bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluating the Effects of Petrophysical Properties on Oil Initially in Place
Authors: Essien Alicia , Akpabio Julius 
Published: August 2020

Abstract
In oil and gas exploration and production, it is essential to have a reliable estimation of Oil initially in Place (OIIP). Reliable reserve estimation depends on the petro physical data used in the volumetric method of estimating OIIP. This estimation is done at the primary phase of exploration where production data are not yet available. The effects of petrophysical data and their sensitivity on OIIP were determined. Average petrophysical data were obtained from reservoir X, Y and Z within the Niger delta and analyzed by running a Monte Carlo simulation using computer-based application such as MS Excel and MS Minitab (Design of Experiments (DOE). 10,000 random data sets were generated for each petrophysical property from the average field data obtained from Reservoirs X, Y and Z in the Niger Delta region. The simulation results were further analyzed using sensitivity indices and Tornado plots. For reservoir X, the percentage effect of porosity, oil saturation, pay thickness, drainage area, oil formation volume factor (oil FVF) on OIIP were 97, 95, 90, 70, and 5 respectively. For Reservoir Y, the percentage effect of porosity, oil saturation, pay thickness, drainage area, and oil FVF on OIIP were 95, 89, 83, 58, and 4 respectively. For Reservoir Z, the percentage effect of porosity, oil saturation, pay thickness, drainage area, and oil FVF on OIIP were 95, 89, 80, 75, and 4 respectively. Results from the various analysis carried out proved that porosity had the highest and positive effect on OIIP, followed by oil saturation and pay thickness, oil formation factor has the least significant effect and in some cases negative effect on estimated OIIP. In the long run, these understanding will help the reservoir engineer identify the sensitivity of each parameter when carrying out volumetric estimation of OIIP and also the need for sourcing quality reservoir and petrophysical data using different available cost-effective and efficient methods.
22yrs After Longford Gas Plant Explosion, are We Threading the Same Path?
Authors: Shittu Ganiyu Adio 
Published: August 2020

Abstract
On Friday, 25 September 1998, the Esso Australia's gas plant at Longford in Victoria suffered a major fire. Two men were killed, eight injured and the state's gas supply was severed for two weeks, causing chaos in Victorian industry and considerable hardship in homes, which were dependent on gas.
The main cause of the fatal accident was attributed to a re-organization of the site personnel that led to drastic reduction of personnel available on site.
Hence, several experience personnel were moved to the office to provide support to field locations and the situation which led to the fatal incident was not managed properly because of lack of knowledge of the team on site.
Oil and Gas companies are back to restructuring and reorganization to manage the difficult economic terrain and competition to drop the cost/barrel, are companies taken note of the lessons from Longford or are they just focusing on the team structure without proper risk assessment for safe change management. Companies have introduced lean projects or restructuring to manage the number of personnel onboard producing fields to the barest minimum with intention to reduce the number of personnel exposed in case of emergency, manage the cost/barrel and also make experienced personnel available at a center designated either as SMART Room or Support center to provide services to all field locations instead of these personnel staying on different sites which will require more personnel.
Personnel involved in this program were engaged and their experiences taken on board to provide a preliminary information on these new concepts for management to focus on the blind spots.
Therefore, Lost Time Injuries (LTI) data are largely a measure of the number of routine industrial injuries, however explosions and major fires are rare, do not contribute to the LTI figures in the normal course of events. LTI data are thus a measure of how well a company is managing the minor hazards, which result in routine injuries, but they tell us nothing about how well major hazards are managed. Hence, the great performance being recorded with the migration to new structures should not make us lose the fact of the potential dangers if the rapid changes are not managed with painstaking change management to ensure all sections are adequately risk assessed and compensated for realistically.
Robust Diagnostics Optimize Decisions on Innovative Deepwater Gravel-Pack Interventions for Water Conformance
Authors: Khong Chee Kin , Sookram Neil , Mukerji Parijat , Cruz Mauro , Martins Fernando , Zett Adrian 
Published: August 2020

