bluuebunny/crossref_metadata_2025 huggingface dataset:
Investigating the Viability of Steam Flooding to Improve Oil Recovery in A Heterogeneous Light Oil Reservoir with Infinite Active Aquifer: A Comparative Simulation Case Study
Authors: Al-Mudhafer Wathiq
Published: June 2013

Thermal oil recovery m ethods could be an effective s olution to many crucial problems not only in hea vy/light oil reservoirs, but also in light oil reservoir. Steam flooding has proved it’s efficiency to change the reservoir and fluid properties in light oil reservoirs leading to higher oil displacement and sweep efficiency. The reservoir under study is the main pay/upper sandstone member in South Rumaila oil field located in Iraq. It is a mature oil field with around 58 years of production with 40 producing wells. The reservoir has an infinite acting aquifer located at the east and west flanks. The strength of this aquifer from the west flank is much larger than it’s in the east flank because the formation permeability at the eastern flank is less th an as at th e western one; therefore, 20 injection wells have been drilled at the east flank to maintain the aquifer water approaching to the reservoir. The formation depth is 10350 ft. sub-sea with a maximum vertical oil column of 350 ft. The average bubble point pressure of 2660 psi and the ave rage reservoir temperature is 210°F while oil density is 34°API. In this study, A comparative simulation study (Black oil and thermodynamic) has been done to investigate steam flooding feasibility improve oil recovery in comparison to two base cases of with and without water injection.

Two reservoir simulators, black oil (CMG-IMEX) & thermodynamic (CMG-STARS) have been applied to demonstrate the impact of steam flooding as heating agent to enhance the sweep efficiency through this heterogeneous reservoir. The steam injection has been done considering the current twenty injection wells with 10,000 stb/day per well. The results showed the co-impact of steam injection with simultaneously enhanced water drive from the aquifer to sweep the oil towards the reservoir crest. The cumulative oil production for steam flooding scenario has been compared with the outcome of the two base cases with and without water injection and demonstrated a significant incremental of oil recovery. The cumulative oil production for the two base cases at the final time step of 1 Feb. 2022 is equal to it's amount by steam flooding on 1 Oct. 2015.
Effect of Diluents on Interfacial Properties and SAGD Emulsion Stability: II. Differential Scanning Calorimetry and Light Scattering Methods
Authors: Balsamo Vittoria , Phan Jenny , Nguyen Duy
Published: June 2013

During the Steam Assisted Gravity Drainage (SAGD) production process, complex water-in-oil-in-water (W/O/W) emulsions are generated, which need to be treated to promote water-phase separation and recovery of the oil. Due to the similar density of heavy oil and water, dilution is frequently required to improve the separation process, but also to reduce the viscosity of the extracted bitumen to facilitate flow. Although significant research has been carried out to understand the stabilizing and destabilizing factors of both water-in-oil and oil-in-water emulsions, studies related to the characterization of complex W/O/W emulsions containing diluents are still limited. When carrying out this type of analysis, the complex relationship among different variables should be considered, such as the chemistry and concentration of stabilizing agents, water-to-oil ratio and droplet charge. Temperature and shearing methods are process conditions that must be also considered.

In this study we combined several techniques to characterize production fluids and synthetic emulsions, using diluents with different composition. Differential Scanning Calorimetry (DSC) was explored as a tool for analyzing the emulsions. Since the oil present in these fluids did not exhibit any thermal transition between -80°C and 30°C, the DSC could be used to quantify the amount of free and emulsified water in one measurement, for either synthetic or produced emulsions. Results demonstrated that this technique has a high potential to characterize emulsified systems with precision, requiring only small amounts of sample and without applying any pre-treatment. The technique can also be used to screen demulsifiers after performing a specific thermal treatment within the equipment.

Bottle tests are commonly used in the industry to monitor emulsion behavior. They are easy to perform, but are subject to the judgment of the experimenter, who measures the partitioning of the phases and in some cases their relative opacity. To perform a more quantitative analysis, demulsification was monitored in real-time, using a multiple light scattering device. Phase separation rates were highly influenced by the nature and amount of diluent used and they were correlated with droplet size, interfacial tension and surface pressure measurements. Results were rationalized based on the differences in the asphaltene-resins interfacial film, which will determine the emulsion behavior upon separation in the field when using demulsifiers.
SAGD Well Pair Spacing Evaluation with Consideration of Central Processing Facility Constraints
Authors: Cheung Kathy (Lai
Published: June 2013

