bluuebunny/crossref_metadata_2025 huggingface dataset:
An Enhanced Oil Recovery Technology as a Follow Up to Cold Heavy Oil Production with Sand
Authors: Coskuner Gökhan , Naderi Khosrow , Babadagli Tayfun
Published: June 2013

Lloydminster area that straddles Alberta and Saskatchewan border contains vast amounts of heavy oil deposits in thin unconsolidated formations. Cold Heavy Oil Production with Sand (CHOPS) has been successfully implemented in these reservoirs. However, primary recovery is still low averaging below 10%. How to economically recover the large amount of remaining oil in place is a challenge. Therefore, an effective follow up recovery process is required.

Steam injection technologies cannot be widely applied because most of the Lloydminster heavy oil reservoirs are thin and the heat losses to overburden and under burden make the process uneconomic. Alternative solvent methods are not commercial yet due to uncertain oil recovery rates and low solvent recovery. Hybrid application of the aforementioned two technologies using hot water together with solvents could be an economic post CHOPS recovery process. The wormholes created during the primary recovery can be used to contact large reservoir volumes with hot water and solvent.

This paper contains the results of hot water and solvent oil recovery experiments conducted in preserved heavy oil cores. Experimental work consisted of three phases. Cores were immersed in hot water in the first phase to pre-heat the formation. Next, cores were exposed to heptane as hydrocarbon solvent. Finally, cores were immersed in hot water again to recover the oil as well as the solvent. The ultimate oil recoveries varied between 42% and 88% OOIP and, the asphaltene precipitation varied between 2.5 wt% and 11.7 wt%. Experiments were also carried out with a distillate from Husky's Lloydminster upgrader used for heavy oil transportation in the pipelines. Better results were obtained if the distillate was used instead of the pure hydrocarbon solvent.

It was observed that oil recovery at the end of the initial hot water injection phase due to thermal expansion and viscosity reduction was negligible compared to the ultimate recovery. However, the first phase serves to condition the reservoir for better diffusion in the second phase when the solvent is injected. The final phase of hot water injection causes the water to strongly imbibe into the matrix enhancing the oil and the solvent recovery.
Understanding HW-CSS for Thin Heavy Oil Reservoirs
Authors: Chang Jeannine
Published: June 2013

This paper evaluates the potential of applying horizontal well CSS (HW-CSS) technology to enhance heavy oil production from non-CHOPS thin pay resources in the Iron River/Manatokan area. Thin non-CHOPS heavy oil and oil sand deposits are a considerable resource. The economics for thermal operations in these deposits are hampered by the fact that they contain less oil over producing horizontal wells than do thicker deposits.

A numerical model was built and simulations were performed to answer the questions: Can HW-CSS be developed to exploit "non-CHOPS" thin heavy oil resources?What is the cut-off pay thickness for an economic application of HW-CSS?How can HW-CSS be used to maximize the net present value (NPV) of oil recovery from thin heavy oil resources?

The initial simulation results indicated that despite a determined effort to develop optimized operating strategies, HW-CSS cannot economically recover heavy oil when the reservoir pay thickness is less than 8 m due to excessive heat loss to the overburden/underburden. Later simulations demonstrated that the cut-off pay thickness for an economic HW-CSS process is around 11 m. With an optimized operating strategy and well spacing, and short well life, a cumulative steam-oil ratio (CSOR) under 6 m3 cold water equivalent (CWE)/m3 oil was achieved. The estimated oil recovery ranged from 30 to 50% depending on the well spacing used in the estimates (either 100 m or 75 m). For a 25 year project involving the installation of a new 8 well pad every 8 years, the internal rate of return (IRR) was estimated to be in the range of 20 - 25%.

For a 1 m reduction in pay thickness (e.g. from 11 to 10 m), the cumulative oil production/m of pay thickness decreased 6 - 8% when the reservoir pay thickness was less than 11 m, decreased 1 to 2 % when the reservoir pay thickness was between 11 and 17 m, and decreased less than 1% when the reservoir pay thickness was greater than 17 m.

The reservoir pay thickness of 14 m displayed the most efficient oil recovery for the reservoir pay thicknesses investigated (5 m to 20 m) although 20 m pay thickness resulted in the highest oil production. Thicker pays had a greater tendency for steam to rise because of an increased gravitational influence resulting in reduced lateral expansion. These pays required smaller well spacing for maximum oil recovery.

Better reservoir conditions such as higher permeability and lower oil viscosity generally achieved better performance. However, for reservoir pay thicknesses of 5 m and 8 m, an initial dead oil viscosity of 30,000 mPa.s resulted in lower oil recovery than having an initial dead oil viscosity of 50,000 mPa.s. The reservoir with 30,000 mPa.s viscosity oil displayed faster pressure and temperature dispersion resulting in ineffective use of the dilation and dead oil re-compaction mechanism.
An Empirical Correlation of Steam Chamber Size and Temperature Falloff in the Early-Period of SAGD Process
Authors: Zhu Lijuan , Zeng Fanhua , Su Shi , Wu Meng
Published: June 2013

Steam Assisted Gravity Drainage (SAGD) is a widely-used thermal oil recovery technique in western Alberta's oil sands reservoirs. Because of reservoir heterogeneity, the wellbore hydraulics and undulation, non-uniform steam chambers will evolve. Numerical simulation allows for the practical prediction of steam chamber size in SAGD. However, the long computational time in 3-D scenarios and the impact of uncertainties in input parameters limit its application.