Abstract
Surveillance in deep water wells is cost prohibitive. There is a need for significant hydrocarbon production or water shutoff incentive to justify the intervention in such wells. The wells straddle multiple stacks of soft sediment reservoirs, being completed with open hole gravel pack. While laterally extensive barriers between various sands units might help the water shutoff / containment, the gravel pack annulus still provides a conduit for water to move upwards and jeopardize the shutoff success. In this campaign a meltable alloy was deployed to plug the flow in both annulus and screens.
In deep water subsea wells, water conformance control is often attempted blindly without flow diagnostic surveillance or production logs as a minimum. This can impact the production due to plugging substantial hydrocarbon production or inadequate flow from the remaining zones. Candidate wells or techniques for shut-off require robust diagnostics to improve the success rate and limit loss of oil or gas production.
In a recent well work campaign production logs were acquired to optimize the water shut-off. Well access is challenged by limited rigup height (short lubricator) and well deviation. The well trajectory impacts the phase presence, mixing and recirculation. It requires a short array of sensors conveyed on tractor. Logging while tractoring capabilities in surface readout mode is required to minimize the rig time, improve depth control and perform real time data quality assurance.
The multiple mini-spinners, electrical and optical probes are all positioned to the well's vertical axis to capture all local changes in the flow regimes. Sensor arrangement is sufficiently compact in this tool to minimize flow disturbance by tool occupancy and movement along the well. Real-time profiling of the complex flow regimes during the acquisition provided better log control and understanding of the downhole phase dynamics.
Changing the mindset about subsea deep-water reservoir surveillance paid dividends in water shutoff operations, both for immediate decision make and for longer term well and reservoir performance management. There was a net benefit by deploying a compact axial array production logging string that allowed accurate rate and phase allocation and further identification of zones to be isolated using an innovative plug-back method that significantly reduced the water production.
Optimisation of Thermal Insulation of Subsea Flowlines for Hydrates Prevention
Authors: Abegunde Mobolaji , Adeyemi Adekola 
Published: August 2020

Abstract
In the development of an oil field, the assurance that produced hydrocarbon will flow is a critical determinant for the development of an oil and gas field even when other disciplines such as subsea design, reservoir engineering, artificial lift equipment, pipeline engineering have done a thorough analysis. Hydrate formation is one of the challenges of flow assurance in an oil and gas pipeline especially those installed in deepwater oil fields. Insulation of subsea pipelines is paramount to the prevention of hydrate formation. This work investigates the best material that is suitable for the thermal insulation of subsea flowlines using the ANSYS software package, and then provide the best composite arrangement of insulation materials for better heat optimisation. Four insulation materials were considered; Aerogel, Mineral Wool, Paraffin Wax and Grooved Mineral. A pipe-in-pipe (PiP) flowline model filled with fuel oil, at an inlet temperature of 60°C, was simulated on ANSYS by varying the configuration of the respective insulation material sheath; the heat transfer method in the PiP is by convection from the outer pipe to the ocean ambience at a temperature of 4°C. Results obtained from the simulation established that Aerogel is best for insulation among those considered, this is because of its low thermal conductivity and high specific heat capacity; in contrast, Grooved Mineral simulation result presented a poor performance. To ensure maximum heat conservation through optimum insulation, a composite configuration of insulation materials was proposed.
Assessment of Health, Safety and Environment Impact of Flavonoid-Derived Demulsifiers
Authors: Airiagbonaye Florence , Achugasim Ozioma , Akaranta Onyewuchi 
Published: August 2020

Abstract
This paper aims at quantifying the Health, Safety and Environment (HSE) impact of some flavonoid-derived demulsifiers using Chemical Scoring Index (CSI). The CSI is based on the three-hazard categories defined by United Nations' Globally Harmonized System for Classification and Labeling of Chemicals (GHS) for defining greener chemicals. Chemical components of each flavonoid-derived product were quantified by scoring the level of hazard posed by the component in relation to its percentage composition in the product.-a carcinogen in a 10% component of a product will be scored higher than in a 1% composition. Additionally, a carcinogen is weighted higher than an ‘irritant’. As such, products with low CSI within same usage group are considered to have lower intrinsic hazard and therefore used in selecting best HSE green chemicals. Eight (8) products were quantified; five (5) modified flavonoids and three (3) commercial demulsifiers. ‘Modified Flavonoids-A’ was considered best HSE chemical with a CSI of 420, while ‘Commercial demulsifier-B’ was the least HSE chemical with CSI of ‘1980’. It is recommended that rather than focus on only the performance and cost of a chemical product, it is essential to consider the Health, Safety and Environment impact in the selection of oilfield chemical products. This model will assist HSE professionals in quick assessment of safer chemicals alongside their performance.
Flow Barrier Detection and Characterisation using Capacitance-Resistance Model: Case Study of a Far East Oil Field
Authors: Ogali Oscar I. , Orodu Oyinkepreye D. 
Published: August 2020

