bluuebunny/crossref_metadata_2025 huggingface dataset:
Steam Flow Tests for Comparing Performance of Nozzle, Tube, and Fluidic Diode Autonomous ICDs in SAGD Wells
Authors: Least Brandon , Greci Stephen , Huffer Ryan , Rajan Raj V. , Golbeck Hart
Published: June 2014

Many operators are considering installation of flow-control devices (FCDs) in horizontal wells to improve steam-oil ratios (SOR) in steam-assisted gravity drainage (SAGD) recovery processes in heavy oil/bitumen reservoirs. The flow-control devices are used to help balance both the steam injection and fluid production in order to increase the oil recovery efficiency and use the full length of the horizontal wells. SAGD injector and producer horizontal wells are typically 3 to 6 meters apart, vertically. Because of this proximity, steam breakthrough to the producer well is possible. In order to reduce the steam loss following a steam breakthrough, operators typically try to slow the total rate of production.

This paper will discuss the testing of passive inflow control devices (ICDs) and an autonomous inflow control device (AICD) in a steam-flow test loop along with testing results to help control the breakthrough of steam. Heated water flow through the ICDs and AICDs was used as the baseline case. Saturated steam simulating steam flow conditions (pressure and temperature) in a SAGD environment was flowed through the devices at two different temperatures, and the resulting flow rates were recorded at several pressure differentials.

The laboratory flow testing has helped demonstrate how the ICDs and AICDs can either help prevent steam breakthrough from occurring or limit the rate of steam breakthrough in the zones of concern. By limiting the flow rate of steam breakthrough, the flow control devices will also help to protect the sand screen from erosion caused by high velocity flow.
Russkoe High Viscous Oil Field - Production And Performance Optimization
Authors: Lachugin D. S. , Edelman I. Y. , Shandrygin A. N. , Aksenov M. A. , Lachugina Y. V. , Abramochkin S. A. , Davidovskiy A. D.
Published: June 2014

The Russkoe oil and gas field was discovered in 1968. It is one of the biggest and complex fields in Russia. It has yet to be put to production, however the development is already concerned by a number of geological and operational issues, such as high crude viscosity, remote location (beyond the Polar Circle), considerable heterogeneity, compartmentalization of poorly cemented sandstones as well as the presence of extensive gas cap, bottom water, and thick permafrost zone.

OJSC "Tyumenneftegaz", a subsidiary of Rosneft, has been responsible for the pilot works to seek operational solutions for full-field development. Intensive pilot wells drilling and testing have been performed since 2007 in different zones of the field. In 2009-2012 23 wells, including 16 horizontal ones, were drilled in these pilot areas. Additionally cold and hot water injection tests have been conducted in one of the pilot areas. The main goal of these studies was to learn and reduce geological risks and to find an effective system for full-field development.

The article presents the data and results of pilot operations as well as the methods and equipment for monitoring of the pilot works including multi-phase measurements of flow rates of producers using Vx tool, measurements of flow rates of injectors, tests of injectivity/inflow profiles in horizontal sections using DTS and PLT systems, measurements of bottom hole pressure dynamics and parameters of PCPs and ESPs using high precision metering systems.

Effectiveness of different control and monitoring methods and of different production technologies has been analyzed. As a result applicability of these methods for the development of viscous oil fields under difficult weather conditions has given using the example of the Russkoe field.
Field Upgrading Of Bitumen To Produce A Synthetic Crude Oil With Improved Properties
Authors: Till Andrew , Rees Andrew , Schleiffer Andreas
Published: June 2014

Crude bitumen extracted from the Canadian oil sands has a high viscosity, so typically it does not flow at normal pipeline temperatures. After extraction the bitumen can be mixed with a diluent (refined naphtha, condensate or SCO) before being pumped by pipeline to a refinery for processing. Alternatively the bitumen can be processed to either improve the viscosity, produce a higher value synthetic crude oil (SCO), or fully finished products before export. These additional costs can significantly impact the overall economics of bitumen extraction.

The Veba Combi-Cracking™ (VCC™) process is a proven slurry based hydrogen addition technology able to process refinery residues, heavy crude oil and even coal. Commonly found in a refinery environment it is also ideally suited to field upgrading, since it can be tailored to produce directly marketable products, a high quality synthetic crude oil, or simply provide viscosity reduction for easy transportation.