In this paper, an empirical correlation between steam chamber size and temperature falloff data during shut-in time was developed in the early period of the SAGD process which is before the moment that the steam chamber starts spreading laterally. The temperature falloff responses and the corresponding steam chamber sizes at different locations in the producer along the lateral were obtained though 3-D numerical simulation studies. Based on the simulation results, an empirical correlation among steam chamber, the temperature falloff rate and the height of liquid level in the producer was derived through regression analysis. The same correlation equation with different coefficients was also found at different shut-in times. Therefore, the proposed correlation is general and can be applied in different reservoirs at different shut-in time during the early period of SAGD process.

The applicability of the proposed empirical correlation in estimating steam chamber sizes along horizontal well is also investigated and validated. Synthetic case study shows that the chamber sizes obtained from the empirical correlation and from simulation are in good agreement and suggests that this empirical correlation can be used to estimate the chamber size distribution along the horizontal well at the early period of SAGD process.
Physicochemical Properties of Bitumen and Solids from Grosmont Carbonate Cores
Authors: Angle Chandra W. , Dabros Tadeusz
Published: June 2013

The Grosmont and Nisku carbonate formations combined contain more than 25% of Alberta's crude bitumen on the basis of initial in-place volumes, making carbonates a significant potential source of bitumen in Alberta. About 400 billion barrels of bitumen is estimated to be located in the Upper Grosmont units1. We have studied seven cores from increasing depth in the formation. X-Ray diffraction data of core particles showed pervasive dolomitization and only minor differences were observed in trace clay and calcites. The cores with trace clay and calcite impurities appeared to have the highest bitumen content. Dean-Stark analysis of four selected cores sub-samples revealed that bitumen contents ranged from 5.84 to 15.4 wt%, with negligible water present in the as-received samples. Photoacoustic Fourier transform infra red spectroscopic analysis (FTIR-PAS) of core solids surfaces before and after the bitumen was extracted showed minor differences among surfaces of the particulates from Upper Ireton (UIR) to Upper Grosmont carbonate (UGC). The organics coatings, not visible by the naked eye, were revealed earlier by fluorescence microscopy and from these previous studies showed how solubility in water was affected.2 Asphaltene contents of bitumens extracted from the cores were all higher than for typical Athabasca oilsand bitumens. Bitumen viscosities measured as a function of temperatures using a falling ball viscometer and a rotational rheometer with plate-plate geometry at constant low shear indicated small differences among the bitumen samples and between the dolomitic bitumens compared to oilsands and SAGD bitumens studied before. Arrhenius fits gave activation energies within experimental errors for the two methods used. Densities measured as a function of increased temperatures were above those of water and varied among samples.
Characterizations on Geomechanical Properties of Colorado Shale Based on Well Logging and Laboratory Testing
Authors: Li Biao , Wong Ron
Published: June 2013

Geomechancial properties of shale are essential to drilling operation and well design for thermal enhanced oil recovery. In this research, well logging and laboratory testing data are integrated to characterize the geomechanial properties of Colorado shale in Cold Lake area, Alberta, Canada. Density and sonic logs were applied to estimate the dynamic deformation modulus, Poisson's ratio, internal frictional angle, and cohesion strength. Gamma ray log is applied to estimate shale's clay content. Triaxial tests and confined torsion tests were conducted on samples to investigate transversely isotropic stiffness parameters and strength at quasi-static condition. The micro fabric characteristics of the clay shale were obtained from SEM images to investigate shale's intrinsic anisotropy. Correlations between geomechanical properties derived from well logging and laboratory testing were generated. Values of deformation modulus and Poisson's ratio derived from laboratory testing and well logging were correlated by introducing empirical coefficients. The anisotropic ratio in rock's Young's modulus is correlated to shale's clay content. The values of log-derived internal frictional angle are consistent with the laboratory tested values. The shale's clay content is found to be an important factor affecting the rock's strength.
Time-Dependent Proxy Modeling of SAGD Process
Authors: Fedutenko E. , Yang C. , Card C. , Nghiem L. X.
Published: June 2013