When developing properties using the steam assisted gravity drainage (SAGD) process, the lateral spacing between horizontal well pair spacing is extensively evaluated during well pad design to optimize resource recovery and economics. However, constraints associated with central processing facilities (CPF) are often not incorporated into the evaluation. With constrained steam supply and fluid processing capacity, the accelerated production that should accompany a reduced well pair spacing scenario may not be realized. In this paper, the economics of developing a SAGD property using 50m, 85m, 100m and 125m well pair spacing are compared within Suncor's MacKay River property. A production development planning tool is used to tie the individual well production profiles to a constrained CPF. While higher oil production rates, a cumulative steam-oil ratio (CSOR) reduction, and slight increase in oil recovery are observed at the well pad level in the 50m well pair spacing scenario, no accelerated oil production is achieved at the CPF level as steam supply and fluid processing capacities are constrained. With larger well pair spacing, the addition of more new pads on an accelerated schedule serves to maximize the CPF capacity utilization and oil production. Hence, the overall oil production at the CPF level is practically the same regardless of well pair spacing. With the areas evaluated in this study, the economics of the 85m, 100m and 125m cases are very close, with the optimum achieved at 100m well pair spacing. The 50m well pair spacing scenario produces the worst economic result as the tighter spacing case requires incremental capital for additional wells to achieve the same resource recovery. Without the accelerated production at the CPF level due to facility constraints or appreciable incremental oil recovery and CSOR reduction overall, there is no increased revenue to offset the increased capital outlay.
Flammability Limits of Diesel and air Mixture for use in Underbalanced Drilling
Authors: Liu Yi , Mehta S. A. , Moore R. G. , Ursenbach M. G.
Published: June 2013

In an underbalanced drilling process, using diesel as an oleic additive to drilling mud increases the chance of explosion if the drilling fluids mix with natural gas or injected air and reach the flammable limits. Although some investigations about flammability limits of drilling fluids have been conducted on the basis of diesel components, further laboratory experimental study needs to be done. Initially, the properties of the two diesel samples, including heating value, molecular weight, densities and simulated distillation characteristics are measured and compared. Then, an experimental study is conducted to investigate the flammability limits of two diesel fuel samples (diesel A and B) at varied conditions of elevated temperature and pressure using a specially designed apparatus.

Based on the experimental results, generally, diesel B exhibits wider flammability range than diesel A. However, diesel A is easier to ignite than diesel B. In addition, the effect of pressure on the flammability limit of diesel B is more profound compared to diesel A.

This research can help diesel selection for specific conditions in the field. Moreover, it is suggested that, to maintain a low probability of ignition or explosion, the minimum diesel concentration of drilling fluid is 4.29% for both diesels under certain conditions.
On Hydrogen Sulfide Evolution and Scavenging within SAGD Steam Chambers
Authors: Kapadia Punitkumar R. , Wang Jacky , Gates Ian D.
Published: June 2013

In the Steam-Assisted Gravity Drainage (SAGD) thermal recovery process, high pressure and high temperature saturated-steam is injected into a bitumen-bearing oil sands formation. For most operations, the steam temperature ranges from about 200 to 260°C and thus under these conditions, the bitumen, in the presence of high temperature steam condensate, undergoes hydrous pyrolysis, i.e. aquathermolysis, yielding acid gases such as hydrogen sulfide and carbon dioxide. Current SAGD thermal reservoir simulation models in the literature often take into account complex spatial heterogeneity of the geology and oil composition and the physics of heat transfer, multiphase flow, gas solubility effects, and viscosity variations with temperature, however, few have taken the chemistry of SAGD into account. Here, we have added aquathermolysis reactions to thermal reservoir simulation model to understand reactive zones in the SAGD process and how the process generates acid gases via aquathermolysis. Given the requirement to constrain or handle sulfur emissions from thermal recovery processes, it is necessary to understand both the physical and chemical sides of the processes. Here, we have explored the possibility of triggering the Claus process underground for in situ scavenging of hydrogen sulfide during SAGD. The application of the research results is specifically to SAGD although the results could be extended to Cyclic Steam Stimulation as well. The results demonstrate that SAGD is not only a physical process that operates largely under gravity drainage but that it is also a chemically reactive process which generates hydrogen sulfide and carbon dioxide. The results also demonstrate that hydrogen sulfide generation reactions occur where there is sufficient heat, water, and oil and thus, the reactive zones are mainly at the edges of the steam chamber and in the liquid pool that sits above the production well. Injecting very small amount of sulfur dixode along with steam could result in initiation of Claus reaction underground resulting into conversion of hydrogen sulfide into liquid sulfur. The results of this study are significant given regulated emission limits of hydrogen sulfide from SAGD operations in Alberta, Canada, and moreover, the ability to potentially reduce emissions by altering the operating strategy or through in situ hydrogen sulfide scavengers offers an elegant way to meet these regulations.
Quantitative Laboratory Assessment Of Aquathermolysis Chemistry During Steam-assisted Recovery Of Heavy Oils And Bitumen, With A Focus On Sulfur
Authors: Montgomery Wren , Sephton Mark A. , Court Richard W. , Watson Jonathan S. , Zeng Huang , Rees Andrew
Published: June 2013

