bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Condensation Temperature Model for Evaluating Early-period SAGD Performance
Authors: Zhu L. , Zeng F. , Zhao G. 
Published: June 2012

Abstract
This paper proposes a new methodology using condensation model to evaluate the early-period SAGD by interpreting the temperature falloff data in injector or producer obtained from fiber optics or thermal couples after the wells are shut-in. Based on the non-condensation model proposed before, the condensation model also assumes a circular hot-zone shape since in the early stage of SAGD operation, and characterize the system as composed of a steam-zone of steam temperature, a cold-zone of reservoir temperature and a transition-zone in between as the initial temperature distribution. Besides, the condensation model incorporates the effect of steam condensation on the condensation-front. The movement of steam condensation-front is calculated to account for the steam-zone shrinkage. Sensitivity analysis over this models indicates that the sizes of steam-zone, transition-zone and the observing location directly affect the temperature behavior at observation point. Synthetic case study shows that the temperature falloffs from condensation model and from simulation are in good agreement and suggests that condensation model can be used to estimate the chamber size at the early stage of SAGD. As is known, it is important to obtain an even steam chamber distribution along the horizontal wellbore to shorten the ramp-up time so that maximized economics can be achieved. In reality, the reservoir heterogeneity, the wellbore undulation and the operation condition make the steam chamber conformance impossible. Because of the ready-to-use temperature data and the semi-analytic solution, the condensation model proposed in this paper can provide quick and reliable estimation of the steam chamber size to help the engineers to monitor and optimize the chamber development thereafter.
Real-Time Imaging of SAGD Steam Conformance By Using White Noise Reflection Processes
Authors: Leskiw Chris 
Published: June 2012

Abstract
4D seismic imaging requires extensive time to setup, implement, and process to provide information on the progress of recovery efforts such as estimates of the size and shape of reservoirs and their internal artifacts. Conventional seismic imaging results in a resolution on the order of tens of meters. As an alternative, white noise reflection processes use sub-noise signals to image reservoirs and can potentially do this at scales below 1 meter.
Both simulations and lab experiments show that reflections from white noise processes can be used advantageously to localize discontinuities and track their movement through media. For example, for steam-based oil sands recovery processes, it is critical to have an understanding of the steam conformance to improve the efficiency of the recovery process. White noise signaling technologies can be used to monitor the spatial distribution of fluids e.g. a steam chamber interface, and objects e.g. shale layers and concretions, at higher frequencies resulting in finer resolution in real-time compared to conventional methods.
The results demonstrate that acquisition and ranging of discontinuities in the laboratory can be achieved at the centimeter scale. The methods are extended to concurrent use of multiple transducers to improve directionality and triangulation of discontinuities.
History Match of the Liaohe Oil Field SAGD Operation - A Vertical- Horizontal Well Reservoir Production Machine
Authors: Bao Y. , Wang J. Y. , Gates I. D. 
Published: June 2012

Abstract
With the decline of conventional oil production, developing and producing heavy oil resources efficiently is becoming more important. The Liaohe Heavy Oil Field steam operation is unique – it started with cyclic steam stimulation (CSS) operation that transitioned into a continuous steam-assisted gravity drainage (SAGD) operation. With respect to oil production in China, this field is considered critical for heavy oil production and technology development. Cyclic steam injection was initially done through vertical wells. This had the benefit that it provided a good start-up of depletion chambers in the reservoir. These chambers then grew under gravity drainage after continuous steam injection (through the vertical wells) and continuous production through a set of horizontal wells was started. Controlled and deliberate transition from CSS to a gravity drainage process with the objective of optimizing energy intensity (GJ injected per unit volume oil produced) with control enabled through production and thermocouple data is a smart field operation which we refer to as a Reservoir Production Machine (RPM). In this paper, as a first step to understand the operation and its impact on the reservoir, we have history matched the CSS operation based on the injection and production data from field. The use of vertical steam injection wells (formerly the CSS wells) in combination with horizontal production wells operated in a SAGD mode of operation is explored. The history-matched model can be used to develop automated RPM technologies to optimize not only energy intensity but also emissions intensity.
Effects of Gravity, Foaminess and Pressure Draw Down on Primary Depletion Recovery Factor in Heavy Oil Systems
Authors: Alshmakhy A. , Maini B. 
Published: June 2012

