bluuebunny/crossref_metadata_2025 huggingface dataset:
Enhancing Oil Rate in Solvent Vapour Extraction Processes through Tee-Well Pattern
Authors: Zeng Fanhua , Knorr Kelvin D. , Wilton Ryan R.
Published: October 2008

The production flow rate in classical VAPEX is far too low for the process to be considered commercially viable. This is largely because the classical process utilizes forces of buoyancy to distribute the solvent and gravity to drain the diluted oil to the producer. This paper presents a new well pattern that may enhance the oil flow rate two to ten times over the classical approach.

In the new well pattern, additional horizontal injectors, perpendicular to the injector and the producer in classical VAPEX, are placed in the top-most region of the reservoir. The enhanced oil rate mechanism for this new well pattern involves two features. First, the injection pressure of the top injectors is set slightly higher than the bottom injector pressure. This facilitates a downward driving force to assist gravity drainage of diluted oil to the producer. Second, the supplementary injectors generate an additional diluted oil profile perpendicular to the diluted oil profile of the classical VAPEX process. Therefore, in the new well pattern, the heavy oil is solvent contacted and diluted in both ik and jk planes, whereas in classical VAPEX, the heavy oil is diluted in only one. A series of numerical simulations were conducted to evaluate this process. In order to obtain reliable evaluation results, the numerical dispersion was eliminated through extrapolating the simulation results at different grid sizes to an infinitesimal grid size (Δy→0).

The simulation results suggest that the oil flow rate can be enhanced two to ten times greater than with classical VAPEX, depending on the well spacing of the top injectors. For example, for a well spacing of the top horizontal injectors of 120 m, the oil flow rate from the original producers will be 5.5 times higher than in the VAPEX scenario. The paper also discusses the effects of the design factors and formation/fluid uncertainties on the performance of this process. Finally, thinner reservoirs and reservoirs with a gas cap are discussed.
Pre-electrocoalescer Unit Adapted to the Extra-heavy Oil Characteristics
Authors: Noik Christine , Dalmazzone Christine , Glenat Philippe
Published: October 2008

For Mobile Extra Heavy Oils (Cold production) and for Bitumen Extra Heavy Oils (Thermal production), dehydration process is based on solvent mixture with additives injection in order to break the Water in Oil emulsions. Dehydration requires injection of large amount of additives, relatively high operating temperature, solvent addition and long retention times inside the vessels.

This process could be improved by electrocoalescence in order to reduce the amount of additive and possibly reduce the vessels retention times to finally reach the oil export specification. However, current commercial electrocoalescence processes have a low efficiency for Extra Heavy Oils because of the presence of polar heavy components limiting the electrocalescence effect and consequently limiting the efficiency of electrostatic coalescer.

The objective is to determine the most efficient electrocoalescence parameters considering the characteristics of two types of heavy crude oils issued from Cold and Thermal productions: the aim is to optimize the development of a pre-electrocoalescer unit adapted to the extra-heavy oil characteristics. This paper presents experimental results for electrocoalescence additive selection and for the optimization of electrical parameters.

The crude oils behaviour was analyzed considering their tendency to form an emulsion under controlled hydrodynamic conditions in relation with the oil/water interface dynamics. For the electrostatic dehydration, the optimization of the emulsion breaker concentration was performed using the Electrical Stability Tester API device. The minimum concentration that triggers electrical short-circuiting in relation with droplet coalescence was selected. The electrical parameters of the pre-electrocoalescer device were determined in presence of the selected additive concentration. For the two types of crude oils, high voltage and high frequency up to 1 kHz are required in combination with the addition of solvent and additive in order to destabilize the water in oil emulsions. Correlation between dehydration efficiency and residence time under electrical stress is established.
Expanding Solvent SAGD in Heavy Oil Reservoirs
Authors: Govind Pradeep Ananth , Das Swapan , Srinivasan Sanjay , Wheeler TJ
Published: October 2008

In recent years, several Steam Assisted Gravity Drainage (SAGD) projects have proven effective for the recovery of heavy oil and bitumen and Expanding Solvent (ES) SAGD pilot projects have shown positive indications of improved performance. This paper presents the results of a simulation study performed to investigate important aspects of the ES-SAGD process. In an ES-SAGD process, a solvent is added to the injected steam that remains in the vapor phase in the SAGD steam chamber and condenses along the walls of the steam chamber. Thus the solvent will have enough time to dissolve/disperse in the bitumen in the mobile zone before steam condensation occurs. Because the solvent blends with the bitumen, it significantly lowers (up to 5 fold) the oil viscosity. This process has the potential to accelerate recovery with less steam requirement per barrel of oil produced.

