bluuebunny/crossref_metadata_2025_split huggingface dataset:
Simulating the Effects of Water Shut-off Treatment by Polymer Gel Injection
Authors: Lashari Zeeshan Ali , Memon Asadullah , Ansari Ubedullah , Memon H. U. , Tunio A. H. 
Published: March 2015

Abstract
Worldwide, the high water production along producing hydrocarbons is affecting the cumulative productivity of wells. Due to complex reservoir parametric changes during the production, the near-by water aquifers or water tables infiltrates highly into the reservoir and starts affecting the well's productivity. Controlling the high water-cut producing wells is very challenging in the petroleum industry and is of prime importance as high water cut wells sometimes creates the mechanical and chemical damages to the equipment, depending on the water composition.
The research is focused on using one of the most effective and economical chemical treatment method. The Colloidal Dispersion Polymer Gel (CDPG) is injected from the injection well into the reservoir having very high the water cut. CDPG injection attempts in increasing the water viscosity, decreasing its mobility towards producing well that results in increasing the reservoir's oil productivity. CDPG injection results in oil increment and reduces 21% water-cut whereas initially it was 78% and now it is 57%. That much amount of water if produced will cost huge techno-economics and increment oil will prominently help to increase profit.
Integrated Approach of Retrograde Condensate Simulation Using Pseudo-Pressures with Modified Equation of State and Velocity Dependent Relative Permeability
Authors: Ahmed Sheraz , Abrar Saad bin 
Published: March 2015

Abstract
It is a well-known fact that the deliverability of condensate reservoirs is a function of condensate formation around the wellbore. Thus, accurate estimation of condensate recovery necessitates properly modeled Equation-of-State (EOS) and subsurface flow phenomena. EOS is a function of numerous parameters of the Reservoir and Fluid contained; however it should be kept in mind that it is almost impossible to exactly match all these parameters, while all the parameters don’t obligate equal significance as well.
This paper describes the most important parameters in EOS which ultimately control the overall condensate recovery. It involves unique simulation methodology to determine the condensate flow in reservoir using velocity-dependent-relative-permeability (VRP) curves (instead of conventional-relative permeability methods) to determine the effect of velocity stripping near the well bore; and the Pseudo-pressure approach.
The modified form of EOS used in the study, along with the VRP curves features accurate condensate flow in the reservoir and its optimization. Moreover, using the pseudo pressure approach, this paper also signifies the reservoir modeling and forecasting methods with minimum amount of time for simulation.
A complete and comprehensive strategy has been presented in this paper, to infer the factors having max influence on recovery. Using diverse sensitivities, it is evident that four parameters have a high influence; which includes compositional-variation with depth, Liquid drop-out, Condensate viscosity and Compressibility, while the rest yield minimal impact. The VPR models also improve history matching and give better forecast; while using pseudo-pressure approach reduces significant time with negligible impact on the results.
Short Axis Logging for Successful Formation Testing in Ovalized Borehole Conditions
Authors: Mughal Muhammad Haroon , Khalid Arsalan , Dar Usman , Arif Fahad , Abbas Mohsin , Abbasi Iftikhar , Malik Mohsin , Bregar Udo B. 
Published: March 2015

Abstract
Pressure is a basic requirement in reservoir simulation, well bore stability studies, well completion design and drilling horizontal sections. Determining reservoir pressures in ovalised/elliptical hole and tight formations with wireline formation testing tools is challenging. When we have hostile logging conditions i.e. high temperature and ovalised bore-hole conditions; it becomes more difficult to obtain the formation pressures. In tight formations, conventional wireline formation testers are unable to obtain reliable pressure values as pretest volumes are very high leading to unstable pressures. This makes the pressure measurement unreliable and no further analysis is possible. Short axis logging with Positioning Calliper helps in orienting the tool towards the short axis (on-gauge side) of borehole wall making it possible to obtain seal and to take pressure points. In addition with new generation wireline formation testing tools, pressure measurement in tight formations is now possible based on the advanced pretest mechanism.
This paper is about a case study where pressure testing in ovalised bore-hole conditions in a high temperature tight gas formation was done in Pakistan. Short axis logging with positioning caliper was proposed as a solution with Advanced Formation Testing tool.
Bimodal Spectroscopy of Formalin Fixed Samples to Discriminate Dysplastic and Tumor Brain Tissues
Authors: Anand S. , Cicchi R. , Giordano F. , Buccoliero A. M. , Guerrini R. , Pavone F. S 
Published: March 2015

