bluuebunny/crossref_metadata_2025_split huggingface dataset:
Advanced Analytics for Data-Driven Decision Making in Electrical Submersible Pump Operations Management
Authors: Adesanwo Moradeyo , Bello Oladele , Olorode Olumide , Eremiokhale Obehi , Sanusi Sherif , Blankson Eyituoyo 
Published: July 2017

Abstract
Increasing demand for cost-cutting measures has seen the petroleum industry taking advantage of new technology to accelerate production and increase ultimate recovery while maximizing reliability of the production system. Electrical submersible pump (ESP) technologies for in-well and subsea boosting systems have evolved to become a critical component in many production operations. However, ESPs are complex dynamical systems whose performance can be degraded by certain faults or events such as gas locking, changes in fluid characteristics, plugged pump, tubing leak and closed valve.
With the explosive growth of sensor data, it is no wonder that knowledge discovery has grown in importance in facilitating descriptive analyses (clustering) and predictive analyses (regression and classification) applications to ESP operations management. Interestingly, the development of appropriate algorithms to process ESP signals, detect events and prescribe optimal decisions given ESP real-time data and auxiliary, predictive observations have until now largely been overlooked.
This paper presents a decision support system for continuous ESP event detection and providing prescriptive analytics tool to analyze and manage ESP operation performance. The system includes a database management system, a real-time data management architecture, a real-time signals processing engine, forecasting system to forecast instance based on real-time data, outlier detection model, a sequence analyzer for event recognition, a prescriptive analytics to provide recommendations concerning the optimal alternative actions to be executed during events and a graphical user interface to visually analyze the flexibility and prescription model instance. The proposed procedure has been tested in a field to verify the functionalities of the system. The results show that the proposed methodology can be efficiently used in a wide range of electrical submersible pump system operation performance management and surveillance. The results demonstrate the importance of the proposed methodology and adapting it to ESP well production operations.
Techno-Economic Assessment of Mini-GTL Technologies for Flare Gas Monetization in Nigeria
Authors: Kanshio Sunday , Agogo Hezekiah Ogo , Chior Ternenge Joseph 
Published: July 2017

Abstract
Nigeria recently endorsed the World Bank's zero routine flaring by 2030 initiative and raised her own goal to 2020. As a step towards achieving the 2020 flare out goal, the Ministry of Petroleum Resources has established a national gas flare commercialization framework. Under this framework, licenses would be issued to third parties who would become off-takers of the gas. While this framework presents opportunity for investment, most of the oil fields where the gas is being flared may be far from existing pipelines and process infrastructures. Additionally, flare gas is often associated with volume, composition and pressure fluctuations, which make technology selection for its utilization more challenging. This paper reviewed some technologies for flare gas recovery and utilization, and identified promising technologies with capabilities of handling flare gas volume below 1 MMscfd. Mini gas-to-liquid (mini-GTL) technologies for producing diesel, methanol and anhydrous ammonia developed by Greyrock, GasTechno and Proton Ventures, respectively, were selected. The technical viability and economic benefits of these technologies were evaluated based on feed gas rate of 500 Mscfd. While all the technologies are technically viable, the gross profit margin of the GasTechno's miniGTL technology with methanol as the GTL product was found to be more attractive.
Mobilization of Clayey Fines by Different Water Salinity Values in the Presence of Aluminium Oxide Nanoparticles
Authors: Ogolo Naomi Amoni , Iloke Emeka , Godstime Timothy G. , Onyekonwu Mike O. 
Published: July 2017

