bluuebunny/crossref_metadata_2025_split huggingface dataset:
Laboratory and Simulation Study of Optimized Water Additives for Improved Heavy Oil Recovery
Authors: Wang X. , Luo P. , Zhang Y. , Charkovskyy V. , Huang S. 
Published: June 2012

Abstract
This paper discusses a laboratory evaluation of the feasibility of different chemical flooding strategies and a simulation study to optimize the feasible strategies for a west-central Saskatchewan heavy oil reservoir. The integrated experimental approach was composed of oil/brine interfacial tension (IFT) measurements, polymer viscosity measurements, wetting tendency measurements, and sandpack coreflood tests. The experimental results showed that the equilibrium interfacial tension between reservoir oil and formation brine could be lowered to an ultralow level (0.05 mN/m) by adding a certain concentration of alkali and surfactant into the brine. The addition of alkali and surfactant caused the wettability characteristics in all tested systems to become oil-wet. All of the polymer solutions exhibited pseudo-plastic behaviour, i.e., the apparent viscosity decreased with increasing shear rate. A series of sandpack coreflood tests were carried out to investigate the recovery performance of alkali + surfactant, polymer, and alkali + surfactant + polymer (ASP) floods. Enhanced oil recoveries (from the chemical flood and extended waterflood) varied significantly from 0.71 to 14.65% OOIP. The coreflood results suggest that in enhanced waterflooding for recovering viscous heavy oil, mobility control by polymer is more important than IFT reduction by alkaline/surfactant. In the simulation study, the relative permeability curves were obtained through history matching. Then, as the sensitive operating parameters, the ASP slugs and polymer concentrations were tuned to show their effects on enhanced heavy oil recovery (EHOR). In summary, ASP flooding provides synergistic effects that can maximize the recovery performance.
Optimum Development Scenario of Heavy Oil Sandstone Reservoir with Gas Cap
Authors: Makkar Christine F. , Makkar Mariam F. , Makkar Nancy F. 
Published: June 2012

Abstract
There are several kinds of unconventional oil production and one of them is heavy oil production from sand reservoirs with initially gas cap. A gas cap near the top of a heavy oil formation is a rare occurrence; however, high gas saturation or desaturated ("air") zones may form as a result of natural depletion.
Heavy oil is increasingly being produced by steam injection, cyclic or continuous, and to a smaller extent, by in situ combustion. A gas cap would increase the tendency of the override of the injected steam or air, resulting in poor vertical sweep. These simplified pictures are complicated by the flow of heat from the gas zones, into the oil zone.
In reservoirs with initially gas cap, it is necessary to inject in the wells that produce excessive gas in order to conserve gas, maintains reservoir pressure, decrease the oil viscosity and thereby increase ultimate oil recovery. This method depends on steam flooding injection in the crest of reservoir and this will heat the reservoir through steam injection and thus decrease the oil viscosity and increase the gas cap size due to thermal vaporization of oil and increase the gravity drainage as well.
Using steam introduces more heat into the reservoir as it flows in the gas cap and helps in distributing the heat.
The field forecast does not examined cold production as there is an initially gas cap and any production without injection in this type of reservoir will consume the pressure support.
A numerical simulation study has been undertaken to explore the optimum method to develop heavy oil sandstone reservoir of 12.8 API with initially gas cap by using steam injection stimulation either by steam flooding and/or steam cycles. This is applied on a sector model of 1200 × 1200 m from the full field model (Fig. 1) utilize compositional, and thermal options. Different sensitivities have been examined such as well spacing, number of injectors and producers, various injection strategies, injection parameters, the duration of steam cyclic stimulation, and well type whether vertical or horizontal.
Integrated Production Chemistry Management Of The Schoonebeek Heavy Oil Redevelopment in the Netherlands: From Project to Start-Up and Steady State Production
Authors: Shepherd Andrew G. , Mcgregor Stuart , Trompert Ruud , Ubbels Sen , van de Gender Bob , van Ommen Theo , van der Knoop Sjoerd 
Published: June 2012