Abstract
The unusually high primary recovery factors observed in many heavy oil reservoirs are often attributed to foamy oil flow, i.e. the non-Darcy flow involving formation and flow of gas-in-oil dispersion. It occurs when the wells are produced aggressively at high drawdown pressures that lead to conditions in which the viscous forces become strong enough to overcome the capillary forces in pushing dispersed bubbles through pore throats. The role of gravitational forces in generating such dispersed flow has not been adequately studied. This work was aimed at evaluating the contribution of gravitational forces in primary depletion of heavy oil formations under foamy flow conditions.
Primary depletion tests were conducted in a 200 cm long sand-pack that was held in either horizontal or vertical orientation. The results of horizontal depletion tests were compared with the depletion tests conducted with the sand-pack in vertical direction. Vertical depletions showed better recoveries at slower depletion rates compared to horizontal depletions.
The recovery factors of both horizontal and vertical depletions were correlated against the average drawdown pressure available to move the oil. It was found that the recovery factor show a strong dependence on the average drawdown pressure. It was also found that the curve of recovery factor versus average drawdown pressure moves slightly towards higher recoveries in the presence of an added foaming agent which increases the oil foaminess.
Use of Acid Gas (CO2/H2S) for the Cyclic Solvent Injection (CSI) Process for Heavy Oil Reservoirs
Authors: Huerta M. , Alvarez J. M. , Jossy E. , Forshner K. 
Published: June 2012

ABSTRACT
Acid gas is a greenhouse gas (GHG) composed of (CO2/H2S). It is produced during oil, gas, and petrochemical operations. During the last several years, there has been an increasing pressure within the oil industry in Canada to further reduce GHG emissions. Another environmental problem within the oil industry comes from the elemental sulphur, which is converted from the H2S and is accumulated on the surface. Currently, there exist two technological solutions to deal with this challenge. The first one is acid gas injection into geological formations for sequestration purposes. This option has been developed in Canada over the last 22 years. The second one is the use of it for EOR operations in conventional oil reservoirs. This option has successfully been applied in Zama, a Canadian conventional oil reservoir.
There is an interest within the oil industry again to evaluate the performance of CO2/H2S to also recover heavy oil during the Cyclic Solvent Injection (CSI) process. The CSI process has already shown success in improving heavy oil recovery after primary cold production (CHOPS) using pure solvents or (CO2 /propane or CH4/propane) mixtures. Consequently, if feasible, CO2/H2S injection for CSI could also contribute to increase the heavy oil recovery factor while eliminating the accumulation of sulphur on the surface and sequestering this greenhouse gas. The results of this work indeed demonstrated that the CO2/H2S mixture tested performs better for the CSI process than some of the conventional solvents previously tested i.e. pure CO2 or methane/propane mixture. Not only the recovery factor was better but also the oil recovery declined less with subsequent cycles by using CO2/H2S mixture rather than using pure CO2. It is important to mention though that the mixture of CO2/propane still shows the best performance in the series of solvents studied so far for the Cyclic Solvent Injection at Alberta Innovates Technology Futures.
Hydroxide Alkalinity Management Using Recycled Boiler Blow Down or Caustic in SAGD
Authors: Weagle Glenn , Maltman Ron 
Published: June 2012

Abstract
Many SAGD facilities will boost the Boiler Feed Water (BFW) alkalinity with caustic to maintain the necessary alkalinity for corrosion protection in Once Through Steam Generators (OTSGs) and to promote rapid oxygen scavenging reactions in the boiler feed water circuit. However, some facilities can facilitate hydroxide addition with recycled boiler blow down into the BFW, thus reducing the necessity of supplemental caustic addition. This operational strategy and the issues will be discussed. This presentation outlines a case study where the management of the recycled boiler blow down resulted in reduction of caustic application, leading to operating chemical cost reductions.
A Geomechanical Methodology for Determining Maximum Operating Pressure in SAGD Reservoirs
Authors: Walters Dale , Wang Jin , Settari A. 
Published: June 2012

Abstract
The thermal recovery of bitumen reservoirs by steam assisted gravity drainage (SAGD) is often designed to maximize the operating pressure while maintaining a safe and economic operation. In general, higher operating pressure can reduce thermal efficiency due to heat losses to over/underburden formation, but the other benefits usually compensate. To name a few, higher steam temperatures can maximize the reduction of oil viscosity, enhance permeability associated with lower effective stress and shear dilation, and give a larger pressure window to allow flexible control of the producer. This is especially important for shallow reservoirs where the pressure window for injection and production is smaller. The limitation of the maximum operating pressure is then based on maintaining caprock integrity. Thus, shear and tensile failure mechanisms should be quantified and managed.
This paper presents a methodology to perform a geomechanical analysis of caprock integrity for SAGD operation and illustrates the available approaches. Both analytical and numerical approaches are compared demonstrating their usefulness. Main factors in the analysis are the knowledge of the initial stress state and proper representation of the complexity of the geomaterials. A typical initial stress state for a northern Alberta SAGD property, Suncor's MacKay River project, is presented showing the potential for low initial minimum total stress and elevated initial shear stress levels. The stress-strain behavior for the MacKay River sand and caprock materials is discussed focusing on the potential for shear dilation in the sand and shear strength behavior in the caprock. An elasto-plastic constitutive model is used to represent the sand and caprock materials. The increase in pressure and temperature alter the stress state and disturb the soil matrix. This disturbance results in shear dilation of the sand matrix creating regions of enhanced permeability and porosity. Also, the transfer of stress and strain to the caprock causes dynamic stress changes and, therefore, dynamic behavior of shear and tensile failure conditions. Calculations are presented showing the stress paths associated with SAGD operations, suggesting better design of lab testing programs and the implications for shear dilation in the sand and shear failure in the caprock. Finally, the results are used to demonstrate locations that are most likely at risk for potential tensile and shear failure. Stress ratios are used to summarize the analysis and quantify and monitor the failure mechanisms.
The above methodology has been developed and applied in several studies of other SAGD projects and aided the operators in the optimization and permitting the operating conditions.
Impact of Adsorption on Mass Transfer in Fractured Reservoirs
Authors: Sharifi Haddad A. , Hassanzadeh H. , Abedi J. , Chen Z. 
Published: June 2012