Abstract
The Capacitance-Resistance Model (CRM) is a semi-analytical modelling approach utilizing non-linear multivariate regression. Using historical production and injection rates, as well as historical bottomhole pressure data if available, CRM quantifies the connectivity and degree of fluid storage between injectors and producers in a reservoir. The CRM has been applied to waterflood management and performance prediction, improved reservoir characterisation, waterflood optimisation and, production optimisation. In this study, the CRM was used in fault characterisation and flow barrier detection. Historical production and injection data from an oilfield from the "Far East" were then used to calibrate the CRM. Thereafter, the resulting CRM parameters were combined with geological data and wells data to characterise two major faults in the reservoir, as well as detect other flow barriers within the reservoir. Based on the results, several sections of one fault have varying degrees of communication. There were also smaller flow barriers within the reservoir section considered around this fault, that negatively impacted the performance of some injectors. The second fault was mostly sealing, with few leakages along the extent of the fault. Capacitance-Resistance Modelling can be used to corroborate the results of Interference Testing, Tracer Test and 4D Seismic in detecting and characterising faults, and as a cost-effective reservoir management tool.
Flared Gas Monetization in Nigeria-Status, Challenges & Opportunities
Authors: Anioke Oluchi , Obuh Matilda , Muhammed Amin , Iyalla Ere 
Published: August 2020

Abstract
The need to eliminate gas flaring & ultimately monetize flared gas in Nigeria is of utmost economic, social and environmental importance. This is because studies indicate that, across the Niger Delta, there are over 178 flare locations from which an estimated 800mmscf of gas is being flared daily. A Nigerian government initiative, The Nigerian Gas Flare Commercialization Programme (NGFCP), is working to achieve a near to total gas flare-out target by the end of 2020. This is planned to be attained via an initial phase programme strategy of mobilizing private sector capital towards gas flare capture projects. The next phase of the program's strategy is to develop a world class investment approach, optimize supply through domestic market utilization and create strong partnerships with the world's most innovative energy countries. The untapped potential and prospects of monetizing flared gas can contribute significantly to the country's economy as it can be utilized domestically through various technologies such as the mini gas to power (GTP), mini gas-to-liquid (GTL), and as compressed natural gas (CNG). A concise study was undertaken, carrying out an in-depth analysis of challenges and issues pertaining to the contracts and market outlets for products of these proposed gas flare-out projects. The study also explored supply chain improvement opportunities and the most effective technologies that could be deployed to take the flared gas to market at the least risk. Based on the studies carried out, the paper seeks to propose best case scenarios for the efficient and effective monetization of Nigeria's flared gas within socio-economic, political and infrastructural contexts of the country.
Implications of Petroleum Industry Fiscal Bill 2018 on Heavy Oil Field Economics
Authors: Nwosi-Anele Adaobi Stephenie , Illedare Omowunmi , Adeogun Oyebimpe 
Published: August 2020

Abstract
Recent increase in energy demand has made necessary the exploitation of Nigerian heavy oil fields neglected in the 1990s. These heavy oil fields were neglected due to low oil price and lack of technology to aid their recovery. Stakeholders in the heavy oil sector have been divided over what fiscal framework applies for the exploitation of Nigerian's heavy oil. The Nigerian Oil Industry has a well-developed fiscal framework for light and medium oil exploitation and the Proposed Petroleum Industry Fiscal Bill (PIFB) 2018. This work studies the economics of an onshore heavy oilfield under the PIFB 2018, to examine the implications of heavy oil exploitation using the PIFB 2018 as a fiscal policy. Field production profiles showing exponential, harmonic and hyperbolic field decline patterns were developed to represent 25.38% recovery factor for a heavy oil field of 196MMSTB OIIP. Deterministic models were built featuring the fiscal instruments of the PIFB 2018, heavy oil price, capital expenditure, operating expenditure and economic metrics. The stochastic model featured the impact of heavy oil price, capital expenditure, price escalation rate, discount rate, and peak production on the contractor's and host government takes for the PIFB 2018. Our stochastic results show that the output variables are most sensitive to heavy oil price, discount rate and capital expenditure. The petroleum industry fiscal bill 2018 is found to be an efficient fiscal policy for the host government and contractor, giving take statistics of 49% and 51% respectively. Varying oil price and discount rate did not make the investment unprofitable but reduced the investment ranking. Exponential decline behavior proved most profitable, while hyperbolic decline proves least profitable. Adjustments of two fiscal instruments of the PIFB was made to enable contractors produce heavy oil using unconventional recovery method and remain in business during periods of low heavy oil price.
Rejuvenating an Aging Asset through a Comprehensive Reservoir Simulation Study
Authors: Yusuf Nurudeen Oluwatosin , Tuitjer Eric , Silpngarmlers Lynn 
Published: August 2020