This paper shows that the VCC™ technology is ideally suited to field upgrading of bitumen. With an Athabasca Bitumen feedstock the VCC™ process can achieve greater than 90% conversion of asphaltenes, and a 95% overall conversion of the 524°C+ material to desirable products, in a single pass. This paper also shows an improvement in overall efficiency and minimisation of undesirable products when compared to other common field upgrading processes. With simple changes to the flowsheet it is capable of producing high quality finished products (Naphtha: 1 ppm S, Diesel: <10 ppm S, Cetane >45, VGO: <100 ppm S, Metals <1 ppm), a fully upgraded syncrude, or alternatively provide significant viscosity reduction (example heavy crude VR reduced from 145, 800 cSt to 3.0 cSt) for export by pipeline.
Opportunities and Challenges of Cyclic Steam Stimulation (CSS) Development in Seal's Cadotte Area
Authors: Jamaloei B. Y. , Singh A. , Solberg A.
Published: June 2014

Murphy's Seal asset in Peace River Oil-sands renders a strong incentive for application of EOR techniques. A combination of primary depletion and thermal/non-thermal EOR techniques (polymer flood, Cyclic Steam Stimulation (CSS), and Vertical Steam Drive (VSD)) are currently being pursued or evaluated by Murphy Oil to increase Seal's production. High oil viscosity in Seal's Cadotte does not allow for primary development and non-thermal EOR schemes in this area. Hence, Cadotte has been considered for application of CSS and VSD. This study highlights the opportunities and challenges of Cadotte's CSS development using pilot results, history-match/forecast, optimization and uncertainty analysis.

The impacts of reservoir features that complicate Cadotte's CSS development are quantified through history-match/optimization, sensitivity analysis and uncertainty assessment. These features include a presence of multiple PVT regions and water pockets, varying rock dilation, fracturing, and pay-zone thickness variation. Reservoir simulation, Latin hypercube designs, and response surface methodology are used to conduct the history-match, optimization, sensitivity analysis and uncertainty assessment.

Because the underlying geology in Seal is complex, one focus of this study is to isolate the effect of geological complexities on CSS development by conducting the history-matching/forecast using a layer-cake model updated by 3-D seismic and log analyses.

By accounting for geological and reservoir/operation variances, this integrated study helps determine optimum CSS development in Cadotte. It also sheds light on how to screen reservoir/operation parameters for successful application of CSS in geologically-complex reservoirs with a varying PVT behavior.
Experimental and Numerical Studies of the Reservoir Permeability and Drainage Height Effects on the Solvent-Diluted Heavy Oil Gravity Drainage
Authors: Lin Lixing , Ma Hongze , Zeng Fanhua , Gu Yongan
Published: June 2014

Solvent-based enhanced heavy oil recovery techniques are promising alternatives to thermal-based methods. A better understanding of the solvent-diluted heavy oil gravity drainage is important to practical field-scale applications of the solvent-based heavy oil recovery processes. In particular, the transmissibility, which is defined as the product of the absolute permeability k and pay-zone thickness h of an oil reservoir, is an important parameter to affect the solvent-diluted heavy oil gravity drainage. In this paper, a series of experimental tests were conducted in a visual high-pressure physical model to study the permeability effect. The physical model was packed with the Ottawa sands of different sizes to obtain different absolute permeabilities in the range of k = 7–54 Darcy. The original heavy oil sample collected from the Lloydminster area in Canada was used to saturate the sand-packed physical model and pure propane was used to extract the heavy oil. The drainage height effect was studied by performing the solvent-diluted heavy oil gravity drainage tests in another visual physical model with a different drainage height. The produced heavy oil and solvent were collected and recorded in each test. The produced oil samples obtained at different times were flashed and the flashed-off heavy oil viscosities were measured. It was found that heavy oil was produced much faster in a higher permeability physical model with a larger drainage height. A new correlation was developed to take account of the reservoir permeability and drainage height effects (i.e., the transmissibility effect) on the heavy oil production. In addition, the average produced solvent–oil ratio (SOR) was determined to be in the range of 0.3–0.6 g solvent/g heavy oil. The average SOR was increased as the reservoir permeability and drainage height were decreased. It was also found that the produced heavy oil viscosity was reduced significantly. Furthermore, numerical simulations were undertaken by using CMG STARS module to match the experimental results. This study provides much-needed physical and practical understanding of the solvent-based heavy oil recovery.
Screen-Inflow-Design Considerations with Inflow Control Devices in Heavy Oil
Authors: Oyeka Onyema , Felten Frederic , Least Brandon
Published: June 2014

Inflow control devices (ICDs) improve oil recovery because of their capability to delay water and gas breakthrough. ICDs also can be applied to heavy oil reservoirs to help overcome the higher mobility of water, and therefore, are now frequently used in Canada's Steam-Assisted Gravity Drainage (SAGD) heavy oil market to improve steam/oil ratio. Unfortunately, upstream flow behavior of ICDs is often ignored; however, flow through the screen-basepipe annulus can induce higher-than-expected pressure losses, and since these losses (not experienced with water) also reduce efficiency and lower performance, special attention should be given to flow-path characteristics.

This paper examines pressure drops through the screen basepipe annulus of a direct wrap-on-pipe-type screen before entering the ICD. Using Computational Fluid Dynamics (CFD) simulations, the axial flow through the screen-basepipe annulus of a direct-wrap screen was simulated for three fluids. In addition, several flow rates and multiple-rib-wire-height wire types were used to cover a broad range of operations. The results of the simulations and analyses support the hypothesis that taller ribs would result in a lower pressure drop through the annulus. These simulations and analyses will show that increasing the rib height will cause the overall pressure drop in the annulus to decrease, often by as high a factor as four.