Abstract
This paper describes the production chemistry management process undertaken during the design, commissioning and start-up phases of the Schoonebeek redevelopment. Challenging separation issues, saline water, together with a multitude of other process conditions, resulted in complex, but robust application portfolio. This was established during the design stages of the project. Early involvement of the production chemistry discipline aided this process. Chemical selection was conducted in adherence to HSSE directives and focusing on unique produced fluid properties. Since start-up, the success of chemical performance has been due to the availability of chemical treatment programs and surveillance/sampling plans. No contingency chemicals have so far been needed at the facilities since start-up. Export oil and water key performance indicators have been for the majority of the time met. Further optimization of chemical applications is an ongoing process which will follow the life of the field.
Effect of Nanoparticles on Migrating Fines in Formations
Authors: Petroleum Technology Development Fund (PTDF) Research Group _ , Ogolo Naomi , Olafuyi Olalekan , Onyekonwu Mike 
Published: June 2012

ABSTRACTFines migration in reservoirs is a serious problem because it gives rise to several problems in hydrocarbon production. Several methods have been proposed and applied to manage this problem but some have failed, some have been ineffective while others consolidate wellbore formations. Rendering formation fines immobile by attaching them to the formation matrix is the best option in controlling migrating fines in reservoir formations. There are indications that the presence of certain nanoparticles in the formation can prevent fines migration by fixing them to the formation.This project therefore investigates the fines trapping capacity of nine nanoparticles in sand packs. The ability of nano treated sands to retain the clays they contain at high flow rates of low salinity water capable of moving fines was examined. The effect of hydrocarbons on the performance of these nanoparticles and other conditions that affect ce their performances were studied. The best performing nanoparticles and the ideal dispersing fluids that aids in accomplishing this task were determined. Experimental results show that dispersing the right kind of nanoparticles in reservoir formations can control fines migration thereby preventing the primary and secondary problems caused by unconsolidated reservoir formations. Field application of this technique will in addition optimize hydrocarbon production and flow assurance.
The Trick Is The Surface - Functionalized Nanodiamond PDC Technology
Authors: Chakraborty Soma , Agrawal Gaurav , DiGiovanni Anthony , Scott Dan 
Published: June 2012

Abstract
Nanoparticles have built tremendous interest in recent years. In this regard carbon nanomaterials are extremely interesting because of their unique combination of mechanical, structural, electrical and thermal properties. With down-hole conditions shifting more towards challenging harsher, deeper and hotter conditions we have explored nanoparticles—nanodiamond in this case—for more demanding applications.
As a result of their inherent extremely high surface energy these very small particles tend to attract each other or exist as clusters. Thus a particle which is "nano" can exist as a submicron-or micron-sized cluster, thus overall exhibiting micron features instead of "nano" characteristics.
To derive the true benefits of a nanoparticle it is crucial to exfoliate and derivatize the surface such that the system is not only true "nano" but also so that the surface is activated to optimize the desired structure property relationship. Derivatization or — functionalization" further stabilizes the nanoparticles in different chemical matrices as well as activates them to directly bond/interact with their chemical environment. Thus functionalization is critical to the successful incorporation of nanoparticles into materials for various down-hole applications.
In this context nanodiamonds have been functionalized for polycrystalline diamond applications such as polycrystalline diamond compact (PDC) cutters for drill bits.
Nanodiamond particles have been derivatized or functionalized to give them unique surface characteristics that allow them to integrate homogeneously into PDC synthesis. We have studied the functionalization of nanodiamond, integration into the PDC matrix and subsequent property enhancement in comparison to the base PDC matrix. The performance of PDC cutters produced will be shown and the behaviors and proposed mechanisms will be discussed.
Experimental Investigation of Heavy Oil Recovery from Fractured Reservoirs by Secondary Steam – Gas Assisted Gravity Drainage
Authors: Mohsenzadeh A. , Escrochi M. , Afraz M. V. , Al-Wahaibi Yahya , Ayatollahi Sh. 
Published: June 2012

