bluuebunny/crossref_metadata_2025 huggingface dataset:
Paisaje agrario en contextos periurbanos mediterráneos: el caso del Gran Sousse (Túnez)
Authors: Hamrita Abdelkarim , Mata Rafael , López-Estébanez Nieves , Rejeb Hichem
Published: August 2021

La protección de la agricultura periurbana mediante la zonificación de determinados suelos como no urbanizables por los instrumentos de planificación urbanística y territorial resulta insuficiente frente a las fuertes presiones de usos residenciales, industriales, infraestructurales y, en ocasiones, turísticos que provocan su fragilidad. En este texto se aborda la potencialidad del paisaje para activar este tipo de agricultura que se desenvuelve bajo influencia urbana directa y se adopta el Landscape Character Assessment como metodología sistemática de identificación y caracterización de los paisajes de la agricultura periurbana del Gran Sousse, la principal aglomeración urbana y turística del Sahel tunecino, con objeto de su evaluación, ordenación y promoción. Se adopta la noción de carácter del paisaje y se relaciona con las políticas públicas de gestión de los espacios agrarios periurbanos tunecinos y la percepción social, mediante entrevistas a una muestra de actores locales y regionales. Se analiza la diversidad paisajística concretada en Áreas Paisajísticas de Agricultura Periurbana (APAP), caracterizadas a partir de su particular fisonomía, y de los principales elementos y funcionamiento pasado y presente. El estudio concluye con la propuesta de un proyecto de paisaje como infraestructura verde, que implica un modelo de gestión de conflictos de acuerdo con las necesidades propias del paisaje, de los agricultores y de la población que lo percibe y lo utiliza como espacio abierto, fortaleciendo su función de productor de alimentos de calidad y de proximidad, como un ejercicio de participación y gobernanza territorial.
Guest Editorial: How To Meet Declining Oil Demand
Authors: Purvis Dwayne
Published: August 2021

As the world reaches a tipping point in its will to address climate change, the industry must find a new way forward, especially in the United States.

Many are right to say that oil and gas are not going away; the transition is planned to take 30 years or more and will not decline to zero production. This fact, though, obscures the reality that peaking, then declining, demand for oil—gas is another story—will structurally change and globally redistribute the industry’s exploration and employment.

The story of oil supply and demand began its race to the top 150 years ago. “Shortage” and “glut” have meant that paired growth got out of sync, not that there was a real loss of production. For many decades the world has needed about 1 million B/D more each year than the previous year, but on a percentage basis growth has slowed. At the same time supply from previous years declines about 5 to 6% per year, arguably higher in recent years. The treadmill for new supply has been running hot for decades.

All major public forecasts in the past year call for oil demand to plateau between now and about 2030 when accounting for ongoing changes to policy. (To be clear, some show a peak in the 2030s in “business as usual” cases, but they also show even sooner peaks if policy and demand changes accelerate). BP’s Energy Outlook 2020 from last fall took the bold—and well-argued—position that peak oil demand is today and that it is only a question of how fast demand declines. “Peak” demand isn’t really a peak like the Matterhorn; it is flatter like a weathered jebel. We know this from the example of the peak oil demand experienced by the developed world. We also know from that experience that forecasting agencies failed to predict the peak OECD oil demand in 2005 literally by decades even as demand turned down.

Reversal of demand growth presents a figurative and mathematical inflection point. Though existing production continues, growth becomes negative, and the pace of the new-supply treadmill plummets. When the need for new supply approximately halves, the Pareto principle tells us that the number of new projects required will fall more than half. Thus, the need for those industry professionals preferentially tasked with finding new oil supply—geophysicists, exploration geologists, drillers, reservoir engineers, landmen—may fall quickly. Other disciplines like operations that service existing production will face only the headwinds of cost reductions and then the long, slow slide toward mid-century targets.

The United States via its swarm of large and small companies has dominated the global supply story for more than a decade with its unique shale revolution, but it had previously shriveled to a second-tier producer. Fig. 1 shows 55 years of oil production history. Fig. 1a shows the US supply deconstructed to its functional parts while Fig. 1b shows ascendent producers on the same scales.
Using Cameras To Understand What Is Happening While Drilling
Authors: Rassenfoss Stephen
Published: August 2021

Can a camera do a better job than humans at creating a minute-by-minute record of drilling activity? Or evaluate damaged drill bits better?

Based on two papers at the SPE/IADC International Drilling Conference and Exhibition, the answer might soon be yes.

Schlumberger researchers showed that video from a camera on the drill floor and on the drilling cuttings shaker kept an accurate record of what the rig was doing at the time, also known as the rig state (SPE 204086).

A paper from The University of Texas-Austin (UT-Austin) showed a camera phone could create images for use in their bit-evaluation program to assess the damage and offer a reasonable explanation for what caused it (SPE 204124).