The important factors that control the performance of the ES-SAGD process are the solvent type, concentration, operating pressure and the injection strategy. Results of sensitivity studies performed on each of these aspects are presented with conclusions and recommendations for operating strategy. Frequently, in heavy oil recovery processes, shear dilation has been reported as a mechanism that enhances the fluid conductivity of the reservoir medium. Even though dilation is typically adjusted as a history matching variable, one of the main problems encountered with that procedure is the huge disparity in production rates that result depending on whether the process is carried out at high or low operating pressures. The capability and limitations of the geomechanical constitutive relations used to model permeability variations with reservoir pressure, built in to the thermal simulator used for the study were explored. It is concluded that dilation is an important factor for SAGD performance at high operating pressure. In order to history match the performance of such projects, it is necessary to increase the porosity and/or permeability within a heterogeneous model and dynamic dilation factor was found to play a crucial role in matching the early time data.
Conventional OTSG Development for Heavy Liquid Fuel Firing in Thermal Applications
Authors: Setchfield W P , Roset J N , Schaffer M , O'Connor D , Kense K
Published: October 2008

The large expansion in future Canadian extra heavy oil in situ thermal production (e.g. SAGD) projects will dramatically increase the demand for natural gas, the current predominant fuel used for the associated steam generation.

For thermal (SAGD) applications, depending on the Steam Oil Ratio (SOR), approximately 40,000 T/day of steam CWE (Cold Water Equivalent) is injected to produce 100,000 bpd of bitumen, requiring some 100 M SCF/day of natural gas to be fired in Once Through Steam Generators (OTSG's.)

Potential natural gas shortages and related price volatility dictate that operators consider alternative fuels for the projected near future growth in Alberta's in situ thermal production.

This paper targets the use of bitumen from upstream sites and derivative residues from upgrading activities as the most convenient alternative fuel sources for thermal operators of established ‘horizontal type’ gas fired OTSG's.

Past attempts to adapt / convert existing gas fired OTSG's to heavy liquid firing were unsuccessful because the conversions were made in haste, without properly addressing and resolving the many fundamental technical challenges involved. In consequence extensive operating problems and resultant poor reliability caused the trials to be abandoned. Furthermore at that time a cost saving benefit in displacing gas burn against heavy liquid was not consistently evident to support the further investment required.

Hence only ‘new design’ OTSG units can be sensibly considered for alternative heavy liquid fuels, also, retaining natural gas as a fuel option gives the Oil & Gas Operator a Multi Fuel OTSG, and some choice in the fuel market place.

This paper presents the methodology, the issues associated with bitumen / residue burning and the related technical solutions in development for this Multi Fuel OTSG product - natural gas firing being retained as an option and for start up.

The concepts and details of the largest transportable OTSG modules are considered, based on manufacturer TIW Western Inc's (TIWW) established gas fired designs, addressing changes necessary for heavy liquid fuel firing.

Combustion, furnace and convection section configurations and materials of construction have been selected for optimal performance / availability, whilst taking due accounts of fouling, cleaning and erosion issues, and both high and low temperature corrosion factors.

Recognising that liquid fuel combustion increases CO2 and other emissions over natural gas firing the technical options for mitigation are being addressed in parallel studies.
Successful Field Implementation of Novel Cementing Solution for ISC Wells: Case Histories
Authors: Meher R. K. , Suyan K. M. , Dasgupta D. , Deodhar S. , Sharma Vinod , Jain V. K.
Published: October 2008

Cementation of In-situ combustion (ISC) wells is a challenging affair as wells are often associated with weak and unconsolidated formation, nevertheless cement rise upto surface is desired to prevent casing failure. Furthermore the cement sheath is also required to withstand extreme stresses due to high temperature cycling experienced during in-situ combustion process.

In heavy oil fields of western India, due to the problem of inadequate placement time and flash setting when in contact with portland cement, the portland cement-silica blends were used for cementation of ISC wells instead of alumina cement blends. But this resulted in insufficient cement rise due to losses during cementation and the set cement failed to contain the strength and permeability in course of ISC process causing charging of sub-surface shallower layers.

For mitigating these problems, non-alumina based thermally stable lightweight lead slurry and a ductile high temperature resistance tail slurry have been developed and implemented for cementation of ISC wells, the details of which alongwith successful case histories are presented in this paper.

In the formulated thermally stable slurries there was neither reduction in strength nor increase in permeability even after thermal cycling upto 650°C. The lightweight slurry composition (S.G.1.60) reduced the hydrostatic head to effect cement rise upto surface. Since these formulations are devoid of alumina cement, all the associated field problems were totally eliminated. Superior cement bondage in comparison to earlier results confirmed the successful field validation.

