bluuebunny/crossref_metadata_2025_split huggingface dataset:
Advanced Mathematical Model for Prediction of Sand Production Rate: A Niger-Delta Case-Study
Authors: Okereke Ndubuisi , Ogbuka Vincent , Izuwa Nkemakolam , Kara Fuat , Nwogu Ngozi , Nwanwe Onyebuchi , Baba Yahaya , Kanshio Sunday , Odo Jude , Oguama Ifeanyi 
Published: August 2020

Abstract
The Tertiary Niger Delta Basin is dominated by a friable, loosely consolidated sandstone formations indicating the likelihood of sand production ocuuring during hydrocarbon production in such formations. The aim of this study was to develop a simple mechanistic model for predicting sand production rate (SPR) in Niger-Delta wells. Two basic criteria (static sanding criteria and the dynamic requirement for fluidization of the produced sand) were used in developing this model. A generic mechanistic model that incorporates the concept of dimensionless quantities associated with sand prediction was developed. In developing the model, loading factor, Reynolds Number, water cut and gas-liquid ratio, GLR were considered. A dimensionless sand production rate (SPR) correlation index was the output from the proposed model. Results indicated that every reservoir has a unique SPR correlation index which represents its propensity to produce sand or its sanding identity. Validation of the proposed model was conducted by comparing the model prediction results with field data. Model validation results showed an agreement between predicted with field results with an acceptable maximum deviation of less than 5% in for onshore wells. The proposed model was further compared to existing models and prediction results show that the proposed model gave better results than others especially when the boost factor, GLR is significantly high. The applications of this study range from field development plans and economics to reservoir management, down to general well completion design and strategies.
A Method of Estimating Reservoir Pressure using Drawdown Test Data
Authors: Idudje Henry , Adewole Steve 
Published: August 2020

Abstract
In conventional draw test analysis, initial reservoir pressure has to be known with precision to aid primarily to determine near wellbore skin. Furthermore, in old wells, the initial reservoir pressure has to be attained before drawdown. For very old wells and tight reservoirs therefore it would take painfuly long shutin time to eventually attain the initial reservoir pressure before drawdown. In largely depleted reservoirs, it may be impossible to actually attain the desired initial reservoir pressure even after a long shutin! Efforts at obtaining the initial reservoir pressure in all these cases would only yield the remaining reservoir pressure since fluid had been produced from the reservoir. On a semilog plot of flowing wellbore pressures versus time, it is not possible to estimate the reservoir pressure to even validate the recorded pressure before shutin.
In this paper, a procedure has been developed to overcome these challenges. The new method plots flowing wellbore pressures against dimensionless pressures on linear axes, assuming infinte-acting flow. The plot gives a straight line with intercept on the flowing wellbore pressure axis yielding the remaining reservoir pressure on extrapolation to dinensionless pressure of zero. Although, developed for horizontal well flow, it can be adapted for vertical well flow with minimal effort. Mathematical procedure employed is based on selection of relevant source and Green’s functions for a horizontal well during infinite-acting flow and assuming the well purely as a line source. A case pressure drawdown test selected for analysis using the method developed here yielded very close reservoir pressure compared to the reservoir being characterized.
Comparative Study of Field Development Scenarios of the Elk City Gas Reservoir using Reservoir Simulation
Authors: Wigwe Marshal E. , Basit Mohammad I. , Elldakli Fathi , Dambani Samuel , Mmuenu Rosemary , Soliman Mohamed Y. 
Published: August 2020

Abstract
Well placement is a critical aspect of Field development planning in order to fully understand the extent of the field to further effectively develop and drain the field. In most cases, the structure of the formation is initially unknown, in addition to other geologic and petrophysical properties that will aid in calculation of GIIP and EUR. The use of analogy alongside decline curve analysis have been great starting points to drill the first few wells while additional data are being collected to enable the use of more advanced tools like reservoir simulation for full-field development study.
This paper presents a study on the production of a gas field and the contributions from seven vertical wells that had been drilled. These seven wells are designated wells p1 to p7. Wells p1, p2 and p6 are located on the anticlines, p3 and p7 are located on the front edge of the reservoir, and p4 and p5 are placed at the center between the two domes. Contour, isopach, isopermx, isopermy and isoporosity maps were used for grid generation, while other modeling software were used for reservoir simulation and visualization. Four base cases were simulated to study the effects of grid sizes and use of local grid refinement (LGR). Four additional "experimental" cases were studied to explore alternative well placement and potential benefit for horizontal and hydraulically fractured wells.
The two poor performing wells (p3 & p7) were considered as good candidates for hydraulic fracturing. Unfortunately, the results were not promising as both wells showed less than 1% improvement in gas recovery and hence may not justify the investment. The use of alternative well placements scenarios for these wells resulted in about 9% incremental recovery while conversion to horizontal wells added a further 3% in recovery. This last investment will be further justified if a dual lateral is considered rather that two separate wells.
Water Control in High-Water-Cut Well Using Cutting-Edge Polymers: Production Optimization Methodology Applied in Burgan Field, Kuwait
Authors: Al-Fadhli Wuroud , Kurma Ravi , Bhatia Kutbuddin , Alboueshi Alaa , Abdelbaky Amr 
Published: August 2020

