bluuebunny/crossref_metadata_2025_split huggingface dataset:
Performance Data of a Distributed Flux Burner in a Heavy Oil Heater Treater
Authors: Bartz David , Gotterba James 
Published: May 2015

Abstract
A common problem with oil-water separation in horizontal heater treaters processing heavy oil is thermal deformation and failure of the heater fire tube. Several factors contribute to the cause of the failure including presence of polymer in the water used for oil recovery, solids content in the oil, and design of the heater treater tank and controls. A key aspect of the tube failure is related to the internal heat transfer from the burner to the fire tube wall. Heat flux typically is concentrated around the burner flame with a resulting hot zone that forms a coking, insulating layer on the outside of the tube. Eventually the fire tube overheats and fails either by collapse or rupture.
Distributed flux burners have been installed to prevent the concentrated hot zone of the tube wall by improving temperature uniformity over the length of the tube. The distributed flux burner utilizes premixed surface stabilized combustion to extend the flame zone over the length of the fire tube, thereby reducing peak wall temperatures while increasing the effective heat transfer to the emulsion. The burner consists of a porous cylindrical ceramic matrix which provides infra-red radiation heat transfer to the fire tube wall to help maximize heat flux uniformity. The burner has been in commercial use for asphalt tank heating and fragile fluid heating for many years and recently has proven to be ideal for effective heating of heavy oil in heater treaters.
As a continuation from results presented in SPE-170172-MS in June 2014, we review recent field experience in heater treaters processing heavy oil at various locations. Improvements in life of the fire tube, throughput of the emulsion and sales oil, and thermal efficiency relative to conventional burners are presented. This paper also describes new specifications and criteria for proper sizing and operation of the distributed flux burner for retrofit of heater treaters.
Application of Novel Hyper-branched Polymer Fracturing Fluid System in Low-permeability Heavy Oil Reservoir
Authors: Liu Yueliang , Li Huazhou Andy 
Published: May 2015

Abstract
Hydraulic fracturing can be used in low-permeability heavy oil reservoirs for improving the production rate. It is challenging to achieve a high degree of fracturing fluid flow-back in low-permeability heavy oil reservoirs. This research investigates the application of a novel hyper-branched polymer fracturing fluid in low-permeability heavy oil reservoirs.
A hyper-branched polymer, which has numerous end groups and possesses a special highly branched three-dimensional spherical molecular structure, is characterized by Fourier Transform Infrared (FTIR) spectrophotometer. Laboratory tests are conducted to evaluate the stability of viscosity at a given shear rate, temperature and shearing resistance, reversible cross-linking property, filtration property, and proppant-carrying performance of this hyper-branched polymer fracturing fluid. The degrees of core's formation damage are compared through conducting coreflood experiments, where the cores are treated with two fluids: the hyper-branched polymer fracturing fluid and guanidine gel fracturing fluid.
The laboratory evaluation shows that the hyper-branched polymer fracturing fluid has good rheological characteristics, a high solubility in water, as well as good temperature and anti-shearing resistance. After being sheared for 90 minutes with the shear rate of 170 s−1 at 150°C, it can still be reversed to gel with high strength because of its reversible cross-linking effect. This fracturing fluid has a good antioxidant ability, which allows its basic fluid to be exposed to air for 48 h without viscosity reduction. Therefore, the basic fluid can be prepared as spare fluid in a large amount, significantly improving job efficiency on site. Meanwhile, field applications in some wells in China show that: the friction of this fracturing fluid during fracturing is about 30%-50% to that of the normal guanidine gum fracturing fluid. Thus it has an ultra-low friction feature. The flow-back rate of the fracturing fluid can reach as high as 80%. Besides, its cost is about 75% to that of the normal guanidine gum fracturing fluid, making it a clean and cost-effective system. The fracturing fluid prepared with hyper-branched polymer possesses outstanding technical advantages as well as good cost effectiveness, implying a promising application in the large-scale fracturing stimulation of low-permeability heavy oil reservoirs.
Steam Injection Schemes for Bitumen Recovery from the Grosmont Carbonate Deposits
Authors: Song Qiuyue , Chen Zhangxin (John) , Ali S. M. 
Published: May 2015

