bluuebunny/crossref_metadata_2025_split huggingface dataset:
Numerical Study of Gas Evolution and Transport Behaviors in Natural Gas Hydrate Reservoirs
Authors: Uddin M. , Wright F. , Coombe D. 
Published: February 2011

Abstract
Gas hydrates are a potentially vast untapped source of natural gas. Recent numerical and field studies suggest the Mallik gas hydrate field in Canada's Mackenzie Delta may represent a technically producible and potentially economically viable reservoir of natural gas. Our initial reservoir simulations using a kinetic reaction approach indicate that gas evolution and transport within porous geologic reservoirs have a significant effect on fluid production characteristics, while field and laboratory data suggest that significant amounts of evolved gas can be trapped for some time within the reservoir, depending on the field operation.
In this work, we invoke modeling concepts extensively employed in quantifying gas ex-solution from very viscous oils to further assess the kinetic behaviour of gas hydrate ex-solution via depressurization. Here the gas bubbles can be categorized into three groups with explicit transport behaviour: small bubbles (water phase), large bubbles (immobile) and connected bubbles (or free gas). These concepts allow the development of a new set of kinetic reactions for hydrate dissociation: one representing the (possibly delayed) conversion of hydrate into water and dispersed gas bubble phases, and one representing the evolution from dispersed bubbles to connected bubbles. These reactions can effectively capture the non-equilibrium fluid flow behaviour observed in field production tests.
For modeling of the transport phenomenon, we assumed two explicit mobility formulations, 1) trapped bubbles (no mobility) and a flowing water phase, and 2) large connected gas bubbles and flowing water (with relative mobility). Relative mobility can be estimated by using traditional grid block relative permeability curves. We then develop a simple mechanistic gas bubbles trapping tool as a function of Capillary Number, which can easily be incorporated into our numerical simulator. This entrapment of the non-wetting gas phase results in higher values of critical gas saturation.
Two case studies based on alternative representations of a Mallik-like gas hydrate reservoir demonstrate that significant errors can result in reservoir modeling if these fluid transport phenomena are not adequately represented in numerical simulations. Aspects of the model developed here have been applied to history matching and prediction of natural gas recovery from clastic, sand-dominated reservoir at the Mallik Site.
Multi-Interval, Horizontal-Completion Strategies Minimize Water Usage and Deliver Increased Production
Authors: Palidwar T. , Nikiforuk G. , Noble V. 
Published: February 2011

Abstract
In recent years, the industry has shifted its focus toward developing unconventional and conventional tight-oil plays, which has led to a steep learning curve in the development and application of new technologies. This paper discusses the progression and findings of operators in a Canadian unconventional oil play, and how current techniques are providing operators with reduced stimulation costs and improved fracture placement, leading to higher initial production rates and cumulative production.
With the advancement of horizontal drilling and completion techniques, operators are revisiting oil plays that had previously been developed with vertical wells or unstimulated, horizontal wells. In many cases, these plays were uneconomic to pursue, except during periods of higher oil prices. With recent improvements in horizontal-stimulation techniques, operators are now finding that cost-effective stimulation methods can be applied that improve the economics of both conventional and unconventional plays.
In one Canadian light-oil play, coiled-tubing (CT) conveyed, openhole fracturing was used initially as a stimulation technique. Production gains were noted, but the water from an adjacent zone limited the effectiveness of this technique. Operators then proceeded to use openhole packer completions as a means of controlling the fractures. This method provided positive isolation between openhole compartments but limited the number of zones that could be completed as well as the options available for workovers following the fracture treatments. More recently, operators have successfully used monobore drilling and completion techniques with a CT-deployed straddle frac stimulation method, providing both economic and low-operational-risk wells at lower drilling and completing costs.
The benefits of the monobore drilling and completion systems are:
Reduced drilling time over other methods Single-stage cementing options Single-trip perforating Full-diameter wellbore simplifies completions. Flexibility in number of intervals and spacing Fracture treatments designed are to maximize zonal coverage Ability to control fracture placement to avoid nearby water zones Flexibility to alter job design during treatment Ability to return to the well following the initial treatment for future treatments Lower water requirements for stimulation Reduced costs lessen environmental impact with reduced water volume Reliable, proven, straightforward process
Compared to other methods, this monobore and CT-straddle frac system has provided a lower-risk, engineered approach for delivering higher initial rates and increased cumulative production throughout the life of the well. It has also lead to the development of tight-oil reserves located outside of the conventional production fairways.
Analysis and Correlations of Viscous Fingering in Low-Tension Polymer Flooding in Heavy Oil Reservoirs
Authors: Jamaloei B. Y. , Kharrat R. , Torabi F. 
Published: February 2011