These results will help determine optimum screen/base-pipe annulus spacing during screen design.
Characterizing the Effects of Lean Zones and Shale Distribution in SAGD Recovery Performance
Authors: Wang Cui , Leung Juliana Y.
Published: June 2014

Performance of steam-assisted gravity drainage (SAGD) is influenced significantly by the distributions of lean zones and shale barriers, which tend to impede the vertical growth and lateral spread of a steam chamber. Previous works in the literature have partially addressed their effects on SAGD performance; however, a comprehensive and systematic investigation of the heterogeneous distribution (location, continuity, size, and proportions) of shale barriers and lean zones is still lacking.

In this study, numerical simulations are used to model the SAGD process. Capillarity and relative permeability effects, which have been ignored in many previous simulation studies, are incorporated to model bypassed oil. A ranking scheme based on cumulative oil production and cumulative steam oil ratio is devised. A detailed sensitivity analysis is performed by varying the location, continuity, size, proportions, and saturation of these heterogeneous features. Lean zones and shale lens (imbedded in a region of degraded rock properties) with different thickness and degree of continuity are placed in areas located either above the injector, below the producer, or in between the well pair. It is noted that among numerous parameters that influence the ultimate recovery, remaining bypassed oil, chamber advancement, and heat loss, continuity and position of these features in relation to the well pair play a particularly crucial role. We subsequently employ neural network modeling for constructing data-driven models to identify and propose a set of input variables for correlating relevant parameters or measures, which are descriptive of the heterogeneity and properties of the shale barriers, to recovery and ranking results.

This work provides a guideline for assessing the impacts of reservoir and saturation heterogeneities on SAGD performance. We identify a set of input variables and parameters that have significant impacts on the ensuing recovery response. The proposed set of variables can be defined readily from well logs and applied immediately in data-driven models with field data and scale-up analysis of experimental models to assist field-operation design and evaluation. The approach presented in this paper can also be extended to analyze other solvent-assisted SAGD processes.
The Polymer in Polymer Flooding: Is its Value Overestimated?
Authors: San Blas P. , Vittoratos E.
Published: June 2014

Reservoir recovery processes are complex and typically entail several physical or chemical mechanisms. Polymer flooding has often been depicted to be dominated by one mechanism: water viscosification reduces the mobility ratio, and stabilizes the displacement front to increase oil recovery. Increasingly though the contribution of mechanisms other than water viscosification is becoming understood. This paper points out two novel insights into polymer flooding: (1) the intrinsic value of the polymer is likely being overestimated and (2) the practice of operating the polymer flood with incomplete voidage replacement may indeed be optimal.

The conversion of a conventional waterflood to a polymer flood entails significant injectivity reduction, up to 50% or more. The maintenance of complete voidage replacement (VRR = 1) would thus require an increase in the number of injectors, or a reduction of total production rate or both. As both interventions reduce the economic returns, most projects operate with incomplete voidage replacement (VRR < 1). We have previously reported that a VRR < 1 improves the waterflood response of heavy oil reservoirs. Thus using the VRR = 1 waterflood as the comparison benchmark to the polymer response may overestimate the value of viscosification – the intrinsic value of the polymer. To quantify this, we have performed numerical simulations of polymer flooding for VRRs ranging from 0.4 to 1.4, deconvolving the relative contributions of the viscosification and VRR < 1 mechanisms. We observe that a polymer flood operated with VRR > 1 (above the oil bubble point) underperforms a polymer flood with a VRR < 1 by as much as one third. We conclude that the intrinsic value of the polymer is overestimated.
Performance of Flue Gas and Foam Assisted Steam Huff and Puff with Horizontal Well in Enhanced Recovery of Fengcheng Oil Field
Authors: Zhang Chao , Li Zhaomin , Wang Hongyu , Wang Shuhua , Huaifeng Yi , Xue Xingchang , Yao Yuping
Published: June 2014

Fengcheng Oilfield, an ultra heavy oil reservoir (viscosity of the gas-free crude oil is 151000mPa · s at 50°C), is controlled by lithology structure and sheltered by faults. The oil bearing area and OOIP of this reservoir are 6.0 km2 and 1190.21 × 104t, respectively. The depth of the oil formation is from 170 to 210m, and the net pay of the oil layer is from 25 to 40.7m.

Because of the ultra-high viscosity of the crude oil, steam huff and puff with horizontal well was employed to improve the recovery of Fengcheng Oilfield. For many years, this technology has been the main and key Enhanced Oil Recovery (EOR) technique for this Oilfield. However, as the formation energy depletes and oil saturation decreases in the near-wellbore area in the later stage of the production, water cut increases tremendously in every soaking cycle, oil-gas ratio decreases and the development effectiveness is seriously inhibited. In order to improve the performance of the steam huff and puff in heavy oil reservoir, flue gas and flue gas foam assisted steam huff and puff with horizontal well was applied for the super heavy oil reservoir, which can improve the sweeping efficiency of the steam in the near-wellbore area.

