bluuebunny/crossref_metadata_2025 huggingface dataset:
An Experimental Investigation of Polysilicon Nanoparticles’ Recovery Efficiencies through Changes in Interfacial Tension and Wettability Alteration
Authors: Roustaei Abbas , Moghadasi Jamshid , Iran Abadan , Bagherzadeh Hadi , Shahrabadi Abbas
Published: June 2012

New technologies are emerging oil industry to afford the need for increasing oil recovery from oilfields, one of which is Nanotechnology. This paper experimentally investigates a special type of Nanoparticles named Polysilicon ones which are very promising materials to be used in near future for enhanced oil recovery. There are three types of Polysilicon Nanoparticles which can be used according the reservoir wettability conditions. In this paper, hydrophobic and lipophilic polysilicon (HLP) and naturally wet polysilicon (NWP) are investigated as EOR agents in water-wet sandstone rocks. These two Nanoparticles recover additional oil through major mechanisms of interfacial tension reduction and wettability alteration. The impact of these two Nanoparticle types on water-oil interfacial tension and the contact angle developed between oil and the rock surface in presence of water phase were investigated. Then, several coreflood experiments were conducted to study their impacts directly on recoveries. Furthermore, optimum pore-volume injection of each Nano-fluid was determined according the pressure drop across the core samples.

The results show a change toward less water-wet condition and a drastic decrease in oil-water interfacial tension from 26.3 mN/m to 1.75 mN/m and 2.55 mN/m after application of HLP and NWP Nano-fluids respectively. As a result, oil recoveries increase by 32.2% and 28.57% when a 4 gr/lit concentration of HLP and NWP Nano fluids are injected into the core samples respectively. According the differential pressure data, two and three pore-volume injections of NWP and HLP Nano-fluids are the best injection volumes respectively. Finally, HLP and NWP Nanoparticles improve oil recovery without inducing any formation damage according the oil recovery and pressure drop data.
Stability and Mobility of Functionalized Silica Nanoparticles for Enhanced Oil Recovery Applications
Authors: Miranda Caetano Rodrigues , de Lara Lucas Stori , Tonetto Bruno Costa
Published: June 2012

For any possible application of hard nanoparticles as an improved oil recovery agent, it is necessary to have a stable wettability modifier with improved mobility properties under broader oil reservoir conditions. Typical oil reservoir conditions with high temperature, pH and electrolytes concentration modifies the way that nanoparticles interact with the solution. In this work, the wettability and fluid diffusivity at the molecular level were studied through Molecular Dynamics simulation. We have studied the stability and mobility of functionalized (hydroxylated, PEG and sulfonic acid) silica nanoparticles for enhanced oil recovery applications, particularly at high salt concentration and high temperature. In order to stabilize the interfacial energy in the nanoparticle-brine interface, ions tend to modify the transport properties of the nanoparticle itself. We have observed an increasing in the diffusion coefficients for nanoparticles with increasing salt concentration at 300K and 0.1 MPa pressure. Our calculations also indicate that adsorption properties and salt solutions greatly influence the interfacial tension in an order of CaCl2 > NaCl. This effect was found to be due to the difference in distribution of ions in solution, which modifies the hydration and electrostatic potential of those ions near the nanoparticle. The brine/oil interfacial tension variation due to functionalized silica nanoparticles was also determined as a function of the terminal group hydrophobicity at 1% salt concentration (CaCl2 and NaCl), 300K and 0.1 MPa pressure.
Focused Magnetic Heating Utilizing Superparamagnetic Nanoparticles for Improved Oil Production Applications
Authors: Davidson Andrew , Huh Chun , Bryant Steven L.
Published: June 2012

A novel method of delivering thermal energy efficiently for flow assurance and for improved heavy oil production/transport is described. The method, an improved form of magnetic induction heating, uses superparamagnetic nanoparticles that generate heat locally when exposed to a high frequency magnetic field oscillation, via a process known as Neel relaxation. This concept is currently used in biomedicine to locally heat and burn cancerous tissues.

