bluuebunny/crossref_metadata_2025 huggingface dataset:
Tiga Tema Konsep Kebersyukuran dalam Perspektif Al-Qur’an: Sebuah Literatur Review
Authors: Karimulloh  , Grasiaswaty Novika , Caninsti Riselligia
Published: August 2021

Banyak nikmat yang diterima oleh seorang manusia, namun sedikit manusia yang dianggap bersyukur di dalam Al-Qur’an menjadi hal penting untuk dikaji. Belum lagi, tidak sedikit penelitian yang membahas kebersyukuran di Indonesia, namun minimnya literasi keislaman terutama dari sumber referensi utama Islam, yaitu Al-Qur’an menjadi tujuan utama dalam penelitian ini. Metode penelitian yang digunakan adalah studi pustaka dengan menganalisis ayat-ayat kebersyukuran di dalam Al-Qur’an dengan pendekatan tafsir tematik dan studi ilmu keislaman. Hasil penelitian menunjukkan terdapat tiga tema besar konsep kebersyukuran yang tertuang dalam Al Quran dan didukung oleh tafsir para ulama. Ketiga tema besar tersebut adalah (1). Perintah untuk bersyukur dalam perspektif Al Quran, (2) dampak positif dari kebersyukuran yang tertuang dalam Al Quran, dan (3) factor-faktor penyebab kebersyukuran yang dijelaskan di dalam Al Quran. Hasil ini juga menjelaskan bahwa orang yang bersyukur pasti mendapatkan keridhaan Allah SWT, dan dia terhindar dari siksa api neraka, serta mendapatkan tambahan nikmat, baik di dunia maupun di akhirat. Agar seseorang bisa bersyukur, maka dianjurkan untuk melihat orang yang lebih rendah derajatnya, mengingat akan nikmat-nikmat yang telah Allah berikan kepadanya, dan memohon kepada Allah SWT supaya diberi kekuatan untuk bisa bersyukur kepada-Nya.
Analisis Penerapan Akuntansi dan Penggunaan Informasi Akuntansi Pada UMKM
Authors: Fatkhiyah Fibaroina Nida , El Junusi Rahman , Nurudin Nurudin , Zakiy Faris Shalahuddin
Published: August 2021

The purpose of this study is to determine the extent to which accounting records are applied and the use of accounting information for MSMEs. The research method used is a qualitative descriptive case study approach. The object of this study took 10 MSMEs registered in the financing of Bank BRI Syariah KCP Semarang. Collecting data from this study using interview methods, questionnaires, and documentation. The data obtained were triangulated and analyzed. The results of this study, that the application of accounting records and the use of accounting information on MSMEs registered in the financing of Bank BRI Syariah KCP Semarang has been implemented even though it is still simple in nature. MSMEs have made accounting recognition such as assets, liabilities, equity, income, and cost of goods and expenses. Financial reports are made in the form of cash flows and notes to financial statements. MSMEs have also used accounting information in the form of operational information, management information, and financial information to make decisions.
Membangun Negeri Dengan Wakaf Produktif
Authors: Selasi Dini
Published: August 2021

Waqf has a function of worship activities, namely by holding our assets to be used in the way of Allah SWT which gives rewards throughout the ages will also have a social function which after the principal of the property is withheld, developed then after being developed will provide results that can be used by the people. This research aims to provide education about the role of waqf in development as well as how the role of waqf for the welfare of the people. This research uses qualitative research methods, data collection techniques using secondary data and using literature study. The results of this study show that waqf has an important role in providing the welfare of the people and waqf also has an important role in developing the country, this is evidenced by the role of waqf in the fields of education, health, economy and finance, technology and agriculture, where these fields are the pillars of development national.
Application of Machine Learning in Predicting Crude Oil Production Volume
Authors: Innocent Okechukwu Prince
Published: August 2021

The production of oil is of great and immense significance as a source of energy worldwide. The major factors affecting the production volume of oil is classified into two groups namely the geological and the human factor. Each group comprises of factors affecting oilfield production volume. The challenge in this project is to find the variable for the crude oil production volume in an oilfield because there are numerous factors affecting the crude oil production volume in an oilfield. The objective of this paper is to provide a more accurate and efficient solution on how to predict the oil production volume.