The present paper proposes the use of a time dependent proxy model with the goal of efficient prediction of the future production performance of SAGD operations from a limited number of reservoir simulations. The proposed model is shown to provide powerful means for developing learning functions from input-output relationships described by the reservoir dynamics entailed by multiple combinations of inputs and controls. A SAGD case with 3 well pairs is used to illustrate the approach. The workflow is organized as follows: The specified number of direct numerical simulations is run for the time horizon of ten years for the given reservoir. These simulations correspond to different combinations of the operational parameters sampled according to the Latin Hypercube Experimental Design (LHD).The time series of the simulated production performance (particularly: entire field Oil Production Rate SCTR, and entire field SOR Cumulative SCTR) are used to build the time-dependent proxy model which represents production performance as an output function of the operational parameters and time. This paper uses and compares the following interpolators in N+1- dimensional space (operational parameters and time): a) anisotropic Ordinary Kriging, b) linear regression with regularization, c) Radial Basis Functions (RBF) Network method. Note that the extension of these methods to include time as the independent variable is one of the significant contributions of this paper.The proxy model is then used to predict the production data for the given reservoir for any time period (even longer than 10 years) and any combinations of the operational parameters.The predicted data are compared with the actual simulation results for the same time period and the same combinations of the operational parameters to evaluate the prediction quality. It is shown that all three proxy models can be used as a light version of simulator to get the production results for any combination of operational parameters and time horizon with much less computational efforts.
Optimized Surfactant–Polymer Flooding for Western Canadian Heavy Oils
Authors: Luo P. , Wu Y. , Huang S.
Published: June 2013

Chemical flooding for Western Canadian heavy oil reservoirs has gained popularity in recent years because of its satisfactory recovery efficiency and low facility cost. Formation brines in most of these reservoirs have extremely high salinity and hardness. Addition of alkali is prone to causing severe precipitation/scaling problems in both the injection/formation brinesand production facilities. As well, breaking of the emulsion generated during oil production is problematic in the presence of alkali. In order to overcome the operation/handling issues associated with alkali, an alkali-free surfactant–polymer (SP) flooding EOR method needs to be developed and evaluated.

In this work, several amphoteric surfactants, which exhibit higher salinity- and hardness-resistance than common anionic surfactants, were evaluated in combination with the polymer polyacrylamide. For the crude heavy oil and brine studied, a fairly low interfacial tension (IFT) of 0.012 dyne/cm was measured at 0.1 wt% of surfactant concentration. Emulsification tests showed that the surfactant could easily generate oil-in-water emulsion in the heavy oil–brine system, while it was more difficult to form emulsion with the SP system due to its higher viscosity. Addition of the surfactant helped to slightly increase the polymer solution's viscosity, since the surfactant itself is a viscoelastic fluid. The SP system exhibited long-term stability with consistent viscosity and IFT, whereas an alkaline–surfactant–polymer (ASP) system had increased viscosity for the first 15 days due to solids precipitation in the brine and possible polymer hydrolysis.

To compare the recovery efficiency by different chemical injectants, three coreflood tests were conducted using P, SP, or ASP systems. ASP flooding had the highest enhanced oil recovery (chemical injection + extended waterflood] of 25.17% original oil in place (OOIP), followed by SP flooding (24.38% OOIP) and P flooding (20.23% OOIP). However, the potential for operational problems evident with the use of alkali might restrict the application of ASP flooding. Varied oil recoveries at the chemical injection and EWF stages, as well as pressure drop variation (resistance factor), indicated that different recovery mechanisms were involved in each chemical flood. Given its satisfactory recovery results and potential to avoid operational problems, with careful optimization, SP flooding presents a promising method for heavy oil enhanced oil recovery, particularly for Western Canadian heavy oil reservoirs.
Method for Attenuation Calibration of Dual Wavelength Raman Distributed Temperature Sensing Systems
Authors: Mitchell Ian , Walsh Russ
Published: June 2013

In this paper we report on a novel technique of applying dual-wavelength Distributed Temperature Sensing (DTS) interrogators to auto-adjust for differential attenuation caused by macro-bending and scattering/absorption based losses. We present the results of a comparison between dual-wavelength technology and traditional single wavelength systems.
Streamline Based Coupled Geomechanics and Reservoir Simulation for Hydromechanical Modelling of CO2 Storage in Saline Aquifers
Authors: Hosseini Behrooz Koohmareh , Chalaturnyk Rick
Published: June 2013