Abstract
The hydrocarbon resources in the Grosmont carbonate deposits in Alberta are over 400 billion barrels. Pilots have been carried out in Grosmont since 1974, but hitherto a commercial recovery scheme remains elusive. This study addresses oil recovery techniques from the Grosmont carbonate deposits, using numerical simulation for several steam-based recovery schemes. Selected simulation results were further analyzed and compared with those from the classical analytical model.
Given the extremely heterogeneous nature of the deposits (karsted, fractured, and high variability in formation properties) and high oil viscosity (2-11 million cp at 20 °C), a typical geological model of Grosmont, with representative petrophysical and geological characteristics, was used to examine several steam injection schemes, using a dual porosity/dual permeability model in CMG STARS. The schemes tested included: single vertical well cyclic, single horizontal well cyclic, steam assisted gravity drainage and steamfloods involving five-spot, nine-spot, seven-spot patterns and the vertical well injector-horizontal well producer arrangement.
The dominant feature of all steam injection schemes was a high steam-oil ratio, although the oil recovery was high in most cases. Experiments showed that the steam-oil ratio of steamfloods can be improved by reducing the steam injection rate and closing certain perforation intervals at critical points in the production life of the well. As a result of optimization, a pattern steamflood case achieved a steam-oil ratio of 8 m3/m3 and recovery factor of 41%. The best horizontal well CSS case, for which the well location is chosen to avoid steam channelling into the top water, gave a good response with a steam-oil ratio as low as 7 m3/m3 and a recovery factor of 18%. The recovery factors of the two processes are comparable considering the fact that the wells in the former were perforated into Grosmont C and D members of the model while the latter targets only the Grsomont C member. SAGD cases have similar steam-oil ratio but smaller oil recovery.
Simulation results were analyzed in the light of dynamic fluid flow, thermal efficiency and drive mechanism and were compared with results from classic analytical methods. Affected by the high fracture vertical permeability and severe heterogeneous formation properties, steam override and oil gravity flow occur in all processes. Uneven steam zone and limited drainage area make it difficult to achieve optimal performance of processes including SAGD, seven-spot pattern steamflood and horizontal well CSS. Early steam breakthrough happened in the pattern steamfloods. A combination of vertical steam injectors and a horizontal producer provided the most uniform formation heating and production of the mobilized oil by both gravity flow and viscous drive, thus achieved the same recovery performance faster than horizontal well CSS and delayed steam breakthrough.
History Matches and Interpretation of CHOPS Performance for CSI Field Pilot
Authors: Chang Jeannine , Ivory John , London Mike 
Published: May 2015

Abstract
CHOPS (Cold Heavy Oil Production with Sand) is a primary production recovery method used in the Western Canadian Lloydminster heavy oil region which contains about 3 billion m3 of heavy oil. It increases heavy oil production rates by creating high permeability channels in the reservoir through aggressively producing sand with the oil. As a result of CHOPS, 5 - 15% of the initial oil can be recovered.
This paper summarizes CHOPS history matches that used the CMG STARS™ simulator and representative process mechanisms in simulating two Husky CHOPS wells, one well was later used as a Cyclic Solvent Injection (CSI) pilot well and the second well was a communicating offset well during CSI. The history matches were pre-processed for the post-CHOPS CSI field pilot. They were part of the $40 million JIVE Program and were in support of a CSIfield development in the Edam area.
The history matches predicted the reservoir conditions (e.g. pressure, effective permeability, effective porosity, fluid saturations, and mole fraction profiles) at the end of CHOPS to set up the CSI initial reservoir conditions (i.e. the start of CSI). Oil, water and sand production were well matched for both of the wells during CHOPS. Foamy oil and sand transport mechanisms were represented in the simulations. The simulation results and the CHOPS model described below provided insight into CHOPS depletion mechanisms and post-CHOPS reservoir characteristics.
At the end of CHOPS, the CSI well was pressure depleted with low liquid inflow. In the simulations, the wormholes were predicted to extend to about 151 m from the CSI well. Wormholes from the offset well reached a source of water and had continuous water inflow. It was predicted that the offset well wormholes penetrated about 220 m into the reservoir.
Conclusions include: The AITF CHOPS model can capture field production mechanisms and reservoir behaviors.Continuing lower rate sand production and wormhole network growth is essential to obtain sustained higher oil production rates during CHOPS.As a result of greater reservoir contact, a thinner pay with longer wormholes can produce more oil than a thicker pay with shorter wormholes.Directly obtaining reservoir properties from the field LAS log data and use of the thin layers in the log file as simulation layers were important in catching fluid flow behaviors and obtaining satisfactory history matches for oil and water production.Good CHOPS history matches and reservoir charactisation are essential for field CSI pilot wells as they quantify the post-CHOPS reservoir conditions, the extension of wormhole networks, and the depletion regions. Consequently, they provide predictive value for developing CSI operation strategies for successful post-CHOPS CSI applications.
History Match and Strategy Evaluation for CSI Pilot
Authors: Chang Jeannine , Ivory John 
Published: May 2015

