bluuebunny/crossref_metadata_2025_split huggingface dataset:
Analysis of Heavy Oil Production by Radio-Frequency Heating
Authors: Bogdanov I. , Cambon S. , Prinet C. 
Published: December 2014

Abstract
During last decades the major companies increasingly exploit such hydrocarbon resources as heavy oil, bitumen or oil shale. The production of oil from such reservoirs is frequently done through reservoir heating, most often via steam injection. However it becomes more and more evident that for some cases there exist better suited technologies and one of them is the electromagnetic (EM) heating assisted oil recovery. According to the EM field frequency different physical mechanisms may underlie the heat release. The radio-frequency (RFH) or dielectric heat generation results from rotation with friction of polar molecules in the EM field.
The advantages of the RFH-based technology are related to the in-situ heating and steam generation from the connate water which eliminates the problems associated with low well injectivity, well injection pressure, the water supply and hence, the water treatment etc. They include also the possibility to apply the heating in shallow or thin reservoirs and also in case of initially mobile heavy oil to optimize the production efficiency using both principal production mechanisms: the gravity drainage and the steam drive.
The large-scale RFH models have been recently developed for numerical simulation of realistic EM power distributions. These models provide a means to critically analyze the processes of oil recovery. In the current study we take advantage of two dedicated simulators and the methodology of loose coupling between them to deliver the calculated EM heating power field to dedicated reservoir simulator.
The combination and competition between two principal production mechanisms for different well patterns, spacing and orientation are considered; their influence together with other operational conditions impact on the efficiency and application limits of the oil recovery method are analyzed.
The analysis of different mechanisms of RFH assisted heavy oil production is an important feature in process design considerations.
Modeling Unconventional Recovery of Next Generation (Extreme Heavy Oil) Deep Tar-Mat Reservoir
Authors: Al-Bazzaz W. , AlMansour A. 
Published: December 2014

Abstract
This study models recovery of deep Tar-Mat available in substantial amounts in the Middle Eastern general and in Kuwait in particular as next generation and strategic reserves for extreme viscous and immobile solid-like unconventional oil. The study considers three unconventional different physical models. These physical models' fundamentals are generated, validated and predicted hence formulated using conventional extraction and unconventional geochemistry technologies. The first conventional recovery physical model is the liquid extracts of Saturates, Aromatics, Resin, Resin-to-Asphaltene (RAS) and Asphaltenes yielding unconventional model (RAS Model). The second unconventional recovery physical model is the elemental fingerprinting of carbon, hydrogen, nitrogen, sulfur and oxygen (H/C Aspect-Ratio Model). The third unconventional recovery physical model is the rock evaluation pyrolysis.
In this study, sixty experimental lab data are performed on five fresh tar mat samples. Also three EOR agents are proposed for recovery techniques, toluene solvent, de-ionized water and surfactant-aided de-ionized water. Since four proposed thermal EOR techniques have been used 25°C, 135°C, 225°C and 315°C temperatures for the recovery, all recovery models honor systematic temperature variation for the recovery.
All three unconventional models are laboratory data-driven models, which will attempt to define recovery patterns, quantify novel phenomenon, and develop new relationships. Each physical Model will have the ability to assess the recovery application for this unconventional reservoir. Assessing the recovery starts with unconventional measuring the API density that is less than 5 °API henceforth the viscosity and the mobility of Tar-Mat-solid-like oil. Then monitor the recovery as the type of EOR agent and temperature conditions are elevated during the recovery process. On the basis of recovery findings unconventional models, new tools will be developed for engineers, geologists and oil companies to prospect this strategic reservoir.
Optimized Steam Pulse Injection (SPI) In a Carbonate Reservoir: Issaran Egypt Field Trial
Authors: Rizkallah M. , Alfy S. A. , Basta G. S. , Ghaleb A. A. , Kortam W. T. 
Published: December 2014

