bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Realistic Model for Estimating Productivity Index of Vertical Well Using Wellhead Data
Authors: Adesina Fadairo , Temitope Ogunkunle , Gbadegesin Adeyemi , Adebowale Oladepo 
Published: October 2018

Abstract
Productivity index calculation has been an established tool for formulating inflow performance relationship in petroleum production engineering field. The accuracy in its prediction is highly desirable to petroleum industry to predict the well production efficiency and aid in economic analysis of the well. Inability to accurately model and predict flowing bottom-hole pressure in a well may result in erotic value of productivity index of a well.
This paper present an improved model for estimating flowing bottom-hole pressure and analyse its effect on productivity index value of a vertical well without ignoring any pressure resisting terms in the governing thermodynamic equation. Satisfactory pressure differential and productivity index results were obtained at any location in the wellbore, at all time and at both steady and unsteady state period using the newly developed model. Generally the flow phenomenon after shut in requires sufficient time to stabilise or advance to pseudo steady or steady state condition has been demonstrated by this study compared with the existing models that stabilised throughout the flowing period. This study also proves that inaccuracy in the results of existing models were not only caused by the effect of pressure restriction due to friction as opined by Guo et al but may have due to oversight of all pressure restriction term in the fundamental governing equation of flowing fluid in a vertical wellbore.
Brown Field Optimization via Well Head Commingling: A Niger Delta Case Study
Authors: Udobata Uchenna , Mogbolu Emmanuel , Agbor Etta , Epebiyi Taiwo , Onyedikachi Okereke , Cosmas Nwankwo 
Published: October 2018

Abstract
Production system optimization is one of the key ways to derive value from existing assets and ensure optimal field development, by integrating all aspects of the production system from the subsurface to the surface networks. Over the years, various tools have been developed in the industry to aid complete system performance analysis and optimization. In most cases, the scope of optimization is limited to the as built fixed assets which often has limited scope for economic modification in the late life of the asset. Additionally, commingling compatible reservoir fluids using intelligent wells has been identified as a viable means of developing marginal stacked reservoirs, which are otherwise uneconomical if conventional development options are considered. Cosby field which is a prolific field in its late life, had been closed in for over 10 years due to asset integrity and subsequent flowline vandalization. The wells are completed mostly as Two String Dual or Multiple producers to target the stacked reservoirs. Field re-entry campaign provided an opportunity to optimize the approach to field development and bring in the wells which had been closed-in. However, the prevailing completion philosophy required each string to have dedicated flowlines ranging from 3000- 9000 ft. This is to convey the fluids from the well to the flow station; hence each interval had to meet an economic criterion to ensure competitiveness. This paper posits a "beyond blind spot" concept identified for the late life re-entry and optimization of the Cosby field oil wells; by identifying suitable candidates for surface fluid commingling using well and reservoir performance reviews and Integrated production system model as tools. This concept, which aligns with the competitive drive within the E&P industry, delivers a facility cost savings of ca. $2.24 million, and allows an economic potential addition of ca 1.5Mbopd and resource volume of ca. 5.2 MMstb to be safeguarded.
Attic Oil Development in Reservoir with Structural Uncertainty and Complex Gas Cap Movement: A Case Study
Authors: Zubarev Denis , Zeito George , Iranshahr Zhanat 
Published: October 2018

Abstract
The initial development of wedge shaped oil reservoirs that are subject to both aquifer influx and gas cap expansion requires optimal well placement relative to the future movements of gas-oil and water-oil contacts. In offshore developments with limited appraisal wells and no field specific analog data, the initial gas cap size and future aquifer performance are often uncertain. The necessity to de-risk the development often results in untapped oil remaining in up-dip or down-dip locations, depending on the balance between the two drive mechanisms. With sound reservoir management the unproduced volumes can be minimized, but in many cases the oil volume remaining after abandonment is sufficient to justify the additional capital cost to recover it. Accurate estimation of remaining in-place and recoverable volumes are critical for small operators, especially in current oil price environment.
This paper presents a case study for attic oil development in Nigeria with a well sidetrack for a reservoir with significant structural uncertainty and complex gas cap movement. An approach combining history matching of numeric simulation models and simple analytic solutions to address the uncertainty in remaining recoverable volumes and optimal well placement is discussed in detail. Results are compared to the performance of the actual well that was drilled.
Feasibility Study and Selection Process for ICD Applications in an Offshore Niger Delta Field
Authors: Zubarev Denis , Nnebocha Ezinne , Vasper Adam 
Published: October 2018