Furthermore, Machine Learning algorithm called Multiple Linear Regression was developed using Python programming Language to predict the production volume of oil in an oilfield. The model was developed and fitted to train and test the factors that affect and influence the oil production volume. After a several studies have been made, the affecting factors were provided from the oilfield which would be trained and tested in order to model the relationship between predictor variable and response variable which are the significant affecting factors and the oil production volume respectively. The predictor variables are the startup number of wells, the recovery percent of previous year, the injected water volume of previous year and the oil moisture content of previous year. The predictor variable is the oil production volume.

Moreover, the model was found to possess greater utility in predicting the production volume of oil as it yielded an oil production volume output with an accuracy of 98 percent. The relationship between oil production volume and the affecting factors was observed and drawn to a perfect conclusion.

This model can be of immense value in the oil and gas industry if implemented because of its ability to predict oilfield output more accurately. It is an invaluable and very efficient model for the oilfield manager and oil production manager.
A Comprehensive Review of Recent Advances in the Estimation of Natural Gas Compressibility Factor
Authors: Omobolanle Oluwasegun Cornelious , Akinsete Oluwatoyin Olakunle
Published: August 2021

Accurate prediction of gas compressibility factor is essential for the evaluation of gas reserves, custody transfer and design of surface equipment. Gas compressibility factor (Z) also known as gas deviation factor can be evaluated by experimental measurement, equation of state and empirical correlation. However, these methods have been known to be expensive, complex and of limited accuracy owing to the varying operating conditions and the presence of non-hydrocarbon components in the gas stream. Recently, newer correlations with extensive application over wider range of operating conditions and crude mixtures have been developed. Also, artificial intelligence is now being deployed in the evaluation of gas compressibility factor. There is therefore a need for a holistic understanding of gas compressibility factor vis-a-vis the cause-effect relations of deviation. This paper presents a critical review of current understanding and recent efforts in the estimation of gas deviation factor.
Targeting and Developing the Remaining Pay in an Ageing Field: the Ovhor Field Experience
Authors: Ihwiwhu Christian , Itotoi Ibi-Ada , John Udeme , Obioha Nnamdi , Okoro Precious , Ndubueze Maduabuchi , Bobade Edward , Awujoola Adedeji , Bekibele Oghenerunor , Adesanya Sola
Published: August 2021

Understanding the complexity in the distribution of hydrocarbon in a simple structure with flow baffles and connectivity issues is critical in targeting and developing the remaining pay in a mature asset. Subtle facies changes (heterogeneity) can have drastic impact on reservoir fluids movement, and this can be crucial to identifying sweet spots in mature fields. This study evaluated selected reservoirs in Ovhor Field, Niger Delta, Nigeria with the objective of optimising production from the field by targeting undeveloped oil reserves or bypassed pay and gaining an improved understanding of the selected reservoirs to increase the company's reserves limits.

The task at the Ovhor field, is complicated by poor stratigraphic seismic resolution over the field. 3-D geological (Sedimentology and stratigraphy) interpretation, Quantitative interpretation results and proper understanding of production data have been used in recognizing flow baffles and undeveloped compartments in the field. The full field 3-D model was constructed in such a way as to capture heterogeneities and the various compartments in the field. This was crucial to aid the simulation of fluid flow in the field for proper history matching, future production, prediction and design of well trajectories to adequately target undeveloped oil in the field.

Reservoir property models (Porosity, Permeability and Net-To-Gross) were constructed by biasing log interpreted properties to a defined environment of deposition model whose interpretation captured the heterogeneities expected in the studied reservoirs. At least, two scenarios were modelled for the studied reservoirs to capture the range of uncertainties.

