bluuebunny/crossref_metadata_2025_split huggingface dataset:
Further Insight into Flow Contribution of Commingled Turbidite Reservoirs – A Deepwater Case Study
Authors: Chukwueke Njoku , Itua Osazua J. , Olubunmi Arogun , Chinenye Chukwuneke , Ipalibo Horsfall , Ringim Mohammed Hafiz 
Published: July 2017

Abstract
The Ajanla field is a deepwater turbidite field located offshore Nigeria. PLT data acquired across two turbidite "A" and "B" reservoirs in the Ajanla-P well before production commenced in the field demonstrated flow potential of the reservoirs at a proportion of 85% | 15% and 100% | 0% drainage contribution at flowrates of 12,000 bbls/day and 5,000 bbls/day respectively.
New infill drilling results and 4D seismic data acquired several years after production commenced have provided significant insight in the sweep pattern in the reservoirs. The 4D seismic data has indicated strongly channelized sweep in reservoir "A" but negligible pressureand saturation changes in reservoir "B". This interpretation was further verified by the results of the in-fill wells which showed low remaining hydrocarbon saturations in "A" but near virgin saturations in "B" after five years of commingled production from both reservoirs through Ajanla-P.
This paper investigates the interplay of several factors such as well completions integrity and water injection constraints critical to effective development of turbidite reservoirs and also discusses how the various data sources were integrated to improve understanding of the dynamics between reservoirs "A" and "B" and their possible impact on the future development of the reservoirs.
Pressure Balanced Modelling for Generating Production Forecast in an Integrated Oil and Gas Asset. A Pilot Case Study
Authors: Nwaokorie Chukwuemeka , Ekong Inem , Vlaardingerbroek Rene 
Published: July 2017

Abstract
Integrated Asset Pressure Balanced Modelling involves the coupling of the reservoir dynamic and surface facilities models into a single integrated tool that allows the simulation of the whole oil/gas field system.
The pilot study was conducted on the company’s export gas portfolio using pressure balanced model (PBM) in a Hydrocarbon Field Planning Tool (HFPT) platform.
In the simulation, HFPT uses a pressure-balanced solution of the integrated system: from the reservoir(s), through wells and surface facilities, to the delivery point. A wide range of fluid models is available, from simple gas-condensate and black oil PVT models to multi-component models with EOS flash calculations. HFPT provides optimization functionality for maximizing the returns in oil and gas fields, while accommodating operational preferences for production allocation and network constraints.
The results from this pilot indicate a successful integration of all subsurface discipline and surface data to create a pressure balance model that support our export gas supplies to NLNG. It also provides the platform to test the impact of the supply/facility constraints on our different portfolio projects.
An Unconventional Approach to Gas Injection - A Niger Delta Field Case Study
Authors: Kallel Narjes , Oni Olugbenga , Heiland Juliane , De Gennaro Vincenzo , Ramaswamy Sunil , Arasi Quadri , Campero Manuel Flores , Odumboni Idowu , Chemmarikattil Rohan , Osauzo Sam , Basu Subhayu , Otevwemerhuere Joseph 
Published: July 2017

Abstract
The use of gas injection and storage approach in enhanced oil recovery (EOR) is receiving increasing attention as an efficient solution to mitigate the effects of anthropogenic greenhouse gas emissions in the atmosphere, improve production by means of increasing static reservoir pressure, and allow optimized utilization of produced hydrocarbons as a function of actual consumption.
During gas injection a geological trap (i.e. active or abandoned reservoir) is used to store excess gas that can be eventually produced for future utilization. This process generates changes in pore pressure within the rock's porous space, affecting simultaneously the state of stress inside the reservoir and in its surroundings. These changes of the state of stress can be at the origin of instability mechanisms associated with fracturing inside and outside the reservoir and of reactivation of existing discontinuities (faults and fractures). If reactivation occurs within the caprock, this could lead to possible reservoir sealing failure and thus leakage of the stored gas at surface. Therefore, deformation of caprock and fault integrity must be assessed to properly manage containment performance and leakage-related risks. Given the intrinsic 3D nature of the problem, to ascertain the feasibility of injecting and/or re-injecting natural gas back into producing formations, it is essential to perform numerical simulations to capture the link between concomitant pressurization and /or depletion. The modelling is done with a 3D reservoir simulator and in-situ stresses changes are obtained by means of a 3D coupled reservoir geomechanics simulator.
A feasibility study of gas injection and storage in a producing reservoir was performed using coupled geomechanics modeling within an E&P software platform. The process started from single-well geomechanics analysis and then passed through 3D structural characterization and properties modeling, in-situ preproduction stress modeling, dynamic simulation, and, finally, injection modeling. Analyses were carried out using injection pressure modeled dynamically in an industry-standard reservoir simulator. This allowed various injection scenarios to be explored, providing a 4D characterization at various time steps in the future of the state of stress within the reservoir and its surroundings. Results highlighted the main risks, which are related to loss of sealing for the caprock and reactivation of induced faults, as well as uncertainties associated with input parameters.
Improving Gas Dehydration Using Pre-Inhibited Glycol
Authors: Achara Azubuike , Osuagwu Michael 
Published: July 2017