Abstract
Horizontal wells increase the reservoir-wellbore contact area, allowing the wells to produce at higher flow rates with smaller drawdowns which is especially important in oil reservoirs with a large gas cap or aquifer. Long wellbore lengths can lead to production challenges such as water or gas coning and cusping, an unwanted fluid breakthrough from high-permeability zones, and uneven inflow along the wellbore and nonuniform reservoir sweep.
Inflow control devices (ICDs), based on well-established technology, have been used in hundreds of wells worldwide. Different ICD types and design methods are available and can be applied to mitigate some of the production challenges. The ICDs are installed as an integral part of the sand screens in the well completion hardware. They can be passive, where the ICD size and configuration does not change after it is run in the hole, or autonomous, where the ICD adapts to changes in downhole fluid-flow properties. However, the decision regarding the use of ICDs as well as the design criteria and selection has to be made prior to the well completion operation.
This paper presents a feasibility study on an ICD application in an offshore Nigeria delta oil field with multiple hydrocarbon-bearing reservoirs. Most of the development wells in the field have horizontal openhole 1,000 to 3,000 ft drain sections completed with standalone screens. Strong aquifer and reservoir heterogeneity create production challenges associated with early water breakthrough and suboptimal reservoir sweep. This paper presents a detailed approach to ICD design, sensitivity analysis, and completion optimization, which is based on the coupling of a 3D reservoir model, segmented wellbore model, and ICD models. The proposed ICD completion design is evaluated and sensitized to subsurface reservoir uncertainties using volumetrics. The final decision process is presented to guide the selection and feasibility of an ICD application for two reservoirs.
4D Seismic Monitoring of Injector Performance and Reservoir Dynamics in a Heterogenous Reservoir
Authors: Agunwoke Godwin Oguguah , Obe Ebenezer , Tuitjer Eric , Ekeng Oyie , Okoro Innocent 
Published: October 2018

Abstract
Monitoring fluid movement in a heterogeneous water-flooded reservoir is key to optimizing water injection, detecting early water breakthrough, and locating bypassed oil. While well- and production-based reservoir monitoring techniques are commonly applied, they lack the inter-well spatial resolution required for an accurate assessment of the current water movement. As a key tool in spatial reservoir surveillance, 4D seismic surveys were acquired over a water-flooded field located offshore of the Niger Delta. The aim was to map fluid-flow paths and barriers, manage injection for breakthrough optimization, and optimize well placement. The application of 4D seismic techniques has tremendous potential to provide inter-well information on fluid dynamism over time, provided there is a clear link between the seismic observables and reservoir variables such as fluid, pressure, or temperature. Using physical properties of the rocks and fluids from input wells, a 2D seismic model was used to predict the amplitude response to changes in saturation. This involves estimation of the amplitude difference expected from incremental water saturation between pre-1987 and post-1996 wells. The study establishes a correlation between saturation and the two previously-acquired seismic (baseline and monitor) surveys, which were acquired over a nine-year interval. We interpreted the injected water flow path, the potential locations of bypassed oil, and compartmentalization. This was achieved by integrating the well production information, predicted seismic amplitudes at the wells, and the seismic attribute maps. The resulting analysis provided new insights into unexpected production behavior, such as the premature watering-out of updip wells relative to offset wells, and the anomalous pressure support across fault compartments. In accordance with the well performance, it was observed that the injected water follows preferential and heterogeneous flow directions, indicating a strong stratigraphic fluid-flow overprint on the reservoir not previously discernible from well data alone. Subsequently, early results from infill drilling and injection management show better well performance leading to improved oil recovery.
Addressing The Impossible History Match Problem: Using a Systematic Approach to Eliminate Model Bias
Authors: Yusuf Nurudeen Oluwatosin , Silpngarmlers Lynn , Eme Vincent O. 
Published: October 2018

Abstract
Cognitive biases are unconscious errors in judgement and decisions particularly those that are under conditions of uncertainty. The impact of bias in reservoir simulation can be reduced by validating model assumptions with a multidisciplinary team and sourcing required data that can help to resolve significant uncertainties.
This approach was utilized for Reservoir_E simulation study where bias in history match parameter was eliminated. In an initial history match attempt, assisted history match method was used to indicate that a single tank model solution was "impossible" for this reservoir. A two-tank history matched model was therefore proposed against prior geologic and engineering understanding of the reservoir. This bias was identified by a multi-disciplinary team after analyzing all available data. This led to a second history match effort which expanded the range of uncertainty parameters and got a good history match with a single tank, in line with understanding of reservoir architecture and flow mechanism. The single tank assumption was later validated with geochemistry analysis of oil samples from existing producers.
This paper demonstrates best practices in conducting reservoir simulation studies by showing the non-uniqueness of simulation models and the need to validate model assumptions using a multidisciplinary team and all available data.
Field Examples Demonstrating Applications of the Five Principles of Reservoir Management
Authors: Ezekwe Nnaemeka 
Published: October 2018