Most recent studies on hydro-mechanical simulation of underground CO2 storage in saline aquifers have been focused either on the early reservoir life and short term migration of CO2 plume, or on near field scenarios in the vicinity of injection well. The main reason is the crucial computational cost that current coupling schemes and simulators carry out. Particularly, realistic inclusion of geomechanics into fluid flow processes is a bottle neck in hydro-mechanical coupling of large heterogeneous models of stress sensitive reservoirs with complex fluid flow and geomechanical physics. This work introduces a new coupling scheme between fluid flow and rock deformation, for rapid hydro-mechanical simulation of large heterogeneous reservoirs with elastic geomechanical constitutive behaviors. The technique is mainly about using of streamline simulations for hydro-mechanical coupling purposes. To assess the efficiency of the technique in terms of speed and accuracy, a large reservoir-cap rock system with relatively large number of grid-blocks was made. The speed and robustness of streamline-based hydromechanical coupling was investigated versus finite volume based flow-geomechanical simulations for the same model with the same geometry and physics. The concept of effective stress was applied in characterizing the stress state. The governing geomechanical and fluid flow equations were implemented based on mass and momentum balance equation for linear elastic materials. Forward flow streamline simulation was performed with 3DSL, which is developed on the FORTRAN platform. This paper first investigated the feasibility of inclusion of geomechanics in streamline simulation, and in the next step compared the efficiency and accuracy of the developed scheme to one of the conventional finite-volume based fluid flow-geomechanical simulations. The FV-FEA tool was developed based on Box-method (subdomain collocated finite-volume finite-element technique) to couple fluid flow and geomechanics to be compared with the so called SL-based hydromechanical coupling. The simulation results and comparative studies between two appraoches, demonstrated that the introduced technique is robust and increases the model efficiency and decreases the computational costs significantly. The approach also demonstrated to be helpful in hydromechanical coupling of CO2 storage, particularly for large domains and during the injection period.
Wellbore Efficiency Model for CO2 Geological Storage Part I: Theory and Wellbore Element
Authors: Nabih Ahmad , Chalaturnyk Richard
Published: June 2013

Storing carbon dioxide (CO2) in deep geological formations is one part of the carbon capture and storage (CCS) process. The process of storing CO2 into deep geological formations is defined as geological CO2 sequestration or CO2 geo-sequestration. Injecting CO2 into a reservoir does not guarantee safe storage because CO2 could leak back to the surface and/or may contaminate specific strata where other energy, mineral and/or groundwater resources are present. Two mechanisms control assurance of storage integrity, which are containment within the geological structure and minimizing the potential for wellbore leakage (Espie, 2005).

This study is concerned with describing the wellbore leakage mechanism utilizing wellbore element, which will be extended to the whole wellbore system. To get a better chance of success in practice, successful CCS depends on the small-scale leakage problem associated with localized flow along wellbores. Our knowledge of wellbore performance for storage purposes is still weak.

The paper is the first of a series to model wellbore element analytically by introducing wellbore sealing efficiency index. Wellbore sealing efficiency can be used as a ranking criteria between different wellbore elements in the same well and/or different wells in the same locality. Moreover, safety performance of wellbore element can be assessed.
Consideration of Geomechanics for In-situ Bitumen Recovery in Xinjiang, China
Authors: Yuan Xinsheng , Dou Shenjun , Zhang Jing , Chen Sen , Xu Bin
Published: June 2013

This paper describes a geomechanical work program carried out in Karamay heavy oil field, Xinjiang Province, China. Three mini-frac tests were conducted to measure the in-situ minimum stresses in the reservoir sands, shale interbed and caprock shales. Geomechanical triaxial tests under room- and high-temperature were completed to investigate the geomechanical properties of the reservoir sands. These works were motivated by repeating the success experienced in Alberta oilsands reservoirs which proactively use geomechanics to enhance the in-situ thermal recovery. One particular technology, i.e. using geomechanical dilation mechanism for early SAGD start-up was successfully demonstrated on one SAGD well pair in the Karamay reservoir. The results from the mini-frac tests and laboratory tests are presented and compared with the oilsands reservoirs in Alberta, Canada. Differences were discovered. Petrophysical and mineralogical measurements were made and geological origins are sought to explain the difference. Furthermore, relevant results from the dilation start-up demonstration are also shared to the end of this paper. Such success has proven again that geomechanics is equally important in the optimization of in-situ thermal stimulation of the heavy oil reservoirs in Karamay heavy oil field.
A Transient Two-phase Fluid and Heat Flow Model for Gas-lift Assisted Waxy Crude Wells with Periodical Electric Heating
Authors: Han Guoqing , Zhang He , Ling Kegang
Published: June 2013

This paper presents innovative iteration algorithms for multi-interface heat transfer in pipe flow. To the best of our knowledge, this is the first approach derived from Drift-flux Model (DFM), which is more competent than mechanistic models for high slippage gas-liquid flow. Consequently, the temperature/pressure distribution profiles can be accurately captured under transient condition.

For waxy crude fields, it's critical to sustain the flowing temperature above the Wax Appearance Temperature (WAT). This is especially challenging for gas-lift assisted wells. The injected gas, commonly at relatively low temperature, leads this flow assurance problem sophisticated. An effective practice is to heat up the flowing fluid by installing an electrical cable in tubing. Such the heat exchange happens at three interfaces in the production system: between cable and flowing crude, flowing crude and injected gas, injected gas and formation. Therefore, it is challenging to model such a multiphase production system including an inner annulus inside tubing as the electrical able installed, and an outer annulus where the gas is injected. To optimize this production system, a rigorous transient multiphase and multi-interface heat transfer simulator has been demanded.

