bluuebunny/crossref_metadata_2025_split huggingface dataset:
SAGD Development Strategy for Concurrent Production of Two Vertically Stacked Clastic Reservoirs
Authors: Jiang Qi , Nugent Daniel , Meyer Kelli 
Published: December 2011

Abstract
The southwest portion of the proposed Taiga project has two vertically stacked bitumen-filled Cretaceous sandstone reservoirs in the Cold Lake area of NW Alberta, Canada. The shallower Lower Grand Rapids Formation is separated from the Clearwater Formation by the transgressive Clearwater. SAGD (steam assisted gravity drainage) is planned for producing both formations simultaneously.
The Lower Grand Rapids Formation differs from the Clearwater Formation in initial reservoir pressure, oil viscosity and fluid distribution. Therefore, this will require individual well placement and operational strategies for each reservoir. The sequence of development for the two reservoirs will not only affect the pad facility design and operation strategy but will also affect the drilling operations. There is a high likelihood of drilling into the areas conductively heated by prior proximal SAGD operations if two formations are developed in a sequential order. This increases drilling risks and costs. Simultaneous SAGD operations within both the Lower Grand Rapids and Clearwater Formations can be used to minimize the complexities associated with well drilling and completions, and to reduce the initial number of surface pads as both formations can be accessed from the wells drilled from the same surface location.
This paper presents the results from both reservoir simulation and geo-mechanical modeling based on geological and reservoir characteristics of these reservoirs. The surface heave due to dual zone thermal operations is also predicted based on the results from geo-mechanical modeling. These studies have led to an optimal design of pads and operating parameters for concurrent production of the two reservoirs which is technically, environmentally and economically efficient.
Restimulation of Wells using Biodegradable Particulates as Temporary Diverting Agents
Authors: Allison Dave , Curry Shawn , Todd Brad 
Published: December 2011

Abstract
During the life of producing wells, there comes a time when the well approaches its economic viability as a producing well. If the reservoir potential is sufficient to support the expenditure, many wells are candidates for recompletion, reperforation, or restimulation. This type of focus on the Barnett shale began in the late 1990s. Drilling activity dramatically increased during the ensuing years and now there are more than 14,000 wells that have been drilled, most of which are producing wells. A lot of these wells are potential candidates for restimulation (refrac) because their production rates have declined but still have significant reservoir potential. The completion techniques deployed in the Barnett evolved over time to where many wells have dozensof perforation clusters and hundreds of individual perforations. Generally, refracsare ineffectual unless the perforations can be temporarily isolated so that the energy of the subsequent fracturing treatment can be focused on individual portions of the reservoir. Additionally, refrac candidate wells often contain challenging wellbore environments that further complicate the ability to successfully refrac the wells. The use of biodegradable particulates to facilitate the temporary diversion and concentration of frac energy has increased the success of restimulation.
This paper discusses the recent development of techniques and materials being used in refracturing operations. Included are discussions of laboratory results of new and novel materials, along with case histories of refrac wells demonstrating application of such materials and techniques.
Evaluation of Long-Term Performance of Oil Wells in Elm Coulee Field
Authors: Kurtoglu B. , Cox S. A. , Kazemi H. 
Published: December 2011

