bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Innovative Approach to Image Fracture Dimensions by Injecting Ferrofluids
Authors: Sengupta Soumyadipta 
Published: November 2012

Abstract
Hydraulic fracturing is a common method used to increase productivity of oil and gas reservoirs. Microseismic technologies have been used to image the dimensions of fractures. Background noise is a serious drawback of this method. This paper proposes a more direct method of measuring fracture dimensions. It shall discuss the magnetic theory, ferrofluids and their magnetic properties, setup of this method and interpretation techniques. Fracturing fluids shall have nano-sized metal particles. These particles will make the fracture a very large conductor and magnetic material in the earth. A variable magnetic field shall be generated by using coils wrapped around the casing string. This variable magnetic field shall generate eddy currents in the fracture. These eddy currents will produce a magnetic field of their own with a distinctive phase shift. An array of receivers shall be placed on the ground which will detect magnetic field signals with a distinctive phase shift. This phase shift is characteristic of the nano metal particles present in the fracturing fluid. The receivers on the ground shall help in determining the fracture length and width. Another array of receivers shall be kept on an offset well to determine the height of the fractures.
Fracture dimensions cannot be studied properly in laboratory because the anisotropy of the formation is very difficult to create. But this method will offer a method of comparison between planned and actual fracture dimensions. This will help in refinement of hydraulic fracturing simulators. Effects of in-situ stress conditions on fracture dimensions shall be better understood.
Manganese or zinc doped ferrite of concentration 160g/bbl and sizes between 10nm to 1μm shall have a magnetic permeability of 50μ0. Silver nanoparticles can also be used since it will provide a distinct phase shift which shall be easily identifiable. This paper shall also discuss the method of interpreting fracture dimensions from magnetic signals.
Shale gas formations are a prime target for hydraulic fracturing. These formations can modelled better with use of this method. Effectiveness of hydraulic fracturing operation can be gauged and improved using this method.
Application of Streamline Simulation to Reservoir Management: Management of WAG Injection Optimization
Authors: Bouaouaja Mohamed , Bassiouni Mahmoud , Nasiri Amir , Shaker Ashraf , Al Basry Ali H. , Masdour Rabah , Takahashi Masahiro , El Mahdi Ahmad 
Published: November 2012

Abstract
Reservoir management practices are classically based on analytical models and standard Reservoir Engineering tools. In the waterfood or water alternating gas recovery process, the analysis is made traditionally with the hypothesis of constant predefined patterns. The producer – injector pair's interaction is quantified based on predefined geometrical analysis of the percentages of contribution of each injector to a producer. In the absence of certain degree of reservoir homogeneity, and also possible injection/production technical issues this method presents a lot of limitation and may lead to erroneous results. Fields in the Middle East are dominantly carbonates and the flow paths are guided by heterogeneous distribution of reservoir characteristics mainly permeability.
This paper outlines a case study for the usage of streamline simulation in predefining the optimized rates of each producer and injector in order to optimize the recovery from individual pattern. The study quantified the interaction between producers and injectors pairs and defined the dynamic pattern distribution through the history. A number of attributes can be derived for each producer injector and pattern. Attributes such as the instantaneous and cumulative voidage replacement ratio, sweep efficiency and injection leakage can be analyzed in order to give more weight in the optimization stage to certain producer and certain injectors. It was concluded that the geometrical lay out of the patterns is not necessary respected and the injectors may support producers outside their geometrical patterns. There was as well a certain amount of the injection that is not contributing to any production and it is not targeting or supporting any specific well.
A number of forecast scenarios were conducted and through ranking different realizations based on total patterns sweep efficiency, the best scenario was selected to determine the allowable volumes to be injected and produced. The scenario showed better control of the patterns as there was a reduction of any redundant injection and the leakage was cut down.
Smart Nano-EOR Process for Abu Dhabi Carbonate Reservoirs
Authors: Haroun Mohamed , Al Hassan Saeed , Ansari Arsalan , Al Kindy Nabeela , Abou Sayed Nada , Ali Basma , Sarma Hemanta 
Published: November 2012