Abstract
A significant challenge in the mature South Kuwait Burgan field is assuring maximum hydrocarbon flow through high water-prone sandstone intervals. Recently, water control or conformance treatments have been considered to make oil production from these reservoirs more economically feasible. This paper discusses the application of a novel downhole chemical methodology that has created a positive impact in overall productivity from this field.
The production profile in this field has been challenging in terms of increasing water volume, which poses a great threat to continued economic viability and may lead to lower production rates, a reduction in recoverable reserves, and premature abandonment. Some of the production-gathering centers cannot handle the ever-increasing volumes of produced water and are operating beyond design capacity. In order to solve this challenge, a downhole chemical treatment was modified as a fit-for-purpose treatment to address the unique challenges of electric submersible pump (ESP)-driven well operations, formation technical difficulties, high-stake economics, and high water potential from these formations. A unique hydrophobically modified water-soluble polymer (HRPM) was implemented in a high water-cut well to selectively reduce water production. Because this well was producing with an ESP, the treatment was pumped down the annular space. A preflush was pumped ahead of the HRPM treatment to remove deposits that could prevent the polymer from effectively adsorbing to the rock surface. The treatment was then overdisplaced with brine.
This technology incorporates an HRPM that is adsorbed on the rock surface, resulting in the alteration of rock surface characteristics. The hydrophobic modification to the base polymer chain adds unique associative properties to the system, which selectively reduce the water's effective permeability in the reservoir, impeding water flow and facilitating increased hydrocarbon flow. A direct result of the implemented treatment is that the post-operation well test and production data show a high sustained hydrocarbon production at a smaller choke size with significantly reduced water cut. This successful treatment confirmed the optimized conformance technology as a solution for the first well in this field.
In order to achieve maximum reduction in water production, this technology is customized based on the temperature and permeability of the treatment zones, thus ensuring it is fit-for-purpose. Furthermore, this paper summarizes the candidate selection, design processes, challenges encountered, production response, and lessons learned from this treatment and can be considered a best practice for addressing high water production challenges in similar conditions in other fields.
A Novel Algorithmic Design and Implementation for Predicting Crude-Oil PVT Properties
Authors: Olatunji Oladipo , Mogbolu Jonathan 
Published: August 2020

Abstract
With the cusp in the advances in Artificial Intelligence and Machine Learning, there have been several development of AI-based PVT models. Although they have offered some advantages in one way or the other, their easy implementation and flexibility have been limited due to computational complexities, and the relatively vast amount of memory allocation required. Also, some of the classical PVT models are wrought with certain setbacks. Some of these models are only accurate within specific conditions of crude-oil type and properties, and hence fail when there are small variations in crude oil properties or when there are different genetic sources or prevalence for the crude oil type. Here in this paper, we have developed a novel algorithmic design and implementation based on a combination of mathematical combinatorics and linear algebra. Using the superposition principle in an ingenious way, we built new, improved and better models from existing PVT correlations and models. Our resulting algorithm known as IntelliPVT offers more robust, more accurate and faster PVT model predictions. IntelliPVT has been written both in MATLAB and Python. Using real field data published in literatures, journals and books, and compared with other realistic conventional PVT correlations, IntelliPVT outperformed these correlations and predicted Crude-Oil PVT properties of Formation Volume Factors, Solution Gas-Oil Ratios, Bubble Point Pressures, Viscosities, and Crude oil compressibilities to the least Root Mean Square Error, R-Squared values between 0.91 and 0.99, and the lowest minimum mean square error with very high computational speed. The novel algorithm offers more accurate results with a faster implementation and applicability to all crude-oil types including heavy oils. Its implementation will ensure a better subsurface characterization, improved reservoir management as well as surface design along the whole spectrum of the oilfield lifecycle.
Benefits of Real-Time LWD Static Borehole Image in Reservoir Navigation Service
Authors: Toyobo Oluwaseun , Imomoh Victor , Okafor Rosemary 
Published: August 2020