Abstract
Unconventional oil reservoirs, such as Bakken, have gained considerable interest in recent years because they have become a great resource to produce oil and gas to meet the energy needs of North America. Performance prediction from these tight reservoirs is a challenge because of the complexity of reservoir flow, well completion, and fracture stimulation techniques. Elm Coulee field, in Bakken, is an example of such unconventional reservoirs and is located in Richland County, Montana. The field was drilled using both vertical and horizontal wells, but in recent years the use of horizontal wells has become the standard practice. The objectives of this study were: (1) evaluate the long-term (7 to 10 years) performance of horizontal wells in Montana Elm Coulee, (2) develop a better understanding of how to predict the long-term performance of younger Bakken fields in North Dakota based on the Elm Coulee experience.
Arps hyperbolic decline curve analysis was used as the main forecasting approach. In Arps analysis, q(t) = qi (1 + bDit)−1/b, where q is the flow rate, D is the decline rate, and b is the decline exponent. It will be demonstrated that forecasts using a constant b overpredicts well performance. To match the long-term performance of Elm Coulee wells, the numerical value of b had to be decreased with time.
Analytical approaches (log-log type-curve diagnostic plots and the Fetkovich log-log normalized plot) were also used to decipher the flow regimes, and to determine the varying decline rate from long-term producing wells in Elm Coulee Field. In addition to analytical modeling, numerical modeling was also used because it is more comprehensive in utilizing a larger set of reservoir parameters such as reservoir heterogeneity variations. This is very useful in transferring what we learned from the long-term performance of Elm Coulee Montana wells to the short-term performance of wells in North Dakota by addressing both geology and reservoir property differences between these fields.
Modeling the Effect of Permeability Anisotropy on the Steam-Assisted Gravity Drainage (SAGD) Process
Authors: Azom Prince N. , Srinivasan Sanjay 
Published: December 2011

Abstract
The SAGD process utilizes horizontal wells hence permeability anisotropy can play a very strong role in recovery. In fact, it has been well documented that poor vertical permeability kills the SAGD process because the steam chamber will not grow properly. Several authors have attempted to model this phenomenom by using time-independent averaging (e.g. harmonic, geometric averaging etc.) methods only to discover the inadequacy of such an approach as several field implementations reveal a definite time component to this effect. Consequently most studies on the effect of anisotropy during SAGD have involved only commercial simulators. However, there exists a need to describe this phenomenon quantitatively prior to any numerical simulation and delineating conditions where it can be considered important or not.
Isotropy of permeability can be geometrically represented as a sphere (or circle in 2D) where the permeability radii are the same in all directions. Anisotropy can be represented as an ellipsoid (or ellipse in 2D) with varying permeability radii in different directions and the principal axes representing principal permeability directions. In this work, we assume that the principal axes point in the vertical and horizontal directions. We will show that the SAGD process has a unique geometry that allows a meaningful mapping of the steam chamber wall to the coordinate frame of such an ellipsoid. We will then use this transformation to incorporate permeability anisotropy within the framework of Butler type models. This will be done in dimensionless space and the results obtained can be used as type curves for correcting any isotropic SAGD model for anisotropic effects.
Our results show that the effect of anisotropy is time dependent (generally obeying a sigmoid function) and there exists a given time for a given set of reservoir and fluid properties, after the effect of anisotropy ceases to exist. This is remarkable because it suggests a way to improve modeling efficiency for reservoirs with strong anisotropic permeabilities.
Our results also explain why most other static averaging methods fail. The analytical expression can be used as a fast SAGD predictive model suitable for history matching purposes.
Log-Based Identification of Sweet Spots for Effective Fracs in Shale Reservoirs
Authors: Hashmy Khaled , Abueita Samir , Barnett Craig , Jonkers Jos 
Published: December 2011

Abstract
Hydro-fracturing and long horizontal sections are needed to generate economic production volumes in shale reservoirs. Many operators resort to multi-stage fracs in horizontal sections that are often sparsely surveyed with LWD or wireline logs. The trend is to space out different frac stages, more or less evenly, along the length of the horizontal with the expectation that reservoir characteristics will conform to those encountered in the vertical pilot hole.
LWD and wireline logs examples presented here distinctly highlight sweet spots with superior reservoir characteristics that are likely to have excellent flow characteristics. Perhaps equally important is the delineation of zones that have inferior reservoir properties, where hydro fracturing will be far less effective. Sweet spots enable operators to concentrate on the most suitable intervals for stimulation to obtain a bigger bang for their bucks.
In marine shales, LWD Spectral Gamma measurements highlight intervals of high Uranium corresponding to elevated Kerogen levels which are zones that are expected to be rich in hydrocarbons. An image log is generated from the cumulative GR to provide structural information. Examples show delineation of sweet spots using LWD density and Spectral Gamma combination.
A LWD Acoustic measurement that employs a unique transmitter provides split fast and slow shear in horizontal sections – yielding elastic properties in the vertical and horizontal directions thereby providing information on anisotropy of these reservoirs. This once again brings out the lateral inhomogeneity and points out the sweet spots where frac dollars need to be concentrated.
The cost of well surveys in a horizontal shale formation can be less than the expenditure on a single frac stage. A Quad-Combo is sufficient for a meaningful evaluation that will permit operators to concentrate on intervals with better reservoir characteristics and thus achieve improved stimulation of the formation.
Investigation of Top-Down In-Situ Combustion Process in Complex Fractured Carbonate Models: Effects of Fractures’ Geometrical Properties
Authors: Fatemi S. Mobeen , Kharrat Riyaz , Vossoughi Shapour 
Published: December 2011