Abstract
A report is presented on natural gas dehydration performance of dehydration units in two different plants using a pre-inhibited glycol/antifoam/pH adjuster blend versus neat glycol with periodic injection of anti-foam and pH adjuster inhibitors.
To investigate the effect of using pre-inhibited glycol, two plants, each containing two gas dehydration trains (modules) were utilized such that while one train employed neat glycol with periodic chemical injection, the other employed the pre-inhibited blend with both trains running simultaneously. The two facilities were selected based on their history of poor dehydration and glycol regeneration performance and internal corrosion while using neat glycol. Performance was assessed based on resulting gas dew point, dissolved iron content, pH stability and glycol loss rate (in form of top-up frequency).
In all four KPIs selected for this study, the pre-inhibited blend out performed its counterpart significantly despite initial concerns that the fixed inhibitive properties of the blend may not be robust enough to address varying operational conditions. Glycol loss rates decreased by 67% and this led to a corresponding reduction in operating cost. Gas dew point was further depressed by more than 5°C thereby restoring the two facilities to within gas export specifications in compliance with Gas Sales Agreements (GSA). pH stability remained within the buffered zone of 8.5 – 10. As evinced by the decreased loss rates, foaming did not occur at this pH range as opposed to typical experience with neat glycol. Corrosion, being inherently more chronic than acute was not measured in this trial, although there was a progressive decrease in dissolved iron content with the pre-inhibited blend. These results imply that not only can dehydration performance be increased and operating costs decreased, but also that the traditional installation of pH adjuster and antifoam injection skids may prove unnecessary for future facilities
The insights made with this new pre-inhibited glycol blend approach presents strong evidence of an opportunity for significant reduction in both operating and capital costs for existing and future gas processing plants as well as a decrease in corrosion rates with prolonged plant life.
Lessons & Concerns from Experiences in Conception, Design and Constructions of Deep Wells in the Niger Delta Basin of Nigeria
Authors: Pedro Abiye Iyalla , Odiete Raphael 
Published: July 2017

Abstract
The experiences garnered in drilling deep wells in the Nigeria Delta Basin of Nigeria are presented herein. The referenced wells were drilled to the deep target series of gas and gas condensate reservoirs at depth range of 4900m – 5530m. The total volumes of the targeted reservoirs are about 60mmstb of oil and 1400bscf of gas.
There were challenges of stuck pipes in phases through some depleted zones/reservoirs that were resolved through brainstorming with the production unit of the company. Other challenges encountered and highlighted are in hole stability, bit selection, Well control, HSE, rig efficiency and cost performance. Drilling the wells in sequence exploits the benefits of immediate application of gathered experiences from the previous wells.
This paper presents the key challenges associated with the drilling of deep wells as experienced in the referenced wells.
Crude Oil and Associated Production Optimization: A Case Study of X Field in Nigeria's Niger Delta Region
Authors: Okafor Emeka , Kalagbor Christian 
Published: July 2017

Abstract
Almost always crude oil is produced in conjunction with associated gas and for the type of reservoir considered in this study, gas production rate over time increases with decreasing pressure. The problem of maimizing production and/or recovery can be addressed by adopting an innovative, multi-stage separation technique. We use theoretical analysis and the latest version of Aspen HYSYS to demonstrate process plant optimization of a real case study of a separation facility in Nigeria's Niger Delta area with the objective to achieve higher plant profitability than those achieved by current practice. Based on the estimation of the optimum separator pressures for a 48,470 bbl/day crude oil and 50.27 MMSCFD gas production facility, it is found that crude oil and associated gas recovery increased by 1,620-bbl/day and 0.21 MMSCFD, respectively. Compared to current practice at the facility, a yearly average of fourteen million US dollars would be realized by our improved multi-stage separation method.
Reliable SCAL Data for Reservoir Modeling: Case Study of a Niger Delta Reservoir
Authors: Wobo Monica A. , Onyekonwu Mike O. 
Published: July 2017