A year ago Teradata announced its Bit-Box, which houses cameras and lights to create 3D bit images. It is now on the market; other companies are working on competing products.

Cameras have gotten small and cheap at a time when innovations like self-driving cars have driven tech companies to speed development of computer-vision tools.

Schlumberger’s goal is to convert video from rig cameras into a constant record of the rig state. It is being done with data gathered by sensors while drilling, or by people if the sensors stop working or generate bad data.

The system leaves gaps when sensor issues are missed or workers are otherwise occupied, which is a maddening problem for those who need to know what is going on at any moment to interpret drilling data.

“We need to understand what the rig was doing when we look at and try to solve problems” using digital analysis, said Crispin Chatar, a drilling subject matter expert for Schlumberger, who presented the paper at the virtual conference.

The bit-evaluation program used phone camera images as a lower-cost substitute for 3D imaging, like the system sold by Teradata.

Mobile phone images come with the risk of bad lighting and varying angles, which the authors said affected the analysis. But those devices are small, and there are plenty of backups available.

“Everybody has a mobile phone at a rig site,” said Pradeep Ashok, a research scientist in the petroleum engineering department at UT-Austin. He believes cameras on mobile devices are the future because “if you could build something that requires no added equipment it will allow more rapid adoption.”

Mobile phone owners also worry about breaking their phone. They may not be so concerned about rig equipment, which is a concern to those selling more-complex imaging devices.

Both projects were early efforts to test what can be done with camera data, which is likely to expand over time.

Schlumberger’s goal of tracking the rig state more reliably and cheaper than when using sensors may not be enough to convince users to change their ways at a time when sensors are proliferating to support more digitally controlled activities. The Schlumberger data were gathered at a test well for an automated rig.
Pilot-Scale Evaluation of Natural-Gas-Based Foam at High Pressures, Temperatures
Authors: Carpenter Chris
Published: August 2021

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201611, “A Pilot-Scale Evaluation of Natural-Gas-Based Foam at Elevated Pressure and Temperature Conditions,” by Griffin Beck, Swanand Bhagwat, and Carolyn Day, Southwest Research Institute, et al., prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, 5–7 October. The paper has not been peer reviewed.

The complete paper presents recent results from a rigorous pilot-scale demonstration of natural-gas (NG) foam over a range of operating scenarios relevant to surface and bottomhole conditions with a variety of base-fluid mixtures. The NG foams explored in these investigations exhibited typical shear-thinning behavior observed in rheological studies of nitrogen- (N2) and carbon-dioxide- (CO2) based foams. The measured viscosity and observed stability indicate that NG foams are well-suited for fracturing applications.

Test Facilities

Two test facilities were used to explore properties of NG foams at a variety of relevant operating conditions to determine whether NG foam is a suitable alternative to typical water-based fracturing fluids.

Pilot-Scale Foam-Test Facility. The pilot-scale foam-test facility (PFTF) is a single-pass pilot plant used to generate and characterize foams at conditions relevant to surface and reservoir conditions. The facility is capable of generating aqueous and oil-based foams using a variety of gases for the internal phase [e.g., methane (CH4), N2, and CO2]. Foams can be characterized at pressures up to 7,500 psi and temperatures up to 300°F. A key benefit of the PFTF is that it can be used to demonstrate new or challenging foaming processes before large-scale or field demonstrations. Further, these processes can be evaluated at conditions relevant to the final application.

The test facility consists of three subsystems: a base-fluid system to pressurize and heat the liquid/viscosifier/surfactant mixture, a gas system to pressurize and heat the liquefied gas stream, and the foam test sections to measure various fluid properties of the NG foam.

Laboratory Foam-Test Facility. Tests performed on the PFTF were limited to foams generated with pure CH4 and tap water. Additional laboratory tests were conducted to investigate the effects of multiconstituent natural gas mixtures and produced water on foam stability. For these tests, the aqueous base fluid for the foam half-life and foam rheology experiments was prepared from either de-ionized water, tap water, or a synthetic produced water based on a water sample from the Permian Basin. Foam fracturing fluids also typically contain a gelling agent and a foaming agent. The gel was prepared by slow addition of guar to a stirred water sample followed by 30 minutes of mixing to ensure complete hydration. The foaming agent was added and stirred in gently. Three foaming agents were used in this study: anionic Foamer A, nonionic Foamer B, and zwitterionic Foamer C.
Optimized Technical and Commercial Strategy for Marginal Field Re-Entry – A Case Study
Authors: Onwuemene Onyeka
Published: August 2021

This paper examines an optimized strategy and approach for executing a marginal field re-entry in the face of harsh global economic realities in the oil and gas sector.

With dwindling and depressing oil prices driven by demand & supply volatility with root causes traceable to some factors such as the prevalent health pandemic, clamor for green energy, climate change discussions, geopolitics etc, the operating model for oil companies will need to drastically change to reflect current realities.