Abstract
In this study, gas-oil gravity drainage process and steam-gas assisted gravity drainage processes for heavy oil recovery from fractured models were investigated experimentally. For each test, six oil- wet saturated outcrop cores, 8.7 cm in diameter and 15 cm length, were stacked in a long core holder. In the first step, gas injection was started into the model at reservoir condition that results in oil production under gas-oil gravity drainage mechanism. In the second round of tests when no more oil was produced by gas injection, the tests were continued using steam-gas assisted gravity drainage process. In this stage, gas was injected together with specific steam/gas ratio at saturated temperature condition. In the course of experiments, oil and water productions, pressure and temperatures of system were monitored carefully.
The experiments were performed using three different combination of gases consist of pure CO2, pure N2 and mixture of 15 % CO2 and 85% N2 as synthetic flue gas. The results showed that after gas breakthrough and fracture depletion, the ultimate oil recovery for CO2 injection was 58.4 % (14.8% for gas injection and 43.6 % for steam-gas co-injection), in the case of flue gas injection, it was 73.8 % (9.8 % for gas injection and 64% for steam-gas co-injection) and for N2 injection was 47% (13.5 % for gas injection and 33.5% for steam-gas co-injection). The results indicate the high performance of flue gas injection for heavy oil recovery from fractured reservoirs during gas-oil gravity drainage and steam-gas assisted gravity drainage processes.
Thermo-Viscous Fingering in Heterogeneous Media
Authors: Sajjadi Mozhdeh , Azaiez Jalel 
Published: June 2012

Abstract
Adverse mobility ratio at the flood front in displacement processes due to temperature difference between the injected fluid and the medium and/or the inhabitant fluid may result in an instability known as thermo-viscous fingering (TVF). In practice such processes mostly take place in heterogeneous environments where the heterogeneity of the medium alters the preferred path of the flow and interacts with TVF. TVF is encountered in thermal-based enhanced oil recovery processes such as hot water flooding, steam flooding, CSS and SAGD or in fracturing. The fingers growth and development can have either favorable or detrimental impacts on the efficiency of these processes. The effects of adverse thermal or solutal mobility gradients and heterogeneity on the instability are quantified. Concentration, temperature, viscosity, and velocity fields have been generated using nonlinear simulations and studied for a better understanding of the mechanism of fingering at different log mobility ratios, heat exchange rates, and heterogeneity profiles. TVF in fields with wider channels is very similar to that in homogeneous fields and different mechanisms for finger development take place in the highly permeable layers. Heterogeneity works in favor of stability as the number of layers increases. In fields with many layers, the fingers induced by heterogeneity diffuse across the narrow channels and produce a widely diffused front which results in even less instability than in a homogeneous field. Heat exchange with the medium causes the thermal front to lag behind the solutal front and induce backward fingering (for unstable thermal front) or build a stable wall following the solutal front (for stable thermal front) and hence affect the sweep efficiency. The mechanism of TVF in heterogeneous porous media and its interaction with channeling are not well understood. Further studies in this field can illuminate the important factors affecting the displacement of heavy oil in Alberta fields.
A Generic Modeling Approach to Evaluate the Application of Different EOR Techniques for High-Viscous Oil in the Russkoye Field in the Russian Arctic
Authors: Gaviria William , Shmidt Sergey , Magdeyev Igor , Zakirov Iskander , Shayhutdinov Ildar , Gabisiani Georgiy 
Published: June 2012