Abstract
Special Core Analysis (SCAL) data has a direct impact on the way fluids are allocated and distributed in the reservoir and simulation models, which would directly impact reservoirs' STOIIP estimation and their distribution. Moreover, it directly affects the performance of secondary and EOR flooding processes, and in turn impacts the accuracy of the oil and gas reserve estimates, and the management of these reserves. Therefore, SCAL data could be considered as one of the most critical reservoir input data for reservoir simulation models.
This paper shows how a reliable SCAL data was used for Reservoir Modeling workflow and it's impacts on the accuracy of the oil and gas reserve estimates results of integrated reservoir studies performed on XX reservoir of an onshore field in Niger Delta. The studies include petrophysical analysis, static reservoir models and building Numerical models.
This Paper sheds light on the theoretical and experimental background of SCAL data. It explains the concept of reservoir wettability and different factors that could induce changes in reservoir wettability. Further, the concept of capillary pressure and its associated hysteresis for different wettability conditions were considered. The concepts of two phase water/oil and gas/oil relative permeability curves and how to generate three relative permeability data for water wet, mixed and oil wet reservoirs were demonstrated. It clarifies the saturation end point of both capillary pressure and relative curves as a function of reservoir heterogeneity and wettability, the idea of reservoir wettability profile.
Prospects of EOR Using CO2 in Reservoirs of the Niger Delta
Authors: Ogolo Naomi Amoni , Wobo Monica Aleruchi , Onyekonwu Mike O. 
Published: July 2017

Abstract
Enhanced oil recovery (EOR) using carbon dioxide (CO2) has proved to be successful in some oil producing regions of the world, but this method has not been implemented yet in the Niger Delta. Crude oil swells when mixed with CO2; this makes the oil light and causes it to flow more easily within the reservoir. This work thus investigates the prospect of using CO2 for EOR in the Niger delta by simulating the outcome with three depleted reservoirs in the region under full water drive, partial water drive and volumetric drive mechanisms. The reservoirs were produced until production was no longer economical, necessitating external support. The life of each reservoir was extended for a production period of twenty years after its economic life under four simulated scenarios. The first was continuous production from each reservoir under the natural drive mechanism to serve as the reference case. The second scenario involved water injection while the third entailed injecting CO2 into each reservoir for twenty years. The fourth method was still CO2 injection but with intermittent water injection; the water alternating gas (WAG) method.
Very significant improvement in terms of oil recovery factor was observed with the reservoir under partial water drive and fluid expansion mechanisms. The reference, water injection, CO2injection and CO2 WAG scenarios for the reservoir under partial water drive mechanism yielded 40%, 63%, 56% and 65% respectively. For the reservoir under volumetric depletion, the reference, water injection, CO2injection and CO2WAG had 33%, 63%, 58% and 61% respectively. There was also improvement for the reservoir under full water drive mechanism with the use of CO2 but it was not very significant probably because full water drive mechanism for oil recovery is efficient and would have effectively swept the reservoir of its recoverable oil.
Best Practice for Marginal Oil Field Development and Production Sustainability beyond First Oil Production. – Niger Delta Case
Authors: Oyakhire Basil , Omeke James 
Published: July 2017

AbstractMore than 13 years after the award of 24 marginal fields and subsequent award of a total of 30 marginal fields by the Federal Government of Nigeria, only 30% of the operators/farmee have being able to achieve first oil and sustained production for more than one year. An equivalent of 58% have achieved first oil.Since the award, these operators and farmee have encountered various financial and technical challenges in bringing their fields to first oil.This paper is an outcome of years of experience working with marginal field operators in the development and management phase of their fields in Nigeria. The discussion in this paper will cover field development planning – from modelling to economics and reservoir management strategies directed from case experiences. It outlines major technical challenges faced by marginal field operators in developing their fields and proffers effective and pragmatic solutions based on best practices in the oil and gas industry to help minimize some uncertainties associated with the field development, optimize allocation of resources, achieve first oil and ultimately, increase production life of the field through sound reservoir management strategies.
Applications of the Normalized Pore Throat Radius Methodology for Improved Hydraulic Flow Unit Characterization Using the Niger Delta Field as Case Study
Authors: Onuh Haruna Monday , OgbeDavid David 
Published: July 2017