Due to rapid global urbanization and increasing population amongst other factors, there is a corresponding huge appetite for oil to meet energy demands. This has led to exploration in unconventional terrains, utilization of the full extent of primary and secondary recovery mechanisms to attain high RFs in already producing fields and in some extreme cases, the development of marginal fields.

In the Niger Delta area of Nigeria, marginal fields usually given up by Oil majors or abandoned following production exigencies and government laws are acquired and operated by indeginous companies. These indigenous players look for the most cost-effective means to produce these assets as it becomes the only way to make profit.

A case study for field re-entry in the Niger Delta, which emphasized relatively/comparatively reduced capital outlay dependent on the technical approach is examined. Lessons learnt are drawn to aid enlightened go-forward actions and that will ensure a go-to template for similar future marginal field re-entry projects.
Reducing Accidents Through the Implementation of the Minimum Industry Safety Training for Downstream Operations Mistdo in the Nigerian Oil and Gas Industry
Authors: Edem Michael , Nwankwo Okechukwu , Muku Jennifer , Usman Fatima , Ike Chidi
Published: August 2021

The Department of Petroleum Resources (DPR), the Petroleum Regulatory agency of the Nigerian oil and gas industry is mandated by law to investigate accidents in the industry. Data obtained from the oil and gas accident database from the Department of Petroleum Resources shows that accidents in the downstream sector contribute about 70%, when compared to the upstream sector. One of the reoccurring root causes from investigations point to administrative barrier failure – which is a lack of training and re-training of staff in the downstream sector on workplace safety. Against this background, the DPR introduced the Minimum Industry Safety Training for Downstream Operations (MISTDO) as part of the Safety Audit Clearance policy launched to drive safety in the downstream sector. MISTDO is a basic safety training which must be undertaken by all personnel working in the downstream sector of the Nigerian oil and gas industry. This paper reviews the recorded accidents that have occurred in the downstream sector between 2014 – 2019; examines the MISTDO courses for the various workers in downstream facilities; analyses the MISTDO tripartite model (Training provider, Operator and DPR) adopted; the effects of implementation of MISTDO and concludes with the value additions of the MISTDO program to the industry.
The Environmental Accounting: Experiences From Overseas and Solutions for Marginal Field Operators in Nigeria
Authors: Oruwari Humphrey Otombosoba
Published: August 2021

Marginal oil field operators have been bedeviled by several challenges since its inception, among which are financial, technological, socio-political, ecological and environmental issues. The study examined how marginal oil field operating in Niger Delta region of Nigeria could integrate and incorporate environmental accounting for managing the environmental performance of their businesses efficiently. Using literature review and case study, the study revealed that at present, environmental accounting is gradually being implemented worldwide. It is the duty of companies to apply environmental accounting to the lives of individuals. The study summarizes some key points regarding environmental accounting, the introduction of environmental accounting in some countries around the world and demonstrates some challenges in our country's application of environmental accounting to provide some solutions to boost the application of environmental accounting to marginal oil field operators in Niger Delta. The study recommends that environmental accounting will enhance the operations of marginal oil field in Niger Delta region.
Optimization of the Turnaround Time and Quality of Production-Screening Tests in Offshore Fields – Some Case Studies
Authors: Eyitayo Stella I. , Lawal Kazeem A. , Abdullahi Ibrahim , Matemilola Saka , Akadang John , Anyanwu Victor , Ainoje Bernard , Alabi Tunde , Owolabi Segun
Published: August 2021

Production-screening test (PST) is performed on a reservoir drill-in fluid (RDIF) prior to running any component of the lower completion assembly that is vulnerable to plugging. This is applicable in open-hole completions in which wire-wrapped production screens are deployed. The key objective of a PST is to reduce the risk of plugging key completion components, such as production screens, during subsequent flow back. Hence, a PST increases the chance of preserving well productivity (or injectivity), ultimate recovery and project economics. However, conducting and achieving PST-quality RDIF in offshore fields can be cumbersome, time-consuming, and expensive, yet the quality is not guaranteed.

This paper presents the formulation, implementation, and results of a simple strategy to reduce the turnaround time and costs of achieving PST-quality RDIF for applications in offshore fields. Employing a combination of on-the-job assessment, empirical data and expert opinions, the strengths and weaknesses of onsite versus offsite (onshore) options of preparing PST-quality RDIF for offshore operations are evaluated.

As a case-study, empirical data from the execution of both onsite and offsite options for an example field are employed for the evaluation. Results of simple cost-time-benefit analysis underscore the robustness and competitiveness of preparing the PST-quality RDIF offsite and transporting same for subsequent test validation and application on the rig.