Abstract
EOR technologies such as CO2 flooding, chemical floods and WAG have been on the forefront of oil and gas R&D for the past 4 decades. While most of them are demonstrating very promising results in both lab scale and field pilots, the thrive for exploring additional EOR technologies while achieving full field application has yet to be achieved. Nano EOR is among the new frontiers that demand more improvements, therefore, new concepts and extensive innovative experimental procedures are required to identify and address key associated uncertainties.
The procedure proposed in this report includes an understanding of the Nano-EOR physical processes on lab-scale models of carbonate reservoir retrieved core plugs. (Ogolo et al., 2010). The main objectives include reducing the HSE concerns of handling and transporting the nano particles as well as targeting the unswept oil.
Carbonate core-plugs from Abu Dhabi producing oilfields with porosity ranging from 10 to 24% and permeability ranging from 77 to 149 mD were tested. Several nano particles including Fe (III) O, CuO and NiO of 50 nm range were tested after the waterflooding stage and compared for ultimate recovery factors. The nano EOR was also compared on the same cores subjected to the same conditions against chemical EOR and Electrically Enhanced Oil Recovery (EEOR). A Smart Nano-EOR process is proposed in this study that allows shifting from simultaneous to sequential Nano-EOR alongside EK.
The results obtained on our tested cores reveal that the waterflooding recovery factor ranged from 48 to 63% based on the rock properties, whereas Smart Nano-EOR revealed an ultimate recovery factor of 57 to 85% respectively. The Smart Nano-EOR process is fine tuned to reach the ultimate recovery factor when the specific mechanism is optimized based on both rock and fluid properties. Uncovering physical process enablers will be discussed in this paper to further understand the mechanisms involved in Smart-Nano-EOR.
Azimuthal Seismic Analysis Yields New Insights for a Giant Onshore Oil Field, U.A.E.
Authors: Mahmoud Sabry L. , Othman Adel A. , El Kadi Hassan H. , Berteussen Karl 
Published: November 2012

Abstract
An azimuthal seismic study for fault and fracture identification was carried out on a giant onshore carbonate oil reservoir in the U.A.E., Middle East. The seismic reflectivity analysis was performed using advanced independently processed azimuthal sectors from compressional waves. The seismic attributes demonstrated superior capability of defining accurately the detailed reservoir faults and the fracture networks. Although the full azimuthal study achieved excellent results, the azimuthal stacks were observed to sharpen the reservoir subtle structural features. Beside the traditional land seismic data processing, additional challenges were to properly process the seismic data due to the surface topography and the lateral variations in subsurface rock properties. Azimuthal processing successfully demonstrated:
Improved fault imaging relative to the available conventionally processed seismic data. Additional information about the seismic anisotropy in the reservoir zones.
The analysis showed encouraging results and a relatively good match to known fault/fracture locations. The successful results of the study suggest that high quality 3D wide azimuthal seismic data with relative true amplitude preservation can be used to identify the fracture permeability pathways in carbonate reservoirs. The azimuthal sectors study and results facilitated the quantification of the presence of faults, and suggest that fractured zones can be identified. Another important procedure in this study is the use of the integrated approach during processing and interpretation. Overall, the results of this Azimuthal Study for fractured carbonate reservoir characterization revealed encouraging outputs and valuable guidelines for similar studies in the future.
An Integrated History Matching Approach of a Fractured Basement Reservoir - Block S2, Yemen
Authors: Zabalza Isabelle , Legrand Nicolas , Neff Pascale 
Published: November 2012