The production of gaseous sulfur-containing species during the steam-assisted recovery of heavy oil and bitumen presents problems owing to their toxicity, corrosion properties and odor. In order to quantitatively study aquathermolysis sulfur chemistry during the thermal (steam-assisted) recovery of heavy oils we have subjected a well-characterized and sulfur-rich bitumen core sample to 150 - 325°C and 70 - 1740 psia (0.48 - 12 MPa) conditions in the continued presence of liquid water for 24 hours. The reaction products include gases, oil flotate, oil sinkate, water-soluble products, and water- insoluble residues. All have been studied with a variety of analytical techniques, including FTIR spectroscopy, chromatographic fractionation (SARA analysis), GC-FPD and GC-MS. Moreover, these techniques have been extended to analysis of the asphaltene fractions. Results suggest that some in-situ upgrading of the oil occurs under these conditions; additionally, gaseous hydrogen sulfide is released at temperatures at and above 250 °C. Variations in the relative abundances of solubility classes and chemical fractions imply that the source of sulfur is via the thermal degradation of resins and/or asphaltenes. The experimental methods, results and quantification approach discussed herein will be useful to support the development of models for engineering design of facilities for the steam-assisted recovery of heavy oils and bitumen.
Effect of Diluents on Interfacial Properties and SAGD Emulsion Stability: I. Interfacial Rheology
Authors: Nguyen Duy , Phan Jenny , Balsamo Vittoria
Published: June 2013

In SAGD (Steam Assisted Gravity Drainage) operations the produced fluids are a complex water-in-oil-in-water (W/O/W) emulsion. A diluent, which is a major operational cost item, is often added to the produced fluid to reduce the density and viscosity of the heavy crude, thereby facilitating oil and water separation. The variable quality of the diluent and various types of diluent can increase the emulsion stability and cause the dehydration of the oil to be more difficult as there are more surface-active agents added to the oil from the diluent stream. In this work, the effect of various diluents on interfacial films was studied by measuring interfacial elasticity and "dynamic" surface pressure isotherms and then correlated with emulsion stability and oil dehydration. Compressibility, crumpling film ratio (ratio of the compressed surface area to the original area at which the interface starts to collapse), and surface pressure were determined from the surface pressure isotherms.

When interfacial rheological measurements were conducted on fluids treated with the diluent, the system behaved as if a bidimensional gel near its gelation point had organized at the interface. In other words, adsorbed amphiphilic materials such as asphaltenes and resins had self-aggregated at the interface and formed a network, which presents all the rheological characteristics of a gel, acting as a stabilizing mechanism for produced emulsions. When the interface was aged for 20 hrs, its gel strength was nearly 70% higher than the fresh interface, suggesting an explanation why aged emulsions are more difficult to treat. As the surface area of an oil droplet submersed in water is reduced, asphaltene molecules adsorbed onto the interface are drawn closer together and resist compression. This gives information about how rigid the drop surface becomes. The software of interfacial rheological measurements can be set up to capture drop images during compression measurements, allowing us to observe the formation of rigid interfacial skins at the oil-water interface. The amount of skin formed at a droplet surface increased with increasing asphaltene concentration and varied in different diluents. Unlike elasticity and interfacial tension measurements, this method can predict emulsion stability in different diluents and at various asphaltene concentrations. A correlation exists between the interfacial compressibility, crumpling film ratio, and emulsion stability: the higher the crumpling film ratio and the lower the compressibility, the more stable the emulsion. This new test method gives more insights into mechanisms of emulsion stabilization caused by the diluent and asphaltene and potentially can be employed to study the structure and demulsifying performance relationships of EBs (emulsion breakers) and REBs (reverse emulsion breakers).
Waterflooding: Same Old, Same Old?
Authors: Alvarez J. M. , Sawatzky R. P.
Published: June 2013

Since the accidental discovery in the late 1800s of the benefits of injecting water into oil reservoirs to improve recovery, water has been the injection fluid preferred by the oil industry for use in recovery processes. Traditionally, waterflooding is considered an effective secondary recovery method for light and medium oil reservoirs. However, as production rates in these conventional reservoirs continue their decline, waterflooding is being considered, and used, more and more for the exploitation of more challenging heavy oil resources. Despite the unfavorable mobility ratio between injected water and more viscous heavy oils, many waterflood projects have been undertaken in heavy oil reservoirs around the world. However, the literature on heavy oil waterflooding is sparse. Those papers that have been published present a wide range of recovery factors for projects, and offer conflicting information on the theory and mechanisms involved in heavy oil waterfloods. The good news is that there is a long history in western Canada with waterfloods in heavy oil reservoirs, spanning more than 50 years. A vast amount of data and anecdotal information has been generated from these waterfloods. This could provide a key to raising the limits, in terms of reservoir conditions, under which waterflooding would be viable.