This approach and the development is a unique solution of the problems in cementation of ISC wells, making it suitable for use as an effective alternative to earlier practices. Field implementation of this development has successfully arrested charging of shallower zones which was endangering the ISC process in fields of western India.
In Situ Upgrading of Heavy Oil Under Steam Injection with Tetralin and Catalyst
Authors: Mohammad A. A. , Mamora D. D.
Published: October 2008

Experiments were conducted to verify the feasibility of in situ upgrading of heavy crude oil by using a hydrogen donor (tetralin, C10H12) and an organometallic catalyst, Fe(CH3COCHCOCH3)3. Three cases were considered: pure steam injection; steam injection with tetralin; and steam injection with tetralin and catalyst. The cases were compared based on final recovery and properties of the produced oil.

The catalyst Fe(CH3COCHCOCH3)3 is highly soluble in tetralin. The concentration of the catalyst in tetralin was kept at 750 ppm. The experiments were conducted in a vertical injection cell. A mixture of sand, water, and Jobo oil, were thoroughly mixed prior to being tamped into the injection cell. For each of the two non pure steam injection cases two types of runs were conducted. In the first type of run, the tetralin or tetralin-catalyst solution was mixed with the sandmix before being tamped into the cell. In the second type of run, tetralin was injected as a slug ahead of steam injection. The Jobo oil used had an oil gravity of 12.4ºAPI and a viscosity of 7800 cp at 30ºC. All experimental parameters and conditions were kept the same for all cases. Produced fluids from the experiments were collected periodically through a series of separators. The cumulative produced oil for each run was then divided into two equal samples, and a series of analysis were carried out. These included measurements of viscosity and API gravity, and elemental analysis.

The experimental results may be summarizeda as follows. Addition of 5 wt% of tetralin increased oil recovery by 15% above that with pure steam injection. Premixing tetralin-catalyst solution with the sandmix yielded 20% higher oil recovery than the pure steam injection. When the tetralin-catalyst solution was injected as a slug, oil recovery was similar to that with injection of just tetralin. Acceleration in oil production was observed for all the runs but was more pronounced with the presence of the catalyst. Both the tetralin and tetralin-catalyst runs showed a potential application to improve recovery and oil quality. The improved oil quality may help reduce cost of oil upgrading on surface.
Applicability and Optimization of SAGD in Eastern Venezuela Reservoirs
Authors: Piña R. José Antonio , Bashbush José Luis , Fernandez Edgar Alexander
Published: October 2008

The work presented in this paper describes the evaluation and stepwise optimization process for a Steam-Assisted Gravity Drainage (SAGD) project using a representative sector model from a field with fluid and reservoir characteristics from an eastern Venezuela formation.

Due to the complexity and number of variables involved in the process, SAGD presents multiple challenges from the design and analysis phases to its final implementation. The objective of this investigation was to understand the impact of key parameters in the process specific to the selected area and to understand the effects on the recovery factor in these reservoirs, which have previously produced with primary recovery mechanisms.

The study touches upon the effect of the component grouping for fluid characterization. A preliminary work consisted of reducing the original 14 components identified in the existing Pressure/Volume/Temperature (PVT) analysis into 2 and 3 pseudocomponents and comparing the stability and results using both fluid characterizations to attain reasonable running times in the simulation process.

Once the fluid behavior was successfully recreated and the model was set up, a sensitivity analysis was conducted using thermal simulation. The parameters analyzed were vertical well spacing, injection steam rate, well flowing pressure, and horizontal length of the well pair. The effect on the oil recovery from the angle of dip in the reservoir and the orientation of the well pair with regard to the direction of dip were also briefly analyzed.

The conclusion presents a highly improved configuration for the SAGD well-pair array that resulted in trebling the oil recovery attained by the initial well arrangement.
Feasibility Study of the In-Situ Combustion in Shallow, Thin, and Multi-Layered Heavy Oil Reservoir
Authors: Liguo Zhong , Di Yu , Yuning Gong , Ping Wang , Lishu Zhang , Changbao Liu
Published: October 2008

All heavy oil reservoirs in TaoBao oil field are shallowly buried, thin, and multilayered in which natural production and cold production technologies have been implemented in past seven years, and obvious increase in oil production was achieved by cold production(up to 9 times than natural production method). However, due to the low reservoir pressure, heterogeneity, and limited formation thickness, the oil production has rapidly decreased, and more than half of the wells have been shut off now. At present, more than 94% oil remained in place is difficult to exploit, and different recovery methods are being invest-tigated, as a result, only in-situ combustion is more potential and seems feasible to enhance oil recovery for such reservoir.

To investigate the feasibility of in-situ combustion, reactor experiment and combustion tube experiment have been carried out at first, the result shows that the optimal fire temperature is above 400°C, and the ultimate oil recovery is more than 80%. Additionally, air injection rate, combustion front velocity and other parameters have been measured or calculated. At the same time, primary reservoir numerical simulation for selected block in Bai92 reservoir are implemented considering that more importance should be attached to the feasibility of in-situ combustion in reservoir scale. Some important factors such as air injection rate are investigated. Moreover, the progress in pilot test of in-situ combustion in B92 reservoir is introduced briefly.