Abstract
Biomedical spectroscopy has gained attention in the past few years for disease diagnosis. Fluorescence and Raman spectroscopies provide finger-print information related to biochemical and morphological alterations when tissues progress from the normal to a malignant stage. Usually, freshly excised tissue specimens are preferred for bio-spectroscopic studies. However, ethical issues, sample availability and distance between the surgery room and the laboratory provide an impelling restriction for in-vitro spectroscopic studies using freshly excised samples. After surgical resection tissues are fixed in 4% formalin for histological studies under a light microscope. The process of fixation prevents degradation of tissues. In this study, we probe the use of formalin fixed sample for differentiating normal and dysplastic brain tissues using fluorescence and Raman spectroscopies. It was found that fluorescence spectral profile changes in the wavelength range from 550-750 nm between dysplastic and tumor samples. Also, significant differences were found in the Raman spectral profiles of such samples. The results indicate a potential diagnostic application of spectroscopy in formalin fixed brain samples for differentiating dysplastic and tumor brain tissues.
Multispectral Video-Microscope Modified for Skin Diagnostics
Authors: Rubins U. , Zaharans J. , Ļihačova I. , Spigulis J. 
Published: March 2015

Abstract
Commercial DinoLite AD413 digital microscope was modified for skin diagnostics purposes. The original LED ring (4 white and 4 ultraviolet light emitters) of microscope was replaced by a custom-designed 16-LED ring module consisting of four LED groups (450, 545, 660 and 940 nm), and an onboard LED controller with USB hub was added. The video acquisition and LED switching are performed using custom-designed Matlab software which provides real-time spectral analysis of multi-spectral images and calculation of skin chromophore optical density. The developed multispectral video-microscope is mainly meant for diagnostics of skin malformations, e.g. skin cancerous lesions.
Changing The Game In The Stimulation of Thick Carbonate Gas Reservoirs
Authors: Thabet ElSayed Ahmed , Brady Mark Edward , Parsons Christopher A. , Byrne Sean , Voropaev Sergei V. , Lesko Timothy Michael , Tardy Philippe Michel , Cohen Charles Edouard , Mchaweh Abdulsalam 
Published: March 2015

Abstract
In this paper we present details of the approach utilized to optimize the completion and stimulation campaign in the continued development of a large gas carbonate field in the Middle East. A new acid diverter was deployed along with a revised placement model, field calibrated to more accurately predict treatment pressure responses, to optimize treatment design and to maximize diversion in this layered reservoir. Results presented include typical stimulation treatment plots alongside model post treatment pressure history matches, pre and post stimulation production logs, clean up data and well test interpretations. We also present details on how this new approach facilitated the execution of simultaneous drilling and well intervention operations.
We describe high permeability, multi zone treatments with a bullheaded matrix acid technique. We observed through large bore tubing treatment pressures in excess of 3000 psi, far above what is typically observed in this field. A degradable fibrous material was incorporated into an in-situ self viscosifying surfactant based acid formulation to effect the diversion responses and we observed negligible returns of fibres during clean up operations. We observed uniform inflow profiles, validating the technique and provide evidence that the use of such a fluid system is capable, in certain circumstances, of reconnecting to natural fracture and loss zones. We have also observed significant benefits in reduced flaring requirements for well clean up.
We conclude that this technique has facilitated enhanced diversion and promoted uniform zonal depletion. We have also found operational benefits in deploying the system in that commingled zones, normally perforated and stimulated in several stages can now be easily and effectively stimulated using a one-stage technique.
The stimulation of thick carbonate intervals presents several challenges if the long term well and field productivity is considered. Overcoming these challenges without additional well interventions such as setting retrievable bridge plugs or the introduction of ball sealers, requiring slick line re-entry to ensure no interference with surveillance activities, significantly reduces operational risk and well site exposure.
Assessing Fluid Migration and Quantifying Remaining Oil Saturation in a Mature Carbonate Reservoir: Dukhan Arab D
Authors: Barrios Vera Levin Jose , Muhamad Rais Tajjul , Trabelsi Ali , Al-Qarshubi Ibrahim , Al-Ansi Hussain Abdulla 
Published: March 2015