Abstract
This paper describes a field trial of an optimized Steam Pulse Injection (SPI) scheme in a heavy oil (10-12O API) dual porosity carbonate reservoir located in Egypt. The field is known as Issaran with approximately 1.2 billion barrels of oil in place. Up dip steam injection in selective wells has been applied since August 2009. The fracture network helps upward distribution of steam, heating of the matrix thus wettability change to water wet and release of oil towards the deeper "drainage off take" points. The steamflooding has worked well until the Instantaneous Steam Oil Ratio (ISOR) was getting closer to uneconomical limits. In December 2013, it was decided to test an optimized SPI scheme in the Upper Dolomite South development (old area). Presently the process is working efficiently with oil being drained towards selective low pressure drainage points and in a calculated fashion using IVRR (Instantaneous Voidage Replacement Ratio) controllers. The SPI scheme calls for "On & Off" injection modes. During the "On Mode" injection proceeds normally in all designated injectors. During the "Off Mode" injection continues in few selected injectors. The "Off Mode" injectors are selected on the basis of controlling IVRR around a fault, known as the "magic fault", with the surrounding wells being target withdrawal points for oil production. SPI was designed to reduce operational costs while also benefitting from the pressure release phenomenon, which releases trapped oil from the matrix towards the fracture system and producing wells. During the first 210 days of field trial approximately 823,610 bbls of steam were saved and the ISOR almost halved. The optimization of the SPI will continue and will undoubtedly allow for the extension of the economical life of the field.
Heavy Oil Quantification Using Nuclear Magnetic Resonance and Elemental Spectroscopy Technologies in McMurray Formation, Mannville Group, Lower Cretaceous
Authors: Bouchou Ramdane , Markovic Milan , Wei Jiang 
Published: December 2014

Abstract
The Athabasca oil sand is one of the three major bitumen deposits in northern Alberta. It contains about 80% of the Alberta total bitumen deposits. The McMurray Formation, Mannville Group, Lower Cretaceous, which contains the Athabasca oil sands bitumen deposit, covers about 46800 square kilometers at an average thickness of 60 meters. The total recoverable reserve is estimated to about 170 billion barrels, which is the second largest oil reserve after Saudi Arabia.
Variation in the formation water resistivity (Rw) and difficulties to accurately estimate the shale volume (Vsh) over the heavy oil zones present a real challenge in water saturation calculation, thus in total reserves estimation. A combination of Nuclear Magnetic Resonance and Elemental Spectroscopy Technologies, with conventional logs, permitted us to quantify the different components of the heavy oil in the reservoir over the McMurray formation.
The technique is to use the clay volume, directly measured with the nuclear spectroscopy tool, to discern the "visible to NMR" heavy oil component from CBW in the 2D NMR analysis. The "invisible to NMR" heavy oil component is estimated using the lithology corrected density porosity and the NMR total porosity. The total heavy oil saturation of one of the five studied wells is compared to core oil saturation and to nuclear spectroscopy oil saturation, diredctly derived from the measured carbon. Excellent matching between the three results is seen.
This approach presents advantages over the classic petrophysical methods, mainly in zones with variable connate water salinity and variable clay minerals. Its application can be extended to any bitumen or heavy oil deposits and will help in reducing coring programs.
Optimal Application Conditions of Steam-Solvent Injection for Heavy Oil/bitumen Recovery from Fractured Reservoirs: An Experimental Approach
Authors: Leyva-Gomez H. , Babadagli T. 
Published: December 2014