The results of these empirical examples show that the offsite option yields about 75% cost-saving relative to its onsite counterpart. In addition to cost saving, other incremental benefits of the former include (i) significant reduction in rig time and personnel; (ii) improved RDIF quality; and (iii) higher chances of preserving well performance and economics. To increase the success rate, residual risks of the preferred offsite option are outlined, and relevant mitigations provided.
Gravity Drainage System: Investigation and Field Development Using Geological Modelling and Reservoir Simulation
Authors: Ezeaneche Obinna Somadina , Madu Robinson Osita , Oshilike Ishioma Bridget , Athoja Orrelo Jerry , Onyekonwu Mike Obi
Published: August 2021

Proper understanding of reservoir producing mechanism forms a backbone for optimal fluid recovery in any reservoir. Such an understanding is usually fostered by a detailed petrophysical evaluation, structural interpretation, geological description and modelling as well as production performance assessment prior to history matching and reservoir simulation.

In this study, gravity drainage mechanism was identified as the primary force for production in reservoir X located in Niger Delta province and this required proper model calibration using variation of vertical anisotropic ratio based on identified facies as against a single value method which does not capture heterogeneity properly. Using structural maps generated from interpretation of seismic data, and other petrophysical parameters from available well logs and core data such as porosity, permeability and facies description based on environment of deposition, a geological model capturing the structural dips, facies distribution and well locations was built. Dynamic modeling was conducted on the base case model and also on the low and high case conceptual models to capture different structural dips of the reservoir.

The result from history matching of the base case model reveals that variation of vertical anisotropic ratio (i.e. kv/kh) based on identified facies across the system is more effective in capturing heterogeneity than using a deterministic value that is more popular. In addition, gas segregated fastest in the high case model with the steepest dip compared to the base and low case models. An improved dynamic model saturation match was achieved in line with the geological description and the observed reservoir performance. Quick wins scenarios were identified and this led to an additional reserve yield of over 1MMSTB.

Therefore, structural control, facies type, reservoir thickness and nature of oil volatility are key forces driving the gravity drainage mechanism.
A Simple Strategy For Subsurface Delivery of Effective Development Wells – Field Examples
Authors: Salako Abdulganiyu , Pelemo Bosun , Otubanjo Modupe , Lawan Zainab , Olushoga Elizabeth , Eyitayo Stella , Ukaonu Cyril , Lawal Kazeem A. , Matemilola Saka , Owolabi Segun
Published: August 2021

Well delivery is an expensive scope in the exploration and field development process. Among other drivers, an ideal well must be delivered safely while achieving top-quartile performance on cost, schedule and business objectives. However, delivering an ideal well amid subsurface uncertainties and tightening budgets is usually challenging.

As part of the drive for continued value creation, this paper presents an empirical process-improvement initiative for de-risking and optimizing the landing of the drain-hole sections of highly deviated wells amid subsurface uncertainties and at minimal costs. A review of the conventional procedure for executing subsurface scope of the delivery of development wells has been accomplished. The review takes advantage of a combination of recent experiences in delivering four horizontal development wells in an offshore field in the Niger Delta, in addition to a catalogue of available knowledge and best practices from other fields and operators.

This review culminates in an improved well delivery optimization process and practice. In addition to promoting operational HSE excellence, it increases the chance of delivering an ideal well, including the mitigation of a subsurface-related non-productive time (NPT) and other related costs. As a complement to the practice, a simple workflow is provided to aid robust decision-making and facilitate applications in practice. For completeness, relevant examples are included to demonstrate the applicability of this new process.
The Implementation of Offshore Safety Program OSP in Nigerian Oil and Gas Industry- A Performance Assessment
Authors: Nwankwo Okechukwu. K , Muku Jennifer. S , Ogunbona Oladipo G. , Ike Chidi. B , Amosa Dr. Mutiu. K , Ogionwo Ebipador
Published: August 2021

The Offshore Safety Permit (OSP) Program is the Personnel Accountability System, being utilized by the Nigerian Oil and Gas Industry Regulator, in line with global best practices to manage the details of over 40,000 oil workers registered to work on offshore and swamp facilities and track their movements to-and-fro such facilities. The Program was introduced in 2012 to standardize requirement for personnel travel to offshore and swamp locations and to eliminate issues such as: non-compliance with mandatory competency and safety training; non-compliance with medical fitness to work requirement; unauthorized extended stay on facilities at offshore/remote location; inaccurate documentation of personnel movement to-and-fro facilities at offshore/remote location leading to delayed/wrong incident reporting. This paper examines, through the review of the OSP policy, Guidelines and database, the value addition of the program since its inception., detailed and insightful discussions are made on the importance and potentials of the OSP program as a simple but integral policy and planning tool in managing risks, enhancing collaboration and improving safety and emergency services in Nigeria's oil and gas industry.
Understanding Oilfield Scale Deposition and Inhibition Mechanisms for Optimum Management: A Review
Authors: Adegoke Samuel Oluwafikayo , Falode Olugbenga Adebanjo , Nwankwo Princess Christiana
Published: August 2021