Abstract
The large, mature Dukhan field is located onshore Qatar. The Arab D is the main oil reservoir in terms of size and production potential. The development of the reservoir commenced from North to South, which created initial differential pressure depletion between two of the southern sectors of the reservoir.
It is believed that differential depletion resulted in considerable fluid migration across sector boundaries. Therefore, it has introduced uncertainty in quantifying the remaining oil in place, recovery efficiency and reserves.
This paper describes the use of conventional material balance and volumetric techniques to investigate the reservoir behavior in order to shed light on fluid migration, the current oil in place and recovery efficiency, as well as identifying limitations and uncertainties. Material balance and fluid migration results indicated new scenarios for oil and water migration between the two southern sectors. The technique has proven to be valuable in understanding a complex reservoir engineering problem.
In order to better understand the migration process and to complement and validate the results of the material balance, and support the numerical simulation study, a data collection programme was carried out by drilling wells and low invasion cores in partially swept zones of the reservoir. The cores are used to determine remaining oil saturation (ROS), residual oil saturation (Sorw), wettability and relative permeability (SCAL) data. The preliminary results of this programme are presented in this paper.
Integration of the available and additional ROS and SCAL data will be instrumental during the subsequent stages of the reservoir study in defining the remaining reserves of the field and future upside potential of the reservoir. Therefore the work programme, assumptions and results presented in this paper may be of general interest and used as a reference for this kind of application.

Introduction
The development of the remaining oil in some areas of the Arab D reservoir will largely depend on the understanding of the fluid migration. As part of the ongoing reservoir studies, conventional material balance and volumetric analyses were carried out on the Arab D reservoir with the aim of characterizing the current drive mechanism and quantifying fluid migration between reservoir sectors.
The first part of this paper describes this analysis which was performed in stages as follows:Collection and validation of input data.Analysis of production, injection and pressure histories.Single tank material balance analysis.Multi tank material balance and sensitivity analysis of fluid migration.Estimation of unswept remaining oil above the current oil-water contact by volumetric analysis.Determination of waterflood sweep efficiency.
Measurement of Gas Viscosity at High Pressures and High Temperatures
Authors: Ling Kegang , McCain William D. , Davani Ehsan , Falcone Gioia 
Published: March 2015

Abstract
Gas viscosity is an important fluid property in petroleum engineering due to its impact in oil and gas production and transportation where it contributes to the resistance to the flow of a fluid both in porous media and pipes. Although the property has been studied thoroughly at low to intermediate pressures and temperatures, there is lack of detailed knowledge of gas viscosity behavior at high pressures and high temperatures (HPHT) in the oil and gas industry.
The need to understand and be able to predict gas viscosity at HPHT has become increasingly important as exploration and production has moved to ever deeper formations where HPHT conditions are more likely to be encountered. Knowledge of gas viscosity is required for fundamental petroleum engineering calculations that allow one to optimize the overall management of a HPHT gas field and to better estimate reserves. Existing gas viscosity correlations are derived using measured data at low to moderate pressures and temperatures, i.e. less than 10,000 psia and 300 oF, and then extrapolated to HPHT conditions. No measured gas viscosities at HPHT are currently available, and so the validity of this extrapolation approach is doubtful due to the lack of experimental calibration.
The falling body viscometer is selected to measure gas viscosity for a pressure range of 3,000 to 24,500 psia and temperature range of 100 to 415 oF. Nitrogen was used to calibrate the instrument and to account for the fact that the concentrations of non-hydrocarbons are observed to increase dramatically in HPHT reservoirs. Then methane viscosity is measured to reflect the fact that, at HPHT conditions, the reservoir fluids will be very lean gases, typically methane with some degree of impurity. The experiments showed that while the correlation of Lee et al. accurately estimates gas viscosity at low to moderate pressure and temperature, it does not provide a good match to gas viscosity at HPHT conditions.

Introduction
HPHT gas reservoirs are defined as having pressures greater than 10,000 psia and temperatures over 300ºF. Modeling the performance of these unconventional reservoirs requires the understanding of gas behavior at elevated pressure and temperature. An important fluid property is gas viscosity, as it is used to model the gas mobility in the reservoir that can have a significant impact on reserves estimation during field development planning.
Accurate measurements of gas viscosity at HPHT conditions are both extremely difficult and expensive. Thus, this fluid property is typically estimated from published correlations that are based on laboratory data.
Unfortunately, the correlations available today do not have a sufficiently broad range of applicability in terms of pressure and temperature, and so their accuracy may be doubtful for the prediction of gas viscosity at HPHT conditions.
Advancing Self-Mitigating Sand Control Screen
Authors: Yeh Charles S. , Moffett Tracy , Petrie Dennis H. , Entchev Pavlin B. , Long Ted , Troshko Andrey , Grubert Marcel Andre , Dale Bruce A. , Barry Michael D. , Hecker Michael Thomas , Howell David A. 
Published: March 2015