The results of primary experiments, reservoir numerical simulation and pilot test show that in-situ combustion is feasible to enhance oil recovery of such shallow, thin and multilayered heavy oil reservoir as B92.
Improved Heavy Oil Recovery by Low Rate Waterflooding
Authors: Mai A. , Kantzas A.
Published: October 2008

This work details the results of ambient temperature waterfloods in unconsolidated sand containing heavy oil (11°API and viscosity of 11,500 mPa⋅s at 23°C). Experiments are performed at rates ranging from 0.4 – 0.02 m/day, in sand with permeability of under 1 D to 9 D. By varying both the injection rate and the permeability of the sand, the relative influence of viscous and capillary forces can be determined. It is shown that by properly controlling the waterflood, significant heavy oil can still be recovered after water breakthrough has already occurred.

The application of this work is for the significant heavy oil resource in Canada that exists in reservoirs that are too thin for thermal operations. A fraction of oil may initially be recovered through primary production, however at its conclusion a significant amount of oil still remains in the reservoir. Waterflooding is a simple process that has potential for recovery of additional oil, in reservoirs where more expensive options will not be possible.

Due to the adverse mobility ratio between water and oil, water breakthrough occurs early in a waterflood, with a significant amount of the oil still being continuous at this time. The key to understanding the displacement of heavy oil by water is to consider the oil recovery after breakthrough. This oil is produced at high water cuts, and under negligible pressure gradients. Oil is therefore recovered by water imbibition into the water-wet sand. By varying the injection rates and the permeability of the sand, the importance of these capillary forces to oil recovery has been quantified.

Capillary forces are generally deemed to be insignificant in heavy oil waterfloods due to the high oil viscosity. As such, concepts of viscous fingering and mobility ratio dominate discussions of heavy oil waterflood responses. In this work, it is shown that not only are capillary forces actually still important in heavy oil reservoirs, but in fact they are a significant mechanism responsible for oil recovery after water breakthrough. With this understood, heavy oil waterfloods can be properly designed to maximize flood efficiency and oil recovery.
Improved Recovery Potential in Mature Heavy Oil Fields by Alkali-Surfactant Flooding
Authors: Bryan J. , Kantzas A.
Published: October 2008

Many reservoirs in Canada are too small or thin for energy-intensive thermal EOR operations. The reservoirs may also be disturbed during primary production, generating low-resistance flow-pathways between injectors and producers, thus injected fluids will follow these pathways and not contact additional oil. In these conditions, alkali-surfactant injection has considerable potential as a technique for additional non-thermal recovery of heavy oil.

During unstable displacement of heavy oil by water, water breakthrough occurs early, and subsequent water injection will channel mostly through the water fingers and bypass significant volumes of continuous oil. It has been shown in other works that alkali and/or surfactant injection can lead to improved heavy oil recovery compared to waterflooding, but researchers have proposed different reasons for this response. This work summarizes the mechanisms that are responsible for improved heavy oil recovery and presents the results of 30 laboratory core floods investigating alkali-surfactant injection into sand-packs containing heavy oil (viscosity 11,500 mPa⋅s at 23°C).

By injecting less than 1% of alkali-surfactant (AS) solution with water, a combination of oil-in-water (O/W) and water-in-oil (W/O) emulsions will form in the water channels, effectively blocking them off. Further injected solution will therefore contact fresh regions of the core. It is shown that this design of AS injection in heavy oil leads to improved sweep efficiency of the flood. This corresponds to lower apparent relative permeability values to the aqueous phase, and a discussion is provided regarding how AS floods can be controlled and optimized.

In any heavy oil reservoir that is considered a viable candidate for waterflooding, AS flooding can also potentially be applied. The significance of this work is that it describes the mechanisms responsible for the improved oil recovery, which allows for optimized design of chemical flooding conditions. This study demonstrates how a small amount of chemical injected along with water can lead to dramatic improvements in the recovery from previously flooded heavy oil fields.
Bitumen Extraction from Oil Sands Ore-Water Slurry Using CaO (Lime) and/or Ozone
Authors: Babadagli T. , Burkus Z. , Moschopedis S. E. , Ozum B.
Published: October 2008

Bitumen extraction efficiency is increased in oil sands ore-water slurry based extraction process by increasing solubility of naturally occurred asphaltic acids by addition of CaO (lime) and/or by oxidation of bitumen asphaltenes by Ozone (O3) to surfactant species, at as low as 35 °C temperature. Experimental findings suggest that a non-caustic bitumen extraction process (i.e. without using NaOH as extraction process aid) could be used commercially by conditioning the oil sands ore-water slurry with CaO and/or Ozone, which would allow high extraction efficiencies at about 35 °C temperature, reduce energy consumption and CO2 emission for the extraction of bitumen and eliminate the accumulation of Na+ ions in the recycled release water. Further tests are on-going to provide sufficient data for the commercial implementation of the use of CaO and/or Ozone at oil sands-ore water slurry based extraction plants.
Feasibility of using Electrical Downhole Heaters in Faja Heavy Oil Reservoirs
Authors: Rodríguez Raúl , Bashbush José Luis , Rincón Adafel
Published: October 2008