Oilfield scales are crystalline minerals made up of Na, K, Mg, Ca, Ba, Sr, Fe, Cl from produced water that can precipitate out in the reservoir, well, pipelines and process during the production and transportation of oil and gas. These precipitates can deposit as a result of thermodynamic and/or chemical changes and pose costly flow assurance issues to the oil industry. Several factors have been identified to be responsible including temperature, pressure, ionic strength, pH, evaporation, bicarbonate anion, super-saturation and contact time and water chemistry. Attempts to solve this problem in the past have focused mainly on the use of chemical inhibitors and the most accepted mechanism of scale inhibition is squeeze injection method. While adsorption and retention of scale inhibitors on rock formations needs more research, there had been improvement to better ways of ensuring adsorption and precipitation through nanotechnology including the use of nano-carbon enhanced squeeze treatment (NCEST). The uses of these conventional inhibitors have been found to be toxic to the flora and fauna in biotic communities during water disposal. In order to reduce the environmental burden caused by these conventional solutions and still manage the problem effectively, greener solutions have been proposed. This review x-rays the mechanisms of scale precipitation and deposition, evaluate the solutions that have been provided in literature based on efficiency, economics and environmental impact and propose guidelines to field operators in selecting optimum solutions.
Integrated EOR Screening in a Marginal Oil Field Environment
Authors: Uche Chukwunonso , Esieboma Samuel , Uche Jennifer , Bukar Ibrahim
Published: August 2021

An evaluation of potential EOR processes applicable in the marginal oil field operation of the Niger Delta region is presented. Technical feasibility, process availability, oil recovery potential, and other uncertainties and risks associated with exploitation of enhanced oil recovery technique in a marginal oil field environment are being assessed. Few Enhanced oil recovery processes, namely polymer flooding, chemical flooding and microbial EOR (MEOR), are considered for possible application in this marginal oil field. The objective of the screening study is to evaluate and rank the EOR options and also select the most attractive method that will have to be further chased to a pilot test stage. Emphasis is strictly on a technical assessment of the incremental oil potential of each of the EOR methods and also identification of critical operational and logistical components of the entire process for their implementation in the offshore operating environment.

Recoverable volumes associated with EOR may be significant, but key project development and implementation challenges and extra cost elements must be considered in any EOR forecast for an effective EOR process ranking. Some of these concerns (e.g. Polymer/chemical supply, facilities requirements, and the impact of EOR on reservoir performance and wellbore integrity) may be significant enough to eliminate a method from being considered further and at that point the best EOR option that requires minimal cost exposure for achieving the best recoverable shall be considered.

Moreso, there is consideration of the quantity and quality of laboratory data that should support the viability of each EOR process being considered. This paper narrates the state of technical readiness for field implementation of each EOR method and identifies remaining work required to progress EOR process in this marginal oil field.
Hydrocarbon Volume Estimate Using Pseudo Steady-State/Pressure-Transient Principles in a Faulted Reservoir
Authors: Uche Chukwunonso , Uche Jennifer
Published: August 2021

The application of pseudo-steady-state and pressure transient response techniques to assist in hydrocarbon volume estimate is presented for a reservoir isolated from its main by a non-sealing fault. The techniques discussed in this paper utilized the pseudo steady state principle to determine the fault boundary behavior dominated flow regime of an oil well which has produced for over eight years in a marginal field of the Niger Delta environment. The material balance technique which utilized accountability of fluid withdrawn/injected and energy conservation principles within the pseudo steady state boundary dominated flow was used alongside with the pressure transient analysis to validate this oil in place number. Seismic attributes was also used to predict the geometry and distribution of the sand based on the conventional seismic interpretation. The seismic attribute analyses clearly show the geometry and spatial distribution of the reservoir sand bodies. Hence, understanding a pseudo steady state dominated regional flow time in a faulted reservoir plays a key role in the management and development of reserves in a marginal field operation.
A Novel Approach to Predicting Combustion Emission Using Ambient Air Quality Parameters in Onshore Eastern Nigeria
Authors: Omion Osemanre Ossy , Maduewesi Chioma , Chukwu Emeke
Published: August 2021

The paper aims to estimate the tCO2e from flare stack sites in the Eastern zone of Nigeria and review air monitoring done at the flare sites with the objective of establishing a model for gas tCO2e emission and gaseous pollutants. It focuses on the South-Eastern region of Nigeria where oil and gas production are being carried out (Imo and Abia states). It zero-in on the hydrocarbon processing and handling facilities (flowstation) and the gas flared volumes. The study was carried out using representative data from an onshore flowstation in Eastern Nigeria. The data consist of gas flared volumes from year 2013-2017 and ambient gaseous emission from air quality report done on the same location. Univariate regression and correlation using Excel were carried out on yearly average ambient air quality parameters (VOC, NOx, CO, SOx, CH4, SPM, NH3, H2S) to check the statistical significance of each parameter as an independent variable and calculated tCO2e as the dependent variable. Excel Muti-variate linear regression method was then used to generate a predictive model for tCO2e and gaseous emission parameters. It presented a relationship between the emission from flared gas and air quality index.
Design and Fabrication of a Carbondioxide Gas Leak Detection System for Oil and Gas Facilities
Authors: Amaobichukwu Chibuzor
Published: August 2021