Abstract
The world's increasing demand for energy has driven energy service companies to develop newer and cost-effective technologies. Such technologies include borehole imaging and geosteering tools, embedded with smart sensors, used for reservoir navigation service. Reservoir navigation service utilizes real-time drilling and LWD (logging-while-drilling) data to optimally position the wellbore relative to a reservoir geometry, given certain drilling and geological uncertainties. To reduce the geological uncertainty, logging with real-time borehole imaging service has proved to be very useful.
The term borehole imaging refers to the generation of logs that are based on the circumferential measurement of a petrophysical parameter along a borehole. LWD borehole imaging provides 100% borehole coverage, high azimuthal and vertical resolution. From the detection of beds to bedding orientation, from lithological boundaries to other structural discontinuities, borehole imaging helps to improve the subsurface geological interpretation during reservoir navigation services.
This paper will review the structural, sedimentological and petrophysical benefits of real-time LWD static borehole images. It will also discuss how the incorporation of borehole imaging in reservoir navigation can improve well placement for optimum hydrocarbon recovery.
Application of ANN in Predicting Water Based Mud Rheology and Filtration Properties
Authors: Oguntade Tomiwa , Ojo Temiloluwa , Efajemue Ewarezi , Oni Babalola , Idaka Joy 
Published: August 2020

Abstract
With the evolution of technology, data is a major sector of engagement in the oil and gas industry. Various studies are done on the subject of artificial intelligence and Artificial Neural Networks are commonly employed. The study seeks to apply artificial intelligence to the prediction of water based mud rheology and filtration properties. Artificial Neural Network (ANN) from MATLAB was used to predict the properties wherein a number of samples were tested in the laboratory and the values from experimentation were input into the neural network and trained to predict more values without physical experimentation. Plastic Viscosity, Apparent Viscosity and Yield point were the rheological properties considered while filtrate volume and cake thickness were the filtration properties looked into. The two statistical parameters used for selecting the neural network with the best predictions were correlation coefficient (R2) and mean squared error (MSE). The ANN predictions were also validated with a new data set. ANN with 15 neurons in the hidden layer and 8 neurons in the hidden layer gave the best predictions for rheology and filtration respectively. The hidden layer with 15 neurons gave an R2 value of 0.92234 and the MSE value was 9.2494. The hidden layer containing 8 neurons gave an R2 value of 0.99978. and an MSE value of 0.694173.
Success Story of Well Interventions Identified via Surveillance Maps
Authors: Dennar Linda , Adebayo Adejoke , Uyouko Ime , Ahmed Suleiman , Nwandu Somto , Chidiebere Christabel 
Published: August 2020

Abstract
Surveillance mapping is a reservoir management process first developed by Shell and Exxon for the Brent field in the UK North Sea. It involves an integrated reservoir-wide management process with the objective of not only understanding subsurface dynamics during production but also delivering a future work programme that will maximize reservoir potential.1
Surveillance Mapping was recently deployed in candidate selection for Short Term Oil Generation and Work Over activities in the Zoom reservoir located in the Niger Delta area. The Zoom reservoir is an East West Trending anticlinal structure, predominantly shore face deposits with incised channels. The Zoom reservoir, which is a large structure, commenced production in August 1991 and 50MMstb of oil has been produced to date. Thirteen oil wells have produced from the Zoom reservoir. These wells were drilled in phases post updates of various development plans published in 2003 and 2010. Production performance across the reservoir started declining due to natural water encroachment, poor productivity issues, well and flow line sabotage etc. This triggered an aggressive strategy to identify suitable remedial action that would support the drive for resuscitating the wells in a cheap and safe manner.
Five wells were identified as potential Short-Term Oil Generation candidates and have been executed successfully with good rewards. This paper will review the success story of candidate wells scoped from the surveillance map and its impact on the optimization of the reservoir potential.
Novel Analytical Technique for Evaluating Static Mud Filtration During Drilling of Horizontal Wells
Authors: Owoseni Sunday , Alonge Oluwaseun , Isehunwa Sunday 
Published: August 2020

Abstract
Horizontal wells have become increasingly important in the development of oil and gas fields due to their added advantages such as increased offtake rates, high drainage areas, and reduced pressure drawdowns. However, many horizontal wells experience rapid production decline due to near-wellbore formation damage caused during drilling and completion operations. Formation damage caused during drilling and completion operations can be reduced if the mechanism of filtration through mud cakes is well understood. Several published analytical models tend to neglect the very important component of filtration around the heel of horizontal wells. A model that describes static mud filtration in horizontal wells during drilling, incorporating damage around the heel was developed and solved using an approximate analytical technique. The results show that drilling mud filtration can be higher in horizontal than vertical wells. It was also observed that filtration at the heels of horizontal wells can be very significant, with the radius of curvature having a great effect on the filtrate volume. The analytical solution also confirmed observations made by several previous researchers that the properties and thickness of mud cakes and the viscosity of the drilling muds affect the volume of mud filtrates during the drilling of horizontal wells.
Alternative Crude Oil Evacuation Project in Swampy Terrain; Challenges and Lesson Learnt
Authors: Kingsley-Akpara Chiamaka , Ezuka Ifeanyi , Owarume Michael 
Published: August 2020

