bluuebunny/crossref_metadata_2025_split huggingface dataset:
Vertical Single-Well SAGD with Multiple Producers
Authors: Hocking G. , Walters D. A. 
Published: June 2013

Abstract
Performance of conventional, steam-assisted gravity drainage (SAGD) horizontal well completions can be significantly impacted in formations with low vertical permeability and interbedded mudstone layers impeding vertical drainage. Also, because of shallow depth, caprock integrity, and/or thief zone issues, the lower operating steam pressure for SAGD completions can impact its ability to grow the steam chamber vertically in a timely manner. Such performance degradation results in lower production rates and often higher steam oil ratios. A vertical well injector/producer was proposed that consists of vertical, propped planes at varying azimuths installed from the bottom to the top of pay. Steam is injected at the top of the pay and liquids are extracted at the bottom. The well operates immediately in SAGD mode (i.e., the continuous injection of steam and the continuous extraction of liquids), resulting in peak production achieved within 30 to 45 days. Reservoir simulations show that the single-well SAGD system's performance is superior to a conventional SAGD completion, achieving greater than 2xNPV10 (net present value) of conventional SAGD in clean McMurray channel sand. Incorporating multiple vertical producer wells with a single central vertical SAGD injector/producer well, yields system performance far superior to a conventional SAGD completion, achieving greater than 6xNPV10 of a conventional SAGD completion in clean McMurray channel sand. The oil production rate for the vertical SAGD system with multiple producers is 4x faster than a conventional SAGD completion, with a greater recovery factor, and a lower cumulative steam oil ratio (SOR) of 1.5 compared to 2.5 resulting in a 40% saving in both Capex and Opex. Simulations of the system in variable geology, indicate that the vertical drainage efficiency of the system is virtually independent of geology, provided the multi- azimuth, high permeability propped vertical planes connect the wells hydraulically and are constructed continuously throughout the pay thickness.
Findings from a Solvent-Assisted SAGD Pilot at Cold Lake
Authors: Dittaro L. M. , Jaafar A. E. , Perlau D. L. , Boone T. J. , Yerian J. A. , Dickson J. L. , Wattenbarger R. C. 
Published: June 2013

Abstract
ExxonMobil and Imperial Oil Resources (Imperial) are conducting a Solvent Assisted - Steam Assisted Gravity Drainage (SA-SAGD) experimental pilot at Cold Lake in the Clearwater formation where up to 20% by volume of hydrocarbon solvent (diluent) has been injected along with dry steam in a dual horizontal well SAGD configuration.
Experimental work performed by the Alberta Research Council (ARC) (Nasr, 2003) and Imperial indicated that addition of solvent to steam increases bitumen rates and decreases steam-oil ratios relative to the conventional SAGD process. The main objective of this pilot has been to produce high quality field data to definitively support these experimental conclusions.
The pilot scope includes two horizontal well pairs (four wells), six observation wells, associated steam and diluent injection facilities, artificial lift, as well as, dedicated production measurement and testing facilities. The SA-SAGD pilot uses existing steam generation, water treatment, bitumen separation and processing facilities at Imperial's Mahkeses plant and existing steam distribution and production gathering systems.
The main focus of this paper is to document the integrated approach taken to ensure that this multi-year pilot is successful and to provide information resulting from this multi-year pilot. Key surveillance products, such as, production/injection measurements, horizontal-well temperature logs, observation-well temperature and saturation logs, time-lapse 3D seismic, and the impact of a mid-pilot solvent switch will be discussed. In addition, this paper will review how these surveillance products are integrated with laboratory data and simulation efforts to improve our understanding of this process and increase confidence in go-forward predictions.
Given the emerging importance of solvent-assisted thermal heavy-oil processes and the accelerated conversion of this technology from laboratory-scale to field-scale, data from a field pilot provides invaluable information in the quest to deploy this emerging in-situ recovery technology.
Fire-flooding Technologies in Post-Steam-Injected Heavy Oil Reservior:A Successful Example of CNPC
Authors: Wenlong Guan , Changfeng Xi , jihong Huang , Junshi Tang 
Published: June 2013