Abstract
This work addresses the challenging task of history matching a fractured basement reservoir.
Habban field, south-western part of Yemen, produces from two different horizons: the Kuhlan sandstone overlaying the fractured basement.
The fractured basement reservoir is characterized by two types of fracturing: background fractures with very low effective permeability of less than 0.001mD and fracture corridors with an effective permeability ranging from 0.01 up to 10 mD, and a total porosity of 1.3% only. Two sets of fracture corridors, with N-S and NW-SE mean orientation, contribute to production whereas background fractures act as storage feeding in those corridors.
The large contrast in properties between Kuhlan and Basement adds-on further challenges: Kuhlan possesses good reservoir properties but moderate storage (~10m thick), whereas fractured basement has extremely poor reservoir properties but significant storage (~700m thick).
Habban field has produced since end 2006 by depletion through 30 slanted wells. To optimally assess different production strategies, a simulation model was built. Dynamic data (MDT, PLT, BHP, production rates) were used to constrain the dynamic model on well by well basis.
Due to this extremely challenging setting, a very high focus was put on a history matching process that integrates geology and reservoir simulation work to result into an enhanced understanding of field mechanisms.
One main conclusion of this integrated history matching approach is that water comes to wells from neighborhood formations through main faults, explaining then the erratic water production (no crest to flank correlation). Second highlight concerns the major contribution of N-S main fractures. Finally understanding of the communication mechanism between basement and Kuhlan was enhanced, showing that despite basement poor properties, basement oil feeds in Kuhlan, as Kuhlan is produced. This synergized understanding of Habban mechanisms is a clear milestone for further well location planning and oil recovery optimization under uncertainty.
Design of an Inline Power Generating System for Remote Oil and Gas Production Installation
Authors: Idachaba Francis E 
Published: November 2012

Abstract
A major challenge faced by oil and gas production companies is the supply of a reliable, cost effective, low maintenance and renewable source of power supply to the remote wellheads especially in areas prone to vandalization. Strategies deployed to provide power supply at these remote locations range from the installation of diesel generator sets, solar panels, inverters and battery banks among others. These solutions have been found to require constant monitoring and fueling in the case of the diesel generators, been prone to vandalization as in the case of solar panels and batteries. The inline power supply system comprises of a turbine system installed in a branch pipe. The system is inserted on a flow line from the wellhead so that it utilizes the fluid flow to provide the required kinetic energy to turn the turbine which is direct coupled to a gear and a DC generator. The output of the generator is fed to an electronic board which comprises of a regulator and a DC/DC converter. The DC/DC converter is responsible for providing the required DC level for wellhead instruments and communication devices. The system comprises of two identical installations in branched pipes providing 100% redundancy. The main application for this technology is in the provision of safe and vandalization proof power supply to remote oil and gas production installations especially at the wellheads. No oil or gas preprocessing is required as the turbine requires only the kinetic energy in the fluid. The use of an active flow line also guarantees the system protection against vandalization. The 100% redundancy guarantees that the system has negligible impact on the production process once deployed. The system provides a safe and cost effective safe power supply system for wellhead locations and reduces the OPEX required to keep the production facility powered
Practical Down Hole Dielectric and Diffusion-based Magnetic Resonance Workflow for Saturations and Viscosity of Heavy Oil Reservoirs Using a Laboratory Viscosity Calibration
Authors: Bachman H. N. , Rampurawala M. , Valori A. , Ali F. , Nicot B. , Sangani P. , Denny T. , Newton S. 
Published: November 2012