Abstract
Russkoye oil field with gas cap, discovered in 1968, is one of the biggest high-viscous oil fields in Russia. It is a challenging field to develop commercially because of its geological complexity, unconsolidated formations, permafrost zone, and high heterogeneous compartmentalized reservoir with a large gas cap, active bottom aquifer, and remote location from main infrastructure. Consequently, a "generic modeling" approach was developed to evaluate the feasibility application of the following Enhanced Oil Recovery (EOR) techniques for this field: cold waterflood, hot waterflood, Water Alternating Gas (WAG), polymers and Alkaline-Surfactant-Polymer (ASP) injection.
The generic model consists of two main parts: a simulation model and a response surface model (RSM) equation.
The simulation model was constructed with uncertainty parameters to represent any combination of reservoir properties and any reservoir situation: large and small gas caps and just oil rim with bottom aquifer. Sensitivity analysis performed for selecting the most influencing parameters. Then a reasonably broad variation of the key parameters considered to successfully constructing the RSM equation. The Monte-Carlo technique was applied to get stochastic production profiles, which enable a rapid and reliable forecast of cumulative production, injection and recovery factor ranges.
The five field development technologies selected were analyzed using this generic modeling approach, prior to the commercial field development to maximize the recoverable reserves. Probabilistic profiles were estimated, taking into account the risk associated with the uncertainty in order to compare and rank selected EOR methods.
The generic modeling approach enables to make recommendations for data acquisition strategy in order to mitigate the influence of the key uncertainties on the commercial development. This approach gives to an engineer fast forecasting tool for estimation of production profiles by changing of boundaries of uncertainty parameters which reflects the change of circumstances after new data acquisition process conducted.
Simulation of Miscible Cyclic Injection Flows in Porous Media
Authors: Yuan Qingwang , Azaiez Jalel 
Published: June 2012

Abstract
The present study examines the development of miscible displacements in homogeneous porous media with a non-constant, time-dependent injection velocity. Numerical simulations for a sinusoidal injection velocity model are conducted to determine the effects of different variables on the efficiency of the displacement. The evolutions of nonlinear fingers with time are analyzed by plotting concentration fields, transversely averaged concentration profiles and sweep efficiency curve. Both the displacing process (injection process) and inverse displacing process (production process) are considered. Convection, transverse dispersion mechanisms, magnitude and frequency of the velocity changes are analyzed and the results are compared with those of a constant injection velocity process.
Experimental Study of Wettability Alteration of Limestone Rock from Oil-Wet to Water-Wet using Various Surfactants
Authors: Golabi Elyas , Azad Fakhry Seyedeyn , Ayatollahi Sayed Shahabuddin , Hosseini Sayed Nooroldin , Akhlaghi Naser 
Published: June 2012

Abstract
The water flooding in the carbonate fracture reservoir is low efficiency because of higher permeability in fractures than in matrix, and water will not imbibe spontaneously into the matrix due to a negative capillary pressure. Spontaneous imbibition of water into carbonate fracture reservoir is a very important issue in secondary oil recovery method. However, almost more than 80% of the entire known carbonate reservoir can be categorized as oil wet. It is therefore important to find methods to alter the wettability from oil-wet to water-wet conditions that are effective in order to improve the recovery from carbonate fracture reservoir. So far, two methods have been developed wettability alterations: 1) addition of certain chemical surface active agent to the injection water, and 2) thermally wettability alteration by steam injection.
In this study, an oil sample with 20 API was used to investigate the effect of the understudied surfactants on wettability alteration in the oil-water-limestone system.
Understudied surfactants were SDBS (sodium dodecylbenzene sulfonate), C12TAB (dodecyl trimethyl ammonium bromide), C16TAB (hexadecyl trimethyl ammonium bromide) and Triton X-100 that were utilized at 0.5, 1.5 and 2.5 wt% concentrations. The experiments were performed several times (0, 1, 6, 12, 24, 48, 72, 96 h) after injection of oil drop under limestone rock sample at reservoir temperature of 80°C. The obtained results showed that the increasing each of the surfactant could cause wettability alteration of the rock from oil-wet towards water-wet situation by passing of time. This alteration was very sharp at the beginning, but it was increases slightly at the time. It was observed that Triton X-100 was more efficient than C16TAB, C12TAB and SDBS to alter the wettability of the rock.
Energy (Heat) Distribution and Transformation in the SAGP Process
Authors: Wang J. Y. , Ezeuko C. C. , Gates I. D. 
Published: June 2012