Abstract
Although the previous static experiments provided critical information as to the existence of a critical temperature range that yields the maximum heavy-oil recovery during steam/solvent injection, dynamic experiment are needed to account for the relationship between the solvent introduced into the system and heavy-oil recovery.
We conducted a series of dynamic experiments in which liquid (heptane) solvent was injected into a heavy oil saturated rock matrix, surrounded by a fracture with and without pre-thermal injection. Water-wet rock matrix (sandstones) was saturated with heavy oil and placed inside a core holder. Next, the system was placed into an oven and maintained at constant temperature conditions. Then, either hot solvent (superheated to be in vapor phase) or cold solvent was introduced into the system through the fracture at a constant rate. Pressure and temperature was continuously monitored along the core and the properties of oil and liquid condensate from gas produced were measured and analyzed. This scheme was repeated for a wide range of temperature conditions.
The first requirement for a successful application is that the solvent should diffuse into matrix effectively before it breaks through and improves gravity drainage of oil by dilution. The second requirement is solvent retrieval. The retrieval of the solvent during solvent injection phase and post-thermal method (steam or hot-water) injection performed at the near-boiling point temperature of the solvent was monitored. Our results and observations indicate that there exists a critical temperature and injection rate that yields a maximized oil recovery and solvent retrieval.
Comparison Between AMPCP and SRP in a Shaly-Sand Reservoir In Terms of Sand Production
Authors: Alnaqi Yaser , Tohidi Bahman 
Published: December 2014

Abstract
Sand production is considered one of the major problems that would affect the economical value of any EOR project. The produced sand will start to accumulate in the wellbore till it kills the Well. This is done by increasing the pressure drop (both frictional and hydrostatic) in the borehole to a point where no more fluid can be produced. It can also exhibit a mechanical damage to the pipes, chokes, surface facility lines and would require continues cleaning.
There are several sand control equipment that can be installed whether in the wellbore or in the formation itself. However, these sand control equipment not only add a cost element to the whole project, but also most of them reduce the Productivity Index of the well. Consequently more wells need to be drilled in order to compensate the production loss due to the installation of sand control equipment.
This paper examines the effect of using Sucker Rod Pump (SRP) and All Metal Progressive Cavity Pump (AMPCP) on the sand production. Both pumps can handle solids to some degree, however, the mechanism of each pump will affect the building of sand arch and thus will impact the amount of sand volume produced.
By comparing the sand production profiles of two vertical wells under Cyclic Steam Stimulation (CSS) completed in the same zone, it was found that the use of AMPCP can help reduce sand production significantly over the SRP. This is attributed to the difference in working mechanisms of both pumps. In AMPCP, the fluid is being pumped by a smooth movement, while in SRP, the upstroke and downstroke movement of the pump have an effect similar to the plunger, which adversely impact the sand arch building. As a result, SRP has a higher tendency to produce more sand compared to that of AMPCP.
Experiments and Simulations of Local Upstream Gas Accumulation Giving Unstable Production in a Flowline/Riser System
Authors: Kjeldby Tor Kindsbekken , Nydal Ole Jørgen 
Published: December 2014

Summary
A set of small-scale air/water experiments has been carried out in a flowline/riser system to demonstrate how local gas accumulation in regions upstream from a riser or a well may give unstable flow, with cycling liquid production at the riser outlet. This unstable flow phenomenon differs from the well-known severe-slugging instability phenomenon in that the instability is driven by gas expansion in the riser, and not by expansion in the upstream pipeline.
A Lagrangian slug tracking model was extended with the option of solving problems with entrained gas in slugs, and used to simulate the experiments. A simplified pressure/momentum scheme is applied. Sensitivity analyses were carried out for selected parameters. Good correspondence between experiments and simulations was found with respect to the period of the instability cycle for this gravity-dominated system. The experimental stability limits are also well reproduced.
Integrated Predrill Pore-Pressure and Borehole-Stability Prediction for Prelude Development
Authors: Hansen K.S.. S. , Wang G.. , Adeleye O.. , McNeil K.V.. V. , Couzens-Schultz B.A.. A. , Azbel K.. , Sarfare M.. , Tare U.. 
Published: December 2014