The Orinoco Belt (Faja) in Venezuela contains one of the largest resources of heavy and extra-heavy oil in the world. Due to the production decline of conventional light crude, projects must focus on increasing the recovery of heavy and extra-heavy oils using thermal and non-thermal methods. Steam-based thermal recovery processes are more efficient in low pressure reservoirs; however due to their depth, the initial pressures of the reservoirs in the Faja are relatively high, in the range of 600 to 1,500 psi with viscosities typically greater than 2,000 cp. For the above reasons, it is important to decrease the pressure of the reservoirs with primary production techniques to facilitate the economical implementation of steam injection based methods.

The initial production of heavy and viscous oils can be accelerated by the adequate use of downhole heaters that, by providing energy to the vicinity of the well, decrease oil viscosity and increase the oil production rate. A consequential advantage of using downhole heaters as a preamble to a steam injection process is that they accelerate early production and reservoir pressure decline while the equipment associated with steam injection, including steam boilers, insulated pipes and proper facilities are designed, ordered, installed and commissioned.

This paper analyzes the effects of downhole heaters as a stimulation method through the use of a numerical model of a representative field in the Ayacucho area of the Orinoco Oil Belt.

The study has been divided in three parts. The first part relates to the use of downhole heaters in thick sands, stimulating both vertical and horizontal wells in the reservoir. The second one evaluates the temporary application of downhole heaters in horizontal wells for a limited period of time to accelerate production and pressure decline, followed by a full implementation of a Steam Assisted Gravity Drainage (SAGD) process. The third part of the paper covers basic economical analyses performed using estimated capital and operating expenses with oil production curves from each case, to assist in the comparison of their worth using common economic parameters.
In-Situ Combustion with Solvent Injection
Authors: D'Silva J. , Kakade G.
Published: October 2008

Production of heavy oil has always been associated with a lot of problems. A major one being the high viscosity of heavy oil due to which it does not flow easily into a producer well. In-Situ techniques like Cyclic Steam Stimulation (CSS), Steam Assisted Gravity Drainage (SAGD), and Vapor Extraction Techniques (VAPEX) are not mutually exclusive and it is becoming increasingly common for wells to be put through one of the techniques followed by the other so as to improve recovery rates.

The main purpose of this paper is to discuss the effect of combining the techniques of In-Situ Combustion with heavy hydrocarbon vapor injection on the same heavy oil reservoir.

This paper with the help of an example case study, gives a detailed explanation of this combination technique as an integrated unit and its various advantages over using just a single technique.
Horizontal Alternating Steam Drive Process for the Orinoco Heavy Oil Belt in Eastern Venezuela
Authors: Fernandez R. Edgar A. , Bashbush José Luis
Published: October 2008

The Orinoco Heavy Oil Belt (Faja) has been exploited under primary recovery techniques using mainly horizontal, fishbone and multilateral wells. This cold development can only recover between 6% and 9 % of the considerable original oil in place existing in the area. Owing to the high viscosities, widely different formation thicknesses and heterogeneities found, the implementation of different thermal recovery methods is necessary.

This project covers a feasibility study considering the Horizontal Alternating Steam Drive (HASD) process geared to increase the recovery efficiency of heavy oil within the Faja reservoirs. The process is based on a repetitive pattern using horizontal wells acting alternatively as oil producers and steam injectors. The recovery mechanism is a combination of horizontal steam flooding between wells and cyclic steam stimulation of each of the horizontal wells in the pattern. Properly implemented, HASD could be more efficient than classical cyclic steam injection and more effective than direct steam flooding.

In contrast to the Steam Assisted Gravity Drainage process (SAGD), HASD uses single horizontal wells cyclically switching between injection and production phases. The steam chamber generated while each well is injecting is laterally driven by the pressure differentials created by adjacent producers, forming a sweeping front between wells. Injectors are converted to producers (and vice versa) providing heat directly to the zones where production will occur gradually extending the steam chambers to the entire reservoir region. Thus, the impact of steam is not that of a simple well stimulation, but also achieves an effective sweep in the vicinity of the producers while decreasing oil viscosity and improving oil drainage.

This project is based on the numerical simulation results from a representative model from one of the Faja main blocks using Eclipse Thermal applied to medium thickness sands in the 20-50 net ft range.

