bluuebunny/crossref_metadata_2025_split huggingface dataset:
Characterizing the Effects of Lean Zones and Shale Distribution in SAGD Recovery Performance
Authors: Wang Cui , Leung Juliana Y. 
Published: June 2014

Abstract
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

Abstract
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 &lt; 1). We have previously reported that a VRR &lt; 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 &lt; 1 mechanisms. We observe that a polymer flood operated with VRR &gt; 1 (above the oil bubble point) underperforms a polymer flood with a VRR &lt; 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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

AbstractCold 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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.