bluuebunny/crossref_metadata_2025_split huggingface dataset:
Laboratory Researches of the Heavy Oil Displacement from the Russkoye Field’s Core Models at the SWAG Injection and Development of Technological Schemes of Pump-Ejecting Systems for the Water-Gas Mixtures Delivering
Authors: Drozdov A. N. , Drozdov N. A. 
Published: June 2012

Abstract
"Simultaneous water and gas" (SWAG) injection is the effective method of enhanced oil recovery. However, until recently the effect of SWAG in the development of heavy oil fields has been studied insufficiently.
In the present study laboratory researches have confirmed that SWAG injection when 25% gas content in the mixture significantly increases the displacement efficiency of heavy oil with the viscosity 217 mPa*s of Russkoye deposit, compared with water flooding. It has allowed extending the effective application of SWAG as a non-thermal method of enhanced oil recovery more than twice.
According to the results of laboratory experiments to pre-extracted and not extracted core material, it was found that the degree of hydrophobic pore surface, which depends on the adsorption of polar components of oil, significantly affect the oil displacement efficiency when SWAG implementing.
It was established that SWAG at the optimum gas content is effective for both hydrophilic and hydrophobic environments. The values of the heavy oil displacement efficiency for the hydrophilic core material of Russkoye field are about 1.8 times higher than for hydrophobic.
The technology for SWAG injection from the use of mono-block multistage pump-ejecting systems has been developed. The technology can significantly improve the systems efficiency and the process of water-gas mixtures delivering into injection wells.
The obtained results allow creating non-thermal energy-efficient methods for developing and improving oil recovery of heavy oil fields.
A Follow-Up Recovery Method After Cold Heavy Oil Production Cyclic CO2 Injection
Authors: Alshmakhy A. , Maini B. 
Published: June 2012

Abstract
Cold heavy oil production with sand (CHOPS) is widely used as primary recovery method for heavy oil in western Canada. This process involves sand production in massive amounts. Sand production creates high permeability zones (wormholes) which extend the drainage radius. Typically 5–10% of the OOIP is recovered by this process. Therefore, the need to find a follow-up process is paramount.
The objective of this work was to experimentally evaluate the potential of using cyclic CO2 injection for recovering additional oil from depleted foamy oil reservoirs. A total of five depletion tests were conducted in a two meters long sandpack kept in a vertical orientation. The primary depletions at different depletion rates were followed by one or two huff-n-puff cycles of CO2 injection.
The total recovery factor after cyclic CO2 injection reached 30% indicating the potential of solvent injection as a secondary oil recovery method. Interestingly, the recovery after the cyclic CO2 injection was more or less independent of depletion rate used in the primary production. It was found that the cyclic CO2 injection was more efficient when the primary depletion was at slow rate and resulted in lower primary depletion recovery.
The results of this study show that it may be possible to re-energize the depleted heavy oil reservoirs by injecting CO2, especially those that did not give high recovery factors during the primary depletion.
Investigation of Emulsion Flow in SAGD and ES-SAGD
Authors: Ezeuko C. C. , Wang J. , Gates I. D. 
Published: June 2012