Abstract
Water salinity is one primary factor that triggers migration of clayey fines in hydrocarbon reservoirs. However, the presence of some agents in the formation can delay this process and Aluminum oxide nanoparticles (Al2O3NP) have been proposed as one of such agents that can control fines migration. The primary objective of this study therefore is to experimentally determine the amount of fines free water effluent (in terms of pore volume) that can be produced from sand packs containing Al2O3 nanoparticles at different levels of water salinity. Another objective is to investigate the optimum sand treatment duration with Al2O3NP in control of fines migration.
The sand samples contained 5% clayey fines obtained from the Niger Delta and a constant flow rate of 3ml/min was maintained for all the experiments which were conducted under standard condition. The amount of Al2O3 nanoparticles used in the samples was 20% of the clay content, but Al2O3 NPs were not used in all the reference experiments. Two different sets of experiment were conducted in this work; the first set of experiment involved flowing various salinity levels of water ranging from 0 – 40g/l through sand packs while the second involved soaking sand in brine for various numbers of days before flowing brine of 5g/l salinity through the sand.
The experimental results showed that Al2O3 nanoparticles have the capacity to control clay mobilization in sands triggered by low water salinity. For the use of light crude at a salinity of 15g/l and 30g/l, about 25pore volumes and 33pore volumes of fines free effluents were produced respectively from the sand samples containing Al2O3 nanoparticles while about 13pore volumes and 21pore volumes of clean effluents were produced for the reference experiments respectively for a bulk volume of sand of about 55cm3. For the use of medium crude at a salinity of 15g/l and 30g/l, about 23pore volumes and 32pore volumes of fines free effluents were produced respectively from the sand samples containing Al2O3 nanoparticles while about 8pore volumes and 13pore volumes of clean effluents were produced for the reference experiments respectively. A comparison of the results of the sand samples containing Al2O3 nanoparticles with the reference results shows that the presence of Al2O3 nanoparticles in sands can control clay mobilization triggered by low water salinity. The results from the second part of the work showed that the maximum volume of clean effluent was recovered on the zero day of soaking. This implies that soaking is not required to achieve effective fines trapping in sand since the performance of fines trapping by Al2O3 NP diminishes with time.
Proposed Technique for Improved Oil Recovery from Thin Oil Rim Reservoirs with Strong Aquifers and Large Gas Caps
Authors: Ogolo Naomi Amoni , Molokwu Victor C. , Onyekonwu Mike O. 
Published: July 2017

Abstract
Oil production from thin oil rim reservoirs with strong aquifers and large gas caps is challenging due to early gas and water breakthrough, movement of the fluid contacts and low oil recovery factor. One means of handling the problems associated with thin oil reservoirs is the use of horizontal wells which improves recovery factor. This work however proposes a measure through which gas injection into the reservoir is used to improve oil recovery factor and minimize water production using vertical wells. A simulation study was carried out using the data from a thin oil rim reservoir in the Niger Delta. The five cases studied are the base case (using conventional vertical wells), use of horizontal wells, water production and disposal, water production and re-injection into the oil zone to improve recovery, and gas injection at the oil water contact.
The recovery factor and volume of produced water were compared for all five cases for a production period of 40years. An oil recovery factor of 25%, 29%, 40%, 33% and 44% were obtained for the base case, use of horizontal wells, water production and disposal, water production and re-injection to improve recovery, and gas injection at the oil water contact respectively. Volume of produced water was lowest while the GOR was highest for the proposed method than any other method. The main disadvantage using the approach of injecting gas at the water oil contacat is the high GOR however; recycling the gas by injecting the produced gas back into the gas cap is a viable solution. The relatively higher oil recovery factor and minimal volume of produced water which are highly desired for effective production from thin oil reservoirs makes the proposed technique worth investigating.
Performance Analysis of Gas Cycling Operation in Retrograde Gas Condensate Reservoir- A Niger Delta Case Study
Authors: Chibueze S. E. , Ibeh S. U. , Onugha I. N. , Obah B. 
Published: July 2017

Abstract
Retrograde Gas Condensate reservoirs are economically valuable assets but constitute a complex system in its management and development. Condensate banking due to liquid condensation below the dew point pressure raises technical and economic concerns in unlocking reservoir potentials. As pressure decreases with production below the dew point, liquid drop out phenomena is inevitable. This has two major consequences for an operator. First, the condensation of liquid/condensates which are immobile and remains trapped in the reservoir pores due to capillary-induced interfacial tension creates a permanent formation damage/impairment signified by a reduction in gas relative permeability and productivity. Secondly, the bulk of heavier and valuable components are lost to the pores of the reservoir rock. In this study, the interactions among fluid flow and reservoir rock properties were integrated in modeling and simulation of a retrograde gas condensate reservoir undergoing gas cycling. Economic evaluations based on reservoir performance indicate that, with gas cycling, a 70% and 90% recovery in condensate and gas respectively with an Internal Rate of Return (IRR) of 41% is feasible.
Extending the Fetkovich Type Curve Approach to Forecast Cumulative Production for Solution Gas Drive Reservoirs
Authors: Olatunde T. E. , Akinpelu L. O. 
Published: July 2017