Abstract
The top down In-Situ Combustion (ISC), involves the stable propagation of combustion front from top vertical injector to the bottom horizontal producer. Besides laboratory studies in conventional sandstones, no application of the process in fractured carbonates has been addressed yet. In this paper a successful combustion tube experiment and history match of Iranian low permeable fractured heavy oil reservoir called Kuh-E-Mond, is presented and accompanied with details of experimental and simulation model. Validated model has been modified further to investigate the feasibility of Top-down ISC in fractured reservoirs mimicking block scale combustion cells. Effects of fractures geometrical properties such as orientation, location, extension, density, spacing, disconnection and dispersion have been considered. Investigation of aforementioned geometrical properties performed for the case of presence of networked fractures (presence of both vertical and horizontal fractures). Results confirmed higher outcome in the case of optimum vertical or horizontal fractures density and spacing. Laterally located vertical fractures enhanced the process in terms of ultimate oil recovery and sweep efficiency. Longer vertical fractures and higher degree of fractures dispersion through the reservoir improved the recoveries compared to the case of extended horizontal fractures and higher degree of horizontal fractures dispersion through reservoir. Depending on the reservoir parameters (such as fracture and matrix permeability) there is an optimum length of vertical fracture in which it enhances the recovery. This means very long extension of vertical fractures could cause early oxygen breakthrough and as a result lower sweep efficiency and oil recoveries. Simulation analysis revealed that Top-down In-Situ Combustion has higher feasibility for the reservoirs with highly networked fractures such as those occurring in the Persian Gulf coast.
Practical Control of SAGD Wells with Dual Tubing Strings
Authors: Stone Terry , Brown George , Guyagular Baris , Bailey William J. , Law David Hin-Sum 
Published: December 2011

Abstract
Practical methods of operating dual/triple tubing strings based on temperature monitoring that is currently available to achieve uniform steam chamber development and enhanced production in a Steam Assisted Gravity Drainage (SAGD) process are presented. The work is motivated by the fact that many operators use dual tubing strings for designing and optimizing steam chamber development. Flow in the region of the SAGD horizontal well pair is often irregular and dual tubing strings may help to even out and improve both injection and production. Problems that operators have with multiple tubing strings in wells include both their control and design. Both injector and producer have two tubing strings each: one landed at the toe and the other at the heel. Control points are applied on each injection tubular. Injection at these control points is regulated by a Proportional-Integral-Derivative (PID) feedback controller monitoring temperature differences between injected and produced fluids.
The PID controller will attempt to accomplish two goals (i) achieve evenness in injection and production conformance along both wells, (ii) enforce a specified temperature offset between the injector and producer in order to improve oil production and reduce steam production and injection. Sensitivity of the feedback controller will be examined for (i) heterogeneity where several permeability patterns will be tested to gauge the effectiveness of coping with reservoir complexity, (ii) update frequency where a comparison will be made between instantaneous and periodic updating of the controller error terms, (iii) ability of the controller to cope with early temperature rises in produced fluids. Well monitoring is accomplished through the use of high temperature fibre-optic temperature sensing that is currently available. Results and discussion are offered on whether an additional tubular landed at the midpoint of both wells will benefit production from a heterogeneous reservoir.
Design of Caprock Integrity in Thermal Stimulation of Shallow Oil-Sands Reservoirs
Authors: Yuan Yanguang , Xu Bin , Palmgren Claes 
Published: December 2011