Abstract
Expanding Solvent-Steam Assisted Gravity Drainage (ES-SAGD) was invented to enhance SAGD performance by reducing energy use while increasing oil production rates and recovery factor. ES-SAGD involves co-injection of solvent and steam. The majority of energy losses occur between the steam generator and sandface and at the top of the depletion chamber (to the overburden). ES-SAGD performance improvement is traditionally ascribed to oil phase dilution which in turn leads to oil phase viscosity reduction. However, the amounts of solvent added to the process are typically very small (&lt; 5-6% by volume) thus it remains unclear how the solvent can lead to significant lowering of the steam-to-oil ratio (~25-50%) and large enhancements of the oil rate (~25 to 100%). Here, we report on how SAGD and ES-SAGD (hexane, heptane and octane solvents) can potentially perform in the presence of in-situ emulsification at steam chamber edge. We present a numerical approach which allows incorporation of emulsion modeling into SAGD and ES-SAGD simulations with commercial reservoir simulators via a two-stage pseudo chemical reaction. Numerical simulation results show excellent agreement with experimental data for low-pressure SAGD and ES-SAGD. Accounting for viscosity alteration, multiphase effect and enthalpy of emulsification appear sufficient for effective representation of in-situ emulsion physics during SAGD and ES-SAGD in very high permeability systems. Results also show that, in-situ emulsification may play a vital role within the reservoir during SAGD; increasing bitumen mobility thereby decreasing cSOR. It was concluded that traditional approach to numerical ES-SAGD simulation can significantly over-predict incremental oil recovery. Results from this work extend understanding of ES-SAGD by examining its performance improvement over traditional SAGD in terms of multiphase behavior at the edge of the chamber, thermal efficiency and incremental recovery. Results reveal that dynamics at the edge of the chamber is more complex than simple solvent dilution model.
Experimental Determination of Asphaltene Precipitation from Different Live Heavy Oils and Technical Evaluation of Potential Inhibitors for the Primary Depletion Process
Authors: Gong Xiaozhu , Gu Yongan , Shu Fuchang , She Yuehui 
Published: June 2012

Abstract
Asphaltene precipitation and deposition can occur in some heavy oil reservoirs during the primary depletion or gas-lift process, when a pressure drop from the subsurface reservoir formations to the surface treating system is rather large. These precipitated asphaltenes may be deposited onto various locations along the production system so that it can be partially or completely plugged. Therefore, it is necessary to determine the possibility and severity of asphaltene precipitation at the early stage of heavy oil production. On the other hand, a number of chemical, thermal, and mechanical methods have been developed to reduce or eliminate asphaltene precipitation and deposition. The most commonly used means is through chemical treatment by applying an asphaltene precipitation inhibitor (API), which is a specially designed and synthesized chemical compound to control or inhibit asphaltene precipitation.
In this paper, both visual and filtration methods are used to determine the onset pressures of asphaltene precipitation and redissolution of a recombined live heavy crude oil during an isothermal pressure-reduction process at different temperatures and gas-oil ratios (GORs). The experimental results show that a higher temperature can lead to a lower onset pressure of asphaltene precipitation and a less amount of precipitated asphaltenes, i.e., delayed and reduced asphaltene precipitation. This is because at a higher temperature, the solubility of the resins in the live heavy crude oil is higher, which helps to stabilize asphaltenes in the oil. It is also found that in contrast, the live heavy crude oil with a higher GOR has earlier and stronger asphaltene precipitation during the isothermal pressure-reduction process. In this case, the composition of the live heavy crude oil with a higher GOR is lighter and the solubility of asphaltenes in such a live crude oil is lower. Thus, asphaltenes become more unstable and likely to aggregate and precipitate. Finally, the filtration method is also applied to evaluate the effectivenesses of two APIs (API-A and API-B) by comparing their abilities to stabilize asphaltenes in the API-treated live heavy crude oils during the isothermal pressure-reduction process. API-A is proven to be capable of substantially lowering the onset pressure of asphaltene precipitation and the pressure-drop increase in the filtration process. Furthermore, API-B is found to be more effective to inhibit asphaltene precipitation than API-A as no noticeable pressure-drop increase during the isothermal pressure-reduction test is measured for the live heavy crude oil treated with API-B.
Gas Transport Mechanisms in Thermal Simulation
Authors: Atif Muhammad , Edmunds Neil 
Published: June 2012