In this work, the viscosity for the flue gas-crude oil systems was measured, and the results show that t the crude oil viscosity is reduced for the dissolution of flue gas with the formation energy improved. The injected flue-gas foam can improve the performance of the mobility of the steam. Additionally, numerical simulation was employed to optimize the injection volume of flue-gas and flue-gas foam. The simulation results indicate that the optimum injection schedule is as follows: 0.5 pore volume flue-gas foam was injected firstly to control the conformance, and then 0.3 pore volume flue-gas and steam were alteratively injected. Such results are vital for the design of a flue Gas and foam assisted steam injection project in similar oil fields.
Caprock Integrity Analysis during a SAGD Operation Using an Anisotropic Elasto-Plastic Model
Authors: Rahmati Ehsan , Nouri Alireza , Fattahpour Vahidoddin
Published: June 2014

Massive steam injection during a steam assisted gravity drainage (SAGD) operation results in significant changes in pore pressure, temperature, stress and volumetric strain in the reservoir sand. These changes trigger the deformation and stress redistribution of the overburden strata, which could lead to containment breach of the caprock through shear or tensile failure. Iso-tropic models have commonly been used to assess caprock integrity. These models are believed to be deficient in capturing the anisotropic response of shale and mudstone, which has been well documented in applications other than SAGD caprock studies.

We developed an iteratively coupled hydro-thermo-mechanical model to evaluate caprock integrity in SAGD reservoirs by coupling a geomechanical model (FLAC) and a thermal reservoir simulator (CMG STARS). We investigated the impact of SAGD operations on stress distribution in the caprock using an anisotropic model that we implemented in FLAC. We repeated the analysis by using the same tool and model, but with the assumption of isotropic shale, and compared the results. Incorporating anisotropy in the model showed an impact on the state of caprock stress and failure pressure of the caprock. It was concluded that shale anisotropy cannot be neglected in caprock integrity investigations.
Advanced Log Characterization of Complex Carbonate Reservoirs
Authors: Smith Charles H. , Hamilton Layne , Ziane Lynda
Published: June 2014

Carbonate reservoirs provide a unique set of challenges in attempting to determine critical properties. The exact determination of porosity, permeability, and fluid type from logs is difficult in tight-reservoir conditions, which is evident in unaltered carbonate systems. Prolific carbonate production can also be achieved when secondary porosity enhancements, such as fractures, vugs, and karsts are present.

Log characterization of these various systems has been rigorous and difficult. Log analysts sometimes arrive at complex conclusions that have little relationship to the reservoir properties, the rates that can be achieved from the system, or the fluid types that may be expected in production. Extensive, as well as expensive, log evaluation techniques and rock characterization studies in complicated laboratory analyses have been used in an attempt to capture these elusive qualities.

Magnetic resonance (NMR) logs were added to logging suites in an attempt to more accurately delineate these important values. The NMR log measures physical properties related to the fluid types and their ability to be manipulated in wellbore conditions. These measurements can then be allocated to establish fluid types and permeability.

This paper examines many types of carbonate reservoirs and summarizes the NMR response to those conditions. Reservoirs will include tight carbonates, with 0–2% porosity, systems that are heavily altered by extensive natural fracturing, and those that have a significant component of vug development. In each of these, permeability will be calculated directly from the NMR relaxation, or T2, measurement, and the fluid type will be indicated by using crossplots of polarization, or T1, with T2. The conclusions will be compared to production rates achieved in each of these reservoirs and to image and core data where available. A positive, generalized description of reservoir properties is achieved in every case, emphasizing the value of NMR as a complex carbonate reservoir characterization device.
Semi-Analytical Modeling of Steam-Solvent Gravity Drainage of Heavy Oil and Bitumen, Part 2: Unsteady-State Model with Curved Interface
Authors: Rabiei Faradonbeh Moosa , Harding Thomas G. , Abedi Jalal
Published: June 2014

Co-injection of solvent with steam in SAGD has shown promise for enhancing oil rates as well as in reduction of energy and water consumption. Modeling and optimization of hybrid steam-solvent recovery processes with commercial numerical simulators can be very time consuming. In addition, the complex interaction of heat and solvent effects in mobilizing heavy oil at the vapour chamber boundary are often difficult to ascertain from the numerical models. Semi-analytical mathematical models can provide insight into the physics of the processes and may be used to estimate production rates and thermal efficiency in much less time.