Abstract
Post-primary recovery from some mobile heavy-oil reservoirs in Western Canada cannot be improved using thermal methods due to environmental concerns and technical difficulties. Moreover, miscible gas injection suffers from low initial production rates, premature breakthrough, and possible, formation damage. Low-tension polymer flooding (LTPF) can be an alternative in these reservoirs. However, a major technical challenge in LTPF is that a fingered displacement front may occur. This instability reduces displacement efficiency and may invalidate normal method of simulating LTPF performance based on relative permeability and capillary pressure concepts. Also, it introduces an additional scaling requirement for using results of experimental tests in larger scales. Therefore, it is important to predict the nature of instability, to avoid viscous fingering, or, where it is inevitable, to be capable to include it as an additional factor in modeling displacement.
Previous experiments of viscous fingering in immiscible displacements have been conducted in presence of high single-phase permeabilities and linear displacement schemes. The question is whether previous findings are valid in displacement schemes similar to oil-field patterns (e.g., five-spot) in which one should deal with varying velocity profiles from injector(s) to producer(s). Hence, the effect of dispersion caused by varying velocity profiles has not been tested completely on viscous fingering.
To help understand viscous fingering in LTPF in heavy oil reservoirs and to overcome the aforementioned limitations, we conducted experiments in low-permeability, one-quarter five-spot patterns. Foremost parameters including oil recoveries at different times to breakthrough, ultimate oil recovery, pressure drops, cumulative saturation profiles, mean local saturations, fingers length and width, dynamic level of bypassing, dynamic population of fingers, rate of growth of population of fingers and number frequency of the fingers were measured. We have correlated some of these parameters with displacement time and front position.
Analysis of experimentally-observed fingering patterns of LTPF in this study is the most detailed interpretation performed to date, which provides new insights into the onset of fingering and fingers development. Results would help numerical simulation and stability theory to satisfactorily reproduce qualitative and quantitative features of finger growth.
Three-Phase Equilibrium Study for Heavy Oil-Solvent-Steam System at High Temperatures
Authors: Jia N. , Gao J. , Huang H. , Zuo J. , Memon A. , Zhao H. , Ng H- J. 
Published: February 2011

Abstract
Reservoir simulation and research activities of heavy oil production processes such as SAGD, VAPEX or the steam-solvent combined hybrid process require accurate values of equilibrium constants (K-values) at elevated temperatures. However, such data is rarely available in open literature either because of the temperature limitation of PVT equipment or difficulties in performing high temperature three phase vapor liquid equilibrium experiments.
In this paper, with the assistance of a state-of-the-art fully visual PVT cell specifically developed for heavy viscous oils and capable of performing fluid phase behavior studies at temperatures up to 250°C and effectively mix samples with viscosity up to 1,000 cP at test temperature, a heavy oil-solvent-steam equilibrium case study is presented. The heavy oil was mixed with solvent and water at specified weight ratio, temperature and pressure in the heavy oil PVT cell. After achieving equilibrium, the volumes of vapor, liquid and water phases were measured. The samples from each phase were drawn for compositional analysis using gas chromatography and K-values of the hydrocarbon components were examined. The component compositions from this experiment were utilized for equation of state (EoS) model turning. This case study shows that with proper care, the EoS can be characterized and used to match with experimental data for heavy oil.
Case Studies of a Simple Yet Rigorous Forecasting Procedure for Tight Gas Wells
Authors: Nobakht M. , Morgan M. , Mattar L. 
Published: February 2011