Abstract
The entire crude oil exploration and production business chain is not complete without an effective evacuation system especially in difficult terrains. The conventional evacuation means is via pipeline; however, this paper presents the economic feasibility of an alternative crude oil evacuation project in OML 42, in the Niger Delta location; lessons learnt and high impact variables in both capital and operating expenditures. The authors share a broad concept of the potentialities, the cost of operations, and some of the problems which were encountered in deploying alternative crude evacuation system.
Field Development Planning based on Static, Dynamic and Geomechanical Modelling of X Field, Niger Delta, Nigeria
Authors: Ezebialu Kenechukwu , Ubituogwale Michael , Odegua Eunice , Idehen Abigail 
Published: August 2020

Abstract
The "X" field is prospective but largely underdeveloped as only four vertical wells have been drilled. The purpose of this project was to prepare a field development plan by building a 3D static geologic reservoir model and estimating the in-place hydrocarbon volumes, simulating the static model to understand how the reservoirs would perform with time and building a 1D Mechanical Earth model to understand wellbore stability. The geological consistency of this model required a cross domain integration of seismic data, well log data and subsurface knowledge across the various subsurface disciplines. Three reservoirs were mapped and well correlation was carried out across the four wells (W–E). Depositional environments were reconstructed using well log information and other available geologic information. Three major lithofacies were interpreted: sands of the upper shoreface, sand-silt-shale intercalation of the lower shoreface, and marine shales. The result from the petrophysical analysis and property modeling showed that the average porosity is approximately 30%, permeability is majorly around 100mD and water saturation range from 0.347-0.461%. In-place volume estimated using the model generated was 568 MMSTB of oil. The model was simulated using different scenarios to forecast field performance. From the 1D Mechanical Earth Model (MEM) constructed, it was observed that the dominant stress regime of this field is typical of normal faults and the orientations of these stresses are in harmony with the regional stress regime of the Niger Delta. By using 1D MEM data, wellbore stability analysis for problematic layers was performed and the optimum mud weight was recommended to prevent common drilling problems and at the same time to maintain stable wellbore.
Deployment of a Digital Oil Field Technology Solution for Real-Time Monitoring and Production Optimization of a Gas-Condensate Field in Western-Niger Delta Region of Nigeria
Authors: Kanu Aime , Afolabi Folorunso 
Published: August 2020

Abstract
In oil and gas fields, the availability of data enables front-line operators and asset teams make informed decisions to intervene, troubleshoot and optimize the production system for oil and gas production targets to be achieved. In most cases, the data is not available thus frontline operators reactively intervene to address production challenges which inadvertently leads to equipment and facility shut-down, unscheduled downtime and ultimately significant production deferment. We have hitherto seen a transition to data-driven decision systems, also referred to as Digital Oil Field (DOF) technology.
DOF Technology is the integration of data, automation and instrumentation technologies that provides a realistic overview of field processes which helps monitor operations for proactive intervention in order to reduce cases of production deferment. It entails real-time monitoring for improved Well and Reservoir Facility Management (WRFM), Production Optimization, Asset Integrity Management and most importantly overall improvements to safety of personnel, that is, minimizing the risk of exposure to high pressure systems at wellhead locations and ensuring significant cost savings. The data gathering framework uses Random Phase Multiple Access (RPMA) and IIOT (Industrial Internet of Things) network anchored on a cloud platform. These services are owned and operated by a local fully Nigerian owned company.
Within the framework of DOF Technology, high-fidelity real-time monitoring sensors have been deployed to 8 gas-condensate producing wells flowing to a Non-Associated Gas (NAG) facility with 5 Processing trains utilizing Joule-Thompson Technology for hydrocarbon dew pointing. The facility has a total installed capacity of 465 MMscf/d and delivers custody of the processed gas according to West African Gas Pipeline (WAGP) specifications via two legacy sales lines 16" and 20" respectively to Nigeria Gas Company (NGC).
This paper presents the application and deployment of the DOF Technology Solution for Real-Time Monitoing of Gas Wells in remote locations to primarily ascertain health status of producing wells, flow assurance and deliverability to customer for power generation and industrial development.