Abstract
Unconventional resources merit strong attention in the oilfield today. Great value is placed on understanding the amount and viscosity of the oil which in turn guides the production strategy. We demonstrate a workflow employed in Middle East carbonate reservoirs containing intermediate to heavy oil. The workflow combines dielectric and nuclear magnetic resonance (NMR) log data, and it is complemented by laboratory measurements. The applicable range of viscosities is tens to thousands of centipoises.
Integrating dielectric and NMR log data provides a more accurate determination of saturation and viscosity. The workflow does not require any change to the processing of the raw data and is simple to implement. We demonstrate the workflow using log data along with correlations from lab measurements on core and bulk fluids. The workflow solves three key challenges for heavy oil analysis.
The first challenge is the overlap of heavy oil and bound water NMR signals, compounded by a radial variation of saturations near the wellbore. Conveniently, the physics of dielectric and NMR measurement results in depths of investigation of 1 to 4 inches. Dielectric-based analysis provides the total water-filled porosity, which improves the NMR-based saturation and fluid characterization. The second challenge comes from the effect of restricted diffusion of water molecules in pores. We show that a restricted diffusion model is required to obtain accurate saturations and viscosity. The third challenge is the reduced NMR sensitivity to viscosity for heavy oil. Lab measurements on core and bulk oil samples provide the parameters required to link NMR to viscosity.
We describe a workflow based on dielectric and NMR log data for a more accurate determination of fluid saturations and oil viscosity. The workflow takes into account a) the combined dielectric and NMR data; b) the carbonate restricted diffusion effect inherent in the NMR response for carbonates; and c) laboratory validation and interpretation support using core plugs in wells where the dielectric data was not available. We use log data covering a range of heavy oil viscosities to demonstrate the workflow in four wells.
Optimization of Inflow Control Device Placement and Mechanical Conformance Decisions Using a New Coupled Well-Intervention Simulator
Authors: Thornton Kim , Jorquera Ricardo , Soliman M. Y. 
Published: November 2012

Abstract
To optimize production from long horizontal wells, the completion design engineer must consider reservoir heterogeneity so that water breakthrough can be avoided. Reservoir heterogeneity is even more critical when combined with the presence of a strong aquifer; one of the methods commonly used to control this condition has been to have uniform water movement towards the horizontal well. Traditionally, inflow control devices (ICDs) have been used in horizontal wells to achieve this goal. However, design of the ICDs and now autonomous inflow control devices (AICDs) to achieve optimum productivity from the horizontal well can only be achieved by properly linking the ICD and AICD design to reservoir characteristics. Unfortunately, operators and service companies have often applied ICDs without adequate methods to verify completion efficiency over time, since available tools to quantify reservoir complexities and their effects over time have not been readily available.
In this paper, a methodology and a numerical simulation approach that are designed to improve the success ratio of mechanical conformance treatments is presented. This approach combines a comprehensive solution for determining ICD and AICD effects on the wellbore behavior with a reservoir numerical simulator. The methodology considers the following: Placement techniquesAnnular flow controlICD flow size, rate, and number of ICDsReservoir fluid propertiesReservoir permeability distribution effectsFluid-property changes including prediction of water and gas breakthrough over time.
A numerical simulator that couples the wellbore and reservoir characteristics has been developed that can provide an efficient means for optimizing ICD/AICD design and initialization. Simulated examples are given for basic conformance phenomena such as coning and channeling. Field cases will be presented that demonstrate the application of this method and how it designed an optimum ICD/AICD completion solution.
This method reduced risks associated with ICD design and optimized the system designs through more accurately predicting water and hydrocarbon production.
Improving the Production Potential of Shale Gas Wells by Optimizing Multi-Stage Completions Cost Using High-Resolution LWD Images
Authors: Janwadkar Sandeep , Thomas Mark , Denney Steve 
Published: November 2012