Abstract
The Steam and Gas Push (SAGP) process was developed to improve the thermal efficiency of SAGD process. In SAGP, non-condensable gas is co-injected with steam into the reservoir. Ideally, the non-condensable gas accumulates at the top of the reservoir and provides insulation which reduces heat losses to the overburden. This means that lower SOR can be achieved at the same recovery factor. It remains unclear how energy is distributed and transformed within the chamber and its edges when non-condensable gas is added to the injected steam. In this work, we compare conduction and convection at edge of the steam chamber during SAGD and SAGP. The results show that both oil production rate and cumulative oil are reduced in SAGP compared to SAGD when 0.8 mole% NCG is co-injected with steam. This is because the injected NCG accumulates at the upper part of the leading edge of the steam chamber and slows down the growth of the steam chamber in that area, which results in lower cSOR but with a reduction of recovery factor. If 0.8 mole% NCG is co-injected at later periods of the operation, lower cSOR results without a significant reduction of oil production rates and cumulative oil production. In this case, the injected NCG migrates directly to the upper part of the reservoir and accumulates at the side edge of the steam chamber, since the steam chamber had already grown to the top of the reservoir. The added gas slows down lateral growth of the steam chamber in the upper part of the reservoir and forces steam chamber growth in the downward direction. From an analysis of energy transport in SAGP and SAGD operations, the results reveal the optimal timing for the onset of NCG co-injection with steam.
Using a New Hybrid Artificial Lift System for Mature Heavy Oil Fields
Authors: López Manríquez Alberto , López Hernández José G. 
Published: June 2012

Abstract
Previous work has been done in depleted carbonated heavy oil fields located in north of Mexico to address the problem of lack or low oil production due to high crude oil viscosity using downhole chemical treatment. In order to make these mature wells economically attractive, this previously acquired experience was combined with venturi technology, resulting in a downhole hybrid system designed as an alternative method to conventional gas lift.
This paper describes an in-depth analysis and the benefits of applying a hybrid artificial lifting system based on the principle of venturi and downhole chemical treatment for improving production in mature heavy crude oil fields. This study also presents various aspects; such as, design, calculations, working principle, and sensitivity analysis. A brief description of the individual components of the system is included as well, showing that this can be modified according to the particular conditions and constrains of a well. A variation of this hybrid system was tested in a pilot project in a shallow well with promising results.
The innovations and technical contributions of this work consist of the following. Firstly, a hybrid lift system such as the one described here is beneficial for depleted reservoirs containing heavy crude oil since it allows for both: reduction of bottom hole pressure and reduction of oil viscosity at down hole conditions. Secondly, since this hybrid system is simple, deploying it into a well using a reduced diameter pipe such as coiled tubing avoids the use of a workover rig, which is crucial form the economical point of view.
Monitoring PPB Levels of Dissolved Oxygen in SAGD Facilities
Authors: Weagle Glenn , Maltman Ron , Archer Andy 
Published: June 2012

Abstract
Many SAGD facilities recycle the produced water for use in steam generation. High opacity, coloured boiler feed water (BFW) from recycled produced water makes dissolved oxygen measurement difficult. New sensing technology using fluorescence decay now permits dissolved oxygen measurement that is unaffected by these conditions. Membrane based dissolved oxygen meters frequently fail in those conditions. Dissolved oxygen levels of 2 ppb were monitored for 6 weeks continuously where it was not previously possible with other techniques. A membrane based instrument was rendered inoperative after 2 days in the same service. In another facility, a 113 ppb oxygen decrease across a heat exchanger from active corrosion was detected. In this presentation several case studies will be used to outline where dissolved oxygen measurement assisted in facility operations, preventing costly maintenance and loss of equipment.