Abstract
Decline Curve Analysis (DCA) is an important tool used in the petroleum industry to forecast future production performance. Forecasting future production performance is one of the critical inputs in the economic analysis of Oil and Gas investments. Conventional DCA (Arps' approach) has however been shown to have limited accuracy in forecasting cumulative production for solution – gas – drive reservoirs.
Fetkovich introduced a novel method of combining rate equation and material balance equation for finite systems to obtain rate – time equations for solution – gas – drive reservoirs, using the backpressure exponent (n) in place of the Arps' decline exponent (b). This work extends Fetkovich rate –time equation approach by developing cumulative – time and cumulative – rate models, for the two basic forms of the material balance equation investigated viz: PR is linear with Np (or Gp), PR2 is linear with NP (or Gp).
The models developed were validated with production data from two reservoirs, the first reservoir presented in the original Arps' paper and the second reservoir located in Niger Delta, Nigeria. The models were found to provide more accurate forecast of the cumulative production of a solution – gas – drive reservoir than the Arps' approach. The developed models also yielded results which compared favourably with the actual cumulative production data from the solution – gas – drive reservoir in Niger Delta. For the Niger Delta reservoir, the forecasted oil in place gives 128.844MMstb while the actual (estimated) oil in place was 127MMstb, a difference of 1.69%.
Gas Tolling – Low Cost Development Options for Small and Stranded Gas Fields in Nigeria
Authors: Adedamola Adegun , Olalekan Abiola 
Published: July 2017

Abstract
Over 70% of Nigeria's onshore gas resources are dispersed in small and stranded fields across the Niger Delta, making their development uneconomical and exacerbating the gas flaring challenge. It's estimated that about 30 tcf of gas reserves, qualified as ‘low hanging fruits’ were undeveloped over the years due to low domestic gas prices and the huge capital outlay for gas processing and transportation facilities. In recent years, reforms in domestic gas prices have improved the economics and attractiveness of gas monetization projects but the challenge of high CAPEX particularly with the recent industry downturn remains a constraint.
Gas tolling, which involves the provision of gas gathering and processing services by tolling companies to gas producers is a unique solution that has the potentials to transform the domestic gas industry. The extant Nigerian Gas Master Plan (2008) and the draft National Gas policy (2016) recognises the important role of gas tolling and seeks to expand its adoption across the country. Still at its nascence in Nigeria, tolling companies (gas facility developers) and gas resource owners must understand the key value drivers and seek to ensure mutually beneficial and sustainable gas tolling models.
This paper therefore seeks to explore the models available to tolling companies and resource owners, highlight the underlying technical and economic considerations by the parties and also provide options that help parties minimize exposure to fiscal obligations. An economic model useful for evaluating the appropriate compensation options for the tolling company and returns for the gas resource owners is also presented. Understanding the dynamics of third party gas tolling will significantly drive the growth of gas development and address the specter of stranded fields’ routine gas flaring in Nigeria.
Simultatanous Operations SIMOPS for Drilling & Production: The NPDC Ogini-Field Approach Planning to Field Execution
Authors: Chieke Chidi Anselm , Ubani Ndubisi , Obi Chinyere C. , Awa Chidi Uka , Bola Adelanke G. , Modibbo Tijanni , Bello Nura 
Published: July 2017

Abstract
Cluster drilling comes with its own attendant challenges; however, operators usually adopt this option in order to reduce environmental footprint and optimize cost. Drilling additional wells in an existing cluster will require simultaneous operation in order to maximize value. The philosophy underlying the rules for SIMOPS is that the interactions between operations must remain manageable (and can be demonstrated to be so) under all conditions that can be realistically foreseen. This paper focuses on four (4) activities that delivered the Ogini field HSE-Case, whose primary objective was to generate an in-house risk assessment and hazard register for Simultaneous Operations (SIMOPS) involved in drilling of the five (5) new Ogini wells namely:- Operational description of Ogini SIMOPS project, Description of HSE-MS, Risk Assessment and Remedial Action Plan (RAP). The SIMOPS for Ogini-field was limited to those activities associated with oil production from the existing wells, drilling operations and laying of flowlines for tie-in of new wells to the flowstation for production.
The Ogini SIMOPS have several HSE components that require critical review; a multi-disciplinary team was constituted to assess/evaluate the Risks and generate a Hazard register used in Simultaneous Operations Planning (SIMOPS) for the project. The Scope of work of the team included coming up with the industry-acceptable strategies to carry out the following operations simultaneously viz:- Flowline Construction, Rig Move, Well Delivery and Production.
A SIMOPS Planning was developed by NPDC Team and approved by DPR. Five (5) horizontal wells were drilled in a cluster (of 4.5m apart) with two producing wells; hooking up the new wells to production facility sequentially while rig was still on site.
Following the review of the distances between the planned five wells and considering future intervention works in this location, after drilling and completion of first two wells, the rig was skidded some meters further away from the initial surface location to drill the subsequent wells. Extended well test was carried out on these completed wells during this operation. This reduced the identified risks associated with SIMOPS and also provided accelerated returns on initial investments.
Gas Cap Development Guideline: Closing the Gap Between Effective Reservoir management and Contract Obligations
Authors: Nwaokorie Chukwuemeka , Ekong Inem 
Published: July 2017