Abstract
Developing unconventional shale gas plays in the Middle East is starting to gain momentum in activity based on the success of unconventional shale gas in North America. A closer look at the statistics reveal that although initial well productivity in North America has increased with the adoption of new drilling and completion technologies, it is still difficult to forecast the success of a single well, as results may be quite inconsistent within the same section or across the play. This paper reviews the factors affecting well productivity and focuses on optimized completions design based on a better understanding of the stress fields in the sub-surface as well as the fracture network. Based on experience from the Barnett Shale, one of the most mature and prolific natural gas fields in North America, the paper will highlight the importance of natural fractures, offset induced fractures, faults, and internal stresses, which are increasingly important to characterize and map as infield drilling increases. A high-resolution logging while drilling (LWD) electrical imaging tool was used to acquire images on a well drilled between two wells drilled between two offset wells 600ft apart within the same section. Fracture systems, faults, and stresses in the field were interpreted and mapped to further develop completions, fracture treatments and well placements. The paper shows how LWD images were used to determine which stages had previously been fractured and to explain how production from offset wells was reduced by as much as 40%. Operators have increased well productivity by up to 20% in more than 300 wells drilled to date. Lessons learned can be applied to most conventional and unconventional plays around the world.
Extended Reach Drilling (ERD) Optimization in Layer a Shale through Geomechanical Characterization
Authors: Grini Morten , Ottesen Steinar , Al Junaibi Hamad Saleh , Jorden John , Crawford Brian , Boyd Douglas Alexander , Martin Wallace W. , Alramahi Bashar , Gosavi Shekhar 
Published: November 2012

Abstract
Significant rock strength anisotropy associated with weak bedding laminations in shale can lead to wellbore instability challenges especially when drilling Extended Reach Drilling (ERD) wells that require low angles of attack relative to the formation bedding planes. Past drilling experience with water-based muds in offshore Abu Dhabi showed a high frequency of hole-cleaning and stuck-pipe events for wells deviated above approximately 40° from vertical. This was attributed to shale instability due to the invasion of the drilling fluids into micro-fractures along bedding planes as longer exposure lengths and times increased with the angle of deviation.
Recently the decision to further develop a giant field with wells drilled from artificial islands has created the need for large numbers of ERD wells that will cross the shale formations at angles in the range of 40° to 85°. Pilot holes have been successfully drilled across shales at angles up to 80° by using non-aqueous drilling fluid (NADF) with mud weights predicted with an ExxonMobil proprietary model that uses previous experience and limited log data. Nevertheless, it was considered advantageous, if not essential, to better understand the mechanisms for shale instability as a function of both the angle of inclination and azimuth of the section, since it is critical to reliable prediction of the mud weight and chemistry required to avoid well-bore instability.
An extensive program of tri-axial compression testing of orientated preserved core plugs was conducted in order to quantify the degree of strength anisotropy associated with both a reservoir cap, Layer A shale and intra-reservoir shales encountered while drilling offshore Abu Dhabi. This work showed that Layer A shale's compressive strength can be reduced by approximately 70 to 75% and the intra-reservoir shares by approximately 45 to 50%, when the shear plane of failure aligns with the weak laminations, compared to loading parallel, or perpendicular to the bedding planes.
The inclusion of the measured strength anisotropy functions into a wellbore stability model is shown to accurately predict the observed mud weights associated with induced wellbore breakout. The non-aqueous (NADF) mud weight required for wellbore stability was incorporated in an Integrated Hole Quality and Quantitative Risk Assessment (IHQ/QRA) study to evaluate the drillability of various ERD well designs. Actual field drilling performance with NADF has also been used to validate the model. Increased understanding of this wellbore failure mechanism has the potential to reduce drilling risk and significantly increase current extended reach drilling limits for ZADCO's long term field development plan offshore Abu Dhabi.
Electrification and Energy Efficiency in Oil and Gas Upstream
Authors: Devold Håvard 
Published: November 2012

Abstract
Oil and Gas electrification projects are being planned in countries as diverse as Norway, Qatar, Saudi Arabia, Malaysia, Russia, Canada and Australia. Climate policies and emissions reductions are important also for these countries, but the project decisions are primarily based on economic considerations. The environmental and economic results of electrification are documented in numerous studies.
Reduced operating costs, improved energy efficiency, uptime, stability and HSE factors such as reduced noise, vibration and fewer ignition sources means that more and more oil companies are now focusing on electrification.
This paper looks at the overall CAPEX and OPEX elements and discusses the operational and economic scenarios and their impact on the life cycle cost of a set of cases; LNG and Offshore Facilities. We believe these models support economic benefits in the longer term, and that the environmental footprint is significantly reduced due to 50-70% improved energy efficiency.