bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mechanical Evaluation of a New Sand Control Screen for SAGD Applications
Authors: Woiceshyn Glenn , Toffanin Ezio , Xie Jueren , Wagg Brian , Fan Chengye 
Published: October 2008

Abstract
Steam assisted gravity drainage (SAGD) wells typically require the deployment of an open hole completion combining sand control with adequate mechanical strength to withstand: 1) aggressive installation loads—compression, torque, bending—that are characteristic of shallow horizontal wells, and 2) severe operational loads—tension, compression, collapse, burst—caused by a combination of high temperature steam injection and formation collapse around the completion.
Historically, slotted liners have been used in Western Canada, primarily because of low cost relative to wire-wrapped screen (WWS) or premium mesh screens. However, slotting base pipe can significantly weaken its mechanical strength, particularly in torsion and collapse, and the slot width can change as the liner deforms under certain load conditions. Reported incidents of mechanical failure and loss of sand control of slotted liners in SAGD wells have generated interest among operators to investigate alternative technologies.
A new sand screen has been developed that involves flush-mounting and securing 25.4 mm diameter fusion bonded metal laminate (FBML) cartridges/discs directly into the base pipe wall. The open flow area of the screen, which can be as high as 20% (versus 2.5% for slotted liner), is dictated by the number of inserted discs (holes) per foot. For an equivalent open flow area, drilling holes in the base pipe is less detrimental to the mechanical strength of the liner than cutting slots. This new geometry results in a sand screen that is cost competitive to slotted liner on a same-open-flow-area basis, significantly stronger, and comparable to a premium mesh screen in terms of sand retention performance.
To independently quantify the mechanical strength and integrity of this new screen for SAGD, an extensive Finite Element Analysis study was performed on 177.8 mm (7"), 38.7 kg/m (26 lb/ft), L80 base pipe for two different hole densities and various single loads, combined loads and thermal cycling. The results, as presented herein, demonstrate that inserting FBML discs into base pipes does not significantly weaken it compared to cutting slots. A stand alone screen (SAS) with almost four times the open flow area of a slotted liner has significantly more torsion and collapse strengths.
Maximizing Heavy-Oil Recovery by Containing Steam through Optimized Cementing
Authors: Ravi Kris , Hunter Bill , Kulakofsky David 
Published: October 2008

Abstract
As the world's traditional oil and gas reserves decline, the industry is challenged to produce from unconventional sources. Heavy oil is found in different parts of the world and could be an answer to the demand for energy. However, heavy oil is highly viscous and traditional methods are not sufficient to produce these wells.
One option is to inject fluid such as steam to decrease the viscosity, making it feasible to produce the heavy-oil reserves. However, the steam heats the casing and the cement sheath in addition to the reservoir of heavy oil. The increase in temperature is high and imposes considerable thermal stress on the casing and the cement sheath. In many wells, the upperhole section is unconsolidated, posing higher risk to the cement sheath when subjected to stresses.
If the cement sheath is unable to withstand the stresses, it could be damaged and fail to provide zonal isolation. The cracks and microannulus in the cement sheath can act as a pathway for the steam to escape. This could considerably reduce the recovery of heavy oil while posing health, safety, and environmental challenges.
The design procedures necessary for evaluating the properties needed in the cement sheath to help withstand thermal stresses are discussed in this paper. Procedures to improve cement slurry placement are also presented. Additionally, methods to reduce heat losses in the upperhole section as well as reduce temperature stresses while optimizing the overall well-construction for heavy-oil recovery are also discussed.
This work should aid in the construction of wells that will contain injected fluids such as steam in the recovery of heavy oil. The cementing procedures discussed in this paper should help improve heavy-oil recovery as well as health, safety, and the environment.
The Progressing Cavity Pump Operating Envelope: You Cannot Expand What You Don't Understand
Authors: Noonan S. G. 
Published: October 2008

Abstract
Progressing cavity pumps (PCP) have been the preferred method of lift for cold heavy oil production for years. They were generally not considered a complex technology, unlike electric submersible pumps for example, and this resulted in many misapplications and poor performance.
Until the PCP industry started to push the envelope in terms of landed depth, production volumes, gas handling, viscosity and aromatics, that testing programs emerged to understand the science behind PCP performance under various conditions. This paper will describe some of the recent findings from these test programs that will help to better select and design a PCP system for heavy oil. Some of this work includes understanding gas handling capabilities, rod string torsion, elastomer swell, metallic stators, and the effects of speed and rotor - stator fit on PCP run life.
The PCP industry has also been plagued with the lack of a "common language" which makes communication of lessons learned and data sharing difficult. This paper will describe the efforts of a group of operating companies to standardize nomenclature and data parameters to facilitate analysis and benchmarking to identify areas for improvement and gaps for technology advancement. This paper will also provide information from the group of PCP users and manufacturers that worked together since early 2006 to create comprehensive international standards and recommended practices for the manufacturing and testing of these pumping systems.
Enhancing Oil Rate in Solvent Vapour Extraction Processes through Tee-Well Pattern
Authors: Zeng Fanhua , Knorr Kelvin D. , Wilton Ryan R. 
Published: October 2008

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.