Dependence of the rate of heat generation by commercially available, single-domain Fe3O4 nanoparticles of ∼10 nm size, on the magnetic field strength and frequency was quantified. Experiments were conducted for nanoparticles dispersed in water, in hydrocarbon liquid, and embedded in a thin, solid film dubbed "nanopaint". For a stationary fluid heat generation increases linearly with loading of nanoparticles. The rate of heat transfer from the nanopaint to a flowing fluid was up to three times greater than the heat transfer rate to a static fluid.

Heating of nanopaint with external magnetic field application has immediate potential impact on oil and gas sector, because such coating could be applied to inner surfaces of pipelines and production facilities. A nanoparticle dispersion could also be injected into the reservoir zone or gravel pack near the production well, so that a thin, adsorbed layer of nanoparticles is created on pore walls. With localized inductive heating of those surfaces, hydrate formation or wax deposition could be prevented; and heavy oil production/transport could be improved by creating a ‘slippage layer’ on rock pore walls and inner surfaces of transport pipes.
Nanotechnology-Assisted EOR Techniques: New Solutions to Old Challenges
Authors: Ayatollahi Shahab , Zerafat Mohammad M.
Published: June 2012

Enhanced Oil Recovery techniques are gaining more attention worldwide as the proved oil reserves are declining and the oil price is hiking. Although many giant oil reservoirs in the world were already screened for EOR processes, the main challenges such as low sweep efficiency, costly techniques, possible formation damages, transportation of huge amounts of EOR agents to the fields especially for offshore cases, analyzing micro-scale multi-phase flow in the rock to the large scale tests and the lack of analyzing tools in traditional experimental works, hinder the proposed EOR processes.

Our past experiences on using nanotechnology to the upstream cases, especially EOR processes, revealed solutions to some of the challenges associated with old EOR techniques. This method that utilizes particles in the order of 1 to100nm brings specific thermal, optical, electrical, rheological and interfacial properties which are directly useful to release the trapped oil from the pore spaces in the order of 5 to 50 microns of tight oil formations.

Laboratory tests using nanoparticles as the EOR agent, developing nano computational models to explore the surface properties and utilizing nano-scale analyzing tools such as atomic force microscopy (AFM), scanning electron microscopy (SEM) and X-ray photoelectron spectroscopy (XPS) mostly for nanoparticles distribution in the pore spaces and on the surfaces for wettability alteration studies are the main parts of this investigation.

This paper summarizes new findings from several different theoretical, analytical and experimental works which shows the effectiveness of traditional methods when assisted by this new technology. Ultimately, based on the past experiences, a roadmap will be proposed to avoid the ongoing trial and error practice in this area.
Magnetic Characterization of Nanoparticles Designed for Use As Contrast Agents for Downhole Measurements
Authors: Avendano Carolina , Lee Seung Soo , Escalera Gabriela , Colvin Vicki
Published: June 2012

Nanotechnology has already contributed significantly to advances in several industries, e.g. electronics, biomedical, aerospace, and more recently the energy industries. In particular, nanotechnology has the potential to pioneer changes in several areas of the oil and gas industry, such as exploration, drilling, production, enhanced-oil-recovery (EOR), and refining. For example, superparamagnetic nanoparticles that could act as contrast agents could be used to accurately determine the oil saturation distribution in a reservoir and help determine bypassed oils. Moreover, by correctly functionalizing the surface of the magnetic nanoparticles, colloidal suspensions of these nanoparticles that are stable at high temperatures and high salinities (oil-well conditions) can be prepared and could be co-injected with sweep and/or fracture fluids and their location determined and tracked over time by electromagnetic measurements. With this in mind, a study of the magnetic properties of ferrite nanoparticles with varying compositions (MFe2O4; M = Fe, Al) has been conducted to determine the magnetic responses of the various particles in order to evaluate the likelihood of using them as magnetic contrast agents in the oil and gas industry.
Water Injection Patterns Optimization Approach on High-Viscous Oil in Russkoye Field
Authors: Zakirov I. , Shayhutdinov I. , Svarovskaya M. , Gaviria W. , Shmidt S. , Shakirova A.
Published: June 2012

Russkoye field, discovered in 1968, is a giant high-viscous oil field located above the Polar Circle in Russia. The commercial development of the field has been a tremendous challenge due to several factors such as a very complex heterogeneous shallow reservoir with a large gas cap, an active bottom aquifer, unconsolidated sands, low temperature, and permafrost zone. At this stage, the development of the field is still on the pilot testing stage in order to understand and evaluate different possible development strategies that assure the maximum recoverable reserves for this kind of field.