In this paper we will discuss lessons learned after 50 years of waterflooding in heavy oil reservoirs, identify gaps in the application of the process, and speculate about what the future may hold as this technology evolves.
Case Study: Thermal Enhance Bohai Offshore Heavy Oil Recovery by Co-stimulation of Steam and Gases
Authors: Sun Yongtao , Zhao Lichang , Lin Tao , Liu Haitao , Sun Yubao , Zhong Liguo , Dong Zhaoxia , Hou Jirui , Li Yiqiang
Published: June 2013

Although there is abundant heavy oil resource in Bohai oilfield, only limited oil production is obtained by non-thermal production technologies such as ESP in past. The practical challenging of thermal production technologies, for instance, CCS and SAGD is the difficulty to install the large conventional steam generator onto offshore production platform.

In order to recover offshore heavy oil in Bohai Oilfield, the largest offshore oilfield in China, at large oil production rate in the limited production platform lifetime, a portable steam and gas generator is developed to produce high temperature and high pressure steam, CO2 and N2 on production platform using diesel oil or natural gas as fuel. The temperature of produced steam could be regulated, usually 150 to 300, and the pressure is up to 20MPa. The components such as fuel tank, water treatment, air injection unit could be easily resembled on the production platform. The steam generated and exhausted CO2and N2 could be injected into oil well to stimulate offshore heavy oil reservoir in huff and puff or SAGP processes.

In past three years, there are 2 non-thermally completed heavy oil wells and 7 thermally completed heavy oil wells are successfully stimulated by co-stimulation with steam and flue gas generated by above generator. As a result, the gas generator is operated soundly, the engineering design and related implement techniques such as insulation, sand control and corrosion inhibition are feasible, and oil production rate increased obviously (more than 100 m3/day oil production rate obtained, it is up to 5 times than cold production), total increased heavy oil production compared to cold production per cycle is about 5000m3 to 10000m3. Primarily, it shows that co-stimulation is much effective and practical for offshore heavy oil production.

In this paper, cases of co-stimulation with steam and flue gas are introduced in detail, and related techniques and practices discussed as well.
Observations on the Mechanisms of Solvent-Additive SAGD Processes
Authors: Edmunds Neil R.
Published: June 2013

Solvent-additive processes (SAP) are a promising, but challenging technology. Perhaps the biggest challenge from an engineering point of view, is that simulators probably work some of the time, but not all of the time; and there is no information about where the line between occurs, or what the correct answer should be, after the line is crossed. Other serious problems are the many degrees of freedom in SAP process design, and the non-linear relationships between process inputs and economic results. There are too many possible designs to try randomly for even a single reservoir, and there is limited theory to interpolate or scale available experimental data.

This paper attempts to assemble some known pieces of the puzzle, and to explore how they may fit together to explain and predict SAP performance characteristics

First, some familiar PVT relationships are presented, with examples using temperature as the independent variable. This helps to clarify the choice of solvent, as a function of reservoir pressure, and also to understand the effect of the increasing solvent "dose". It is shown that SAP will create a double front, one where the water is condensed, and a second where the solvent is absorbed by, and drains with, the oil. A vapor blanket separates the two fronts.

Secondly, simple estimates are given for the temperature distribution in the vapor blanket (i.e. solvent-active zone). Together with PVT data for the same pressure, these allow the thickness of a vapor blanket to be estimated.

Finally, SAP mass transport limits are considered, by observing that the second front essentially constitutes VAPEX. The Butler-Mokrys theory is discussed, in view of its failure to predict certain experimental results; it is argued that this results from neglect of capillary pressure effects, which in fact are dominant at the front. A purely empirical correlation by Nenniger is introduced, which can be rearranged to predict the maximum solvent speed, also as a function of temperature.
Incorporating 4D Seismic Steam Chamber Location Information into Assisted History Matching for A SAGD Simulation
Authors: Hiebert A. D. , Kumar A. , Card C. , Close J. C. , Ha H. , Morrish I. C. , Sun F. , Porter S.
Published: June 2013

Modern assisted history matching tools allow an engineer to specify the uncertain parameters in a simulation dataset then perform an optimization to minimize the difference between observed field data and the corresponding simulation outputs. During this optimization, multiple simulations are run, with the uncertain parameters varying within the ranges specified by the engineer. The difference between the observed field data and the simulation output is measured by an objective function. Standard objective functions have been reported in the literature for the difference between observed and simulated production and injection rates, and for measurements in time and space done at observation wells. In this work we incorporate an additional objective function term that measures the difference between the observed and simulated steam chamber location and shape. In addition, the differences in 3D volumes were visualized, which lead to a better physical understanding of what parameters should be adjusted during a history match.