With explicitly integrating with the subsurface boundary condition, our new algorithms can optimize the cable length, heating period, supplied power, or gas injection rate for the aforementioned production system. This new method has been successfully applied for several gas-lift assisted wells in a waxy crude field located in north China. The power consumption has been noticeably decreased by 30% than the historical field performance. The delegated optimization scheme reduces the shut-in time in winters, which has promised a cost-saving development.

The presented model not only satisfies the exceptional modeling requirements for periodically-heating crude producers, but also it is appropriate for other heat transfer investigations under transient multi-interface and multiphase flow condition.
Rodless PCP Technology: From Theory to Reality; Analyzing One Year of Performance
Authors: Garcia Gilberto Jose
Published: June 2013

Oil producers have been utilizing Progressing Cavity Pumps (PCP) for decades, as it is the optimal method of artificial lift to effectively handle fluids with high solid content. These wells can be vertical, directional or horizontal, while the latter two optimize in-flow performance and maximize fluid rates. Conversely, these well-bore geometries create high contact loading between the rod and tubing, which ultimately leads to an increased and costly intervention frequency to repair failed rod and/or tubing. While there are several products that exist to prolong run-time in these environments (Endless Rod, Tubing Rotators, etc.), these failures cannot be entirely eliminated, and in some cases make these wells uneconomical to produce.

The oil industry has been looking for an alternative to effectively and economically produce these troublesome oil wells. Many producers have been on a crusade seeking an alternative to a conventional rod driven PC Pump. This crusade has led to the development of a Rod-less PCP system, allowing the full benefit of the pumps ability to handle solids, while eliminating the primary cause of failure: the rod string.

A major requirement to effectively operate a Rod-less PCP system is the ability to provide sufficient rotational torque. With this in mind, a team of industry professionals in their respective fields (Electrical Submersible Pumps, PCP, and Sensor-less Surface Control or SSC) began working cohesively to develop an all-inclusive system. The system provides full surface control and monitoring using the down-hole intake/discharge pressure gauges, a vibration sensor, and a motor winding thermocouple.
Shale Barrier Failure Strategies in Heterogeneous SAGD Reservoirs: A Case Study
Authors: Wu Yongbin , Jiang Youwei , He Wanjun , Guan Wenlong , Zhao Xin , Qi Shilong
Published: June 2013

In Xinjiang, China, a huge volume of heavy oil deposits is not commercially developed yet due to the high in-situ oil viscosity that is higher than 100,000 to 1,000,000+ cp and the strong reservoir heterogeneity. Two SAGD pilot tests with 11 wellpairs in total have been carried out since 2008 while the extensively distribution of shale barriers result in the poor SAGD steam chamber conformance, low production rate and high SOR.

This paper presents the workflow to break shale barriers to improve the steam chamber development along horizontal section, to reduce the SOR and to enhance the economic performance. The first step of the workflow is to select representative core and shale barrier samples and quantify the geomechanic data by high-pressure-high temperature dilation and shale barrier failure experiments. Meanwhile, the geologic model is built taking into account geological uncertainties of the reservoir and the core analysis results. And then, a small set of SAGD wellpair models are selected as the typical wellpair models by classifying different patterns of shale barriers distribution along horizontal section. Finally, the upscaled thermal reservoir models with geomechanics models using the data acquired by geomechanic experiments are investigated to model and optimize operation strategies for dynamic fracturing and shale barrier failure during SAGD phase.

The research reveals that the high-pressure CSS is an effective method to break the shale barrier distributed between the horizontal segments of the producer and the injector, which has been verified by field experience and the numerical simulation. It is forecasted that the case without HP-CSS will have the steam chamber growth at 50% percent of horizontal segment, which is 40% less than the case CSS. The ultimate oil recovery factor is 34.54%, which is 16.31% less than the case with HP-CSS; and the cumulative oil/steam ratio is 0.175,, which is 14.5% less than the case with HP-CSS, encouraging SAGD performance after HP-CSS shows a better economic performance, which is worthwhile to carry out and also has a significant guidance for the similar SAGD reservoirs to improve the performance.
Cold Heavy Oil Development: Learn from the Past, Plan for the Future
Authors: Tg. Othman Tg Rasidi , El Emam M Medhat , Tewari Raj Deo , Ramli Anis Salwa , Anasir Nadiah , A. Rahman M. Izzat , Sulleh Shahida , M. Ahmed Sameh
Published: June 2013

Worldwide energy demand is continuously increasing with the current pace of development and oil continues to play a crucial role in total energy mix. It is becoming difficult to meet the demand of crude oil with existing light and medium crude oilfields as production from these fields which are mostly in matured stage, are declining. This has necessitated more attention for increasing the exploitation of heavy and extra heavy oilfields.

Estimates of recovery factors contain inherent uncertainty especially more in early stage. The range of uncertainty in estimates of reserves depends mainly on the degree of geologic complexity, the maturity of the asset, the quality and quantity of geologic and engineering data and the operating environment. Therefore, it becomes critical to understand and determine reservoir parameters which are crucial in estimation and prediction of well and field performance in heavy oilfields. Well spacing, completion techniques, operating practices and regulations can have a significant influence on ultimate recovery.