Summary
Pore-pressure (PP) and fracture-gradient (FG) predictions were prepared for Prelude development wells in the Browse basin in offshore northwest Australia. The PP forecasts were based on resistivity- and sonic-based models calibrated with pressure measurements and drilling events, such as kicks from existing wells. FGs were based on leakoff tests and loss events from offset wells and were not necessarily equal to either the minimum compressive principal stress (often considered a lower bound to FG) or the formation-breakdown pressure (often considered an upper bound to FG that includes effects of formation tensile strength and near-wellbore hoop stress). The minimum compressive horizontal stress was calculated from lithology-dependent effective-stress ratios. Maximum horizontal stress was inferred from observed breakouts. PP and stresses were combined with formation properties from well logs and laboratory rock-mechanics tests to provide input for elastoplastic (shales) and poroelastic (sands) borehole-stability (BHS) models.
These techniques are applicable to exploration, appraisal, or early-development wells that have potential for encountering geopressured formations in high-angle well sections requiring good predrill estimates to adequately plan the casing and drilling programs and determine BHS. The predrill studies can be extended to provide integrated real-time PP and BHS while drilling, and the models can be recalibrated after each well to provide updated predictions for subsequent wells.
There are only minor deviations in the predicted PP and FG among the different well locations considered. Common features include potential loss zones in the shallow overburden, pressure ramp within the Jamieson, pressure regression below the Aptian, and near-hydrostatic pressure within the Upper Swan and below. The BHS models indicate that minimum-required mud weight in deviated sections could be up to 20% higher than that required to balance formation PP. In one well that would cross a suspected fault, the risk of fault reopening or reactivation is low.
Laboratory-Scale-Model Testing of Well Stimulation by Use of Mechanical-Impulse Hydraulic Fracturing
Authors: Frash Luke P. , Gutierrez Marte , Hampton Jesse 
Published: December 2014

Summary
Reservoir stimulation is commonly used to increase well-production rates and enable economic oil and gas recovery from conventional and unconventional reservoirs. One potential stimulation method that has been laboratory tested as a means to increase well injectivity after conventional hydraulic fracturing is mechanical-impulse hydraulic fracturing (MIHF). MIHF is a high-strain-rate stimulation method that uses a mechanical-energy source as an alternative to rapid gas expansion. Field-scale viability of MIHF was evaluated by use of elastic mechanics and thermodynamics. Results from laboratory tests are presented in which associated flow data indicated significant increases to well injectivity after MIHF stimulation. Tests were performed in two granite specimens with dimensions of 300×300×240 mm3 and 300×300×300 mm3, respectively. The first specimen was unconfined at room-temperature conditions, whereas the second was subjected to heating and true-triaxial confinement. Stimulated well injectivity was evaluated with a series of step-constant-pressure and step-constant-flow injection tests.
Assessing the Biotreatability of Produced Water From a Qatari Gas Field
Authors: Janson Arnold , Santos Ana , Katebah Mary , Hussain Altaf , Minier-Matar Joel , Judd Simon , Adham Samer 
Published: December 2014