For a steam injection process like Steam Assisted Gravity Drainage (SAGD), 4D seismic may be used to determine where a steam chamber is located in a reservoir at a point in time. The objective function developed in this work measures the difference between an observed chamber's shape and location in the reservoir and the corresponding shape and location for the chamber indicated in the simulation output. The objective function is a binary mismatch function, checking each simulation grid block to see if the seismic chamber and the simulation chamber agree or disagree, and calculating the ratio of the total volume of disagreements over the total volume of agreements.

This steam chamber mismatch function was included in an assisted history match performed on a well pair from Suncor Energy's SAGD project at Firebag. The inclusion of this additional information added additional constraints to the simulation model, leading to a conceptually more dependable history match and a better geological and dynamic characterization of the reservoir.
Coupled Geomechanical and Thermal Simulation of SAGD Process
Authors: Bao X. , Chen Z. , Dong C. , Deng H. , Liu H. , Zhong H.
Published: June 2013

SAGD (steam assisted gravity drainage) is a coupled geomechanical problem because continuous steam injection changes reservoir pore pressure and temperature, which can alter the effective stress in-situ, resulting in the dynamic changing of porosity and permeability. A conventional modeling approach remains difficult in capturing the Flow-Stress interactions, as well as in modeling surface deformation during injection and production. Therefore, to optimize SAGD operating strategy and minimize the environmental risk, a coupled geomechanical simulation that solves the flow and stress equations simultaneously is the solution. In addition, thief zone SAGD performance is very sensitive to the high injection pressure, which may cause the great heat loss due to steam breakthrough into thief zones.

Flow-stress coupling (STARS+Geomechanics) using a modular coupled approach is investigated in this paper. The iterative coupling between the thermal simulator and stress model has the advantage of flexibility and computational efficiency, where pressure and temperature changes occurring in the reservoir simulator are passed to the geomechanical simulator to compute the changing of stress and strain, and update porosity and permeability simultaneously. A generalized hyperbolic constitutive model for oil sands that approximates the dominant mechanism is implemented; the failure envelope is defined by a Mohr-Coulomb relation controlled by the friction angle. Coupled geomechanical simulation results demonstrate the permeability enahncement and surface heave, caused by dilation and thermal expansion, associated with the steam injection.

A control volume and K-value based multiphase multicomponent thermal simulator (FATS) is utilized aiming to investigate the detrimental effect of thief zones (top water and top gas). Results have been validated by STARS, demonstrating that the steam chamber has been shifted into thief zones after steam breakthrough under high injection pressure.
Synergistic Interactions Between Different Components on Blending
Authors: Kailey Ishpinder , Behles Jacqueline , Blackwell Catherine
Published: June 2013

Chemical demulsification is the most widely used method for breaking water-in-diluted bitumen emulsions in oil sands processing. In this paper, the properties and the performance of six intermediates and three blends were investigated. The intermediates and blends were characterized by their relative solubility number (RSN). The results showed that the RSN is an additive property. The dehydration efficiency of the blends was higher than the individual components at the same dosage, indicating there were synergistic interactions among the components on blending. The performance of the demulsifiers was correlated to the interfacial tension (IFT), yield stress of underflow, and bitumen loss to tailings. The equilibrium IFT results did not illustrate any correlation with the performance of the demulsifiers. The yield stress of the underflow, which included settled solids, water, and a rag layer increased with increasing dosage of either intermediate or blend. In addition, the bitumen loss to underflow increased with increasing dosage of either intermediate or blend. The yield stress and bitumen loss to underflow reduced on blending the intermediates. The bitumen loss to underflow increased the size of the aggregates present in the underflow, increasing their immobility and constriction to flow, and eventually a higher yield stress.
Challenges of Multiphase Flow Metering in Heavy Oil Applications
Authors: Viana Flavia , Mehdizadeh Parviz , Owston Rebecca A. , Supak Kevin R.
Published: June 2013

Multiphase flow metering has become very important to the development of marginal oil and gas fields, since the economics of producing these fields do not justify the construction of new platforms; instead, they are tied back to existing infrastructure. In such cases, several fields are tied back to common facilities requiring each unprocessed stream to be measured prior to comingling. Multiphase flow metering is also a promising alternative to traditional test separators in those cases where having a large vessel is not feasible, and in the production of heavy oils where separation represents a big challenge.