Abstract
The analysis of fluid transport in fractured reservoirs is of great concern in petroleum and environmental engineering. The objective of this work is to study mass transfer between the matrix and the fracture network in such complex formations. In this study, the impact of adsorption on mass transfer in a fractured medium with variable fracture spacing is investigated. Development of a mathematical model for mass transfer in dual porosity systems enhances predictions of the rate of mass transfer between matrix and fracture. In addition, it provides a tool for an appropriate design of advanced oil and gas recovery processes. Mass transfer is modeled based on the advective-dispersive transport with adsorption in an infinite acting dual porosity reservoir under radially divergent and continuous injection. The fracture spacing has been taken into account by including the variable rock matrix block size distribution in the developed model.
By employing this model, the effects of the adsorption rate on the mass transport in a subsurface environment are analyzed. The impact of the rate of adsorption on the accumulation of the injected tracer (catalyst) in a reservoir is investigated. An understanding of the effect of adsorption on advective-dispersive mass transport with variable fracture intensity can be a key finding to develop and design advanced oil recovery processes.
An Extensive Review on the Effective Sequence of Heavy Oil Recovery
Authors: Mohammadpoor M. , Torabi F. 
Published: June 2012

Abstract
Different enhanced oil recovery (EOR) techniques for heavy oil reservoirs were reviewed for their ranges of applicability using available reports and publications. EOR screening criteria found in the literature are reprinted and provided. After reviewing more than 100 papers on the subject, it is apparent that there is a definitive knowledge gap on the effective sequence of EOR recovery strategies. While there are numerous studies on the application of heavy oil recovery techniques, there is a lack of comparison and categorization of the results.
For Canadian reservoirs, the first recovery method that is implemented first is either waterflooding, cold production or in some cases steamflooding. Chemical flooding and other emerging technologies are mostly coupled with these methods. In most reports, conversion of producers to injectors and introducing line drive and edge drive will improve the waterflooding performance. However, coupling waterflooding with horizontal wells, the addition of water mobility control agents and steam stimulation did not improve the waterflooding performance in some cases. In the case of fractured limestone reservoirs, it seems that immiscible gas injection is a suitable EOR method to implement, but because of the reservoir complexity, a clear understanding of the recovery mechanism and reservoir geology is needed. In-situ combustion and steamflooding are among the most efficient heavy oil recovery methods with a large range of applicability, and next to waterflooding, can become the most widely used heavy oil recovery method. Fireflooding methods can be more profitable if they are coupled with simultaneous or intermittent water injection with air.
The results obtained from this paper not only will help the petroleum industry to apply each technique to the right candidate fields, but also it will prevent researchers from duplicating unsuccessful research projects.
New Upstream and Downstream Technologies for Extra Heavy Oils
Authors: Zolotukhin Anatoly , Bokserman Arkady , Kokorev Valery , Nevedeev Andrey , Ushakova Alexandra , Shchekoldin Konstantin 
Published: June 2012