Abstract
MazeFlo™ technology enables a sand control screen to self-mitigate mechanical damage and improve reliability in sand-prone well production. A self-mitigating screen uses redundant sand control screens and compartment baffles to restrict the effects of any mechanical screen failure to a local compartment. The hydrocarbon flow continues intact through the remaining undamaged screen compartments. This innovative, patented technology is being commercialized in collaboration with a selected service company.
This paper reviews the initial design and development of the self-mitigating screen prototype. The screen design balances flow hydraulics, well performance, mechanical integrity, and manufacturing complexity all while maintaining practical screen dimensions. Successful self-mitigation, after failure of an outer screen, requires that the incoming sand packs a compartment to shut off the flow path before any significant erosion occurs along the flow path to the redundant inner screen. The baffles are configured to both redirect fluid momentum from any "hot spot" inflow at the outer screen and impose a minimal friction loss during production through undamaged compartments. Each component in a compartment is designed to sustain erosion from the incoming sand of a failed outer screen. The offset outer and redundant inner screens are sized to minimize the impact on productivity when compared to conventional screens. The mechanical strength of the self-mitigating sand screen is also targeted to be equivalent to conventional screens.
Development of the self-mitigating screen prototype is proceeding and includes extensive qualification by multiple modeling techniques and physical testing. The innovative, self-mitigating capability expands the current operating limits of screens in sand control completions. In a broader view, the self-mitigating screen enhances overall reliability and longevity and can be integrated with other emerging technologies such as openhole zonal isolation, inflow control, and intelligent wells for enhanced production flexibility. MazeFlo sand screens will expand ExxonMobil's suite of innovative sand control solutions that include Alternate Path® technology, NAFPacSM process, openhole gravel packing with zonal isolation, and customizable sand control for extreme length completions and injection conformance.
Increasing Recovery in the Complex Reservoirs in the Al Shaheen Field, Offshore Qatar, by Mastering Reservoir Pressure for Large Scale Horizontal Infill Drilling
Authors: Lopdrup Thomas P. , Ohrt Henrik Bjerre , Lechner Michael , El-Itawi Ghina , Noman Rashed , Jaafar Mohd Rushdan 
Published: March 2015

Abstract
The giant Al Shaheen field offshore Qatar comprises six stacked carbonate and sandstone reservoirs developed with extended reach horizontal wells. More than 130 horizontal production and injection development wells had been drilled up to end 2005 when implementation of a new large scale field development plan commenced. The new development plan, FDP 2005, comprises 163 additional horizontal development wells from six existing and three new locations.
The initial development phases in Al Shaheen comprised radial and parallel well patterns of long horizontal wells with a well spacing designed to enable effective appraisal and data gathering. A significant part of the FDP 2005 is dependent on successful horizontal infill drilling where close well spacing is required to ensure optimal recovery of the low permeability carbonate formations.
The combination of stacked reservoirs, reservoir heterogeneities, long horizontal wells, close well spacing and past production and injection result in pressure regimes along the wells which are challenging to predict but crucial to manage for successful well planning and execution. Successful implementation of the FDP 2005 requires a detailed and systematic approach for reservoir pressure conditioning to ensure acceptable pressure gradients along the new wells while at the same time minimize the impact on the short term oil production.
This paper describes the challenges related to the reservoir pressure conditioning in the complex Al Shaheen field offshore Qatar. The applied methodology covering systematic use of reservoir simulation models, nodal analyses, pressure transient analyses and timely shut-in of producers and injectors to map and manage pressure regimes is presented.

Introduction
The Al Shaheen field is located in Block 5, offshore Qatar, covering an area of some 2080 km2, Figure 1. The main reservoir targets include the Lower Cretaceous Kharaib B and Shuaiba carbonate formations and the overlaying Nahr Umr sandstone formation, Figure 2. The carbonate reservoirs are characterized by relatively thin oil columns with a large areal extent with typical permeabilities in the 1–10 mD range. The reservoir fluid properties exhibit large lateral variations, with oil gravities ranging from 16–38 °API within the same reservoir. The field contains several gas caps and shows large variations in solution gas-oil ratio and saturation pressures.
Following the discovery of the Cretaceous oil accumulation in 1974, various operators drilled a number of appraisal wells and comprehensive studies were conducted at the time in order to establish the feasibility of development. However, well tests in the vertical appraisal wells yielded discouraging results and it was concluded that development was not economically feasible1.