Primary recoveries from heavy and extra heavy oil fields are very low in cold production mode. Therefore, application of thermal enhanced oil recovery becomes inevitable to improve the recovery from such reservoirs. However, cold production is still favorable at early stage due to low upfront investment.

This study has reviewed and analyzed the development and performance of large number of fields of various sizes under cold production spread over different parts of the globe and developed statistical relationships between geologic-engineering parameters and deliverables like recovery and production. These empirical relations can form basis and be used as guiding principles for heavy oil asset evaluation, initiating the early primary development and their benchmarking to the established industry practices in cold production.
How Heavy Gas Solvents Reduce Heavy Oil Viscosity?
Authors: Imai Motonao , Nishioka Ichiro , Nakano Masanori , Kaneko Fuminori
Published: June 2013

In the past decade, in-situ heavy oil recovery processes have been proposed and successfully applied to field operations. In conventional ways like cyclic steam stimulation (CSS) and steam assisted gravity drainage (SAGD), viscosity of heavy oil is reduced by steam injection. However, since the cost of steam generation remains high, solvent injection has been considered to decrease steam-oil ratio (SOR). In many cases, solvent means relatively heavy hydrocarbon gas components ranging from C3 to C6. In this paper, we discuss the effect of heavy gas solvents on viscosity reduction.

Our target reservoir is the Yufutsu oil field, Hokkaido, Japan. Its produced oil is highly viscous and we have to consider an enhanced oil recovery process. Viscosity and gravity of the Yufutsu fluid are 846 cP and 11°API respectively at stock tank condition. Since gas injection is one reasonable choice to reduce oil viscosity, we conducted swelling tests and viscosity measurements using two different gas samples. The first gas sample is a light gas mixture which is a main product of the facility and pipelined to the markets. The second one is a heavy gas mixture which is a subsidiary product of the manufacturing processes, and contains C2, C3 and C4 components significantly. According to our swelling tests, the heavy gas mixture achieved greater swelling factor and viscosity reduction than the other. In terms of viscosity reduction, the heavy gas achieved 94%, while the light gas achieved 88%.

Additionally, we conducted simulation studies to examine the effect of heavy gas solvent on viscosity reduction. We generated 2-dimentional preliminary heavy oil reservoir models. The results of simulation studies indicate that the injection of heavy gas solvent reduces oil viscosity, and increases oil recovery more than the light gas case.

In conclusion, according to our experiments and simulation analyses, the heavy gas solvent shows more oil viscosity reduction than the light gas solvent. This fact implies the heavy gas components, C2, C3 and C4, play important roles in oil viscosity reduction, and will help to decide an optimal composition of solvents in heavy oil production.
A State-of-the-Art Computational Fluid Dynamics Simulation for Erosion Rates Prediction in a Bottom Hole Electrical Submersible Pump
Authors: Marsis Emanuel , Russell Ronnie
Published: June 2013

Electrical submersible pumps (ESP) are used extensively in the production of oil and gas. A multi-vane pump is a special type of ESP designed to handle high gas volume fractions and eliminate gas lock. Erosion in ESP systems due to sand production is a major problem that can cause equipment failure. Extensive numerical study has been performed to simulate the flow of sand particles inside a multi-vane ESP pump.

This study utilizes two computational fluid dynamics (CFD) erosion models. The first CFD erosion calculation model, ERC-2003, was empirically developed in 2003 by Russell et al. (Russell 2004), and applied in this paper to predict erosion rates inside an ESP. The second CFD erosion model, ERC-2008, is a modification developed by Ronnie Russell in 2008 to broaden the accuracy range to low-velocity flow. A state-of-the-art erosion prediction technique is presented in this paper. The generalized CFD code utilized in the simulations in this paper was ANSYS Fluent for erosion prediction. Discrete phase models (DPM) and Eulerian-Eulerian granular models were compared, and the pump pressure head was used to validate the hydrodynamic models. Results show that the pump diffuser casing and impeller blades' pressure sides consistently have the highest erosion rates. In addition, the Eulerian-Eulerian granular model shows a more homogenous distribution of sand concentration in the pump compared to the DPM model. The main difference between the two models is that the Eulerian- Eulerian granular model considers the two phases and solves for each phase separately from the beginning of the simulation, while the DPM model stops the fluid iterations to carry out its discrete particle tracking iterations. Therefore, the Eulerian- Eulerian granular model can predict erosion in turbomachinery more accurately compared to the DPM model.
Effect of Dead Oil Viscosity and Injected Solvent Type on SVX Process Performance
Authors: Knorr Kelvin(Kelly) D , Imran Muhammad
Published: June 2013

This work presents experimental results of four 3D physical model experiments that were performed to evaluate the dependence of solvent vapour extraction (SVX) recovery process performance on initial dead oil viscosity and injected solvent mixture composition. Model excavation studies were also performed to approximate the solvent movement in the physical model and to map out the residual oil saturation and precipitated asphaltenes.