Abstract
The five principles of reservoir management are: 1. Conservation of reservoir energy. 2. Early application of simple strategies. 3. Sustained and systematic collection of data. 4. Implementation of improved technologies. 5. Long term retention of staff in multi-disciplinary teams. These principles can be combined with emerging technologies to devise and implement optimized reservoir management strategies.
Advances in technologies for optimization of reservoir management strategies have made significant advances in the areas of real-time reservoir monitoring, interval flow control, and downhole flow measurements. The petroleum industry can achieve real-time reservoir management by installing these revolutionary technologies to improve and optimize economic recovery of hydrocarbons.
Installations of downhole sensors and inflow control devices in many wells with data transmission/communication links have created a new class of smart/intelligent wells. Smart/Intelligent wells are equipped with devices that enable remote monitoring, control, and transmission of data from multiple zones thereby providing capabilities to reduce remedial costs and optimize reservoir performance. Data analytics can be used to ‘mine’ the huge data collected from these wells and fields and used to improve production processes.
Field examples that demonstrate applications of the five principles of reservoir management with installation of advanced technologies to improve reservoir management and hydrocarbon recovery are: 1. The Agbami Field, Offshore Nigeria 2. The 26R Reservoir in California, USA and 3. The Shaybah Field in Saudi Arabia.
RFID Zone Management and Barrier Control System
Authors: Flores Brennan 
Published: October 2018

Abstract
Throughout the last few decades, the oil and gas industry has made tremendous advancements in Safety. The number of safety incidents in the work place, especially fatalities, has significantly decreased. Industry leaders continue to strive to improve safety practices and procedures. Two of the largest threats facing personnel in the industry today are the exposure to "objects that drop from height "and "line of fire exposures". Targeted efforts such as Dropped object campaigns have been initiated to collectively address the dropped object exposure. Line of fire exposures associated with high-pressure temporary iron from piping and/or connection failures, exposing workers in the area have been managed through various methods. Although many efforts exist to mitigate these risks, none have been as effective as exclusion zones. Technical safety analysis often determines which areas pose threats to working personnel identified as an "exclusion zone", essentially mandating that an area be controlled by permit to work and stipulated by procedure.
I have developed a real-time tracking and feedback system that is capable of geo-fencing exclusion zones and recording any barrier breaks allowing technical safety professionals, front line supervisors and company representatives the opportunity to address the issues first hand and amend procedures and policies to improve their safety performance altogether. The concept offers a software platform that tracks personnel in real-time within isolated zones and immediately alerts personnel if a restricted zone is breached through an architecture of RFID readers and tags. Finally, the data can be processed in a way to provide valuable feedback to move towards a safer work behavior.
The software platform managed to successfully signal an alert and record the tag ID when a test subject crossed the RFID reader holding the RFID tag, proving the full-functionality of the barrier control system. The implementation of this system can be used to ultimately control the location and flow of personnel on platforms and rigs in order to make the oil and gas industry a safer environment.
Janus Nanoparticles for Enhanced Oil Recovery EOR: Reduction of Interfacial Tension
Authors: Giraldo Lady J. 
Published: October 2018

Abstract
Today, global energy demand increases significantly, but supply growth does not increase in the same proportion. The oil industry has been affected by the shortage of discoveries of new deposits of oil. Thus, it is compelling the development of cost-effective enhanced oil recovery (EOR) alternatives that allow the increase of the current hydrocarbons supply of actual reservoirs. Hence, the nanotechnology emerges as a good option as the use of nanoparticles and nanofluids has shown potential benefits in improving the efficiency of chemical treatments. Nevertheless, field applications of nanoparticles have been avoided due to current studies indicate that nanoparticles concentrations higher than 10,000 mg/L are needed, which disable the implementation due to high costs and the possibility of formation damage. Hence, the main objective of this study is the development for the first time of unconventional and engineered designed 0-D nanomaterials, namely NiO/SiO2 Janus nanoparticles that can be used for enhancing the oil recovery at low concentrations (~100 mg/L) without the risk of formation damage in the reservoir. These type of nanoparticles, due to its low size and 0-D characteristics, can improve the swept efficiency in the reservoir and increase the recovery. The primary mechanism of these nanomaterials is their strategic positioning at the oil/water interface and reduction of the interfacial tension. The Janus nanoparticles can migrate at the oil/water interface. The Janus-based nanofluids (nanomaterials dispersed in determined carrier fluid) flooding were assessed for reducing the interfacial tension (IFT), increasing the viscosity of the displacement phase, and altering the rock wettability, which impacts the capillary number and hence increases the crude oil recovery. The synthesized nanomaterials were characterized by TEM, stability, IFT, rheology, contact angle measurements and coreflooding tests under real reservoir conditions (fluids, pressure, temperature and rock samples) looking for flow assurance previous to a field trial. The results showed an increase of the capillary number at a very low concentration of 100 mg/L of both nanomaterials, mainly attributed to the decrease in the interfacial tension, which can lead to the increase of the oil recovery. Displacement tests using conventional SiO2 nanoparticles-based nanofluid at a concentration of 100 mg/L did not show an increase in oil recovery regarding the one obtained in the waterflooding step. Meanwhile, the nanofluid based on the engineering designed nanomaterials at the same concentration of 100 mg/L showed an increase in oil recovery up to 50%.
Experimental Study of Heavy Oil Recovery Mechanisms During Cyclic Solvent Injection Processes
Authors: Plata Maria 
Published: October 2018