Abstract
This paper summarizes a project that was part of the $40 million 2006-2010 Joint Implementation of Vapour Extraction (JIVE) pilot program managed by the Petroleum Technology Research Centre and including Husky Oil, CNRL, NEXEN, Alberta Innovates–Technology Futures, and the Saskatchewan Research Council. The project was in support of a cyclic solvent injection (CSI) field pilot in the Lloydminster region of Saskatchewan that was evaluating the potential of CSI to exploit reservoirs following cold heavy oil production with sand (CHOPS).
History matches were performed for two Edam CHOPS wells in the Colony formation and they determined initial reservoir conditions (e.g. pressure, effective permeability, porosity, fluid saturations, and gas and oil phase mole fractions) for subsequent CSI simulations. Thin formation layers (~15 cm) were used in the CHOPS simulations to improve representation of wormhole generation and advance. One well had rapid sand production that quickly declined whereas the other well had continuous sand production due to wormhole propagation and scouring and resulted in sustained oil production.
The reservoir model for the application of CSI contained a number of wells including the CSI well and two communicating offset wells (Figure 1). Using an Alberta Innovates–Technology Futures (AITF) CSI model, a history match was obtained for CSI Cycle 1. Eleven different potential injection/production strategies were then evaluated for Cycle 2 and the simulation results were used in the design of this cycle. One conclusion was that expanding the solvent injection period from 1 to 2 months increased the combined oil production for the three wells by 29% but resulted in a 46% increase in net solvent to oil ratio. Figure 1Conversion from post-CHOPS radial geometry to Cartesian geometry for CSI simulations
Determination of Two-Phase and Three-Phase Relative Permeabilities in Heavy Oil/Water/Gas Systems
Authors: Modaresghazani J. , Moore R. G. , Mehta S. A. , Fraassen K. C. 
Published: May 2015

Abstract
An experimental study was conducted to investigate the relative permeability behaviour of a typical Canadian bitumen, water and gas. Series of isothermal core flood experiments were conducted on an unconsolidated core composed of cleaned Athabasca sand matrix and relative permeabilities of the involved phases were determined. Athabasca bitumen was used as the oil phase and distilled water and nitrogen were used as water phase and gas phase respectively. A vertical sand-pack core-holder of 1.5 inch diameter and 2 feet long was designed and fabricated to perform sequential injection of oil, gas and water at reservoir temperature and pressure, while collecting information on pressure drop across the core and fluid volumes. The history match technique was used to determine relative permeabilities for two-phase and three-phase water/oil/gas systems.
Improving Horizontal Well Placement in the Orinoco Oil Belt with the Use of Bed Boundary Mapping Technologies
Authors: Cuadros G. , Chamat E. H. , Villarroel N. , Scrofina J. , Cermeño E. , Rodriguez O. 
Published: May 2015