This integrated approach led to the identification of bypassed oil in some areas of the selected reservoirs and an improved understanding of the studied reservoirs. Dynamic simulation and production forecast on the 4 reservoirs gave an undeveloped reserve of about 3.82 MMstb from two (2) identified oil restoration activities. These activities included side-tracking and re-perforation of existing wells. New wells have been drilled to test the results of our studies and the results confirmed our findings.
What Strategic Policies can Save Nigeria in the Energy Transition?
Authors: Ojukwu Kelechi
Published: August 2021

The world is fast changing and so is the energy mix. A global clarion call by scientists inspires an immediate action to circumvent the visible effects of climate change or face the damning consequences in the coming few years. Scientists and environmental lobbyist are campaigning against the consumption of fossil-based fuel and mounting more and more pressure on the international financial bodies including calling on government around the world to refrain from further financing of fossil fuel projects. This is surprisingly gathering momentum on regular basis, thereby posing existential threat to third-world oil producers, which are largely dependent on royalties and tax revenues from crude oil and other natural resources in order to sustain their economies. The future trends warn of a looming dooms day when these remaining reserves may no longer be able to attract the requisite funding necessary to develop them, let alone explore them.

Besides Niger Delta, most other petroleum basins in Nigeria are highly under-explored but presumed to have significant hydrocarbon resources, albeit mainly gas. For that reason, these basins and their resources do not yet count in the nation's wealth of booked resources. It is believed the country can also benefit from significant amounts of oil discoveries that are invisible to conventional technologies or intentionally bypassed in natural recovery methods. These could present less costly alternatives to uplift the nation's reserves booking and in so doing minimize uncertainty involved in deep water or frontier explorations. Nigeria should therefore aim to ramp up its capital investment to boost oil & gas production in the next couple of years so as to harness th abundant discovered resources whilst there is still time to do so.

To take advantage of Nigeria's vast portfolio of hydrocarbon resources, the nation must explore strategic policies aimed to enhancing exploration and production interests while simultaneously expanding other value chains and promoting the investment in alternative or renewable energy. It must expediently exploit the remaining reserves so as to make the most of what it has. Then the wind fall from that exploitation can be ploughed back into the economy to facilitate the implementation of large-scale alternative energy projects as it plans to eventually substitute the fossil fuel energy. This paper presents some thought-provoking but radical ideas of how this can be achieved in the near term.
A Comprehensive Review on CO2/N2 Mixture Injection for Methane Gas Recovery in Hydrate Reservoirs
Authors: Aregbe Azeez Gbenga , Fadeyi Ayoola Idris
Published: August 2021

Clathrate hydrates are non-stoichiometric compounds of water and gas molecules coexisting at relatively low temperatures and high pressures. The gas molecules are trapped in cage-like structures of the water molecules by hydrogen bonds. There are several hydrate deposits in permafrost and oceanic sediments with an enormous amount of energy. The energy content of methane in hydrate reservoirs is considered to be up to 50 times that of conventional petroleum resources, with about 2,500 to 20,000 trillion m3 of methane gas. More than 220 hydrate deposits in permafrost and oceanic sediments have been identified to date.

The exploration and production of these deposits to recover the trapped methane gas could overcome the world energy challenges and create a sustainable energy future. Furthermore, global warming is a major issue facing the world at large and it is caused by greenhouse gas emissions such as carbon dioxide. As a result, researchers and organizations have proposed various methods of reducing the emission of carbon dioxide gas. One of the proposed methods is the geological storage of carbon dioxide in depleted oil and gas reservoirs, oceanic sediments, deep saline aquifers, and depleted hydrate deposits. Studies have shown that there is the possibility of methane gas production and carbon dioxide storage in hydrate reservoirs using the injection of carbon dioxide and nitrogen gas mixture. However, the conventional hydrocarbon production methods cannot be used for the hydrate reservoirs due to the nature of these reservoirs. In addition, thermal stimulation and depressurization are not effective methods for methane gas production and carbon sequestration in hydrate-bearing sediments.