Abstract
Steam injection is an effective technology for heavy oil development. With the increasing of the recovery percent, the technical effectiveness and economic efficiency of continuous steam injection will substantially decline. Therefore the fire- flooding can be considered as a follow up EOR technology in these steam-injected reservoir. Because of the complicated secondary water and steam channels distribution, fire flooding in post steam injected reservoir is far different from that in original reservoir. In this paper, the mechanism and problems associated with development engineering of fire flooding in post steam injected heavy oil reservoir was studied systematically by using 1D&3D physical simulation systems and reservoir numerical simulator. The temperature of combustion zone decreased and high temperature zone enlarged because there existed secondary water formed during steam injection which could absorb and carry heat towards producers out of combustion front during fire flooding, but high saturation of water in layer caused by secondary water had less influence on the quantity of fuel deposit and air consumption.
There is a living example of fire-flooding in post-steam-injected heavy oil reservoir in Xinjiang oil field of CNPC, and it is the first major pilot of fire-flooding in this kind of reservoir, namely H1 Block Fire-flooding Pilot. H1 Block had been steam- injected for more than 10 years and oil recovery factor had nearly reached 30%. Before fire-flooding test, the reservoir had been abandoned for many years. In this paper, the fire-flooding model, well pattern, well spacing, and air injection rate was optimized based on the reservoir property and the existed well pattern in H1 Block, and the key techniques of ignition, lifting, and anticorrosion was also selected in the same time. The H1 Block Fire-flooding Pilot was carried out in the late of 2009. Up to now, more than 30 wells produced oil, 16 of them produced stably. The daily oil production increased from nearly 0 to 48t/d, water cup decreased from nearly 100% to 60%, and AOR decreased from more than 5000Sm3/m3 in the beginning to 2200 Sm3/m3 by far. The forecasted ultimate recovery factor will reach 65%.
Insights into Heavy Oil Recovery by Surfactant, Polymer and ASP Flooding
Authors: Bryan J. , Shamekhi H. , Su S. , Kantzas A. 
Published: June 2013

Abstract
At the end of primary production in heavy oil reservoirs, significant volumes of continuous oil remain in place. As production rates decline this EOR target has tremendous value for heavy oil producers. Many of these reservoirs are poor candidates for thermal recovery. Furthermore in regional sands or post-CHOPS systems, it may not be easy to pressurize these reservoirs for solvent-based recovery. Chemical flooding has potential for EOR in these systems, because the injection of chemicals can lead to the buildup of pressure gradients between injectors and producers, at least at the laboratory scale. These pressure gradients evolve due to improved viscosity of polymer solutions, the formation of emulsions in surfactant or AS floods, or both. The objective of this work is to improve our understanding of the mechanisms by which heavy oils are produced through chemical flooding.
Linear core floods were run on systems containing two heavy oils of variable viscosity: 500 mPa•s and 16,000 mPa•s. For the lower viscosity oil polymer floods and ASP floods are compared. These tests illustrate the impact of improving the injection fluid viscosity vs. the additional benefit from the addition of surfactant. It was observed that heavy oil is produced more efficiently from ASP flooding compared to polymer flooding alone. The residual oil saturations are lower in ASP floods, even with lower differential pressure across the core. For the higher viscosity oil some production was achieved through AS flooding alone, but the addition of polymer was important for improving recovery.
Tests were also run on a parallel core system, containing cores of relatively high and low permeability. This was a representation of a post-CHOPS reservoir containing preferential flow channels due to the presence of wormholes. Both surfactant and ASP solutions only accessed the high permeability core, so oil was bypassed in the lower permeability sand even with the addition of chemicals to water. This result demonstrates that laboratory studies may be dramatically over- estimating the success of chemical flooding in heavy oil, and poses a challenge for successful implementation of chemical floods in heterogeneous post-CHOPS heavy oil fields.
Coupling of Solvent and Hot Water to Improve Heavy Oil Recovery: Experimental and Simulation Studies
Authors: Luo Weiguo , Torabi Farshid 
Published: June 2013