Abstract
The success of a horizontal drilling campaign depends on the implementation of appropriate technologies and procedures to manage uncertainties and risks that may affect the overall economy of the project. This is the case for most fields in the Orinoco oil belt—the largest reserve of heavy oil in the world—which is mainly developed via horizontal drilling. As with other fields in the area, Junin-6 presents special challenges for horizontal well placement. The friable shallow reservoirs include some of the shallowest currently developed in the Orinoco oil belt. The main target sands range in thickness from 30 ft in the Arenas Basales (Basal sands) to 250 ft in the Oligoceno (Oligocene) reservoir. The lateral sections vary from 3,000 to 4,000 ft. This, combined with a high geological complexity, lack of 3D seismic data, and a limited number of correlation wells, makes the horizontal well placement a real challenge in many cases.
Advanced logging-while-drilling (LWD) technologies had to be implemented in the challenging cases, such as in the Basal sands reservoir. A proactive approach based on bed boundary mapping technologies, combined whenever possible with point-the-bit rotary steerable systems, is being used to improve horizontal well placement in this field.
The main results include net pay increase and cost reduction compared to wells executed with conventional technologies. The risk of unproductive drilling has been considerably reduced, especially in the thinnest formations drilled in this field. The best results were achieved when LWD bed boundary mapping was combined with point-the-bit rotary steerable systems, since this type of technology enabled better well trajectory control, faster execution, longer horizontal sections, and safer completions.
This paper presents the main challenges for horizontal well placement in the giant Junin-6 heavy oil field and how they are being addressed with the use of advanced geosteering technologies.
Evaluating SAGD Performance due to Changes in Well Spacing and Length
Authors: Verney M. J. 
Published: May 2015

Abstract
Over the past several years, there has been a shift to drill longer wells with tighter inter-well spacing in projects using steam assisted gravity drainage (SAGD). An understanding of the impact on performance as a result of different well length and spacing can justify such a change for future well drilling. This paper examines the performance from various McMurray formation SAGD projects in the Athabasca region that have well pairs that are developed at different lengths and spacing. Changes in bitumen rate per well-pair, recovery factor and steam to oil ratio (SOR) were assessed at different well lengths and inter-well spacing. Certain performance characteristics from pads with tighter inter-well spacing were better than wider spaced pads. Furthermore, no significant changes in performance were noted in regards to changes in length.
Dissolution and Mobilization of Bitumen at Pore Scale
Authors: Bayestehparvin B. , Abedi J. , Ali S. M. 
Published: May 2015

Abstract
Steam injection, in various forms, has been commercially successful for in situ recovery from the oil sands. One of the recovery methods being tested – with an aim to reduce steam requirement – involves the injection of a suitable solvent, by itself, or in combination with steam. Solvents are being utilized at a pilot scale in both cyclic steam stimulation (CSS) and steam-assisted gravity drainage (SAGD) processes. The present study examines the mixing of a solvent with bitumen at the pore scale, using an analytical model with typical field data.
The convective diffusion equation is solved for a spherical geometry, and applied to a drop of bitumen is a pore space. Calculations are done for a number of solvents, viz. pentane, and hexane. The rate of bitumen dissolution is determined for both static and dynamic conditions, for a number of velocities corresponding to typical field injection rates. The diffusion coefficients are taken from the latest laboratory data reported. Calculations are also done for heating of the bitumen (without solvent) for the same conditions. The resulting bitumen viscosity is compared as a function of time, for both solvent injection and heating.
Results show that the time of solution of a bitumen drop in the solvent is of the order of days. The time varies with the type of solvent (largest for pentane), and the injection velocity. The times to attain the same viscosity by solvent injection in one case, and conduction heating in the other, respectively, differ by orders of magnitude. The significance of this finding for field application of solvents is discussed.
The outcome of this research will improve our understanding about solvent diffusion and dispersion process for bitumen in porous media. This will help us to modify the current modelling approach to capture more realistic mass transfer and solvent/bitumen interaction in porous media.
Investigation of Nanoparticle and Surfactant Stabilized Emulsion to Enhance Oil Recovery in Waterflooded Heavy Oil Reservoirs
Authors: Pei H. H. , Zhang G. C. , Ge J. J. , Zhang J. , Zhang Q. , Fu L. P. 
Published: May 2015