As part of the development strategy, eight water injection pattern schemes including horizontal and vertical wells, and different well spacings were simulated to find the optimal waterflooding patterns, and to evaluate different well trajectories, and different injection bottomhole pressures, for the next pilot area.

The water injection pattern schemes evaluated were horizontal wells line drive, 7-spot, 7-spot inverted, 9-spot, 9-spot inverted, 5 spot, combined line drive with horizontal producers and two deviated injectors, and combined line drive with horizontal producers and three deviated injectors.

The complete analysis was carried out on the basis of the technical results and the economical evaluation. Several parameters were studied to compare performance and efficiency of different water injection patterns, such as voidage replacement ratio, cumulative oil, water and gas, production profiles, sweep efficiency, injected pore volume, and reservoir pressure behavior. The optimization of the four well spacings between 100 m and 400 m and the injection bottomhole pressure range was performed using an analytical approximation. The economical evaluation for each water injection pattern analyzed was executed by means of the economical standard analysis: net present value, internal rate of return, profitability index, lifting cost, and payback period.
Paradigm Shift in Polycrystalline Diamond Bit Design for Canadian Heavy Oil Sands
Authors: Maw Jason , Knull Craig , Clegg John
Published: June 2012

PDC drill bits have grown from niche to mainstream products by gradual, subtle evolutions in design and materials technology. Occasionally, there have been more dramatic step changes in design or materials that have launched PDC bits into new applications. This paper will talk about such a step change: the design, manufacture and application of a contiguous blade of polycrystalline diamond. Rather than blades made up from individual cutters, as with a conventional PDC bit design, this bit has full-length, contiguous polycrystalline diamond coverage, without gaps between cutters on each blade. The advantages of this arrangement are many. Most obvious is the ability to drill erosive and/or abrasive formations without erosion. Often PDC bits, especially lighter set bits, can lose steel or matrix body material between the cutters due to erosion or abrasion, and this can be life-limiting. With no gaps between the cutters, this ceases to be a problem. Other possibilities include: bits for more conventional formations where a contiguous blade can be used instead of backup cutters, enhancing ROP and stability. The paper describes how various challenges were overcome: bit design; materials selection; polycrystalline diamond blade manufacture. It will also discuss applications of this technology in bits specially designed for the oil sands in northern Alberta, Canada, focusing on: Dull condition enhancement as a result of avoiding cross-blade erosion and abrasionPolycrystalline diamond blade durabilityThe effect of a smaller number of contiguous blades on ROP and PDC bit economics.

This represents a step change in bit design with the potential to redefine bit design across the applications spectrum.
Upscaling Study of Vapour Extraction Process through Numerical Simulation
Authors: Xu Suxin , Zeng Fanhua , Gu Yongan , Knorr Kelvin D.
Published: June 2012

Vapour Extraction (VAPEX), a process to recover heavy oil by injecting vapourized solvent into a reservoir, has been extensively studied through small-scale 1-D and 2-D laboratory tests. Recently, a series of large-scale 3-D tests have been conducted by Saskatchewan Research Council (SRC). In this study, 2-D tests were conducted under the same conditions as those for the 3-D tests; then, numerical simulation models were investigated to reduce the uncertainty in upscaling the results from 2-D tests to 3-D tests. This helps to better understand the uncertainty in predicting the field-scale VAPEX performance.

Plover Lake heavy oil was used in the tests, and the sandpack permeability was about 4.4 Darcy. In each test, the initial waterflooding was conducted prior to the subsequent solvent injection. Then, a numerical model was established to simulate the 2-D test. History match of the 2-D test was conducted by tuning the uncertainties such as the relative permeability, capillary pressure, solubility, and the wall effect in sand-packing. Afterwards the tuned parameters were applied to predict the 3-D test performance. Through comparison of the predicted and experimental results in the 3-D test, the capability of predicting up-scaled VAPEX processes through numerical simulation was examined, and the differences between physical and numerical modeling were identified.