In the recent past, there has been cases of carbon dioxide leak related incidents and casualties. Carbon dioxide has been recognized as a significant worthy hazard in the industrial environment for about 100 years. low concentrations of carbon dioxide are not harmful, but on a high concentration can affect the respiratory function and the central nervous system. This prompted the development of this carbon dioxide gas leakage detection system as a safety measure to reduce this risk. This carbon dioxide gas leakage detection is developed with an Arduino microcontroller and an MQ-135 sensor for a highly accurate and fast response system. The detection system incorporates an LCD Screen for displaying the status and level of concentration of the gas leakage, a buzzer as an alarm to give audio alerts, indicating and alerting users on the gas leakage, a number of LED lights to indicate the gas leakage status. The system also incorporates a GSM Module which sends SMS alerts and make calls to users during the gas leakage regardless distance. The Arduino microcontroller is programmed using embedded C++ language and all the peripherals connected to it through its pins. When the detector is in normal state, the LED light is lit on Green to show a normal range in concentration of gases and/or absence of a gas leakage. When there is gas leakage, the system transitions into a harmful state. The system displays the status of the gas leakage on the LCD Screen just as other LED lights light up in conjunction with an alarm buzz giving an audiovisual alarm to the monitoring mobile device. Also, the GSM Module sends out SMS alerts and calls to designated users regardless of their distance from the gas leak vicinity to notify them of the gas leak in order to take immediate action to control the gas leakage situation. The gas leakage detection is not only highly accurate but cheap and portable and can be used for industrial and domestic safety.
Conceptual Field Development Plan for X Field
Authors: Ibrahim Khadijah , Nzerem Petrus , Salihu Ayuba , Okafor Ikechukwu , Alonge Oluwaseun , Ogolo Oghenerume
Published: August 2021

The development plan of the new oil field discovered in a remote offshore environment, Niger Delta, Nigeria was evaluated. As the oil in place is uncertain, a probabilistic approach was used to estimate the STOOIP using the low, mid, and high cases. The STOOIP for these cases were 95 MMSTB, 145 MMSTB and 300 MMSTB which are the potential amount of oil in the reservoir. Rock and fluid properties were determined using PVT sample and then matched to the Standing correlations with an RMS of 4.93%. The performance of the different well models were analyzed, and sensitivities were run to provide detailed information to reduce the uncertainties of the parameters. Furthermore, production forecast was done for the field for the different STOOIP using the predicted number of producer and injector wells. The timing of the wells was accurately allocated to provide information for the drillers to work on the wells. From the production forecast, the different STOOIP cases had a water cut ranging from 68-73% at the end of the 15-year field life. The recoverable oil estimate was accounted for 33.25 MMSTB for 95 MMSTB (low), 55.1 MMSTB for 145 MMSTB (mid) and 135 MMSTB for 300 MMSTB (high) at 35%, 38% and 45% recovery factor.

Based on the proposed development plan, the base model is recommended for further implementation as the recovery factor is 38% with an estimate of 55.1 MMSTB. The platform will have 6 producers and 2 injectors. The quantity of oil produced is estimated at 15000 stbo/day which will require a separator that has the capacity of hold a liquid rate of about 20000 stb/day. The developmental wells are subsequently increased to achieve a water cut of 90-95% with more recoverable oil within the 15-year field life. This developmental plan is also cost effective as drilling more wells means more capital expenditure.
Eco-Toxicity of 2-Di Methylamino Ethylmethacrylate 2-DMAEM as a Commercial Kinetic Hydrate Inhibitor KHI
Authors: Elechi Virtue Urunwo , Ikiensikimama Sunday Sunday , Ajienka Joseph Atubokiki , Akaranta Onyewuchi Emmanuel , Okon Okon Efiong , Chris Davies Ibienebo
Published: August 2021