All of the four experiments — designated as SVX 14, 15, 16 and 17A — were performed on a 3D physical model (having permeability and porosity of ~4 darcy and ~33%, respectively) that was oriented vertically to provide model dimensions of 2.5 m thick by 0.2 m wide by 0.5 m long. The 0.5-m-long horizontal top injection and bottom production wells were separated laterally across the width and vertically across the thickness. Prior to solvent injection the model was resaturated with live oil containing methane at a gas/oil ratio ranging from 8.5 to 11 sm3/sm3. The initial dead oil viscosity at 21°C for SVX 14, 15, 16 and 17A were approximately 13,000, 33,000, 16,000, and 48,000 mPa•s, respectively. The composition of the injected solvent mixture for SVX 14 and 15 was ~57/43 mol% of methane (C1)/propane (C3) and for SVX 16 and 17A was ~57/43 mol% of carbon dioxide (CO2)/propane (C3).

The analysis of the experimental results revealed that the initial dead oil viscosity had a significant effect on the SVX performance. Higher oil production rates were achieved with the lower viscosity oils for both injected solvent mixture types, with a more pronounced effect observed when using the CO2/C3 solvent mixture. The results also showed that the CO2/C3 mixture resulted in earlier solvent breakthrough and initial oil production, reduced solvent makeup requirements (i.e., better solvent recycle stream), and reduced solvent retention in the model/reservoir, as compared to the C1/C3 solvent mixture. The residual oil saturation mapping showed that the CO2/C3 mixture led to comparatively lower values in the drained regions and higher amount of precipitated asphaltenes remaining in the model, although there was evidence of some precipitated asphaltenes close to both the injection and production wells in all four experiments, regardless of the solvent mixture type. Finally, this mapping also indicated that the solvent/oil interfaces and solvent chambers were more uniform and predictable for the CO2/C3 solvent mixture injection.

The field scale application and optimization of SVX processes requires that relationships be established among oil production rates, solvent utilization, and important process parameters such as matrix permeability, initial oil viscosity, solvent mixture composition, solvent utilization, etc. This work has attempted to generate such relationships for the two most promising mixed solvent systems being considered for use in heavy oil reservoirs.
A Novel Solvent Injection Technique for Enhanced Heavy Oil Recovery: Cyclic Production with Continuous Solvent Injection
Authors: Jiang T. , Jia X. , Zeng F. , Gu Y.
Published: June 2013

Solvent-based in-situ enhance oil recovery (EOR) techniques are extensively studied to improve oil recovery factors (RFs) for heavy oil reservoirs. Continuous injection, such as vapour extraction (VAPEX), and cyclic injection, such as cyclic solvent injection (CSI) are two main categories of solvent EOR techniques. The production rates of VAPEX are low in field tests. CSI does not show exciting results due to the quick reservoir pressure depletion and the sudden reservoir energy loss, which causes the oil to regain its viscosity.

A new enhanced heavy oil recovery technique, cyclic production with continuous solvent injection (CPCSI), is proposed in this paper. In this process, a vapour solvent is continuously injected into the reservoir to maintain reservoir pressure and also supply extra gas drive to flood the diluted oil out through an injector that is located on the top of the reservoir, while a producer, which is located at the bottom of the reservoir, is operated in a shut-in/open cyclic way. A series of experiments have been conducted to validate the CPCSI performance by using different sand-pack models with 4¬-5 Darcy permeability, and saturated with Western Canada heavy oil sample. Gaseous propane is continuously injected through an injector at a constant pressure, which is below the dew point pressure, and producer was operated with a cycle of 50-minute-shut-in/10-minute-open period.

Experimental results show that, the oil is diluted and drained down by gravity during shut-in period, then produced in producer opening period by solution gas drive and gas flush. In comparison with VAPEX and CSI, CPCSI offers free gas driving, and still keeps oil diluted in the well opening period and produced by the gas flush. The RFs are up to 85% of OOIP in 1-D tests. Also, shorter height model has highest average production rate in comparison with others. Test results are also validated by 2-D physical model, in which the RF is improved by 11% by using the lateral CPCSI compared with classic lateral VAPEX. Well configurations and the shut-in/open scenarios are key optimization factors that affect CPCSI performance.

This work shows that CPCSI could be an alternative optimization production scenario for applying solvent based in-situ EOR techniques for Western Canada heavy oil reservoirs.
Integrated Solution for Underbalanced Perforation and Wellbore Clean Up as an Alternative Methodology
Authors: Mohamed H. N. , Osuji-Bells G. A. , Khalid M. Zaidan , Khaira K. , Lafontan J. , Ismail M. Rizal
Published: June 2013

Conventionally, a well completion would involve perforating the reservoir followed by a separate run to clean up the wellbore from perforating debris and burrs on the casing and liner to prevent damage to the completion packer when passing through the perforated interval. This is especially prevelant in dual completion and single selective completion wells where the lower packer will have to be run past the upper set of perforations. The wellbore clean up bottomhole assembly typically consists of a drill bit scraper and magnets run between the perforating and well completion phases.