Abstract
In recent years, the Cyclic Solvent Injection (CSI) process has shown to be a promising method for enhanced heavy oil recovery in Canada. CSI laboratory studies work for only 2 to 3 cycles due to low incremental oil in subsequent cycles. However, in field pilots the CSI keeps operational after many years. This study intends to capture the full production mechanisms responsible of heavy oil production in CSI to better understand the phenomena in field applications.
A physical sandpack model was used to test the CSI response. The sandpack was saturated with live heavy oil of 7900 mPa.s viscosity at 24 ° C, and primary production was run. Five CSI tests were then conducted to simulate the performance under the gravity effects. The experiments were conducted in a horizontal and vertical mode injection respectively at high and low-pressure depletion rates using 70 mol % CH4 and 30 mol % C3H8 solvent mixture. The sandpack was Computed Tomography (CT) scanned after every cycle to provide information about the gas and oil saturations evolution.
When CSI was run on the horizontal core, the incremental oil recovery was negligible for both slow and fast drawdown rates. When the sandpack was vertically flipped and rapidly produced, the three CSI cycles exhibited higher recover, and similar incremental recovery per cycle. This result indicated that even at high drawdown pressures, gravity segregation can effectively maximize the cross-flow mixing between solvent and heavy oil to penetrate the un-swept areas.
The results of this study demonstrate the importance of gravity drainage in the CSI process, and the relative significance of gravity forces on successful oil recovery rates. The results of this study illustrate the limitations of previous horizontal laboratory tests and show an improved test configuration for modeling and prediction of the improved response observed in CSI pilots.
Simulation of Network Fracturing in Tight Gas Formation with Coupled Shear Fracture Propagation Model
Authors: Li Mei 
Published: October 2018

Abstract
Hydraulic fracturing is one of the key technologies for effective exploitation of unconventional reservoirs such as tight gas, shale gas and coalbed methane. Discontinuities such as natural fractures and bedding are developed in these reservoirs, which makes them among the most technically complicated reservoirs. Significant amounts of oil and gas are often strapped within the matrix. Network fracturing techniques often implemented to increase the connectivity of matrix and natural fractures and enhance the production. Current techniques lack adequate understanding of complex propagation and distribution of hydraulic fractures in fractured formations, which precludes any meaningful optimization and prediction of the effect of fracturing treatment.
In this study, a fluid-solid coupled shear fracture network propagation model considering dual media, permeability anisotropy and stress sensitivity is built to simulate the fracture network morphology in tight gas formation. A quasi-continuous method is adopted to describe the discontinuous problem due to the pre-existing fractures, which greatly reduces the cost of calculation. The developed code is flexible enough to allow either shear fracturing of matrix or pre-existing fractures or secondary shearing of induced fractures to be examined on the basis of reservoir conditions during the fracturing process. Fracture morphology is acquired by examining the failure condition of each element which precludes presetting fracture propagation path.
Different cases of simulation will be presented to study some important features of fracturing in unconventional reservoirs on the basis of naturally fractured tight gas reservoir condition in of eastern Sichuan Basin, China. It is found that reservoir condition, like in-situ stress difference, significantly affect the width of fracture network. The hydraulic fractures prone to shear along the pre-existing fractures and the phenomenon became more obvious under smaller pre-existing fractures orientation condition. Besides, weak mechanical property of pre-existing fractures is conductive to the formation of complex fracture network.
Model-Based Cluster Spacing Optimization Increase Recovery and Profitability in Eagle Ford
Authors: Jones Miranda 
Published: October 2018

Abstract
Historical horizontal completions designs have very wide cluster spacing, leaving behind significant volumes of hydrocarbons. This paper develops a workflow for optimizing cluster spacing using simulated production curves in unconventional oil and gas fields. Optimizing cluster spacing reduces unstimulated reservoir rock left between widely spaced fractures, more efficiently draining the stimulated reservoir volume and increasing expected ultimate recovery and initial production. This paper illustrates the workflow developed by finding an optimal range for cluster spacing in the retrograde/wet gas region of the Eagle Ford. It is estimated that optimizing cluster spacing in this fluid window will increase ultimate hydrocarbon recovery by 20% and the net present value of each well by 50-60%.