Summary
Reuse of significant quantities of produced water (PW) extracted during gasfield operations requires treatment to remove both organic and inorganic materials. Biological treatment is generally regarded as the most cost-effective method for organics removal. For industrial waste waters, biotreatment faces distinct challenges because the PW composition can dramatically affect sludge settleability, a critical parameter in the operation of conventional biotreatment systems. Membrane bioreactors (MBRs) have an inherent advantage and have proved to be successful in the treatment of industrial waste waters because a membrane filter is used to separate the treated water from the sludge rather than separation being contingent on biomass settleability.
The outcomes of a bench-scale experimental study on the application of an MBR to the biotreatment of PW from Qatari gas fields are presented for three operating parameters: hydraulic-retention time of 16 to 32 hours, solids-residence time of 60 to 120 days, and temperature of 22 to 38°C. The impact on chemical-oxygen-demand (COD) removal was evaluated through experimental testing by use of three parallel bench-scale MBRs. Low sludge concentrations (0.3–1.5 g/L of volatile suspended solids) were attained throughout, with instantaneous-flux values ranging from 3 to 15 L/(m2·h).
Results indicated that the COD removal averaged 60% (54–63%), approximately one-third of this value being attributed to physical removal, with the operating parameter values shown to have no statistically significant effect on removal. Although trends were consistent with some previously reported studies performed on refinery waste water, overall removals were lower than expected. The pH of the bioreactor sludge ranged from 4.9 to 6.0, averaging 5.2, compared with a feedwater pH of 4.3, possibly contributing to the low carbon removal recorded. Adjustment of the feed pH to more than 6.5 caused a precipitate to form that contributed to membrane fouling. However, all feedwater acetate and more than 90% of the oil and grease were removed by the MBR treatment.
Treatment appeared to be carbon-limited, accounting both for the absence of nitrification (with all removed organic nitrogen apparently being assimilated into the sludge) and for the low sludge-solids concentrations attained. Evidence suggests the feedwater contains a significant fraction (approximately 40%) of highly recalcitrant organic compounds presumed to be nitrogen-containing field chemicals (e.g., scale inhibitors and corrosion inhibitors).
Experimental Study on Sand-Carrying Mechanism and Capacity Evaluation in Water-Producing Gas Wells and its Application in Artificial Lift Optimization
Authors: Dong Changyin , Li Yanlong , Zhang Qinghua , Feng Shengli , Zhang Lihui 
Published: December 2014

AbstractFor the unconsolidated gas reservoir with sand production, when the gas well produces water, the flow in wellbore is essentially gas-liquid-solid three-phase flow. The flow mechanism and sand-carrying capacity tend to obviously affect the artificial lift system operational situation and optimization. In this paper, the gas-liquid-solid multi-phase flow with different water-gas ratio (WGR) and sand concentration were experimentally simulated to investigate the flow mechanism and sand-carrying capacity of gas-liquid flow. The results indicate that once the well starts to produce water, it's more difficult for the gas to carry produced sand than there is no water produced. Gas flow rate and WGR are the dominant factors affecting the flow mechanism. As WGR increasing from zero, the flow pattern tend to be mud-gas flow with no sand carried, annular flow with sand, plug flow with sand and further patters similar to these of normal gas-liquid two phase flow with the same WGR. The prerequisite of sand-carrying can be described as that the gas be able to carry liquid flow to a certain velocity, at which the liquid has enough velocity to carry the sand flowing contained. According to the systematic experimental results, the critical sand-carrying gas rate and the quantitative relationship of sand rate and gas flow rate were obtained. Based on the experimental data, a sand-carrying evaluation model for gas well with and without water production are developed. The model is used to predict the critical sand-carrying gas flow rate with certain sand diameters and the maximum sand rate carried by a given gas flow rate. Finally, considering the characteristics of sand-carrying in wellbore, a new integrated coordination chart for gas well with water and sand production is put forward to evaluate the real well operational situation and help to make decision of well measurement such as adjusting gas nozzle, sand control and others. The method has been applied in Sebei gas filed, a typical gas filed with serve sand and water production, and the effect is good.
Discussion of Asymmetric Cost Behavior—Sticky Costs: Expenses versus Cash Flows
Authors: Shust Efrat , Weiss Dan 
Published: December 2014

ABSTRACT
This note highlights a subtle aspect of the asymmetric costs literature not covered in the comprehensive review by Banker and Byzalov (2014). Specifically, we test the assertion underlying this literature that reported expenses can serve as an appropriate proxy for estimating the asymmetry of economic costs. Our findings refute this assertion, indicating that reporting choices influence the estimated asymmetry level of reported expenses. As a result, reported expenses are significantly more asymmetric (sticky) than economic costs. This evidence suggests that reporting choices required by GAAP matter in estimating cost stickiness. These findings enrich Banker and Byzalov (2014) by suggesting that future asymmetric costs research should (1) look for alternative accounting variables with the potential to capture economic costs, and (2) explore how various types of reporting choices affect asymmetric cost behavior.