Abstract
Heavy oil and bitumen are found in many places worldwide, with the largest deposits in the world being in Canada (Alberta), Venezuela and the former Soviet Union.
Among huge conventional and unconventional oil resources so-called Bazhenov series represent one of the highest hydrocarbons potential in Russia. Its resources of light oil considerably exceed conventional oil resources, and extra heavy oil resources are estimated to be hundreds of billion tons (some estimates go beyond 2 trillion tons). Despite huge geological HC resources allocated in BS technology for their effective development is still a challenge.
Thermogas is one of the promising EOR technologies that are under development in Russia. First theoretical as well as experimental and pilot results indicate that this technology could be successfully deployed for the development of hydrocarbons located in Bazhenov series.
It is anticipated that the use of Thermogas technology for extraction of hydrocarbons from BS, based on successful application of similar technology for enhanced recovery of light oils from fractured dolomite formations in USA, can result in recovery of at least 35–40% of their resources. This could open up huge yet poorly estimated world unconventional oil resources that enable sustainable production of hydrocarbons at a global scale for many decades.
Technology of "cold" mechanical oil processing is another "attraction point" of intensive research in Russia. This new approach is based on extremely localized "injection" of required amount of energy in order to break intermolecular and intramolecular chemical bonds in hydrocarbon compounds and molecular conglomerates. Technological effect is gained by means of initiation of the cavitation processes in the treated medium.
Heavy organic molecules (asphaltenes, long paraffin and other complexes) and their conglomerates present in crude oil and subjected to this technology undergo breakdown of chemical bonds and, as a result, drastic changes in crude oil properties like viscosity and, to a lesser extent, density.
Although technology is at its initial, i.e. "nucleus" development phase, its applications are perceptible in many potential areas of application, from up- to mid- and to downstream petroleum sectors.
Recent developments in Thermogas EOR as well as in cold mechanical oil processing are described in this paper.
Laboratory Evaluation of Thermoreversible Gel for In-Depth Conformance Control in Steam-Stimulated Wells
Authors: He Hong , Wang Yefei , Zhao Mengyun , Cheng Limin , Liu Peng 
Published: June 2012

Abstract
Cyclic steam stimulation(CSS) is one of the most common methods used to improve oil recovery in heavy oil reservoirs. However, due to reservoir heterogeneity, unfavorable mobility ratio and gravity segregation, steam channeling through high permeability zones occurs, resulting in poor sweep efficiency and a reduction in ultimate oil recovery. To settle the steam channeling problem, this paper presents the laboratory evaluation of a thermoreversible gel formed from hydroxypropyl methylcellulose (HPMC) for in-depth conformance control in steam-stimulated well. The effects of concentration of HPMC, sodium chloride and urea on the gelation temperature, gel strength and degree of syneresis observed in gel samples were studied. The long-term thermal stability of the thermoreversible gel was evaluated. Sandpack flow experiments were conducted to evaluate the reversibility of plugging and selective plugging ability.
The experimental results showed that as the concentration of HPMC increased, the gelation temperature, degree of syneresis decreased and gel strength increased. Based on proper gelation temperature, good gel strength, degree of syneresis and economical cost, the proper concentration of HPMC should range from 2.0wt% to 2.5wt%. The gelation temperature and gel strength increased with increasing sodium chloride concentration. While as urea concentration increased, the gelation temperature increased and gel strength decreased. After aging for 60days at 110°C, about 3.5% syneresis was observed in gel samples, which indicated that the gel had good long-term thermal stability. The singular and parallel sandpack flow results showed that the thermoreversible gel had good reversibility of plugging and selective plugging ability.
Therefore, these results indicate that the thermoreverible gel studied here are good candidates for in-depth conformance control in steam-stimulated wells, which can provide a basis for field application.
Full Field Applicability of MWAGD Process Coupled With Horizontal Well Pair Model to Recover Extra Heavy Oil and Bitumen
Authors: Bansal Gopal , Jha Ashutosh Kumar , Chauhan Nitesh , Sharma Tushar 
Published: June 2012

Abstract
Applicability, assessment and work-how of Micro-Wave Assisted Gravity Drainage (MWAGD) process in Mehsana (India) heavy oil field along with added advantages over SAGD were presented in the previous part of this paper [1]. Various studies have been done during last 10 years illustrating wider applications of micro-wave heating of heavy oil reservoirs through quantitative and qualitative exercises. But the main problem that arises in micro-wave heating is very low penetration depth of micro-wave radiations which limits the application of this unconventional thermal EOR method on full field scale.
The scope of this paper is to eliminate this problem by using horizontal well pair combination which enhances the drainage area within the heating radius of micro-wave radiations.The phenomenon of conversion of Micro-wave energy to heat energy is described and finally, a mathematical model based on energy balance principle is developed.
Two parallel and vertically aligned horizontal wells are drilled. The upper well is production well and lower well is micro-wave source well with their length and vertical separation on the order of 500 meters and 15 meters respectively. In the lower well micro-wave sources are installed at various positions along the length with longitudinal spacing on the order of 20 meters. Advantages of heating of oil from the lower well are explained in lucid manner. This type of installation model confirms the coverage of larger reservoir volume in spite of short penetration depth of micro-wave radiations. Along with volumetric and selective heating in this process heat is developed within the formation fluid rather than being brought to it from the outside, and hence the fluid is heated more uniformly throughout the medium. Also, above proposed model can be applied effectively in case of carbonate formations where uneven sweeping occurs along steam assisted gravity drainage (SAGD) well pairs due to vuggs and fractures.