Abstract
Gas portfolio development and the need to support Nigeria's Gas master plan is currently a high priority effort in government and international companies. Therefore, it is important to have a standardized approach for the development of the Gas Cap reservoirs. This guideline will provide a clear process to support the asset/study team in securing appropriate approvals from the government regulatory body (e.g. DPR) for the development of the gas cap resources.
Gas categorization guideline is adopted as a classification system for the company's gas reservoirs to help demonstrate the timing of availability of gas cap production. The classification is driven by the time remaining to produce the economic ultimate recovery from the oil rims associated with the gas caps and processing plants/evacuation ullage availability.
The objectives of the guideline are: To facilitate development planning and gas forecasting via a transparent picture on what the gas resources categories are. While existing fields mature, the development decisions regarding the oil rims become focused on ever reducing infill drilling targets. It is important to be aware how these decisions impact the availability of the gas cap production. The classification helps to provide clarity and transparency in this respect. This clarity aids to demonstrate the robustness of the Company's gas delivery promise.To help in defining standardized approach in getting approval for gas cap development from Department of Petroleum Resources (DPR). In defining this approach, a concise Gas cap release methodology is developed to guide asset and study teams in taking decisions on Gas cap development.
A clear workflow was developed for Gas Cap Development and subjected to company's internal assurance process.
Proper value assessment is done comparing the oil development and the company's gas requirement. Several sensitivities were carried out on the reservoir gas cap blowdown timing and the total reservoir NPV against the different GCBD timing (Figure1). Figure 1GCBD Optimal Timing Sensitivity
Brown Field Value Realization Via Gas Lift Deployment: A Case Study of NAMUB Field
Authors: Mogbolu Emmanuel , Agbor Etta , Ukeko Onoriode , Briggs Tamunoseleipiri , Ndukwe Agwu 
Published: July 2017

Abstract
The primary focus of a wells, reservoir and facilities management team is to guaranty shareholders value by improving production and optimize recovery. Several best practices abound in the industry to achieve this goal. Some screening criteria are used during integrated field reviews to benchmark identified opportunities and rank/select viable candidates for execution. This screening criteria includes: economic ranking, reserves, doability and regulatory policies. The resulting unconventional study allows for a better reservoir management plan.
This paper presents an integrated methodology utilized to restore oil production for a brown field via gaslift project. This was applied in the NAMUB Field case and the information obtained can be applied on other fields with similar scenarios.
In the case of NAMUB field, the estimation of the incremental oil resource volume was estimated using Material Balance models that are calibrated with pressure data and history matched. The field did not meet up with conventional screening criteria for Gaslift Project. This is due to technical, non-technical and economic reasons.
The field studied is composed of stacked reservoirs that have not had oil production for about ten years. Therefore, it was pertinent that a project had to be executed to restore/ carry out oil rim development. This was further made expedient due to the gas cap blowdown of the reservoirs. The continuous gas development impacted on the recovery of oil and further eroded oil resource volume. This integrated study comprised of Surface Engineering disciplines, Petroleum Engineering/ Geoscience disciplines, Economists and Business Planners.
The outcome of inter-reservoir communication studies and sensitivity analyses was integrated to manage uncertainties leading to robust outcomes. The results obtained were not benchmarked against any previous one, as this was a unique step out scenario the company had to deal with. The performance of the 5 wells will be monitored against actual production to validate the methods and processes adopted in this study.
The integrated approach used in the study across the diverse disciplines allowed for seamless delivery of the project.
Application of Artificial Neural Networks in Predicting Critical Rates for Vertical Wells in Oil Rim Reservoirs
Authors: Owolabi Olukunle O. , Ogungbamigbe Samuel E. 
Published: July 2017

Abstract
Critical coning rate determination as a measure of preventing coning in oil fields with underlying aquifers and overlying gas caps are a fundamental aspect of production planning in field development plans. This has always been carried out using existing correlations having large error margins. This study is aimed at developing a more accurate prediction model based on artificial neural network.
A sensitivity analysis making use of Tornado and Spider plots was used in determining the important input variables and the magnitude of their impacts on critical rates. Twelve variables were determined and were used as input parameters in constructing the network using a feed forward layered network with Bayesian regularization for fit testing to predict critical rates.
The results predicted by the Network averaged in between rates from other correlations for the same set of field data. The Network had a mean standard error of 611.7 which was the lowest when compared to the error generated by other correlations. A large variance was also noted between the rates generated from all correlations for the same data set.
The results above validate the use of the model as a predictive tool in determining critical rates. Exposure of the neural model to a wider range of data from mature fields that have already faced coning problems will be needed to fine tune the network to give even more accurate results. It is recommended that more studies be carried out in determining all variables affecting coning in oil fields.