Abstract
The relation between porosity, permeability and pore architecture in complex reservoir units, typical of the thin bedded canyon turbidite system within the clastic reservoir rocks is complicated and indistinct. The sedimentary architecture usually overprinted by late diagenesis results in the intrinsic complexities which pose major problems in modelling these systems. Detailed assessment of flow units is essential for a better understanding of the reservoir flow behavior and relation between storage and flow capacity. These units are zones composed of similar rock types that are in hydrodynamic communication, which possess stratigraphic continuity and have a strong relationship to pore geometries and rock type, but may not correspond exactly with the depositional facies.
This paper presents the application of the normalized pore throat radius (Rtot¯) methodology for improved hydraulic flow units characterization and production optimization in complex reservoir systems. A modification of the reservoir quality indicator (RQI), Stratigraphic Modified Lorenz Plot (SMLP) and Leverett J-Function methodologies for hydraulic flow unit characterization using the Rtot¯ concept demonstrates improved calculation of hydraulic flow units using dataset from the Niger Delta deep water turbiditic system.
Results of the analysis for the various genetic reservoir units demonstrate an improvement of 60% over existing methodologies with additional capability for delineating between zones with excellent high communicationand baffles. In addition, Correlation between the irreducible water saturation from mercury injection capillary pressures and FZI presents an improved efficacy of the Rtot¯ model for hydraulic flow zone characterization.
The Possibility of High Recovery from a Naturally Depleted Oil Reservoir
Authors: Ibe Mmakwe , Elias Arochukwu , Igali Iyegoe , Emeka Ezeike , Akwaowo Otung , Manson Egberibine 
Published: July 2017

Abstract
Recoveries beyond 70 % from naturally depleted oil reservoirs usually pose some concerns and suspicions regarding the in-place volumes and possible production allocation issues. These concerns are strongly influenced by a view that such recoveries are not common in most basins of the world. The impact of this perception is a restriction of further developmental activities and some subtle pessimism in reserves estimation on the culprit reservoir(s). It also results in a series of reviews aimed at justifying or nullifying the current reality - the latter of which is preferred. This work details the result of an inquiry into this possibility from the perspective of both the dynamics of oil recovery and real field cases from the Niger Delta basin.
Three approaches were adopted to resolve this inquiry. The first explored global benchmarks in order to gain insights on what has been observed globally. The second established from past studies the prevailing factors that govern recovery and to understand practices and natural circumstances that influence these factors. Finally, real cases of naturally depleted water driven reservoirs were considered with a view to highlight the key factors at play in the performance of these reservoirs.
The results were consistent and showed that globally recoveries above 70% are possible. It has also been further established that recovery factors are largely influenced by 4 efficiencies namely - microscopic sweep efficiency, macroscopic sweep efficiency, connected volume factor and economic efficiency factor. These efficiencies are always at play in all reservoirs and a consistently high value in all of them will correspond to a high recovery. A minimum of 93% in each of them (if all values were equal) or at least 70 % in one (the other efficiencies are 100%) guarantees high recovery. In all the field cases where high recovery factors were observed, high values can be attributed to each of these efficiencies.
The study concludes that recovery beyond 70 % is possible from natural depletion in oil reservoirs under water drive. In such reservoirs, further development including Short Term Oil Generation activities should not be discouraged even as resulting cumulative RF may seem higher than commonly encountered values. It is critical for the achievement of high recovery from new developments to focus on the controllable factors that influence recovery when designing such projects.
Economic Optimization of Water and Gas Shut-Off Treatment in Oil Wells
Authors: Egba Amba Ndoma , Ajienka Joseph A. , Iledare Omowumi O. 
Published: July 2017

Abstract
It is estimated that on the average, three barrels of water are produced for every barrel of oil. Billions of Dollars are spent each year in treating unwanted water and gas production in oil wells. Water and Gas Shut-Off (WGSO) treatment has helped to reduce cost and improve oil recovery in some cases, while in others, this method has failed to economically recover the remaining oil in the reservoir. Economics drives the oil and gas business because the objective is to take decision that will reduce cost and maximize profit. Any decision that is made without this consideration, may be an exercise in futility. Therefore, detailed economic evaluation as a diagnostic tool for WGSO treatment has become imperative.
Despite the technical appeal, WGSO schemes can also be related to games of chance. Company has to decide whether to risk the money or not since it is not certain whether there will be a simultaneous increase oil and decrease in water/gas production. There is absolutely no 100% guarantee of success because the justification for the selection of any WGSO treatment method will be based on the probable incremental hydrocarbon production. Some water and gas control treatment can guarantee substantial production increase while others could be less successful. This introduces some degree of uncertainty, making WGSO treatment a risky venture. So, the quantification of risk and uncertainty is necessary.
Though the optimal decisions in water and gas shut off application differ from company to company, the objective however is to obtain a condition under which the marginal and total revenue from water shut off will be equal to the marginal and total cost of the operation. To Optimize WGSO application in oil wells, we must determine the production rate that maximizes its total profits.
Against this backdrop therefore, an economic model is developed that is used to evaluate water and gas shut-off candidates. This model incorporates Monte Carlo simulation and risk analysis on different reservoir parameters, incremental recovery and oil price to optimize WGSO applications. It allows for the determination of the probability distribution function for the different economic indicators that will help in ranking WGSO opportunities.