In this study, an unsteady-state semi-analytical model was developed to predict the oil flow rate in the steam-solvent assisted recovery process. The model assumes a curved interface with transient temperature and solvent distribution in the mobile zone. It also accounts for transverse dispersion and concentration-dependent molecular diffusion for solvent distribution. The oil flow rate and interface profile are predicted at each time in an iterative fashion. The results show that the coefficient of diffusion-concentration function significantly affects the solvent penetration depth and its distribution. The semi-analytical model was able to predict oil production rates using different solvents co-injected with steam, in agreement with reported experimental data.

The proposed model reveals the complex interaction of heat and solvent solubility and diffusion as they affect mobilization and production of viscous oil. This model may be used to find the optimal operation parameters for the process over a range of different reservoir qualities and pressures, in a very time-efficient manner. The final outcome may lead to an efficient design of a steam-solvent recovery process that utilizes less water and reduces the amount of energy and gas emissions per barrel of oil produced.
Cold Heavy Oil Reservoir Characterization by Time-lapse Seismic Inversion, a Case Study
Authors: Riazi N.. , Lines L.. , Russell B..
Published: June 2014

Cold heavy oil production with Sand (CHOPS) is one of the major techniques which is applied in heavy oil production fields, especially in Canada. In this technique, high viscosity heavy oil is extracted with sand by using cavity pumps. In addition to causing fluid changes in the reservoir during the period of production, the CHOPS technique causes changes in the mass of the reservoir rock during the production time due to the simultaneous extraction of sand and oil. Therefore, it is important to model the reservoir changes in CHOPS fields in order to determine how to increase the recovery of the heavy oil. Time-lapse seismic analysis has proven to be one of the best methods which is capable of monitoring production-related changes beyond the wells. Time-lapse seismic analysis involves the use of repeated seismic surveys which are acquired in the same area. By analyzing the differences between these repeated surveys we are able to infer changes due to production.

To start, rock physics modeling was done on the available well log data from wells in the area to model how fluid substitution in the reservoir would change elastic properties such as P-wave velocity, S-wave velocity and density within the reservoir. This modeling can help us understand how elastic properties extracted from time-lapse seismic data can be interpreted. Rock physics modeling was done by using the Gassmann equation and applying the Batzle and Wang relationships for fluids. Next, 4D calibration steps were applied to the time-lapse seismic data to reduce non-reservoir related anomalies and allow us to focus only on production-related changes in the reservoir.

Model-based post-stack and pre-stack seismic inversion was then applied to the time-lapse seismic data to extract the elastic properties at both horizontal and vertical scales, over one of the CHOPS fields in Saskatchewan, Canada. Different elastic volumes such as time-lapse acoustic impedance, shear impedance and density were output from the seismic inversion process. Other time-lapse seismic attributes such as Lambda-Rho (P-impedance squared minus two times S-impedance squared) and Mu-Rho (S-impedance squared) were also computed after the performing time-lapse seismic inversion. The changes observed from the time-lapse seismic inversion and other time-lapse attributes helped us to recognize high production zones and to delineate the areas which could be targeted during the next recovery steps in the reservoir production. Combining rock-physics modeling and time-lapse seismic analysis provided us with a useful tool to monitor the production processes in the reservoir between wells. The seismic results are in good agreement with observed production changes and reservoir simulation results.
Design of Thermally Stable Surfactants Formulations for Steam Foam Injection
Authors: Cuenca Amandine , Lacombe Emie , Morvan Mikel , Le Drogo Viviane , Giordanengo Remi , Chabert Max , Delamaide Eric
Published: June 2014

Steam injection is currently the most widespread method for heavy oil recovery. However, a serious limitation of this method is its energy cost due to heat losses in the reservoir. Steam foams can be used to increase the apparent viscosity of steam. Such an improvement of steam mobility control optimizes the heat distribution in the reservoir and reduces the impact of reservoir heterogeneities in order to raise oil recovery.

Optimized formulations are required to generate stable steam foams in reservoir conditions. This paper presents an original workflow to design efficient combinations of surfactants for steam foam stabilization. The first step is the selection of surfactants demonstrating a good chemical stability at steam temperature, together with a good solubility. The second step consists in evaluating foam stability of these formulations at high pressure and temperature.

We study the thermal stability of surfactants using anaerobic screening tests at high temperature. The chemical structure of surfactants is evaluated through quantitative NMR analysis before and after thermal treatment in various conditions (temperatures from 150 to 250°C and durations from 24h to a week). Generated data permit a better understanding of surfactants degradation mechanisms. A customized high pressure/high temperature sapphire view cell is used to investigate the impact of high temperature on the solubility of formulations and to generate foams in reservoir conditions of pressure and temperature. A custom image processing routine is used to measure foam volume as a function of time, in order to evaluate foam stability and rank formulations.