Therefore, the gas replacement method for methane production and carbon dioxide storage in clathrate hydrate is investigated in this paper. The research studies (experiments, modeling/simulation, and field tests) on CO2/N2 gas mixture injection for the optimization of methane gas recovery in hydrate reservoirs are reviewed. It was discovered that the injection of the gas mixture enhanced the recovery process by replacing methane gas in the small and large cages of the hydrate. Also, the presence of N2 molecules significantly increased fluid injectivity and methane recovery rate. In addition, a significant amount of free water was not released and the hydrate phase was stable during the replacement process. It is an effective method for permanent storage of carbon dioxide in the hydrate layer. However, further research studies on the effects of gas composition, particle size, and gas transport on the replacement process and swapping rate are required.
Produced Water Disposal in Deep Aquifers: Case History Review of Ughelli East-30 Pilot Injector
Authors: Peter Osode , Olusegun Oluwatoyin , Ologun Temitayo , Anyanwu Obinna
Published: August 2021

A water injector pilot well - Ughelli East-30, was drilled across high-permeability unconsolidated sandstone aquifers to dispose 30 Mbwpd of produced water in November 1998 and suspended in December 1998 due to lack of injectivity. Review of the failed pilot injection was performed as part of an extensive water management study for a cluster of onshore fields located in the western Niger Delta area.

The technical investigation focused on the target disposal aquifer petrophysical parameters, produced water composition analysis, well completion design and injection performance result. Potential impairment mechanisms and failure risk factors for injectors with similar cased-hole, perforated completion design in analogue reservoirs were also investigated.

The poor well injectivity performance was attributed to sub-optimal sand control completion design and the ‘water hammer’ effect which resulted in massive sand fill as evidenced by a sand bailing exercise during November 1999 riglessre-entry in the well. The 17-ft rat hole below the bottom aquifer sand perforations was also deemed to be inadequate for the sand fill which apparently bridged the perforations.

Optimal completion requirements to prevent water injection failure in unconsolidated sandstone formation has been brought to the fore in this paper which is expected to steer engineers focus to those factors with high impact on water injection system performance.
Taming the Monster: Arresting Excessive Sand Production Problem in ARAMU037
Authors: Ako Emily , Nnanna Erasmus , Somtochukwu Odumodu , Moradeke Akinmade
Published: August 2021

Chemical Sand Consolidation (SCON) has been used as a means of downhole sand control in Niger Delta since the early 70s. The countries where SCON has been used include Nigeria (Niger Delta), Gabon (Gamba) and UK (North Sea). SCON provides grain-to-grain cementation and locks formation fines in place through the process of adsorption of the sand grains and subsequent polymerization of the resin at elevated well temperatures. The polymerized resin serves to consolidate the surfaces of the sand grain while retaining permeability through the pore spaces.

In a typical Niger Delta asset, over 30% of the wells may be completed with SCON. A high percentage are still producing without failure since installation from1970s. Where the original SCON jobs have failed, re-consolidation has also been carried out successfully. Chemical Sand Consolidation development has evolved over the years from: Eposand 112A and B, Eposand 212A and B, Wellfix 2000, Wellfix 3000, Sandstop (resin based), Sandtrap 225, 350 & 500 (resin based) and lately Sandtrap 225,350, 500 (solvent based) and Sandtrap ABC (aqueous based).

There have been mixed results experienced with the deployment of either of the latest recipes of SCON. This was due to the fact that the conventional deployment work procedure was followed with the tendency for one-size-fits-all approach to the treatment.

This paper details the challenges faced with sand production in ARAMU037, the previous interventions and how an integrated approach to the design and delivery of the most recent intervention restored the way to normal production. The well has now produced for about 2 years with minimal interruption with the activity paying out in less than 6 months. The paper also recommends the best practice for remedial sand control especially for wells in mature assets.
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

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

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

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

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

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

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<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

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

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

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

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

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.
Estimation of Bottom Hole Pressure in Electrical Submersible Pump Wells using Machine Learning Technique
Authors: Sanusi Sherif , Omisore Adenike , Blankson Eyituoyo , Anyanwu Chinedu , Eremiokhale Obehi
Published: August 2021