Gas hydrates are known impediments to flow. Mitigation of gas hydrates in deep offshore with accessibility issues is by chemical injection. This paper considers the effect of 2-Di(methylamino) ethylmethacrylate (2-DMAEM) a kinetic gas hydrate inhibitor and a Local Inhibitor (LI) on Clarias gariepinus, a marine organism. The assessment was done using Random Complete Block Design (RCBD), a standard method of toxicity testing. Its effect was compared to that of a local Inhibitor (LI). The test carried out showed that at the end of the exposure period, 2-DMAEM caused 100% mortality in concentrations of 10 and 100ml/L and had significant differences in water parameters across the row as concentration increased. The LI caused 0% mortality in same concentration ranges and had no significant differences as concentrations increased across the row. 2-DMAEM should be discarded as an inhibitor given its inherent danger while LI should be harnessed and developed as gas hydrate inhibitor.
African Continental Free Trade Agreement: the Pros and Cons on the Oil and Gas Industry in Nigeria
Authors: Ayodele Emmanuel , Akpogomeh Oshogwe , Amuah Freda , Maduabuchi Gloria
Published: August 2021

Nigeria has oil and gas as her major source of revenue, accounting for more than 80% of her foreign exchange, with the AfCFTA, that has been signed and ratified not just by Nigeria but by other African countries taking away tariffs on goods and services produced across the continent irrespective of the market where it's been sold. The AfCFTA being the second largest free trade agreement in the history of World Trade Organization is aimed at uniting African markets. This paper aims to review the framework of the continental free trade agreement, it pros and cons, its grey area, and its impact on the Oil and Gas Industry in Nigeria. The impact of the agreement on the local industries servicing the oil and gas industry is considered as well. The paper reviews the possible advantage of the AfCFTA on the Nigerian oil and gas market. The possible threats to nationalization in the oil and gas industry due to the availability of cheap labour and technical expertise across the continent in the country is analyzed. Solutions to protect the oil and gas industry in Nigeria is recommended as well.
Carbon Dioxide Sequestration Using Activated Carbon From Agro Waste-Waste Bamboo
Authors: Ayodele Emmanuel , Ezeagwula Victoria , Igbokwubiri Precious
Published: August 2021

Bamboo trees are one of the fastest growing trees in tropical rainforests around the world, they have various uses ranging from construction to fly ash generation used in oil and gas cementing, to development of activated carbon which is one of the latest uses of bamboo trees. This paper focuses on development of activated carbon from bamboo trees for carbon capture and sequestration. The need for improved air quality becomes imperative as the SDG Goal 12 and SDG Goal13 implies. One of the major greenhouse gases is CO2 which accounts for over 80% of greenhouse gases in the environment. Eliminating the greenhouse gases without adding another pollutant to the environment is highly sought after in the 21st century. Bamboo trees are mostly seen as agricultural waste with the advent of scaffolding and other support systems being in the construction industry. Instead of burning bamboo trees or using them for cooking in the local communities which in turn generates CO2 and fly ash, an alternative was considered in this research work, which is the usage of bamboo trees to generate activated, moderately porous and high surface area carbon for extracting CO2 from various CO2 discharge sources atmosphere and for water purification. This paper focuses on the quality testing of activated carbon that can effectively absorb CO2. The porosity, pore volume, bulk volume, and BET surface area were measured. The porosity of the activated carbon is 27%, BET surface area as 1260m²/g. Fixed carbon was 11.7%, Volatility 73%, ash content 1.7%.
Flow Behavior of Horizontal Well Completed Within Two Sealing Faults Inclined at Right Angle
Authors: Johnson Johnson , Adewole Ezizanami
Published: August 2021

At inception of a production rate regime, a horizontal well is expected to sweep oil within its drainage radius until the flow transients are interrupted by an external boundary or an impermeable heterogeneity. If the interruption is an impermeable heterogeneity or sealing fault, then the architecture of the heterogeneity must be deciphered in order to be able to design and implement an effective work-over or well re-entry to boost oil production from the reservoir.

In this paper, therefore, the behavior of a horizontal well located within a pair of sealing faults inclined at 90 degrees is investigated using flow pressures and their derivatives. It is assumed that the well flow pressure is undergoing infinite activity, and each fault acts as a plane mirror.

The total pressure drop in the object well is calculated by superposition principle. Damage and mechanical skin and wellbore storage are not considered. The main objective of our investigation is to establish identifiable signatures on pressure-time plots that represent infinite flow in the presence of adjacent no flow faults inclined at 90degrees.

Results obtained show that the flowing wellbore pressure is influenced strongly by object well design, object well distance from each fault, and distance of each image from the object well. Irrespective of object well distance from the fault, there are three (3) images formed. Central object well location yields a square polygon, with two image wells nearer to the object well at equidistance from the object well, and the farthest image well to be 2d2. From the object well For off-centered object well location within the faults, a rectangular polygon is formed, with each image at a different distance from one well to another. Dimensionless pressure and dimensionless pressure derivative gradients during infinite-acting flow are (4.6052/LD) and 2/LD, respectively for all well locations within the faults.
Design and Development of a Solar-Powered Pump System with Liquid Level Sensor and Controller Using Internet of Things Iot Technology
Authors: Ejimuda Chinonyelum , Okoli Kingsley
Published: August 2021

Renewable energy in our world today has greatly helped the ecosystem by reducing the amount of carbon content in the atmosphere. Recent studies have shown that the dependence on the National grid and fossil fuels for generating power for pumps is becoming alarming and as such, an alternative source for energy generation to power the pump system necessitated this research. The research relies on solar-generated power for driving pumps as opposed to fossil fuels. A submersible centrifugal pump was used because of its wide usage in various industries such as Oil and Energy, Pharmaceutical, Breweries, Production industries, Water corporations, Domestic and Commercial buildings, etc.

