PePVEAT device utilized in this study is the first portable electronic device that performs GVE on petroleum products. GVE testing was performed on pure 1 L samples of PMS, AGO, and DPK obtained from the Nigerian National Petroleum Corporation (NNPC) using PePVEAT. The results obtained from GVE analysis of AGO, PMS, and DPK showed that the three petroleum products exhibited unique and varying chemical characteristics during GVE.
AGO gives off its peak emissions between 10-20 seconds from test onset, DPK gives off its peak emissions between 10-30 seconds from test onset, and PMS gives off its peak emissions between 50-70 seconds from test onset. AGO emits 17.52-46.58 ppm of methane, 5.35-11.93 ppm of LPG, 35.51-84.6 ppm of butane, and 10.38-69.86 ppm of toluene. PMS emits 92,063.67-152,168.18 ppm of methane, 301.035-573.61 ppm of LPG, 2210.89-3424.94 ppm of butane, and 1983.02-7187.29 ppm of toluene. DPK emits 27.13-62.14 ppm of methane, 20.2-74.1 ppm of LPG, 120.41-1635.85 ppm of butane, and 1159.75- 1633.09 ppm of toluene.
These variations in timing and concentrations of emissions shows that GVE can be utilized to detect and distinguish between AGO, PMS and DPK. The results obtained from GVE analysis of AGO, PMS, and DPK showed that Since PMS, AGO and DPK, each have unique chemical emissions during GVE, as was demonstrated in this paper, it is possible that GVE can be utilized to detect the adulterations of PMS with AGO and the adulteration of AGO with DPK. Future work involves investigating the ability of GVE to detect AGO-adulterated PMS, DPK-adulterated AGO, DPK-adulterated PMS, AGO-adulterated DPK,and PMS-adulterated DPK. The degree and percentage of adulteration that can be detected using the GVE technique will also be examined.
Enhanced Oil Recovery Improvement Using Augmented Waterflooding to Induce Fluids Flow Orientation in a Reservoir
Authors: Udie Celestine , Faithpraise Fina , Anuka Agnes 
Published: August 2021

Abstract
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%
Unconventional Method of Estimating Oilfield Reserve Initially in Place Using Decline Trends Analyses Techniques
Authors: Udie Celestine , Faithpraise Fina , Anuka Agnes 
Published: August 2021

Abstract
Methods to estimate reserves, recovery factor and time are highlighted using uconventional method, to reduce the challenges in an oilfield development. General Information about reserves production estimation using long and short production data is collated. The collated data are plotted against time to build production decline curves. The curves are used to estimate the decline rate trends and constants. The decline constant is then used to predict reserves cumulative recovery. The rate trend is extrapolated to abandonment for estimation of reserves initially in place, recovery factor and the correspondent time. The reserves values are compared with field values for accuracy. It was observed that the result using data from long time production history accuracy was 99.98% while evaluation models built with data from short production history accuracy was 98.64%. The models are then adopted after validation. The validated curves are used to build the governing models which are finally used in estimating cumulative reserves recovery and initially in place. It is concluded that accurate reserves, recovery factor and time estimation challenges can be achieved/matched up using rate decline trend techniques.
An Approach to Estimating Reserve Volumes by Discounting Unauthorized Production Via Crude Oil Theft
Authors: Ihebuzor Valentine , Onyeneke Obinna , Adebari Adeola , Ogbonnaya Obasi 
Published: August 2021

Abstract
Reserves are typically estimated and re-validated throughout the life of a producing field. The accuracy of this estimation is based on the availability of relevant and current data from that reservoir or field and other factors. There are several methods for estimating reserves, but the choice of which method is to be applied is often based on the data available per time. However, these methods are known to be associated with varying degrees of uncertainties arising from quality of data, the assumptions adopted and the experience of the evaluator. The biggest uncertainty in reserve estimation lies in the inability of the commonly available methods to estimate and discount the huge volumes lost due to unauthorized production by third parties, through crude oil theft, illegal bunkering activities, and spills. This leads to the gross overestimation of reserves and the economic viability of an asset, especially in onshore and shallow offshore assets where such illegal activities are typical and rampant. This paper showcases an approach of estimating reserves, through the integration of multidisciplinary data, which enables the estimation and discounting of crude oil volumes lost due to illegal production from a reservoir.
Efficient Wellbore Optimization Through Rock Property Analysis and Evaluation
Authors: Ogunrinde Joshua Oluwayomi 
Published: August 2021

Abstract
There are numerous problems encountered during drilling such as wellbore instability, drilling mud weight estimation, as well as selecting good casing and bit for the drilling operations. It is therefore important to understand and accurately determine the strength of the rock in order to avoid these common drilling problems which are mostly encountered during well operations. It is of paramount importance to determine uniaxial compressive strength (UCS) from core and sonic log data so as to accurately predict rock strength for better well planning. In this work, we were able to obtain a correlation to determine UCS from data obtained from ten (10) wells in different locations in onshore Niger Delta using the regression analysis method. The correlation of UCS versus Poisson's ratio gave R2 value of 90.0%. The R2- value tending towards one (1) indicates that this model can be reliably used to predict ND-UCS and the p&lt;0.05 shows that there is significant relationship between ND-UCS and Poisson's ratio. The model was validated with an entirely different well data and it predicted over 89% rock UCS data when compared to the actual rock UCS data. This study also provides an understanding of the variation in UCS and Poisson's ratio with depth for effective rock property analysis and evaluation. These correlations will help well engineers to make informed decisions on rock strength predictions during well planning and operations as well as manage wellbore stability optimally.
Comparative Analysis of the Rheological Behaviour of Irvingia Gabonensis Ogbono and Foreign Polymer for Bentonite Formulated Mud.
Authors: Ayodele Emmanuel , Ekuma David , Okafor Ikechukwu , Nweze Innocent 
Published: August 2021