Abstract
Stakeholders in the in-situ oilsands development take the caprock integrity issues very seriously. The industry is faced with the challenge of determining an optimal operating pressure in the reservoir. In general, the pressure should stay low enough to ensure the caprock integrity while being high enough for enhanced oil production and economics. This paper presents a comprehensive work program on the subject for a shallow oilsands play.
Caprock integrity is concerned about the induced stress and deformation in the caprock during the thermal stimulation of the oilsands reservoir. A mini-frac test program was undertaken to define the original in-situ stress state. Laboratory tests were carried out to measure the deformation and strength properties. Simulations were run to calculate the induced stresses and evaluate them against the mechanical strength. Consequently, a factor of safety is delivered for a given operating pressure. This paper will cover all these geomechanical work components. Both field data and theoretical considerations are included to augment the technical descriptions.
Prediction of the Viscosity of Solvent Diluted Live Bitumen at Temperatures up to 175°C
Authors: Motahhari H. , Schoeggl F. F. , Satyro M. A. , Yarranton H. W. 
Published: December 2011

Abstract
Accurate predictions of heavy oil and bitumen viscosity as a function of temperature, pressure, and composition are required for the design of thermal and solvent based recovery methods. In this case study, the applicability of the recently developed Expanded Fluid viscosity correlation is tested on measured viscosities of diluted dead and live bitumen at temperatures from 20 to 175°C and pressures up to 10 MPa. The data were collected for: 1) an Alberta bitumen, 2) a condensate, 3) diluted bitumen with 3, 6 and 30 wt% condensate, 4) live bitumen, and 5) diluted live bitumen with 3 and 5.9 wt% condensate. The live oil viscosity was 820 mPa.s at 50°C and 2.5 MPa compared with a dead oil viscosity of 3180 mPa.s.
The Expanded Fluid (EF) viscosity correlation relates viscosity to density at any given pressure and temperature; it requires three parameters for each fluid. In this study, the dead bitumen and the condensate solvent are treated as single components and the viscosity correlation parameters are determined by fitting viscosity data. The parameters for the solution gas, live bitumen, and the bitumen-solvent mixtures were determined from mass based mixing rules. The parameters for the pure components that made up the solution gas were previously determined.
The correlation was fitted to dead Alberta bitumen and the condensate with average relative deviations of 11% and 1.5%, respectively. The viscosity of the live bitumen was predicted to within 20% and 28% of the measured value based on measured and calculated mixture densities, respectively. Diluting the live and dead bitumen with 3 to 30 wt% solvent reduced the viscosity by one to three orders of magnitude and the viscosities were predicted with an average relative deviation under 16 and 37% based on measured and calculated mixture densities, respectively.
Modeling of Asphaltene Precipitation Due to Steam and n-alkane Co-injection in the ES-SAGD Process
Authors: Badamchizadeh Amin , Kohse Bruce F. , Kumar Anjani 
Published: December 2011