A five-horizontal well array set up was used as the model to assess this fairly new thermal recovery technique. During the investigation, different scenarios were analyzed to obtain a generalized step-by-step optimization procedure for the process under the specified fluid and reservoir conditions.

Sensitivity analyses were performed considering the relative positioning of the horizontal well placement in the reservoir column; different injection sequences; varying the duration of each injection cycle; various injection rates; and lengths of the horizontal reach of the wells.

The results of this investigation can be used as a reference to optimize the performance of the HASD process for sand bodies of medium thickness.
Electro-Magnetic Heating in Viscous Oil Reservoir
Authors: Das Swapan
Published: October 2008

Formation resistive heating, commonly known as EM (Electro-Magnetic) heating, has been considered as a potential thermal recovery method in the viscous oil reservoirs for almost three decades. In situ viscosity reduction by the heat generated in the formation helps in the recovery process. The formation acts as a resistor in the current flow path. Numerous patents and reports have been published on this. Application in deep reservoir and negligible heat loss in the overburden, are the two most important features of this thermal recovery process. There are examples of few pilots in Canada, Brazil and elsewhere. This also has been proposed as an option to accelerate SAGD start up.

This paper presents the limitation of EM heating in the formation and its applicability in few viscous oil reservoirs. It appears that in the EM heating process, heat penetration is significantly lower than that of a steam based process. Simulation of electrical heating in the simulator is tricky. The amount of estimated heat input is very sensitive to grid refinement. In reality, there is a potential for generating hot spots at the electrodes which was reported to be one of the reasons for failures in the field applications.
Distribution of Multi-Component Solvents in Solvent Vapor Extraction Chamber
Authors: Das Swapan
Published: October 2008

In the solvent vapor extraction of heavy oil and bitumen, commonly known as the Vapex process, viscosity of the oil is reduced by dilution with solvent. Although laboratory experiments are generally carried out using single component solvents, in the field application the commercially available solvents always contain impurities. These components distribute in the in situ oil at different proportions depending on their solubility at the operating conditions and their concentration in the injected mixture. In general it is expected that the non-condensable solvent components hinder the process.

This paper presents the results of a simulation study to investigate partitioning of solvent components inside the vapor chamber in the Vapex process. It appears that the non-condensable solvent components accumulate at the solvent vapor-viscous oil interface. The solvent component diffuses through this vapor boundary layer to the oil interface. However, the rate of diffusion in the gaseous phase is much faster than that of the molecular diffusion in the liquid phase. The later is the rate controlling step and dominates the performance of the process.
Effects of Well Placement and Intelligent Completions on SAGD in a Full-Field Thermal-Numerical Model for Athabasca Oil Sands
Authors: Akram F.
Published: October 2008

Estimated at 2.5 trillion barrels, Canada has the world's largest share of ultra-heavy oil and bitumen resources. While shallow heavy oil reserves are extracted from pit mines, deeper reserves can only be extracted through wells. Production of these reserves requires methods such as steam-assisted gravity drainage (SAGD) and cyclic steam simulation (CSS) (Butler, 1991). Optimal well placement defines the propagation of steam within the reservoir and the resulting flow of crude.

SAGD recovery methods require tremendous amounts of steam in order to get the crude to flow. Costs to generate and inject steam in a SAGD pad are significant. Finding ways to use steam more effectively in these operations should result in increased production efficiency and improved financial return on these projects. By strategically placing steam injectors and by controlling the amount of steam injected it may be possible for these results to be achieved.

A study was conducted to examine several completion strategies and to test, with the use of a simulation model, what the expected production, and steam requirements for these strategies would be. The simulation model examined multiple well pairs to see these results in a full-field environment. To assess the financial impact of these strategies, a fiscal model was developed that evaluated SAGD project costs and then examined the incremental cost and value of each of the completion strategies. Results show that although using steam effectively in these strategies may not yield the highest recovery, it does improve the expected value of these projects.

This paper describes the process, operational control, and financial analysis used to design and validate the SAGD model. The study focuses on a completion strategy that demonstrates a strong potential to reduce SOR and ultimately operational cost. Incremental financial analysis is included to examine the impact of choosing any such strategy.
A Singular Methodology to Design Cement Sheath Integrity Exposed to Steam Stimulation
Authors: Garnier A. , Saint-Marc J. , Bois A. -P. , Kermanac'h Y.
Published: October 2008

Heavy oil production is one of the new challenges the Oil and Gas industry faces today with reserves of trillions of barrels. When well production is considered, heavy oils viscosity must be reduced to gain mobility and have oil flowing. Between all possible techniques, steam stimulation is today the most promising.

Steam is injected through the well down to the reservoir to warm it up with temperature up to 250°C, inducing extreme thermal stresses to the well, especially when the temperature gradient through the well components is maximum, like during first steam injection or during work-over when the well should be quickly cooled down and heated up again to rapidly restart production.