Abstract
Many authors have published effects of Non Condensable Gas (NCG) injection during steam assisted gravity drainage (SAGD) operation, on one hand it provides an insulation blanket to the steam chamber and avoids heat loss to the over burden and improves the economics of the project, but on the other hand it can stall the steam chamber growth in the middle of high pay zone, provided the reservoir has high solution gas. All the commercial simulators predict the accumulation of the gas blanket ahead of steam front. However, field operations have proved that the NCG are produced along with bitumen and water and doesn't accumulate, but simulators are unable to predict the right amount when it comes to history matching and accurate predictions. This paper is focused on numerically findings of the gas transport mechanism in the SAGD operations. Many possible mechanisms were considered and found that most of the commercial simulators lack the function of gas production due to viscous liquid drag, which contributes a lot towards gas production especially during early years of SAGD. Solubility exclusion of the two major NCG i.e. CO2 and CH4 in both water and oil phases is another reason for under-estimating the gas production. Along with the above two mechanisms, interestingly, the constraints on the production wells in the simulators also account for a great deal of NCG production. Now instead of using a fraction of GOR, simulation engineers can include the complete GOR of the Alberta bitumen reservoirs to history match and predict the correct amount of bitumen and gas production.
The Use of Pressure Transient Analysis Tools to Interpret Mini-Frac Data in Alberta Oilsands Caprocks
Authors: Powless Kenneth R. 
Published: June 2012

Abstract
The use of pressure data to understand reservoir flow characteristics has been evolving since Darcy's Law was published in 1856. Welltesting has evolved from straightline methods to sophisticated interpretation models which use Log-Log pressure and derivative diagnostic plots to recognize flow regimes. This allows analysis to be performed on a valid subset of the data.
It has long been known that reservoir fluid flow alone will very rarely if ever create a Bourdet derivative slope of greater than one. Mohamed et al (2011) showed that for tight shale gas mini-fracs, the derivative slope during fracture closure is equal to 3/2. This diagnostic signature is readily apparent in Mini-Frac tests of the Alberta oilsands caprock which flags it as a nonreservoir geomechanical effect.
Mattar (1997) showed reservoir flow has a characteristic shape on the primary pressure derivative plot: the primary pressure derivative data continuously declines for all reservoir flow regimes. The primary pressure derivative appears to stop declining while the fracture is closing and resumes declining after the fracture is closed (it can increase for the forced closure case).
Barree et al (2009) uses G Function and Square Root plots and their derivatives to indentify flow regimes as the basis for establishing fracture closure. This sounds familiar to Bourdet's pressure derivative rationale.
This paper shows these methods compliment conventional PTA and give consistent repeatable mini-frac solutions for oilsands caprocks. The incorporation of fracture solutions into PTA programs is another step forward to delivering reliable, consistent analysis for mini-fracs, however, these solutions only exist for falloff whereas the 3/2 slope and primary pressure derivative also work for flowback assisted fracture closure.
Several examples will be presented to illustrate that Pressure Transient Analysis is a useful tool for resolving Mini-frac data, especially the start and end of fracture closure.
Sonic Azeotropic Gravity Extraction of Heavy Oil from Oil Sands
Authors: Seibert Brian Howard 
Published: June 2012

ABSTRACT
The Sonic Azeotropic Gravity Extraction Heavy Oil Recovery Process utilizes natural gas liquids (NGLs), extracted from local rich natural gas sources, in the "wild" condition to heat and extract heavy oil from oil sands. The gas liquids are vaporized by heating and are super-saturated with produced water vapor for injection in a vertical well from the surface through a perforated liner into the subsurface bitumen formation. A movable packer system segregates the vertical well into an upper outer injection annulus equipped with an in-line Hartmann acoustic resonating hot vapor injector and an inner lower production annulus equipped with a progressive cavity pump.
The superheated azeotropic NGL/water vapor flows into the oil sand formation horizontally and radially outwards in a focused bitumen solvating and mobilizing process. The acoustic waves resonate through the leached quartzite sand and are absorbed by the interstitial heavy oil, accelerating the mixing of the condensing NGL with the cooler bitumen at the quartzite/oilsand interface, allowing the vertical well to establish many of the characteristics of a SAGD horizontal well pair.
The mobilized solvated bitumen drains by gravity into the lower well bore where it is pumped to the surface via the progressive cavity pump using one of two possible processes. If surface subduction is allowed, the lower production section of the well bore will be equipped with a perforated liner sized to encourage the flow of some sand into the well bore for pumping to the surface with the heavy oil, which generates the formation of wormholes in the unconsolidated sand for improved oil production. Otherwise, the lower production section will be equipped with a slotted liner to preclude the flow of sand into the well bore. The pump's variable speed drive allows pressure pulsing, causing vaporization of the condensed solvent, and establishing a pulsating foamy-gas drive.
Feasibility Study of Solvent-Based Huff-n-Puff Method (Cyclic Solvent Injection) to Enhance Heavy Oil Recovery
Authors: Qazvini Firouz A. , Torabi F. 
Published: June 2012