The increasing need for energy, combined with depleting worldwide light oil resources, has generated substantial interest in heavy oil reserves. Heavy oil applications involve low API gravity oils which are also very viscous. The production, transport, metering, and processing of heavy oils present a number of challenges associated with the increased resistance to flowing given the high-viscosity characteristics of heavy oils and the tendency to form emulsions. The hydrodynamics of high-viscosity oils presents various challenges in multiphase flow metering, including dependence of the discharge coefficient on the viscosity of the oil at low Reynolds numbers on Venturi-type meters used in commercially-available multiphase flow meters (MPFMs). Other issues are also related to the tendency of heavy oils of forming emulsion and the effect of complex fluids on the performance of the meters.

This paper presents a review on heavy oil, multiphase flow metering, and the challenges faced by multiphase flow meters in heavy oil applications. The purpose of this review paper is to provide relevant information that can be used in the selection of multiphase flow meters for heavy oil applications. While other studies on the subject have focused on one specific problem or flow metering technology, this paper provides a general overview of the various issues across existing flow metering technologies. Special focus is given to in-line multiphase flow meters, since they provide some advantages over other types of MPFMs in heavy oil applications. In-line MPFMs have the ability to measure the oil, water, and gas flow rates directly in the multiphase flow stream without separation of the phases. The inherent characteristics and physical properties of heavy oils impose additional constraints to MPFMs, as well as the enhanced recovery methods employed for the production of heavy oils. The main issue is associated with the tendency of heavy oil to form complex mixtures (emulsions, foam, etc.) as they can lead to inaccurate measurement of phase fraction and flow rates. The additional water or steam added to the reservoir to increase recovery rates can result in flow instabilities, high water cuts, and changes on the continuous phase. Thermal production methods can also cause inaccurate readings and compromise the integrity of the meters.
Polymer/Gel Enhanced Foam Flood for Improving Post-Waterflood Heavy Oil Recovery
Authors: Zhou Wei , Dong Mingzhe , Wang Xiaoqi
Published: June 2013

Due to its low cost, excellent injected performance and good blocking capacity for high permeability zones, polymer/gel enhanced foam flood has been proven as an efficient method to improve oil recovery. This paper presents an optimization study of the slug size of polymer enhanced foam (preformed foam) and a study of gel-enhanced foam on oil recovery and high permeability zone blocking for a Saskatchewan heavy oil. A series of sandpack tests with different slug sizes are conducted to investigate the oil recovery performance of polymer enhanced foam flood. The experimental results indicate that, by considering the foam flood efficiency, the optimal slug size of polymer enhanced foam flood is 1.5 PV in this study. For gel enhanced foam flood, the single-sandpack tests suggest that the gel enhanced foam flood and extended waterflood can still significantly improve the oil recovery (up to 24.1%) after polymer enhanced foam flood; the parallel-sandpack test indicates that gel-foam can efficiently promote the oil recovery in the lower permeability layer by modifying the injection profile. In summary, gel enhanced foam can be used as the fourth recovery method for heavy oil reservoirs after initial waterflood and polymer enhanced foam flood.
An Integrated Practical Approach to Forecasting Multi-well SAGD Production using Analog, Analytical, and Numerical Modeling Techniques
Authors: Adesimi Yomi , Wang Jin
Published: June 2013

There are many challenges in making rigorous economic decisions for capital intensive SAGD projects. Among those challenges is the need for reliable production forecasts. The traditional forecasting techniques of analogy, numerical simulation, and analytical methods are each burdened with their own drawbacks. The resulting production forecasts can vary to such a degree that the validity of the results obtained from each approach is questionable. When used in isolation, the individual forecasting techniques yield a significantly different result from each other, making economic decisions an imposing task.

This paper presents an integrated ternary approach which draws on the strengths of each methodology. A database of 70 SAGD well pairs from Suncor's MacKay River property is used to obtain analogs. It captures the variations in reservoir quality, reservoir thickness, and well design. In addition, an internally developed Monte-Carlo analytical tool, based on fundamental physics (i.e. material/energy balance, gravity drainage theory), is used to generate a probabilistic range of oil and SOR forecasts. This tool utilizes statistical distributions of static and time- dependent variables. Finally, numerical simulation models are also generated in conjunction with Suncor's geostatistical modeling process. The simulation input parameters are obtained through validation of multi-well simulation models against a long period of historical field data in MacKay River project area. The integration of these methodologies is presented in detail in this paper.