Abstract
There are abundant heavy oil deposits characterized by shallow depth, thin pay zone, low porosity, and bottom water in Western Canada. These types of reservoirs are neither suitable for thermal heavy oil recovery techniques (e.g. SAGD) nor for solvent injection (e.g. VAPEX). Coupling of Solvent and Hot Water (CSHW) injection was proposed and examined as an alternative to improve the heavy oil recovery in these reservoirs.
In this study, a series of core flooding tests and numerical simulations were conducted to investigate and evaluate the CSHW injection performance in thin heavy oil reservoirs containing oil with viscosity of around 1,000 to 6,000 cP. To identify the contribution of hot water and solvent as well as their effectiveness when they combined, three types of core flooding tests were performed individually using hot water, solvent, and CSHW injection. In addition, the effects of oil viscosity, water injection temperature (15°C, 24°C, 50°C, 65°C) and solvent (C1, C3, C1+C3) on oil recovery were examined. Moreover, effects of parameters such as injection rate, displacement volume, slug size, and injection pattern were also investigated. Furthermore, the core flooding tests were history matched based on the established numerical simulation model. The effects of temperature and solvent components on multi-phase fluid flow were examined through numerical simulation. As the result, the optimal CSHW injection parameters were screened based on experimental and numerical studies conducted.
Results of this study showed that the oil recovery factor was enhanced by 19.1% when temperature of injection water increases from 24°C to 65°C. More importantly, it was found that the CSHW is a more feasible option that recovers higher amount of oil at lower cost when compared with pure solvent or hot water injection. In addition results indicated that if smaller slugs of hot water and solvent are injected, the recovery process is more efficient. In this particular study, injection of smaller slugs resulted in 53.5% recovery factor. These results indicate that the CSHW is a promising hybrid process for the heavy oil recovery which requires low facility investment.
Impact of Thermal Pore Pressure on the Caprock Integrity during the SAGD Operation
Authors: Yang B. , Xu B. , Yuan Y. 
Published: June 2013

Abstract
Thermal stimulations of reservoirs cause significant amount of thermal energy stored subsurface and pore pressure altered from its original in-situ state. Such thermal and hydraulic disturbances inevitably stress and deform the rock formations including the reservoir and its overlying caprock, making the caprock integrity an important issue. This paper discusses the importance of thermally induced pore pressure for caprock integrity during a SAGD process. Relevant laboratory and field observations are presented to demonstrate its real existence, and then, numerical simulations are used to illustrate the major influencing material parameters and their evolving importance in space and time with respect to the steam chamber development. Finally, discussions are given about importance of the thermal pore pressure on the caprock integrity.
Enhance Heavy Oil Production of Horizontal Well by Distributed Downhole Electrical Heating
Authors: Zhong L. , Lin H. , Wang Y. , Lu F. , Chen Y. , Lin J. , Zhang Y. , Fan Hongyan , Jiang Cheng 
Published: June 2013

Abstract
Horizontal wells are widely drilled to produce heavy oil for its large reservoir contact, and the length of horizontal well usually ranges from 100m to longer than 1000m. Up to now, limited attention are attached to flow in the wellbore and vicinity of horizontal well and its influence on production performance. In fact, the influence of flow resistance in wellbore and vicinity of horizontal well on heavy oil production should not be ignored for cold production, and even thermal processes such as CSS.
In order to investigate the flow in wellbore and vicinity of horizontal well, rheological characteristic of heavy oil and water mixture are measured at different temperature and water cut, and flow in the wellbore and vicinity of horizontal well and according oil production improvement by distributed electrical heating are investigated primarily based on experimental simulation and reservoir numerical simulation. The rheological measurement results show that more than 50% - 90% reduction in viscosity of heavy oil and water mixture could be obtained as temperature increasing from inflection point temperature (80 - 90℃) to 120℃. Up to 2 - 7 times of fluid production index could be obtained by distributed electrical heating in pipe flow experiment. Both sand paced model experiment and numerical simulation indicate that oil production by distributed electrical heating is 1.5 - 4 times than that of cold production, and oil production by combination of CSS and electrical heating in production period is 1.2 - 2.0 times than CSS. In order to improve heavy oil production in cyclic steam stimulation process, a 1400m long, distributed electrical heater packed in coiled tubing is developed using stainless steel jacked mineral insulation cables. It is successfully installed and soundly operated in a horizontal well in Liaohe Oilfield. As result, about 30% - 50% increase in average oil production rate is obtained by distributed electrical heating, the production period is evidently extended, and approximately 10℃- 20℃increase in wellhead temperature obtained.
It is potential to improve heavy or waxy oil production in horizontal well by distributed electrical heating both in cold production and thermal production such as CCS. Furthermore, such coiled tubing packed heater could be used to heat the injected steam to increased the steam quality and temperature, or serves as igniter for in-situ combustion. Additionally, it offers a new way to develop downhole steam generator.
Understanding the Steam Hammer Mechanism in Steam-Assisted Gravity Drainage (SAGD) Wells
Authors: Irani Mazda , Zeleke Patou 
Published: June 2013