We designed and constructed an automatic solar-powered pump system, integrated, and programmed the sensors using Arduino microcontroller and C++ programming language, respectively. We analyzed the telemetry data from the sensors and predicted the illuminance of light on the solar panel and sent the information via a web server using a GSM module. The solar-based pumping system consists of a submersible centrifugal pump, solar panel, solar charge controller, battery, remote controller, GSM module, photo sensor and a liquid level sensor. The photo sensor returns values ranging from 0 to 1023. The higher values: 700 – 1023 indicate that the sensor is in darker surroundings. The lower values: 0 - 650 indicate lighter surroundings when there is sufficient light on the sensor or its surroundings on the web server which display the plotted values in real-time. The system has been found to be viable and economical in the long run compared to the conventional system which uses fossil fuels. The solar energy received from the sun is converted to electrical energy by the solar panel. A proportion of the energy is used during the day while some is stored in the battery to be used at night or when the weather is cloudy. The controller regulates the liquid level in storage with the aid of liquid level sensor and affords the user the opportunity to control the system remotely. This system can be used for small and remote applications.
Improving Water Injectivity Through Lateral Radial Drilling into the Reservoir
Authors: Essien Effiong , Onyejiaka Uchenna , Onwukwe Stanley , Uwaezuoke Nnaemeka
Published: August 2021

Poor formation permeability and near well bore damage may limit water injectivity into the reservoir in a water injection project. This paper seeks to evaluate the effect of radial drilling technique on water injectivity and oil recovery in water flooding operation. Radial drilling technology utilizes hydraulic energy to create lateral perpendicular small holes through the casing into the reservoir. The holes may extend to 100 m (330 ft) into the reservoir to access fresh formations beyond the near wellbore, and damage zone. A black oil simulator (Eclipse 100) was used to modeling a lateral radial drill from the borehole into the reservoir, and that of a conventional perforation of the wellbore respectively. A simulation study was carried out using various presumed radial drill configurations in determining injectivity index, displacement efficiencies, recovery factor and water cut of the process. The determined results were further compared with that of the conventional perforation process case respectively. The results show a significant improvement in water injectivity in radial drill case with the increasing length and number of radials as compared to the conventional wellbore perforation case. The determined Recovery factor shows a progressive increase with increase in the numbers of radials drilled, irrespective of the radial length. However, it was observed that, the more the number and length of the radials drilled in to the reservoir, the higher the water cut from producer wells. Radial Drilling Technology, therefore, has a promising potential to improving water injectivity into the reservoir and thereby optimizing oil recovery in a water flooding operation.
Uncertainty Management Using Multi-Scenario Modeling in a Partially Appraised Field
Authors: Okechukwu Sedoo , Orekoya Adedoyin , Alamina Precious , Anyaehie James , Sonde Adekoyejo , Ozoemene Uchechukwu
Published: August 2021

Considering the imminent end of the ‘easy oil’ era, the increasing demand for energy and the global push towards the energy transition, oil and gas companies are more than ever interested in sustainable ways to develop marginal and complex hydrocarbon fields economically, through the application of technology and maximization of data analysis. In small partially appraised fields where the cost of drilling an appraisal well could derail the project economics, it becomes necessary to sweat the limited data available for reservoir modelling. The uncertainty analysis must be robust enough to ensure that the adopted field development strategy would yield a positive net present value despite the wide uncertainties associated with the field.

The conventional workflow for subsurface uncertainty modelling involves defining the uncertainty ranges of static and dynamic reservoir parameters based on a single reservoir model concept. This paper focuses on a marginal field case study where the multi scenario modelling approach was adopted. This approach considered alternate reservoir geologic concepts based on different interpretations of the reservoir architecture, taking full cognizance of the available data, reservoir uncertainties and regional geology knowledge.

Field Alpha is located onshore of Niger Delta in Nigeria. The geologic setting consists mainly of multi-storey, complex channel-belt systems, incising through Shoreface deposits. The reservoir of interest is an elongated structure with only two well penetrations located at the opposite distal part of the structure. The key reservoir uncertainties are reservoir structure, architecture, connectivity, and property distribution. Two possible distinct architecture were interpreted based on regional correlation and seismic. This paper focuses on how the interpretations and other information informed a robust development strategy that yielded significant (30 %) reduction in development cost and positive net present value.