To avoid zonal isolation failure and steam release at surface, new rules should be considered when designing barriers of a well exposed to steam stimulation, especially in very shallow fields. If classic rules could be applied for casing design, pioneering rules should be considered to design cement sheath.

This paper presents a singular methodology to design cement sheath long term integrity in very shallow conditions. First, stresses in the field are evaluated with a rock mechanics simulation. Then, thermal gradient in well components while heating are evaluated with a thermal simulation of the well. Both results are injected in Total's dedicated software to determine the mechanical properties the cement should have to withstand thermal stresses. Different cement systems from service companies are then triaxial tested before being evaluated in a cell reproducing the field to validate simulations' results.

This methodology was successfully applied to Joslyn field wells, Canada, where a resilient cement system with low Young's modulus and high tensile strength was selected and pumped. Since results are positive, this methodology has been extended to other Total's fields worldwide where steam simulation is considered.
A Novel Process for Heavy Residue Hydroconversion Using a Recoverable Pseudo-homogeneous Catalyst (PHC) System
Authors: Romocki S. M. , Rhodey W. G.
Published: October 2008

Conventional hydroconversion of residue has been achieved through high pressure, capital intensive processes with significant operating costs associated with maintaining catalyst activity. Despite the usefulness of heterogeneous catalysts in numerous refining processes, their potential for hydroconversion of heavy feeds with high levels of sulfur, nitrogen, resins, asphaltenes and metals is limited.

This paper will introduce a Pseudo-homogeneous Catalyst (PHC) developed for the specific chemistry of heavy hydrocarbon feeds. The term pseudo-homogeneous provides a convenient description of nano-scale unsupported catalyst particles uniformly dispersed throughout the feed. As a result of particle size, nanoparticle suspensions exhibit properties similar to colloidal solutions.

Residue processing using a high performance pseudo-homogeneous catalyst system results in improved cracking and hydrogenation performance at lower process severity. The PHC system in the Heavy Residue Hydroconversion (HRH) process achieves up to 95% residue conversion at pressure below 7.3 MPa, reaction temperatures between 400 - 460 °C, with feed space velocity between 1,0-2,0 h-1; making PHC systems well suited for deep conversion of hydrocarbon residues.

The sustainability profile of the HRH process is improved as residue conversion to liquids is maximized, while up to 95% catalyst is recovered and regeneration within the process.

Pilot plant results from hydroconversion of Athabasca vacuum bottoms using a pseudo-homogeneous catalyst (PHC) system are discussed.
Increase Oil Recovery of Heavy Oil in Combustion Tube Using a New Catalyst based Nickel Ionic Solution
Authors: Ramírez-Garnica M. A. , Hernández-Pérez J. R. , Cabrera-Reyes M. C. , Schacht-Hernández P. , Mamora D. D.
Published: October 2008

In this research an ionic liquid base Nickel was used in a combustion tube with heavy oil from Gulf of Mexico. The underlying objective is to increase the mobility and quality of the oil inside the reservoir by effect of the ionic solution catalyst during the combustion.

The catalyst, used in the experiments was previously mixed with heavy crude oil of 12.5 °API. The catalyst in liquid phase is based Nickel. This ionic catalyst is highly soluble and ultradispersed in heavy oil, and it was mixture with heavy crude oil with a concentration of 500 ppm wt.

The porous media used in the combustion tube was a triturated dolomite carbonated rock with a 35.23% of porosity, and a particle size of 0.42 mm. This rock was used for two experiments at the same saturation conditions: heavy crude oil (23.79%), and water (25.26%).

The results obtained shown the advantages of use of this catalyst in relationship of a conventional combustion as follows: (1) important viscosity reduction, (2) increment of oil production, 85% vs. 77.67%, (3) faster combustion front, (4) higher efficiency in the combustion, 75.86 vs. 197.28 ft3 air/ft3 hydrocarbons, (5) higher temperatures through the combustion process, around 600 °C, and (6) reduction of the contain of sulphur, resins and asphaltenes in the oil produced.

Using this kind of Nickel ionic solution catalyst at low concentration would permit to increase the recovery factor, and upgrade the oil properties in-situ.
Integrated Petrophysical Approach for Determining Reserves and Reservoir Characterization to Optimize Production of Oil Sands in Northeastern Alberta
Authors: Anderson Andrew , Koch Jim
Published: October 2008

The acquisition of triple-combo logging data, borehole imaging data, dipole sonic, and select magnetic resonance data, offered the unique opportunity to study a specific set of wells in the McMurray Formation of northeastern Alberta. Each one of the data sets provided valuable information about the geologic setting, fluid properties, or rock properties. The true value of the logging data comes from combining the analyses and interpretations to produce a complete picture of the geology, reservoir potential, and production potential. This integrated approach is based on the interpretation of results from the image data, while incorporating standard log data, including electric, nuclear, and acoustic measurements; dipole sonic data; and nuclear magnetic resonance data. Subsequently, shaly sand analysis from these measurements was added to provide key reservoir petrophysical information. Finally, the addition of nuclear magnetic resonance data supplied insight into the producibility of the reservoir.