With the growing importance and application of Machine Learning in various complex operations in the Oil and Gas Industry, this study focuses on the implementation of data analytics for estimating and/or validating bottom-hole pressure (BHP) of Electrical Submersible Pump (ESP) wells. Depending on the placement of the ESP in the wellbore and fluid gravity of the well fluid, there can be little or no difference between BHP and Pump intake Pressure (PIP); hence these two parameters were used interchangeably. The study focuses majorly on validating PIP when there are concerns with downhole gauge readings. It also has application in estimating PIP when the gauge readings are not available, provided the relevant ESP parameters are obtainable. ESP wells generally have gauges that operate on "Comms-on-Power" principle i.e. downhole communication is via the power cable and loss of signal occurs when there is no good electrical integrity along the electrical path of the ESP system. For proper hydrocarbon accounting and statutory requirements, it is important to have downhole pressure readings on a continuous basis, however this cannot be guaranteed throughout the life cycle of the well. Therefore, an alternative method is essential and had to be sought.

In this study, the Response Surface Modelling (RSM) was first used to generate a model relating the ESP parameters acquired real-time to the PIP values. The model was fine-tuned with a Supervised Machine Learning algorithm: Artificial Neural Network (ANN). The performance of the algorithms was then validated using the R-Square and Mean Square Error values. The result proves that Machine Learning can be used to estimate PIP in a well without recourse to incurring additional cost of deploying new downhole gauges for acquisition of well and reservoir data.
Front-End Integrated Production System Modelling for Production Optimization – Experience from a Niger Delta Field
Authors: Okoro Felix , Arochukwu Elias , Adomokhai Segun , Dennar Linda
Published: August 2021

The M001 project involved the hook-up of 12 wells (17 conduits) which were drilled and completed between year 2000 and 2005 but were closed-in for operational reasons, until year 2019 when the first seven (7) conduits on cluster MX1 were cleaned up successfully. The seven conduits (Well-A, Well-B, Well-C, Well-D, Well-E, Well-F & Well-G) were expected to flow via three 8" bulk lines. Post well open-up and handover to production, significant bulking / backing out effects were observed.

An average Flow Line Pressure (FLP) of ∼22 bar was recorded on the flowlines, hence limiting the capacity to bulk the wells, [FLP increases towards Flowing Tubing Head Pressure (FTHP) hence, pushing the well out of the critical flow envelope as FTHP<<1.7FLP]. Due to this challenge, total production from Cluster MX1 was sub-optimal with only five (5) conduits out of seven (7) able to flow due to bulking and backing out effect. The sub-optimal performance from the conduits were investigated using the Integrated Production System Model (IPSM) / PIPESIM models. Four different scenarios were run in the model and the calibrated IPSM model indicated all 7 conduits should flow if there are no surface restrictions. The model identified pressure, mass and rate imbalances in the integrated system and suggested the presence of a restriction at the manifold, causing sub-optimal production from the wells.

The model outcome triggered an onsite investigation / troubleshooting from the wellhead to the manifold at the facilities end where an adjustable choke was identified in the ligaments of the manifold. In line with process safety requirements, a risk assessment was carried out and a Management of Change (MOC) raised to remove the adjustable choke at the manifold.

Post implementation of the intervention, all the seven (7) conduits produced without any bulking effect. Total production realized from the seven (7) conduits post execution of the recommended action is ca. 9.3 kbopd against 5.2 kbopd pre-intervention. A total of ca. 4.1 kbopd production gain was realized and 10 mln USD proposed for additional bulkline was saved.
A Review of Wet Gas Flow Metering Correlation
Authors: Adenubi Solomon , Appah Dulu , Okafor Emeka , Aimikhe Victor , Okologume Wilfred
Published: August 2021

Entrained liquids in produced natural gas introduce flow-prediction errors in gas metering; hence there is a need to correct flowmeters’ response to these errors. The development of improved wet gas flow correlations is an effective means of optimizing the predictive capabilities of these meters. This study reviews selected wet gas flow correlations, assesses their merits and demerits, and offers novel options and possibilities for developing highly optimized wet gas correlations for industrial applications. Prospects and possibilities for developing highly optimized wet gas flow correlations are also suggested in this paper, resulting in a significant expansion of the use of wet gas flow meters. These possibilities will include model development and experimental investigation of wet gas flows under relatively high-pressure operating conditions.