Abstract
Steam-assisted gravity drainage (SAGD) is one of the successful thermal recovery techniques applied in Albertan oil sands reservoirs. When considering in situ production from bitumen reservoirs, viscosity reduction is necessary to mobilize bitumen thereby flowing toward production well. Steam injection is currently the most effective thermal recovery method. While steam flooding is commercially viable, condensation-induced water hammer (CIWH) resulting from rapid steam pocket condensation can be a challenging operational problem. In steam flooding, steam is injected through a well down to the reservoir, warming it to temperatures of 150ºC to 270ºC (302ºF to 518ºF) in order to liquefy the bitumen inside the reservoir (Garnier et al., 2008; Xie and Zahacy, 2011). The liquified bitumen then drains to a lower well through which it is produced to the surface. In this process, steam pockets can become entrapped in subcooled condensate inside either the injection or production tubing causing a rapid collapse of the steam pocket. This type of rapid condesation is commonly referred to as "steam hammer".
In this study three different scenarios are explored to better understand steam hammer situations in SAGD wells. These scenarios are: (1) at injectors or producers during the start-up phase (or circulation phase), (2) in the injection tubing during the injection phase, and (3) in the production tubing during the injection phase. Modelling each of these scenarios indicates that steam hammer occurrence is likely in two of the three scenarios but that its incidence can be mitigated. The likely scenarios for steam hammer occurrence are in either the injection or production tubing during the start-up phase, and the injection tubing during the injection phase. Steam hammer occurrences during the circulation period can be controlled by lowering the injection pressure and controlling water drainage into the reservoir. Flow shocks that occur as a result of Counter-Current Flow Limiting (CCFL) are very likely to take place in the injection tubing during the injection phase but can be controlled by injecting at a higher steam quality. The least likely scenario for steam hammer occurrence is in the production tubing during the injection phase. This is because the produced (or breakthrough) steam temperature would need to be more than 20ºC higher than the produced liquid temperature to initiate a water hammer condition.
Modelling Fluid Flow in Grosmont C Carbonates Using Fractals - A Concept
Authors: Yuan Jian-Yang , Russel-Houston Jen , Nugent Daniel 
Published: June 2013

Abstract
Bitumen saturated carbonates of the Grosmont C member of the Grosmont Formation in the Saleski area are intensely fractured. The fractures connect the vuggy porosity and are the reason for in situ permeabilities that exceed 10 D. These carbonate rocks are more hydrophobic with high bitumen saturations. Most existing pilot data suggest the reservoir is in general "leaky" in comparison with siliclastics, such as the McMurray or Clearwater Formations. Furthermore, it is also observed that during CSS operations, especially in the earlier cycles, oil cuts are initially high and decrease with time. This character differs from CSS in siliclastics where initial oil cuts are low and increase with time. To fully understand these observed phenomena, we believe that common knowledge gained in studying siliclastics may not be enough. Geological studies have indicated that the Grosmont carbonate fracture system may not be a well-defined dual scale fracture-matrix system. It may be better defined with a multiple scale system. Geological models using the concept of fractals having self- similarity and fractional dimension have been proposed by Wagner et al.. In this presentation, we further postulate that the fractal nature of the Grosmont carbonates offers explanations to the above-mentioned observations. Using the published data of pilot tests in Grosmont, we demonstrate that it is possible to attribute "the loss of pressure" to very large total contact areas between fractures/vugs and the rock matrix in a fractal system, although the matrix permeability can be very low. The high oil cuts were interpreted as the result of considering high permeability channels with significant volume. Numerical simulations confirmed these assertions. This fractal point of view sheds some lights on our journey of eventually understanding and mastering the fluid flow behaviours in Grosmont carbonates.
Effective Dehydration of Canadian Heavy Crude Oil and DilBit
Authors: Sellman Erik , Murtagh Terry , Manuel Ben 
Published: June 2013