Abstract
Emulsion flooding has great potential for enhancing the recovery of heavy oil, especially for reservoirs in which the oil recovery by water flooding is low and thermal methods are not suitable. This study presents a study of nanoparticle-surfactant stabilized emulsion to enhance heavy oil recovery in waterflooded heavy oil reservoirs. The phase behavior tests and rheology studies were first performed to investigate the influence of nanoparticle on the stability and bulk rheological properties of the emulsion system. Then, the core flooding and microscopic visualization tests were conducted for investigating the displacement mechanisms for enhanced heavy oil recovery by nanoparticle-surfactant stabilized emulsion. The phase behavior tests and rheology studies show that the addition of nanoparticles can not only improve the stability of the emulsion, but also greatly increase the bulk viscosity of emulsion. The core flooding conducted with the emulsion co-stabilized by nanoparticle and surfactant show a marked improvement in oil recovery over the surfactant-stabilized emulsions. The tertiary oil recovery can reach over 40% of the initial oil in place (IOIP) for crude oil with the viscosity of 350 mPa•s at 50 °C. The micromodel tests indicate that the nanoparticles can thicken the emulsion to the desirable mobility, which can damp the viscous fingering phenomena to dramatically improve sweep efficiency. In addition, the heavy oil can be emulsified into the water phase to form oil-in-water emulsions with the aid of the surfactant. These results demonstrate that the nanoparticle-surfactant stabilized emulsion has a great potential for enhanced oil recovery in waterflooded heavy oil reservoirs.
Chemical Additives and Foam to Enhance SAGD Performance
Authors: Li Ran , Etminan S. Reza , Chen Zhangxin 
Published: May 2015

Abstract
SAGD (steam assisted gravity drainage) is known as the main technology to tackle the exploitation of heavy oil and oil sand resources in Alberta. The oil industry seems to be well-educated today about SAGD's challenges and opportunities. Enhancing the efficiency of SAGD operations remains an area of investigation as it is tied to economic and environmental measures. Use of chemical additives and foam with SAGD is a strategy proposed on this account.
Foam is dispersion of gas in a continuous water phase with thin films (lamella), acting as a separator. Given its sensitivity to oil distribution, foam tends to reside in higher permeability layers with less residual oil. Thermally stable surfactants are essential to maintain the foam life because surfactants stabilize lamella by decreasing the water-gas interfacial tension. Adding surfactants also lowers the interfacial tension at the water-oil interface and further produces water in oil or oil in water emulsion. In situ emulsion generation is thus another active mechanism that is involved as a result of surfactants presence.
Due to the above properties, steam movement is hindered, and gravity override is consequently limited, thereby resulting in high injection pressure that thoroughly displaces oil. Also, foam injection is conducive for blocking thief zones and decreasing channeling. In terms of emulsification, oil in water emulsion flow decreases water permeability created by emulsion droplets entrapment in throats, transferring the injection flow into poorly exploited areas. More trapped oil is mobilized by interfacial tension drop. The existence of water in oil emulsion contributes to heat transfer because the generation reaction is exothermic. All mechanisms mentioned are incorporated to illustrate CAFA-SAGD (chemical additives and foam assisted SAGD) performance and compare it with SAGD in both homogeneous and heterogeneous reservoirs using CMG® STARS. The reservoir under study is analyzed with low permeability layers, top water, bottom water, and lean zones for the heterogeneous case. The surfactants properties and foamibility are considered through appropriate reactions introduced into the simulator. The phase behavior for emulsification regulates different relative permeability regimes into the oil flow. We find that adding additives contributes to higher production and leads to less steam consumed.
This study incorporates viscosity reduction, mobility control, interfacial tension drop, and emulsification mechanisms to present the effects of chemical additives and foam towards SAGD performance. Our results indicate that using additives with SAGD can maintain a uniform steam chamber growth while reducing the heat loss to overburden. It has a significant long-term oil production capability.