Traditionally, dipmeter and image results are used for mapping of channel sands in the McMurray Formation. For this application, however, the image data provided high-resolution delineation of shale beds. This use of the image data leads to a critical reservoir heterogeneity description, which is required for vertical permeability information to optimize production. Shaly sand analysis results (volume of shale, sand calculations, water saturation, and permeability) are combined with core data, when available, and both the core and shaly sand analysis results were incorporated along with the image interpretations. Finally, nuclear magnetic resonance data was added for the key wells, providing comparison of bound to free water, as well as permeability and lithology-independent porosity. When combined, each data set adds either qualitative or quantitative information that is iteratively used to refine and complete the integrated petrophysical analysis.

In this investigation of the McMurray sand characteristics, initial interpretation of the image data revealed that the depositional environment does not match that of the typical fluvial-estuarine sands; subsequently, an interpretation of all wireline data was performed. The results of this interpretation indicate a shoreface environment. Integrating all petrophysical measurements enabled geoscientists to obtain a more complete picture of the subsurface.
Production of High Quality Water for Oil Sands Application
Authors: Beaudette-Hodsman Chris , Macleod Brian , Venkatadri Ramraj
Published: October 2008

Canadian oil sands in the province of Alberta are a hydrocarbon source for North America. By the year 2015, the oil sands will be producing in excess of 3 million barrels/day of crude oil. A number of companies operate Upgraders that convert the bitumen that is extracted from the oil sands into light sweet crude oil. Steam is required to heat utilities at the Upgrader facility.

In one major oil sands extraction site, well water is being used as feed water for the boilers producing this steam. Reverse Osmosis (RO) systems were designed and installed to produce high quality water required for this application. The pretreatment system was designed with conventional multimedia technology. The RO system required feed water with silt density index (SDI) of 3 or less. Due to ineffectiveness of the conventional pretreatment system, the SDI of the RO feed water was in the range of 12-20. This resulted in severe fouling of the RO membranes and production losses.

In order to optimize the performance of the RO membrane system, a pressurized microfiltration membrane system was delivered and commissioned within 5 days to replace the existing pre-treatment system. The new unit contained an automated PVDF hollow fiber microfiltration membrane system mounted in a trailer. SDI values in the range of 1.0-2.5 were immediately observed in the feed water to the RO system. The end user has enjoyed significant cost savings and ease of operation as a result of this innovative technology. This paper describes the details of the installation and the superior performance data gathered at the end user site.
Improved Simulation Design Factors for Unconventional Crude Vacuum Units: Cracked Gas Make & Stripping Section Performance
Authors: Remesat Darius
Published: October 2008

Operating data has been gathered and shared to attempt to provide insight for design considerations for unconventional heavy oil/bitumen vacuum crude units, specifically data for cracked gas make and stripping section performance. As corroborated in literature5,7,9, unconventional crudes need to have appropriate design considerations applied into the design simulation.

Designers should "track down" all relevant data to improve the chances of realistically representing the expected operating situation from the design choices made. The data provided in this paper can be used a validation point for vacuum column designs with unconventional crudes.
Optimization of SAGD Wellbore Completions: Short Production Tubing String Sensitivities
Authors: Cokar Marya , Graham John
Published: October 2008

A simulation study was carried out to examine the effects of changing the landing position of the short production tubing string relative to the heel of a SAGD production well. A homogeneous discretized wellbore model with the riser section was used in this study. Generally, a reservoir is modeled independent of the wellbore. However, this study models the reservoir and wellbore simultaneously to understand the interactions between them.

This paper outlines two independent case studies, which are outlined below: The first study involved shortening the short production tubing string relative to the heel of the well. It was found that as the short tubing string was pulled back from the heel of the well the bitumen production rate decreased, and the amount of steam produced through the short production tubing string increased.The second case study outlines the impact of extending the short production tubing string past the heel of the well on bitumen production and SOR. From this case study, it was found that as the short production tubing string was pushed past the heel of the well, the bitumen production rate stayed the same, but the steam injection rate decreased which consequently decreased the SOR. It was also observed that a lower pressure differential between the injector and producer well was established when the short production tubing string was extended.

The results for this study will assist SAGD producers to re-evaluate the position of the short production tubing string, and find the most economical position for this string. This paper creates the foundation for further simulation efforts to incorporate a discretized model with the build section coupled to the reservoir. This will allow production engineers to optimize bitumen production by simultaneously simulating the reservoir and wellbore strings together.