Abstract
The dominant flow regime observed in many hydraulically-fractured tight/shale gas wells is linear flow. This flow regime may continue for several years, and will ultimately become boundary-dominated flow, at much later times.
Nobakht et al. (2010) introduced a simplified method of production forecasting for tight/shale gas wells which exhibit extended periods of linear flow. The method is simple as it relies principally on a plot of inverse gas rate versus square root time, and it is rigorous in that it is based on the theory of linear flow and combines the linear flow transient period with hyperbolic decline during boundary-dominated flow.
In the present work, this simplified method is reviewed and applied to almost 90 wells producing from the Montney formation in N.E. British Columbia, Canada. The vast majority of these wells exhibit linear flow for extended periods of time.
The advantages of the simplified forecasting method are: (1) It is not biased towards any flow regimes, as no superposition time functions are used; (2) Reliable forecasts can be obtained without invoking pseudo-time and its associated complexities; and (3) The only parameter that needs to be specified externally is the drainage area.
The method can be used for forecasting horizontal wells with multiple hydraulic fractures. By assigning different drainage areas to each fracture, a relationship can be developed between expected ultimate recovery (EUR) and original gas in place (OGIP) assigned to each fracture. This translates into recovery factor versus number of fracture stages. The resulting forecasts can be used directly to examine the economics of multi-stage fracturing.
Understanding Hydraulic Fracture Geometry and Interactions in the Horn River Basin through DFN and Numerical Modeling
Authors: Rogers Steve , Elmo Davide , Dunphy Rory , Bearinger Doug 
Published: February 2011

Abstract
In the Horn River Basin, evidence points to one of the key elements of a successful well completion being the effective connection of the hydraulic fracture into the natural fracture system, allowing the well to connect to a significantly enhanced drainage volume. However great uncertainty exists with respect to the nature of the natural fracture system and importantly how the hydraulic fracture interacts with it.
To provide a framework to address these uncertainties, an approach has been developed within a Discrete Fracture Network (DFN) code. The DFN approach provides a platform to construct realistic fracture models of stochastically generated fracture elements constrained and conditioned by well and surface data. Simulation of hydraulic frac development through these DFN models using a rule based approach allows the rapid modelling of the interaction between the hydraulic frac and the natural fracture system with calibration of the model being provided by the generation of a simulated micro-seismic cloud. Comparison of the simulated micro-seismic pattern to field measurements increases confidence in the DFN approach and allows the tuning of key hydraulic properties as part of the calibration process.
An additional challenge at this stage of the plays development however is that many of the developments are relatively data poor and therefore the rigorous simulation of detailed models conditioned to well data is often not possible. To address this, a number of simulations were run on more generic models where key properties such as fracture length, fracture aperture and intensity were varied and their impact on the resultant micro-seismic pattern observed. This more parametric approach allows well observations to be interpreted within a better constrained framework of fracture network knowledge. These DFN based simulations were supplemented by detailed geomechanical models using a hybrid FEM-DEM code that allowed the coupled stress-flow modelling of hydraulic frac interaction and pressure evolution, enabling certain stimulation design factors to be considered as well as testing the basis for the more stochastic modelling.
The benefit of these combined simulations is that a framework is developed to integrate, interpret and test all the fracture related information, allowing more guided development decisions to be made as well as identifying critical data gaps to be addressed.
Simulation Study for Designing an In-Situ Combustion Pilot in the Orinoco Belt of Venezuela: From Laboratory Studies to the Field Scale
Authors: Anaya I. , La Cruz R. E. , Alvarez A. J. , Gutierrez D. , Skoreyko F. A. , Card C. 
Published: February 2011