The results show that the waterflooding performance can be successfully predicted, whereas the uncertainty in upscaling the VAPEX process is large. In the waterflooding period, the predicted oil recovery factor was 25.78% compared with 23.4% in the 3-D test. In the VAPEX process, the difference between the predicted and measured oil recovery factors was in the range of 0.75–25.14%, depending on the different combination of uncertain parameters. This fact indicates that different scales of physical modeling are required in order to reduce the uncertainties in predicting the field-scale VAPEX performance.
Estimation of Heavy Crude and Tar Sand Oils Viscosity in the Presence of Diluent
Authors: Bahadori Alireza
Published: June 2012

Heavy oil resources are assuming greater importance because of the increasing energy needs of the world. Compared to conventional oil, heavy oil is much more viscous and hence it presents many technical challenges at all stages of oil recovery and processing. In this work, a simple correlation, is presented here for prediction of heavy crude and tar sand oils viscosity as a function of kerosene volume fraction and temperature. The heavy crude and tar sand oils viscosity is calculated for temperatures in the range of 5 to 90°C and kerosene volume fraction up to 0.45. The proposed method is superior owing to its accuracy and clear numerical background, wherein the relevant coefficients can be retuned quickly if more data becomes available in the future. Estimations are found to be in excellent agreement with the reliable data in the literature with average absolute deviation being around 2%.
Duplex and Super Duplex Stainless Steels, and Their Applications in Steam Assisted Gravity Drainage (SAGD)
Authors: Schulz Zach , Reno Tyler
Published: June 2012

As oil reserves decrease, the level of difficulty to extract oil increases. With this increased difficulty, the service conditions involved in Steam Assisted Gravity Drainage (SAGD) are increasingly more aggressive. In an effort to maintain low raw material prices without sacrificing performance, duplex and superduplex stainless steels have been used for many applications to resist corrosion from chlorides, withstand extremely high pressure and still stay cost competitive. This summary of case histories shows where duplex stainless steels have been successfully utilized in the Alberta Oil Sands as well as across the globe. Duplex stainless steels have replaced leaner austenitic stainless steels and low alloy steels because of their increased corrosion resistance. In other cases, duplex and superduplex stainless steels have replaced higher nickel- chromium-molybdenum grades because of their lower cost and similar performance. For example, super duplex stainless steel has already been used as an alternate to six percent molybdenum grades in brine concentrators throughout Alberta, Canada.
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

"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

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

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 (< 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

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

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

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

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

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

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

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

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.
Optimal Grid System Design for SAGD Simulation
Authors: Shin Hyundon , Hwang Taeho , Chon BoHyun
Published: June 2012

The steam-assisted gravity drainage (SAGD) process is currently the widely used one among the in-situ recovery methods to produce bitumen from Alberta oil sands in Western Canada. A thermal process requires very small grid size to provide the better description in the reservoir simulation model than the coarse grid; however the simulation runtime will take longer. The relationship between the number of grids and runtime is not linear but exponential. It is important to design the proper grid size giving reasonable results with shorter runtime.

In this study, the optimal grid system design has been investigated through numerical simulation sensitivity studies for the SAGD process. A 1×25×1 m (i, j, k direction; j is wellbore direction) grid size is accepted as a standard size for the SAGD simulation. Grid size sensitivity study has been conducted to determine the maximum grid size that shows a closer result to the 1×1 m case and also the impact of grid size in j-direction as well as the i/k ratio in SAGD simulation.

The simulation results shown an i/k ratio is more important than a grid size itself. Based on the CSOR and oil production as well as steam chamber shape, the 2×2 m grid case is closer to the 1×1m case results than 3×1 m case. For the grid size optimization in the wellbore direction (j direction), the grid size of over 25 m cases are no big difference in both production and steam chamber shape for a homogeneous model, and there is no steam chamber propagation to the j-direction. The maximum grid size in j-direction to see the wellbore end effect is 10 m in this study. Considering the reservoir heterogeneity, if shale barriers exist, the impact of grid size in j direction is more important and the smaller grid size is required for the proper numerical simulations to describe steam chamber development in field scale SAGD project. For j-direction grid design, a hybrid type of grid system, a fine grid size in wellbore end zone and regular grid size in wellbore zone, may help to see the steam chamber development with saving a degree of simulation runtime.
Experimental Evaluation of Dispersion and Diffusion in a UTF BItumen/n-Butane System
Authors: Frauenfeld Ted , Jossy Chris , Jossy Eddie , Wasylyk Brad , Diaz Brigida Meza
Published: June 2012