Abstract
The world energy demand is continuously increasing. Therefore heavy oil and bitumen reservoirs are driving more attentions for world energy supply. There are large amount of bitumen reserves in Canada. Only very small portion of bitumen reserves (~15%) in Alberta is mineable, and rest must be recovered using in-situ techniques. Bitumen viscosity can be reduced substantially by heating or dilution with a solvent. Steam Assisted Gravity drainage (SAGD) has been employed commercially to recover bitumen from Athabasca oil sands. This method requires large amount of water, facilities for water treatment, and natural gas to generate steam. There have been attempts to develop and optimize hybrid SAGD processes to reduce water consumption during bitumen recovery by steam. The co-injection of steam and solvent additives (e.g. ES-SAGD, SAP, SAS) can improve bitumen recovery due to its viscosity reduction by dilution with solvent and heating by steam. The experimental and pilot studies with steam and n-alkane co-injection shows enhanced oil recovery, and reduction in steam consumption (Nasr et. al., 1991, 2001, 2002, 2003). The phase behaviour of the bitumen and n-alkane solvents at SAGD operating condition is very complex and there is possibility of multiphase formation or asphaltene precipitation. The recent pore scale experimental study of this process has shown evidence of asphaltene precipitation during the ES-SAGD with n-alkanes (e.g. Pentane, Hexane) (Mohammadzadeh et. al., 2010). There are few published asphaltene precipitation data for Athabasca bitumen and n-alkanes at different temperature and pressure in the literature (Sabbag et. al. 2006). These data were used to develop an EoS model for the asphaltene precipitation using the CMG-WinProp Asph/Wax multiphase flash calculation. The asphaltene precipitation during the steam and n-alkane co-injection was studied using STARS thermal reservoir simulation model. This paper explains a method to characterize Athabasca bitumen based on the experimental SimDist data. A technique for tuning the solid solubility model parameters was addressed to develop asphaltene precipitation model for n-heptane and Athabasca bitumen. Also the asphaltene precipitation modeling with STARS, its effect on the steam chamber development and ES-SAGD performance are discussed.
Importance of Shale Anisotropy in Estimating In-Situ Stresses and Wellbore Stability Analysis in Horn River Basin
Authors: Khan Safdar , Ansari Sajjad , Han Hongxue , Khosravi Nader 
Published: December 2011

Abstract
Shale formations have laminated structures which result in significant differences in mechanical properties along the orientations parallel to and perpendicular to laminations (bedding planes). These differences lead to anisotropic horizontal stresses. Failure to consider the effect of anisotropic behavior of shale can have severe consequences for drilling. In rocks with anisotropic mechanical properties and strength, there is a high risk of wellbore instability while building deviation angle from vertical sections. Conventional wellbore stability analysis approaches do not consider material anisotropy and laminated nature of shales, which can result in underestimated stresses leading to incorrect safe trajectory or mud-weights.
Shale formations in the Horn River Basin (HRB) are strongly anisotropic with anisotropic ratios varying from 1.2 to 3.5. In this paper, the authors demonstrate the importance of considering anisotropy in estimation of in-situ stresses and wellbore stability analysis. Two field case study examples are presented to underscore the consequences of neglecting anisotropy in wellbore stability analysis.
Comparative Study of Multistage Cemented Liner and Openhole System Completion Technologies in the Montney Resource Play
Authors: Wilson Brad , Lui David , Kim James , Kenyon Mike , McCaffrey Matt 
Published: December 2011

Abstract
The Montney Formation Resource Play, which straddles the border between the Canadian provinces of British Columbia and Alberta, is considered by many to be one of the largest natural gas resource plays in North America. Original gas-in-place estimates for the Montney range from a minimum of 80 tcf to as high as 700 tcf. Despite horizontal, multistage stimulation being common practice to effectively exploit tight gas sand and shale reservoirs, determination of the optimal methodology and identification of the parameters that affect optimization have yet to be fully understood.
This paper compares two different multistage hydraulic fracturing technologies applied in the Lower Montney Formation: cemented liner and openhole multistage system (OHMS) completions. In-depth analysis was performed on field data from 15 wells divided into two separate geographical areas within the same field. Comparisons included production analysis, lateral lengths, number of stages, stage spacing, proppant volumes, and pump rates. Additionally, operational time and cost comparisons on a per well and per stage basis for both technologies were determined.
Based upon the field data analyzed, the application of OHMS completion technology is appropriate for the Lower Montney in the region of the play studied. Application of this technology for the wells selected in the two study areas resulted in both greater initial production rates and overall cumulative production than cemented liner completed wells. Additionally, less time was required to perform the fracture stimulation job when using OHMS technology as compared to cemented liners. Both the average total cost of completion and average cost per stage in conducting cemented liner jobs was higher than employing OHMS completions.