Abstract
Solvent-based processes have demonstrated a significant potential to enhance heavy oil recovery. However, their applicability needs to be investigated for different solvents and operating conditions. In this study, a comprehensive experimental and reservoir simulation analysis was conducted on the feasibility of solvent-based, huff-n-puff method to enhance heavy oil recovery. Carbon dioxide (CO2), methane (CH4), propane (C3H8), and butane (C4H10) were tested under different operating conditions. A physical model with a1800-md permeability and 24% porosity Berea core mounted in a high-pressure core holder was designed. For all tests, the core was saturated with a Saskatchewan heavy oil with viscosity of 1423 mPas at 22 °C. Fourteen huff-n-puff experiments were conducted. The effect of operating pressure, soaking time, and solvent composition were investigated. According to the results, for all types of solvent the produced oil at elevated pressure was lighter (in terms of density and viscosity) and the recovery factor was higher. The highest recovery of 71% was obtained by injecting pure CO2 at near-supercritical conditions (7239 kPa at 28 °C), while pure CH4 at the highest operating pressure of 6895 kPa was 50%. Also, adding 19% hydrocarbon solvent to pure CO2 increased the recovery factor by 10% at aoperating pressure (e.g., 2317kPa). The governing mechanisms that contributed to the production were recognized to be solution gas drive, viscosity reduction, extraction of lighter components, formation of foamy oil, and to a lesser degree, the diffusion process. The oil viscosity was reduced to 62 mPas by injecting CO2 at 7239 kPa. The highest incremental recovery for CO2-based solvents and CH4 occurred at the 2nd and 3rd cycle, respectively. Longer soaking time improved the incremental recovery of the first cycles, though the final recovery did not noticeably change. The result of history matching with the simulated model was quite reasonable with maximum 10% discrepancy between recovery factors of these two approaches.
SAGD Well Placement in Ultra-Defined Point Bar Deposit
Authors: Su Y. , Wang J. Y. , Gates I. D. 
Published: June 2012

Abstract
The creation and evolution of point bar systems is well understood in meandering river deposits. A large fraction of Athabasca oil sands deposits are ancient point bar systems characterized by bedded, sandstone-dominated strata with interbedded siltstone layers. The recovery process of choice for these deposits is the Steam-Assisted Gravity Drainage (SAGD) process due to the high viscosity of the oil, low solution-gas ratio, and often caps rock not sufficient to with stand injection pressures of Cyclic Steam Stimulation. However, because of the presence of siltstone interbeds, these reservoirs commonly have lateral and vertical lithological heterogeneity which interfere with the formation of uniform steam chambers along SAGD wellpairs. Other units in point bar deposits that impact SAGD chamber development within the formation include remnant channel succession and channel lag. The objective of this research is to construct a detailed three-dimensional point bar model to determine how its heterogeneity impacts SAGD performance. Here, the point bar model is based on the Lower Cretaceous Middle McMurray Formation in the Athabasca oil sands deposit in Alberta, Canada. Single SAGD wellpair submodels at different locations and orientations were extracted from the point bar model. The results of the reservoir models simulation suggest that attention must be paid to SAGD wellpair placement in point bar systems.
Onset of Convective Mixing at the Edge of Steam Chamber in Steam-Solvent Recovery of Heavy Oil and Bitumen
Authors: Rabiei Faradonbeh M. , Harding T. G. , Abedi J. , Hassanzadeh H. 
Published: June 2012