Laboratory experiments at Alberta Research Council (now Alberta Innovates Technology Futures) have indicated the potential for improving the recovery of bitumen and heavy oil, and a substantial reduction of SOR relative to SAGD, by the addition of substantial volumes of light hydrocarbon to steam as an enhancement of SAGD. Many scaled lab model experiments have been completed, some of which have identified solvent/steam ratios that outperformed low pressure SAGD. In order to more reliably scale the results of these experiments, it was desired to measure the rate of oil production and hence solvent front advance rate in field permeability sand. The experiments were isothermal to simplify the numerical simulations. Three experiments were completed, one at 68°C one at 80°C and one at 100°C. The respective butane pressures were 700 kPa, 1020 kPa and 1450 kPa. The respective oil rates were 52.5 g/h, 62.3 g/h and 63.2 g/h. Solvent front advance rates were 7.81 cm/d, 9.0 cm/d and 9.42 cm/d. These rates translate into SAGD-like rates when extrapolated to a field size project.
Hydrophobically-Modified Cellulosic Polymers for Heavy Oil Displacement in Saline Conditions
Authors: Bai Jiang , Wassmuth Fred R. , Jost Robert W. , Zhao Liyan
Published: June 2012

Commercial polymer floods have generally used partially hydrolyzed Polyacrylamide (HPAM) as the polymer of choice, since HPAM generates high viscosities in relatively fresh brines at a reasonable cost. In high salinity or hardness brines, the anionic charges on the HPAM polymer chain interact with the dissolved cations, shrinking the hydrodynamic size of the polymer molecules. The smaller hydrodynamic radius generates lower viscosities and requires higher polymer concentrations. In order to reduce the polymer loading in saline brines, a series of hydrophobically modified biopolymers have been synthesized. The non-ionic nature of hydroxyethyl cellulose (HEC) provides an ideal polymer back bone since it does not interact with the dissolve cations. Hydrophobic groups (aliphatic hydrocarbon chains) are attached to the backbone of the polymer to impart associating properties between polymer molecules. The inter-molecular interaction between the hydrophobic moieties led to a significant viscosity increase in comparison to polymers without hydrophobic groups. Several screening steps were used throughout the product development to arrive at practical polymer formulations: 1) Filtration; 2) Sandpack tests; 3) Corefloods in the presence of oil. By varying molecular weight of the base HEC polymer and the amount of hydrophobic content, practical polymer products were developed for polymer flood applications. Coreflood tests showed that the hydrophobically modified HEC generated significant resistance factor in saline brines, outperforming the HPAM polymers.
SAGD Startup: Leaving the Heat in the Reservoir
Authors: Anderson M. T. , Kennedy D. B.
Published: June 2012

Successfully starting up Steam Assisted Gravity Drainage (SAGD) well pairs is crucial in achieving good wellbore temperature conformance and rapid production ramp-up. Performing a SAGD startup effectively and economically is a significant challenge in the industry and reservoirs with mobile water offer an opportunity to optimize and accelerate this process.

A traditional SAGD startup involves steam circulation, where steam is injected into a well down the long tubing string to the toe and fluids are produced back to surface at the heel. Steam circulates across the full horizontal length of the well and conductively heats the near reservoir. In reservoirs with mobile water, there can be fluid losses to the reservoir during circulation, allowing for convective heating of the reservoir.

In a bullheading startup, return fluids are not produced and all injected steam is forced to leak off into the reservoir. By avoiding fluid returns, bullheading offers significant advantages over circulation in terms of thermal efficiency, steam demand, operational simplicity and facility requirements.

This paper examines the effectiveness of a bullheading startup compared to a circulation startup through a simulation study and field trials at Suncor Energy Inc’s Firebag in-situ project.