We demonstrate the thermal stability of specific surfactants up to 240°C in anaerobic conditions. A strong influence of temperature on foam stability is observed. Our experiments serve as a baseline to design new formulations giving much longer foam stability at 185°C than benchmarks based on alpha olefin sulfonate (AOS) and alkyl aryl sulfonate (AAS). This paper thus aims at providing new insights on steam foam applications with the development of a dedicated surfactant selection workflow and the characterization of new steam foam formulations with improved performances.
Quantifying the Uncertainty Associated With Caprock Integrity during SAGD Using Coupled Geomechanics Thermal Reservoir Simulation
Authors: Pathak Varun , Tran David , Kumar Anjani
Published: June 2014

With a growing emphasis on safety of thermal operations in the Canadian oilsands operations, the focus of the industry on caprock integrity during SAGD has been increasing. A SAGD operation may create a high degree of deformation in the reservoir rock because of the stresses induced by pressure and temperature. This might yield to a failure of both the reservoir rock as well as the caprock. Thus, there is a need to understand the impact of various geomechanical and operational parameters on overall safety of a SAGD operation.

In this paper, caprock failure during SAGD was modeled using a coupled simulator to integrate reservoir flow with geomechanical deformation. Representative Canadian oilsands properties were used for the simulation. Both shear and tensile failures were modeled and the surface heave/deformation was recorded.

Sensitivity analyses and uncertainty assessments were performed to understand the effect of various geomechanical properties on caprock integrity and surface heave, including Young's modulus, Poisson's ratio and thermal pore pressure. At the same time, operating conditions such as well spacing and maximum injection pressure were also altered to see their effect on caprock integrity. This was done for different geological scenarios and different reservoir depths. Based on this study, we attempt to develop a generic workflow for quantifying the uncertainty associated with caprock integrity and minimizing the risk associated with caprock failures in any SAGD project.
De-Risking the Reservoir for a Commercial Development of the Grosmont Bitumen Carbonates in Alberta
Authors: Yang Daniel
Published: June 2014

Improving on initial experience in the Saleski pilot with wells drilled between 2008 and 2010, a second generation well (drilled 2012) delivers economically attractive bitumen rates at efficient steam-oil ratios. This performance de-risks the reservoir and forms a solid basis for development planning. A larger scale follow-up project will help to optimize well spacing, multiple-well operations, management of well interference, artificial lift systems, etc.

Despite comparable conditions of cyclic operation, two wells located in the same reservoir perform differently. This is related to differences in drilling conditions, well completions and stimulation methods. After pioneering horizontal drilling into the Grosmont Carbonate formation, the performance of the second generation well in Saleski is significantly improved. This paper presents the performance indicators for the pilot well and discusses the key learning steps that led to the improvement.
A Numerical Investigation of the Hydraulic Fracturing Mechanism in Oil Sands
Authors: Taghipoor Siavash , Roostaei Morteza , Nouri Alireza , Chan Dave
Published: June 2014

This paper describes a numerical investigation of hydraulic fracturing in oil sands during cold water injection. Previous studies have shown that hydraulic fracturing in unconsolidated or weakly consolidated sandstone reservoirs is highly influenced by the low shear strength of these materials and is quite different from competent rocks. As such, existing classical hydraulic fracture models are incapable of predicting the fracturing process of weak sandstone reservoirs. This paper presents a numerical tool to simulate hydraulic fracturing in oil sands and weak sandstone reservoirs.

A smeared fracture approach is adopted in the simulation of tensile and shear fracturing in oil sands. The model incorporates various phenomena expected in hydraulic fracturing, including poroelasticity and plasticity, matrix flow, shear and tensile fracturing and concomitant permeability enhancement, saturation-dependent permeability, stress dependent stiffness and gradual degradation of oil sands due to dilatant shear deformation and strain localization.

The results of the hydraulic fracturing simulation indicate that poroelasticity as well as shear fracturing can result in breakdown and propagation pressures larger than the maximum in-situ stress. Applying such pressures in fracturing operations can compromise the caprock integrity. It is found that at injection pressures below the vertical stress, saturation-dependent relative permeability and the development of shear fractures in the reservoir highly influence the injection response.
Predictive Field-Scale Simulations for the Design of a Solvent Injection Pilot
Authors: Chang Jeannine , Ivory John
Published: June 2014

This paper summarizes a study that was part of the $40 million Joint Implementation Vapor Extraction Program and was in support of a planned solvent (60% CH4 – 40% C3H8) injection field pilot at Fort Kent, Alberta where CHOPS wells are prolific oil producers. The pilot design was for a horizontal well between and below four vertical wells. The vertical wells were to be on CHOPS before becoming solvent injectors with the horizontal well as a producer.

CHOPS simulations were based on matching specified oil production. The simulations utilized an AITF CHOPS model (with CMG STARS™ as a platform) to design CHOPS operating strategies. The CHOPS simulations determined: (a) wormhole penetration length required to maintain the specified oil rate, (b) when to stop CHOPS and start solvent injection, and (c) the initial conditions (wormhole occupied region, fluid saturations, etc.) for solvent injection simulations. The predicted post-CHOPS reservoir properties were transferred to a reservoir model that represented part of the proposed well arrangement and was used in the solvent injection simulations.