This integrated approach provides a basis for comparing relevant SAGD performance indicators, such as oil rate and SOR. The results generated from the integrated approach have served to increase confidence in the robustness of the associated business decisions.
Got Steam? Understanding ESP Steam Handling Capabilities in the Centrifugal Pump
Authors: Noonan S. G. , Baugh A. , Klaczek W. , Wonitoy K. , Wilson L.
Published: June 2013

The successful development and implementation of high temperature Electric Submersible Pump (ESP) technology for Steam Assisted Gravity Drainage (SAGD) applications has allowed operators to reduce their flowing bottom-hole pressures and achieve higher production rates. However, operating under these conditions brings the Pump Intake Pressure (PIP) closer to the saturation pressure of steam, which can result in live-steam production through the pump. The effect that live-steam has on pump performance is not particularly well understood, and has been a key challenge for operators when designing and optimizing ESP systems for SAGD applications.

In early 2011, ConocoPhillips, Baker Hughes and C-FER Technologies embarked on an experimental test program to determine the consequences of producing live-steam through a centrifugal pump. This new program was meant to build on multi-phase work that had begun over a decade ago at the University of Tulsa (TU), where researchers had focused on experimentally measuring the two-phase flow performance of ESP stages with air and at moderate temperatures [Pessoa and Prado 2001]. The TU work ultimately resulted in a wave of new technology aimed at increasing ESP gas handling capabilities. Following a similar testing and ESP instrumentation philosophy, this new collaboration looked to build upon the TU experiments and expand the test fluids to include live-steam, water, and air at higher temperatures.

This ultimately involved the design and construction of a unique high temperature Steam Flow Loop that allows for live-steam injection into a centrifugal pump, while monitoring both head and performance degradation. This paper will reveal some of the unique test results collected with the first pumping system, including snapshots of the stage-by-stage pressure contributions captured in real-time as air or air and steam migrates through the ESP being tested. These results also demonstrate the impact the presence of other gases can have on steam flashing and how it is important to consider both the gas and steam vapor effects in SAGD ESP designs.
Vertical Single-Well SAGD with Multiple Producers
Authors: Hocking G. , Walters D. A.
Published: June 2013

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

ExxonMobil and Imperial Oil Resources (Imperial) are conducting a Solvent Assisted - Steam Assisted Gravity Drainage (SA-SAGD) experimental pilot at Cold Lake in the Clearwater formation where up to 20% by volume of hydrocarbon solvent (diluent) has been injected along with dry steam in a dual horizontal well SAGD configuration.

Experimental work performed by the Alberta Research Council (ARC) (Nasr, 2003) and Imperial indicated that addition of solvent to steam increases bitumen rates and decreases steam-oil ratios relative to the conventional SAGD process. The main objective of this pilot has been to produce high quality field data to definitively support these experimental conclusions.

The pilot scope includes two horizontal well pairs (four wells), six observation wells, associated steam and diluent injection facilities, artificial lift, as well as, dedicated production measurement and testing facilities. The SA-SAGD pilot uses existing steam generation, water treatment, bitumen separation and processing facilities at Imperial's Mahkeses plant and existing steam distribution and production gathering systems.

The main focus of this paper is to document the integrated approach taken to ensure that this multi-year pilot is successful and to provide information resulting from this multi-year pilot. Key surveillance products, such as, production/injection measurements, horizontal-well temperature logs, observation-well temperature and saturation logs, time-lapse 3D seismic, and the impact of a mid-pilot solvent switch will be discussed. In addition, this paper will review how these surveillance products are integrated with laboratory data and simulation efforts to improve our understanding of this process and increase confidence in go-forward predictions.

Given the emerging importance of solvent-assisted thermal heavy-oil processes and the accelerated conversion of this technology from laboratory-scale to field-scale, data from a field pilot provides invaluable information in the quest to deploy this emerging in-situ recovery technology.
Fire-flooding Technologies in Post-Steam-Injected Heavy Oil Reservior:A Successful Example of CNPC
Authors: Wenlong Guan , Changfeng Xi , jihong Huang , Junshi Tang
Published: June 2013

Steam injection is an effective technology for heavy oil development. With the increasing of the recovery percent, the technical effectiveness and economic efficiency of continuous steam injection will substantially decline. Therefore the fire- flooding can be considered as a follow up EOR technology in these steam-injected reservoir. Because of the complicated secondary water and steam channels distribution, fire flooding in post steam injected reservoir is far different from that in original reservoir. In this paper, the mechanism and problems associated with development engineering of fire flooding in post steam injected heavy oil reservoir was studied systematically by using 1D&3D physical simulation systems and reservoir numerical simulator. The temperature of combustion zone decreased and high temperature zone enlarged because there existed secondary water formed during steam injection which could absorb and carry heat towards producers out of combustion front during fire flooding, but high saturation of water in layer caused by secondary water had less influence on the quantity of fuel deposit and air consumption.