Abstract
Heavy crude oils and diluted Bitumen (DilBit) continue to be a challenge to dehydrate for the Oil & Gas Industry. These challenges include reduced crude oil / formation water density difference, higher crude oil viscosity and often smaller water droplets due the production techniques used for heavy crude oil production.
Other challenges include higher crude oil conductivity and increased crude oil emulsion viscosity formed by higher water cuts and increased solids content in the crude oil. Typically crude oil dehydration vessels use heat, retention time and AC type electrostatic dehydration technology. The AC technology produces limited voltage gradients and is not efficient for treating conductive crude oils, leading to the use of very large vessels and power units.
The traditional remedy to the above challenges often leads to high operating temperatures, high dosage of demulsifier chemicals, equipment fouling, production upsets and use of very large treaters. This leads to both higher operating expenditure (OPEX) as well as higher capital expenditure (CAPEX).
The use of combined AC / DC electrostatic technologies provides high bulk water removal efficiency in the weaker AC field combined with higher removal efficiency of small water droplets in the stronger DC field. Further improvements include amplitude modulated electrostatic fields, high frequency AC fields, improved electrode configurations as well as improved fluid distribution inside the electrostatic treaters.
More efficient dehydration and desalting processes provide potential for operating the treaters and desalters at lower operating temperatures and reduced dosage of demulsifier chemicals, in addition to the potential for using smaller treaters.
This paper describes improved crude oil dehydration using advanced electrostatic dehydration technologies and an efficient test method for optimized use of production chemicals, including case studies.
A New Solvent to Extract Bitumen from Oil Sands
Authors: Wang Guanqun , Nasr-El-Din Hisham A. , Petcavich Robert , Estrada Roy T. 
Published: June 2013

Abstract
A new environmentally friendly aqueous solution was developed to enhance recovery of bitumen from oil sands. The new solvent is water-based fluid with surfactants as the main component. The solvent can reduce the interfacial tension and change the wettability of the rock surface, which improves the efficiency and production of heavy oil recovery.
Extraction tests were conducted to evaluate the performance of the solution by soaking the oil sands with the solvent at different temperatures and times. Meanwhile, the composition of the new solvent was continuously adjusted to enhance recovery. Then, coreflood tests were conducted to evaluate the new solvent on recovery of heavy crude oil from Canada. Berea sandstone cores, with an initial permeability of 60 md, were used to conduct the coreflood tests. The cores were 6-inch length and 1.5-inch diameter. When the cores were fully saturated with heavy oil, the whole setup was placed in the oven at the designated temperature and heated for 24 hours to reach equilibrium. Then the cores were flushed with various fluids at a flow rate of 5 cm3/min. Core effluent samples were collected and the amount of crude oil was determined through the extraction method.
For the bitumen extraction tests, the first generation of the new solvent can only extract about 80% of the total bitumen at 70°C after 5 minutes soaking. About 90% of recovery was achieved at 90°C with the same solvent. The final generation of the solvent could extract 99% of the total bitumen at 70°C. For the coreflood tests, the new solvent recovered almost 90% of the heavy oil at 90°C and nearly 95% at 170°C. Meanwhile, the recovery factor was only 75% by flushing with 5 wt% KCl at 90°C.
This paper will summarize the results obtained and address the methodology of using the new solvent in the field.