Conclusions from the post-CHOPS solvent injection simulations included: During the post-CHOPS re-pressurization period, solvent should be injected in the horizontal well as well as the vertical wells. This strategy reduces subsequent channeling between the vertical and horizontal wells.Solvent injection performance depends on: (a) lateral offset between vertical injectors and horizontal producer, (b) layers in which vertical wells are perforated, (c) maintained pressure difference between injectors and producer, (d) operating pressure, and (e) gas production rate.Oil rates were significantly reduced by spreading of injected solvent in the high permeability region created by wormholes and by displacement of oil in this region away from the wells.
The Evolution of Water Saturations in the McMurray Oil Sands: A Product of Geological History and Capillary Pressure
Authors: James Bruce Rennie
Published: June 2014

This paper examines the role played by geological history and by capillary pressure in the evolution of the unusual water saturations of the McMurray reservoir of the Athabasca Oil Sands Region (AOSR). The McMurray formation water and bitumen have been a dynamic system evolving through geological time in order to maintain equilibrium between buoyancy and capillary pressure. The main driving force was the change in hydrocarbon as well as formation water density so that they became similar in value.

These changes were likely caused by a combination of factors including hydrocarbon biodegradation, reduction in temperature and pressure through erosion of the overburden above the McMurray, and lowering of water salinity. The weakening of buoyant forces would enable capillary pressure to increase the average water saturation and to redistribute water and hydrocarbon so that water was preferentially moved to areas with a higher fines fraction.

The paper reviews pertinent geological history and discusses theoretically how water saturation should have changed as a result of changes in oil/bitumen and in formation water density. Field data from two sites with different levels of biodegradation as well as a conventional non-biodegraded analogue were analyzed in light of the theoretical expectations.

There will be water saturations above irreducible levels and hence some water mobility throughout much of the McMurray. There also is evidence that the irreducible water saturation in good quality McMurray reservoir sands at one site is ~ 10% or less. It is possible that the present McMurray irreducible water saturation levels are somewhat similar to what they were at the time of first oil charge approximately 80 million to 110 million years ago.

High-water saturation zones form when biogenic gas in depleted gas caps is replaced by water, as concluded by Fustic at al., (2013). As water is drawn into the depleted gas cap from the surrounding reservoir, water saturation can be lowered to nearly irreducible levels at the base of the reservoir below. Capillary pressure can also create transition zones below these high-water saturation zones. Therefore, thin depleted paleo-gas caps could create zones of elevated water saturation much thicker than the original gas caps. There can be significant heterogeneity in these high-water saturation zones across the McMurray Formation and at field scale.
Experimental Studies: Shear Induced in Single Phase Permeability
Authors: Abdallah Ben Kais , Hamoud Mohamed , Chalaturnyk Rick
Published: June 2014

Absolute permeability plays an important role in reservoir engineering. Reservoirs like oil sands are shallow unconsolidated formations and stress dependent. During steam-assisted drainage (SAGD) the effective stress increases as results of either increasing in temperature or pore pressure. Rock properties for instance permeability will be induced by this change to influence therefore reservoir calculations.

To understand the behavior of stress-strain in unconsolidated reservoir during a SAGD, a series of drained triaxial compression tests were performed to study the shear-induced changes in absolute permeability at low stress conditions. The experimental program included stress-strain tests under two different paths: isotropic unloading and increasing of mean stress was followed by permeability tests at each levels of strain and at different confining effective stresses.

Results from this study showed a substantial increase of absolute permeability in the lower case of 50 kPa of effective confining stress. This gain was up to 88%. In the higher level of effective confining stress, however, there was a decrease of absolute permeability.

The aim of this project was to provide an empirical correlation linking the absolute permeability to effective confining stress and volumetric stain so that the behavior of absolute permeability at different overburden depths will be understood.
Coupled Wellbore/Near-Well Flow and Geomechanical Thermal Simulation of Cyclic Steam Stimulation with Different Geometric Fractures
Authors: Li Ran , Chen Zhangxin , Xu Jinze , Zhong He
Published: June 2014

Cyclic steam stimulation (CSS) is a commercial in situ recovery method that involves injecting steam into formations at high pressure to reduce the viscosity of heavy oil and bitumen. The injection pressure is typically above the reservoir fracture pressure to induce fractures, which can improve reservoir permeability and fluid mobility. Geomechanics and heterogeneities near a well significantly affect reservoir fracturing, particularly under thermal conditions. In addition, oversimplified descriptions of fracture geometry may fail to represent actual reservoir performance. Thus modeling near-well flow effects coupled with geomechanics is essential for detailed large-scale thermal simulations with fractures. Conventional methods have exhibited limitations in capturing interactions among wellbore/near-well flow, geomechanics, and fluid flow during CSS development. Therefore, flow/stress/near-well flow coupling under different fracture geometries is investigated in this study.