There is a living example of fire-flooding in post-steam-injected heavy oil reservoir in Xinjiang oil field of CNPC, and it is the first major pilot of fire-flooding in this kind of reservoir, namely H1 Block Fire-flooding Pilot. H1 Block had been steam- injected for more than 10 years and oil recovery factor had nearly reached 30%. Before fire-flooding test, the reservoir had been abandoned for many years. In this paper, the fire-flooding model, well pattern, well spacing, and air injection rate was optimized based on the reservoir property and the existed well pattern in H1 Block, and the key techniques of ignition, lifting, and anticorrosion was also selected in the same time. The H1 Block Fire-flooding Pilot was carried out in the late of 2009. Up to now, more than 30 wells produced oil, 16 of them produced stably. The daily oil production increased from nearly 0 to 48t/d, water cup decreased from nearly 100% to 60%, and AOR decreased from more than 5000Sm3/m3 in the beginning to 2200 Sm3/m3 by far. The forecasted ultimate recovery factor will reach 65%.
Insights into Heavy Oil Recovery by Surfactant, Polymer and ASP Flooding
Authors: Bryan J. , Shamekhi H. , Su S. , Kantzas A.
Published: June 2013

At the end of primary production in heavy oil reservoirs, significant volumes of continuous oil remain in place. As production rates decline this EOR target has tremendous value for heavy oil producers. Many of these reservoirs are poor candidates for thermal recovery. Furthermore in regional sands or post-CHOPS systems, it may not be easy to pressurize these reservoirs for solvent-based recovery. Chemical flooding has potential for EOR in these systems, because the injection of chemicals can lead to the buildup of pressure gradients between injectors and producers, at least at the laboratory scale. These pressure gradients evolve due to improved viscosity of polymer solutions, the formation of emulsions in surfactant or AS floods, or both. The objective of this work is to improve our understanding of the mechanisms by which heavy oils are produced through chemical flooding.

Linear core floods were run on systems containing two heavy oils of variable viscosity: 500 mPa•s and 16,000 mPa•s. For the lower viscosity oil polymer floods and ASP floods are compared. These tests illustrate the impact of improving the injection fluid viscosity vs. the additional benefit from the addition of surfactant. It was observed that heavy oil is produced more efficiently from ASP flooding compared to polymer flooding alone. The residual oil saturations are lower in ASP floods, even with lower differential pressure across the core. For the higher viscosity oil some production was achieved through AS flooding alone, but the addition of polymer was important for improving recovery.

Tests were also run on a parallel core system, containing cores of relatively high and low permeability. This was a representation of a post-CHOPS reservoir containing preferential flow channels due to the presence of wormholes. Both surfactant and ASP solutions only accessed the high permeability core, so oil was bypassed in the lower permeability sand even with the addition of chemicals to water. This result demonstrates that laboratory studies may be dramatically over- estimating the success of chemical flooding in heavy oil, and poses a challenge for successful implementation of chemical floods in heterogeneous post-CHOPS heavy oil fields.
Coupling of Solvent and Hot Water to Improve Heavy Oil Recovery: Experimental and Simulation Studies
Authors: Luo Weiguo , Torabi Farshid
Published: June 2013

There are abundant heavy oil deposits characterized by shallow depth, thin pay zone, low porosity, and bottom water in Western Canada. These types of reservoirs are neither suitable for thermal heavy oil recovery techniques (e.g. SAGD) nor for solvent injection (e.g. VAPEX). Coupling of Solvent and Hot Water (CSHW) injection was proposed and examined as an alternative to improve the heavy oil recovery in these reservoirs.

In this study, a series of core flooding tests and numerical simulations were conducted to investigate and evaluate the CSHW injection performance in thin heavy oil reservoirs containing oil with viscosity of around 1,000 to 6,000 cP. To identify the contribution of hot water and solvent as well as their effectiveness when they combined, three types of core flooding tests were performed individually using hot water, solvent, and CSHW injection. In addition, the effects of oil viscosity, water injection temperature (15°C, 24°C, 50°C, 65°C) and solvent (C1, C3, C1+C3) on oil recovery were examined. Moreover, effects of parameters such as injection rate, displacement volume, slug size, and injection pattern were also investigated. Furthermore, the core flooding tests were history matched based on the established numerical simulation model. The effects of temperature and solvent components on multi-phase fluid flow were examined through numerical simulation. As the result, the optimal CSHW injection parameters were screened based on experimental and numerical studies conducted.

Results of this study showed that the oil recovery factor was enhanced by 19.1% when temperature of injection water increases from 24°C to 65°C. More importantly, it was found that the CSHW is a more feasible option that recovers higher amount of oil at lower cost when compared with pure solvent or hot water injection. In addition results indicated that if smaller slugs of hot water and solvent are injected, the recovery process is more efficient. In this particular study, injection of smaller slugs resulted in 53.5% recovery factor. These results indicate that the CSHW is a promising hybrid process for the heavy oil recovery which requires low facility investment.