As a result of the increasing emphasis on reducing operating costs and increasing operating efficiency, a new system was designed for perforating wells in underballanced condition and performing post perforation wellbore clean up in the same run by using standard equipment and techniques. The concept was developed after identifying the opportunity to optimize operations in wells where the perforating and wellbore clean up equipment operations are required.

Five jobs have been performed employing this combined underballanced perforating and wellbore clean up technique which have resulted in significant savings in rig time and increased operating efficiency. This paper summarizes the practical experiences gained during the development and deployment of this integrated perforating and wellbore clean up technique.
Efficient Displacement of Heavy Oil using Three Hydrocarbon Phases
Authors: Okuno R. , Xu Z.
Published: June 2013

Mixtures of oil with solvent gas can exhibit three-hydrocarbon-phase behavior at reservoir conditions, where the solvent-rich liquid (L2) phase coexists with the gaseous (V) and oleic (L1) phases. Three-hydrocarbon-phase behavior has been studied in the literature for CO2 floods and enriched gas floods at relatively low temperatures. Prior research on heavy-oil displacement with enriched gas presented that displacement efficiency at a given throughput can be non-monotonic with respect to gas enrichment. Slim-tube experiments for such displacements showed that oil recovery increased first, then decreased, and increased again with increasing gas enrichment. An optimum displacement with a high efficiency of more than 90% was observed when three-hydrocarbon-phase flow was present. However, detailed mechanisms for such an optimum displacement with three phases have not been explained in the literature.

In this research, we investigate mass transfer on multiphase transitions between two and three phases for three-hydrocarbon-phase displacements. Simple conditions are derived for the multiphase transitions that yield high local displacement efficiency by three hydrocarbon phases. The derivation is based on the generalized jump conditions for a multiphase transition shock from analytical theory of one-dimensional gas injection. The conditions derived are applied to explain non-monotonic oil recovery in quaternary displacements and the West Sak oil displacements.

Oil recovery at a given throughput can be non-monotonic with respect to pressure or gas enrichment. Such a non-monotonic trend can occur when local oil displacement by three hydrocarbon phases becomes more efficient, but slower, with decreasing pressure or decreasing gas enrichment. An optimum pressure or enrichment can occur as a consequence of the balance between the local displacement efficiency and the propagation rate of three hydrocarbon phases. The West Sak oil displacement with enriched gas studied in this research yields a high displacement efficiency of more than 90% at 1.5 hydrocarbon-pore-volumes injected at 53% methane dilution.
SAGD Pad Performance in an Ultra-Defined Athabasca Point Bar Deposit
Authors: Su Yi , Wang Jingyi , Gates Ian
Published: June 2013

It has been shown that the performance of a Steam-Assisted Gravity Drainage (SAGD) well pair is affected by its orientation and position within a point bar. In typical commercial operations, multiple wellpairs, usually arranged parallel to each other, are arranged in pads within oil sands reservoirs. Thus, the overall performance of the recovery process in a point bar is not that of a single well pair but reflected by oil accumulation differences, interactions between well pairs (pressure and fluid flow), and how the well pairs interact with the structure and geometry of the point bar including the arrangement of inclined heterolithic strata relative to the SAGD well pairs. This research describes how the point bar structure impacts the performance of a pad of SAGD wellpairs and the impact of pad orientation on performance of the pad. The results show that the performance of well pairs in a SAGD pad are affected by the orientation of the pad within the point bar. Also, the results show that the variability of the performance of the well pairs within the pad is large and thus, single well pair models do not provide sufficient analysis of process performance due to the heterogeneity of the point bar. In other words, pad-scale models are required for recovery process evaluation and design.
Benefits of Passive Inflow Control Devices in a SAGD Completion
Authors: Banerjee Sudiptya , Abdelfattah Tarik , Nguyen Hang
Published: June 2013

Passive inflow control devices (PICDs) have been in use for decades as a tool to manage both frictional effects within the completion system and reservoir heterogeneities that result in an unbalanced injection or production profile. These tools provide an additional pressure drop at select points along a well lateral, evening the distributed flow profile and maximizing economic recovery of oil and gas. Conventional applications of PICDs have become increasingly well understood, yet novel uses still exist, such as the use of PICDs in steam-assisted gravity drainage (SAGD) environments. The SAGD well is characterized by a number of challenges, including poor development of the steam chamber, low reservoir pressure, uneven oil production, and contrasting reservoir permeability. In this paper a typical Albertan SAGD environment is considered against known PICD behavior to quantify the economic benefits of PICD use in the SAGD well pair. Furthermore, the specific benefits of hybrid-geometry autonomous PICDs are highlighted for use in the production well, focusing on possible "steam trap" effects with this geometry. Lessons learned regarding PICD simulation in a thermal environment are shared, outlining a suggested workflow for future modeling work.