Abstract
With increasing world demand for energy, greater attention has been placed on the exploitation of the huge existing resources of heavy oil and bitumen. Although thermal in-situ recovery methods such as steam assisted gravity drainage (SAGD) have been very successful in exploiting such resources, the thermal efficiency of SAGD, its greenhouse gas emissions and water requirements remain major concerns.
Co-injection of solvent with steam shows promise for enhancing oil rates as well as reducing energy and water consumption with correspondingly lower environmental impacts. In hybrid steam-solvent methods, there is a balance between the solubility of the solvent and its ability to reduce bitumen viscosity. Proper selection of the solvent for the reservoir operating conditions is key for optimizing process efficiency and maximizing performance improvement over the steam-only method.
Convective mixing at the edge of the steam chamber enhances heat and mass transfer rates which increases oil mobility and production rate. In this study, the convective mixing at the steam-bitumen interface is examined using theoretical stability analysis of the thermal-solvent boundary layer. Several alkane solvents were compared based on the time required for the onset of the buoyancy-driven instabilities in the system. The results show that there is a higher degree of convective mixing for some intermediate solvents, which is in agreement with reported laboratory and simulation results. The onset of convective mixing and the wavelength of the instabilities are obtained as a function of reservoir and fluid properties for various solvents.
These results can aid in the screening and selection of appropriate solvent additives to steam for a given reservoir and bitumen properties; also this analysis can be applied for mixtures of solvents to optimize the overall efficiency of the steam-solvent recovery method.
Experiences in Eliminating Steam Breakthrough and Providing Zonal Isolation in SAGD Wells
Authors: Brooks Robert T. , Tavakol Habib 
Published: June 2012

Abstract
For the last two decades major oil companies in Canada have been paying much more attention to heavy oil, which is an alternative unconventional reservoir (Canada and Venezuela have some of the largest bitumen deposits in the world). The main reasons for development could be the continued high price of oil, and improved technology to extract heavy oil, with a high recovery factor (up to 60% of the oil in place). Injecting steam is the most distinctive technique of heating up the formation rock and assisting in oil flow. Controlling steam injection and its distribution, and achieving economical recovery in an effective manner, has been a continuous mind-boggling issue for the heavy oil producers, and has been a great challenge.
High-temperature water and oil swellable packers have been developed to aid, and optimize, cyclic steam stimulation and Steam Assisted Gravity Drainage (SAGD) applications in heavy oil reservoirs. Simplicity is one of the great advantages of the swellable packers, which provide an ease of operation. The packer allows for uniform, or selective, placement of steam along the entire length of horizontal section, and is designed to handle high temperature 575°F (302°C), and more than adequate differential pressures associated with steam injection. Screens or slotted liners are run in hole to allow steam to be pumped in between the well pairs. Steam breakthrough, or diversion, has been experienced in numerous wells due to lost circulation, or sand erosion and/or plugging of the slotted liners, which creates problems for continuous production. Swellable packers can be installed in conjunction with inflatable packers, screens, slotted liner, or scab liners, in order to distribute steam and provide zonal isolation. In the event of steam breakthrough, swellable packers can be deployed to isolate the affected zone(s). This intervention technique will assist in efficient continued production and the elimination of steam breakthrough.
The technique of steam injection has been improving over the years, but still has room for refining of the processes. Some older wells have encountered issues of steam channeling through the cemented casing & breaking out at the surface; which has been seen to create a threat to the environment. A horizontal well completed with slotted liner, or recently with specially designed type of screens, provides a far better method than perforated casing for injecting steam into the formation.
This paper presents a solution with a unique technique, for SAGD wells, for resolving wasted steam injection at the toe section of the well, and repair of steam breakthrough in production legs. Every operator is coming across new learning experiences almost every day, although most of this information is proprietary, we are proposing a different solution path to overcome some of these issues.