Abstract
With a peak production of ∼30,000 bopd, "Field_M" was one of the most prolific fields in Niger-delta. However, over a forty-year period, production has declined to less than 3% of the peak value. In order to unlock new potentials in this asset, a multi-disciplinary team embarked on an asset re-assessment using reservoir simulation studies while focusing on the top reservoirs in the field with the highest expected incremental recovery. The first group of studies were done on a genetically related stack of four (out of available eleven) reservoirs: two depleted reservoirs and two virgin reservoirs, using a single comprehensive structural and stratigraphic framework.
For virgin reservoirs, probabilistic simulation studies were conducted with decoupled static and dynamic parameters. The most dominant parameters were identified and used to guide selection of P10/P50/P90 models. Sensitivities studies were conducted under different recovery mechanisms and different development scenarios using both idle wellbores and new wells. Erstwhile economically challenged opportunities due to small in-place volumes were improved by consolidating these opportunities. Integration of new opportunities were facilitated using the comprehensive model which allowed the testing of wellbores across all reservoirs simultaneously1.
For depleted reservoirs deterministic history matches were done using available pressure and production. History match helped to characterize connectivity between faults and across multiple lobes in these reservoirs2, an important factor in planning infill drilling. Post history match sensitivities provided reactivation opportunities and infill developments under secondary recovery mechanism.
The study outcomes will drive implementation of waterflood in these reservoirs in addition to non-rig intervention and infill drilling. The study identified a total of nine opportunities: two reactivations, two new injection strings and five new producing strings with an incremental recovery of 26 MMBO.
Effect of Polymer Additives on the Rheology and Fluid Loss of Water Based Muds
Authors: Adeyemi Gbadegesin , Fadairo Adesina , Ogunkunle Temitope , Oladepo Adebowale , Oredeko Olugbenga , Vitoria Ojei , Tomomewo Olusegun , ICHI Eberechi 
Published: August 2020

Abstract
In drilling operations, the effects of filter cake properties and filtration control on drilling fluid cannot be undermined in the process of wellbore construction and stability in order to obtain a successful drilling activity. This paper used experimental approach to investigate the effect of filter cake on fluid loss and formation damage using the formulated environmentally friendly water base polymers. Four mud samples were formulated separately, the first four mud sample were prepared with Acrylamide monomer (AAM) while the other four mud sample were done with Carboxylmethyl cellulose (CMC) by-polymer. The polymers varied for each sample from 5g-20g while other composition remain constant. High pressure high temperature fluid loss test was conducted on the formulated mud sample.
The results obtained with Acrylamide monomer (AAM) looks more interesting, giving a reduced fluid loss of about 8. lcm3 and a reduced filter cake thickness of about 0.042cm3 this means formation damage reduction with Acrylamide monomer (AAM) based mud. The Carboxylmethyl cellulose (CMC) fluid was found to be pseudo-plastic with shear thinning behavior, the fluid experienced a drastic decrease in plastic viscosity of 11 cp and yield point of about 351b/ 100fta, Acrylamide monomer (AAM) showed the higher shear rate and shear stress than Carboxylmethyl cellulose (CMC), it also acted as a better viscosifier. This can be attributed to the OH branches on the glucose rings, because of the negative charge it carries. The Acrylamide monomer (AAM) gave a relatively lower fluid loss with an increase in the polymer concentration and also gave lower filtration values at increased temperature and pressure conditions. Results shows that AAM reduces fluid loss better than CMC
Production Tubing Integrity Evaluation for Complex Workover Well Operations in Niger Delta
Authors: Anyanwu Chinedu , Agbo Ejimofor , Olusola Bukola 
Published: August 2020

Abstract
To successfully carry out a workover on a well that was completed more than 20 years ago as a dual string completion with a dual packer and two Permanent Packers is complicated. The presence of a slickline fish of unknown dimensions in hole further complicated the nature of the workover thus making it susceptible to failure during the retrieval of the tubings. A Tubing Integrity Evaluation Methodology (TIEM) was used to properly assess potential failure points and craft out execution strategy to mitigate them. The TIEM adopted in this paper involved carrying out a detailed tubing stress analysis on the completion tubings where axial loads exerted on the tubing; weight, buoyancy, point loads on crossovers, piston loads, ballooning; as well as triaxial stress effect of axial, radial and tangential stresses were all estimated. The yield strength and yield stress completion tubing were de-rated by 30 percent as a precautionary measure due to the age of the completion tubings. The maximum overpulls the tubings could sustain without failing by parting, axially or yielding triaxially were calculated. These overpull forces was compared with the force required to unseat the dual packer as well as snap out from seal assemblies of the permanent packers to decide whether the tubing was to be cut prior to pulling or not during the tubing retrieval operation. Several fishing scenarios of slickline and drill pipe fishing were analysed based on the location of the slickline fish. Based on the results of the detailed tubing stress analysis, the maximum overpull the short string and long string sections could sustain were 58,000 lbs and 23,000 lbs respectively while the maximum force required to unseat the dual packer was 50,000 lbs. Thus, it was decided to pull the short string within the overpull limit while the long string was to be cut above the packer prior to unseating the packer. The Tubing evaluation helped to properly assess potential failure points and craft out execution strategy to mitigate or avoid potential problems associated with the workover operations with unknown dimensions of fish in the wellbore.