A facies-controlled geostatistical model is first constructed for a Cold Lake reservoir to obtain more reliable results. A fully coupled model is further generated from this geological model. After local grids near wells are refined, we construct different fracture geometries by changing the fracture length and direction. In this study, uncertainty analyses on fracture geometry near the vertical wells are performed. The simulation results show that omitting geomechanics and wellbore modeling increases oil recovery. Moreover, oversimplified fracture geometry with simple planes overestimates an oil rate. Furthermore, fractures with complex geometries and geomechanics exhibit high conductivity and provides effective channels for steam and bitumen but at the same time, it may cause steam channeling and decrease the efficiency of steam injection.
Upscaling Study of Cyclic Solvent Injection Process for Post-CHOPS Reservoirs through Numerical Simulation
Authors: Zhang Min , Du Zhongwei , Zeng Fanhua , Xu Suxin
Published: June 2014

Cyclic Solvent Injection (CSI) is the most promising process for a post-CHOPS reservoir (Chang and Ivory 2012). Experimental studies suggest that oil recovery can reach up to 62% at the lab scale, which indicates the potential viability of the CSI process. This paper summarizes experimental results of six CSI tests with three physical models with different scales. Typical western Canadian heavy oil sample with a viscosity of 4830 cp at the reservoir conditions was used. Numerical simulation models were established to simulate these tests. The uncertainties in upscaling CSI process, such as relative permeability curve, capillary pressure, reaction rate in foamy oil model and dispersion coefficient were investigated by numerical simulation. In history-matched cases, the same relative permeability curves were obtained for these six CSI tests only with different capillary pressure. Sensitivity analysis illustrates that adding an appropriate capillary pressure in each test could refine the match results between simulation and experimental data. Generally, the larger the model is, the smaller the capillary pressure is. Therefore, the capillary pressure may be neglected in field scale applications. In addition, the location of the wormholes may affect the magnitude of capillary pressure employed in history-matched cases.

A typical western Canadian heavy oil post-CHOPS reservoir (M-reservoir) was employed to study the uncertainties during the CSI process by numerical simulation. The uncertain parameters include oil relative permeability, gas relative permeability, capillary pressure and dispersion coefficient. The Design of Experiments (DOE) method was utilized to define the simulation matrix, and 18 simulation cases, with 7 factors in 3 levels, were run. The multiple inferences were covered as much as possible. The oil recovery factor for ten-year production was selected as the response variable. The range between 18 estimates and "standard" value (14.611%) in terms of the recovery factor was from 0.04% to 1.42%. After that, the multiple-linear regression was performed to construct the response surface in DOE and the proxy equations were then generated. Three thousand Monte-Carlo simulations, in total, were performed to generate the probability distribution functions, which indicated that the P90, P50 and P10 estimates of the oil recovery factors were 14.08%, 14.69% and 15.33%, respectively. This study demonstrates that through simulating experiments from physical models with different scales, the uncertainties in predicting the field-scale CSI performance can be significantly reduced.
New Insights on Chemical EOR Processes for Heavy Oil
Authors: Hocine S. , Magnan A. , Degré G. , Rousseau D. , Rousseau N.
Published: June 2014

Chemical EOR methods have become an increasingly attractive option for heavy oil reservoirs where thermal methods cannot be applied, like in thin reservoirs. The use of surfactants for heavy oil is only reported, both at lab and field scale, in a limited number of cases and mostly in combination with alkali to benefit from the generation of in-situ surfactants. However, operational issues (such as scale or corrosion) associated with the use of alkali as well as negative impacts on project logistics are often mentioned. The objective of this work is to demonstrate at lab scale the efficiency of alkaline-free surfactant-polymer processes in the context of heavy oil reservoirs.

The present investigation is focused on a Canadian heavy oil (14°API and 1400 cP) in representative reservoir conditions (high permeability sandstone, temperature of 35°C, low salinity). A dedicated synthetic surfactant formulation is designed using a screening methodology based on a robotic platform. Ultra-low interfacial tensions are evidenced from phase behavior and confirmed by spinning-drop tensiometry. Oil recovery performances of the surfactant formulation are then evaluated in corefloods.

Cores at Swi are first polymer flooded until no oil is produced to reach a residual oil saturation. Surfactant-Polymer formulations are then injected. Typical results show that additional oil is produced as a continuous oil bank (up to 100% ROIP depending on the slug size) and with a moderate adsorption if a salinity gradient strategy is applied (typically 0.2 mg surfactant per g of rock). This indicates that the surfactant is able to mobilize most of the residual oil. The results of this exploratory investigation show that alkaline-free surfactant-polymer processes could be applied to heavy oil reservoirs while minimizing operational issues. Complementary work will also be presented on optimization of the process through injection strategy improvement and surfactant dosage reduction as well as on extrapolation of the lab results to field-scale technical and economical feasibility.