Abstract
Drilling fluid are complex fluids consisting of several additives. These additives are added to enhance and control the rheological properties (such as viscosity, gel strength and yield point) of the mud. These properties are controlled for effective drilling of a well. This research work is focused on determining the rheological behavior of drilling mud using industry-based polymer and Irvingia Gabonensis (ogbono) as viscosifiers. Water based muds were formulated from the aforementioned locally sourced viscosifier and that of the conventional used viscosifier (Carboxylmetyl cellulose, CMC). Laboratory tests were carried out on the different muds formulated and their rheological properties (such as yield stress, shear stress, plastic viscosity and shear rate) are evaluated. The concentration of the viscosifiers were varied. The expected outcome of the research work aims at lowering the total drilling cost by reducing the importation of foreign polymer which promotes the development of local content in the oil and gas industry. The research compares the rheology of mud samples and the effect of varying the concentration (2g, 4g, 6g, 8g, and 10g) of both CMC and Ogbono and determining the changes in their rheological properties. The total volume of each mud sample is equivalent to 350ml which represent one barrel (42gal) in the lab. From the result, at concentration of 2g, the ogbono mud has a better rheology than the CMC mud, but at a concentration above 2g, CMC mud shows a better rheology than ogbono mud, that is, as the concentration of CMC is increased, the rheological properties of the mud increased while as the concentration of ogbono is increased the rheological properties decreased. The viscosity of the drilling fluid produced from the ogbono were lower than that of CMC, it could be used together with another local product such as cassava starch, offor or to further improve the rheology and then be a substitute to the conventional viscosifiers.
The Limitation of Reservoir Saturation Logging Tool in a Case of a Deeper Reservoir Flow into a Shallower Reservoir Within the Same Wellbore
Authors: Ekeregbe P. Merit 
Published: August 2021

Abstract
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.
Integrated Approach to Geostatistics For Optimal Reservoir Properties Distribution – Case Study of X-Reservoir in Niger Delta Basin
Authors: Madu Osita Robinson , Athoja Jerry Orrelo , Kalu Amarachi Queen , Onyekonwu Obi Mike 
Published: August 2021

Abstract
In-depth knowledge of geostatistical analysis, environment of deposition and reservoir facies types is important for optimal distribution of reservoir properties across the reservoir grid. Geostatistics is a veritable tool that is quantitatively used to model spatial continuity, anisotropy direction and capture reservoir heterogeneity for optimal distribution of reservoir properties. When spatial continuity and heterogeneity level of the reservoir are adequately understood and modeled, representative property distribution becomes possible. In the face of limited well data, modeling major and minor directions of horizontal variogram is highly impaired and it becomes difficult to adequately distribute properties within the reservoir grid with enough control. This study is focused on the integration of seismic data, core data, well logs and geological knowledge to carry out geostatistical analysis to optimally distribute facies, porosity and permeability properties within the grid. The degree of reservoir heterogeneity was determined quantitatively using semivariogram and Lorenz plots of core porosity and permeability data. Variogram map generated from seismic attribute was used in combination with the sparse well data points to determine the horizontal variogram. The available well data was adequate enough to model the vertical variogram. The environment of deposition was interpreted as lower to upper shoreface with channel deposits and some shallow marine influence. The properties were normal-scored and modeled with the determined variogram parameters while biasing them with facies. Results of the semivariogram and Lorenz plots showed that the reservoir is fairly heterogenous in terms of spatial continuity. Major direction of the geological continuity is in the Northeast-Southwest direction while the minor direction is orthogonal to it. Final result of the modeled properties was in consonance with the facies types described from the environment of deposition.
3D Seismic Data Design, Acquisition and Interpretation of Kolmani Exploratory Field, Upper Benue Trough, Gongola Basin; Nigeria
Authors: Abdulkadir Usman , Hashim Jamaluddeen , Kumar Ajay , Yau Umar , Simon Akpam , Dawaki Adamu 
Published: August 2021

Abstract
In an Oil and Gas field development plan, identifying appropriate reservoir location of a field and deciding the best design strategy as well as meeting the economic hydrocarbon viability are imperative for sustainability. 3-Dimensional seismic data have become a key tool used by geophysicists in the Oil and Gas industry to identify and understand subsurface reservoir deposits. In addition to providing excellent structural images, the dense sampling of a 3D survey can sometimes make it possible to map reservoir quality and the distribution of Oil and Gas.
Primarily, Seismic data sets were retrieved from the ongoing Kolmani exploratory work of upper Benue trough, bordering Gombe-Bauchi communities of Nigeria and Simulation study from improve design was conducted using PETREL and SURFER software's to obtain numerous coordinates from the source and receiver lines respectively and subsequent formation of strategic-designs that shows different arrangements of the prospect area, an interpretation of the acquired data sets that indicates the reservoir location appropriately and probable onset of drilling spot. The well to seismic was also merged using synthetic seismogram that shows the location of reservoir (s) from the seismic data obtained and four different wells with anticipated depths respectively. The overall aim of the whole design and simulation studies is to aid petroleum Geologist and Geophysicists avoids common pit falls by reducing dry holes and increasing the overall number of productive wells prior to actual commencement of drilling in this prospect area and elsewhere.
Determination of Optimum Rate in a Condensate Well with a Case of a Wellbore Liquid Loading
Authors: Ekeregbe Merit P. 
Published: August 2021

Abstract
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.