Abstract
In-situ combustion (ISC) is a promising enhanced oil recovery process for the vast heavy oil accumulation of the Orinoco Belt in Venezuela. Combustion tube tests were performed to assess the feasibility of the process in a reservoir of the area. Given the successful laboratory results, it was decided to proceed with the design of a pilot test. Along with the basic design calculations, a simulation model was built to aid in selecting optimum well locations and operating strategies of the pilot. This would also be used for history matching of the actual operation and further optimization. One of the features of the model is the inclusion of the foamy oil behavior exhibited by the oil. For the modeling of the combustion process, a kinetic model developed in-house by PDVSA Intevep using thermo-gravimetric and scanning calorimetry experiments from an analog field, was employed. The first stage of the study involved the characterization of the oil into the same pseudo-components utilized by the kinetic model. A match of relevant PVT data was done for this purpose. In the second stage, the field scale model was history matched with the new fluid model, which included the foamy oil behavior. The best agreement with field measured data was obtained with a dispersed-gas foamy oil model with velocity dependence of the reaction that converts the low-mobility dispersed gas into high-mobility free gas. The following stage consisted of the history match of the combustion tube test, which was partly achieved with an assisted-history-matching tool. In the last stage, the results obtained from the combustion tube match were applied to the field model. In order to determine the most appropriate locations of production and injection wells, several pilot configurations were studied combining vertical and horizontal wells. A sensitivity analysis was completed using operational parameters such as injection rates and distance between producers and injectors wells. Based on ultimate recovery, the best pattern configuration was selected along with the optimum operational parameters. This paper illustrates the application of a workflow for modeling ISC from laboratory experiments to the field scale.
Towards Seismic Detection and Characterization of Gas Hydrate Accumulations in Permafrost Environment: An Example From the Mallik Gas Hydrate Field, NWT, Canada
Authors: Bellefleur G. , Riedel M. , Huang J. , Milkereit B. , Brent T. 
Published: February 2011

Abstract
Three internationally-partnered research well programs in 1998, 2002, and 2007-08 studied the Mallik gas hydrate accumulation in the Mackenzie Delta, Canada, and have allowed successful extraction of subpermafrost core samples with significant amount of hydrates. Gas hydrate bearing intervals were logged with a comprehensive suite of tools and their producibility was tested in 2002 using thermal stimulation and in 2007/08 using depressurization techniques. Thus, the Mallik gas hydrates are well-characterized and are ideal targets for testing geophysical imaging techniques. Here, we apply acoustic impedance inversion to 3D seismic data acquired over the Mallik area to characterize gas hydrate occurrences and to help define their spatial extent away from well control. The inversion method converts reflections into acoustic impedances from which velocity and hydrate saturation were estimated. The extent and geometry of the two lower hydrate zones were mapped with high confidence and show a distribution controlled by local geology. Correlation between the uppermost hydrate zone and the 3D seismic data could not be established with confidence, because of geological heterogeneity and/or inappropriate seismic imaging. The heterogeneity of the Mallik gas hydrates was parameterized following a method based on multivariate conditional stochastic simulation of well-logging data. Following this method, multi-dimensional heterogeneous models of petrophysical properties (Vp, Vs and density) of hydratebearing sediments were constructed and used to assess effects of heterogeneity on gas hydrate volume estimates. Models including small-scale heterogneities provide volume estimate nearly an order of magnitude lower than earlier estimates which did not include effect of heterogeneity.
The Effect of Low Molecular Weight Multifunctional Additives on Heavy Oil Viscosity
Authors: Oldenburg T. B. , Yarranton H. W. , Larter S. R. 
Published: February 2011

Abstract
Highly viscous heavy oil and bitumen are becoming more important in the world energy mix as conventional resources decline. Any successful in situ recovery process must mobilize the highly viscous bitumen and move it to a production well. Standard methods use heat provided by steam (SAGD) or solvent (VAPEX), with encouraging combinations of steam and solvent (ES-SAGD) but these routes have inefficiencies. Alternative ways of mobilizing bitumen might involve viscosity reduction management of more fundamental controls on bitumen viscosity including managing internal physicochemical interactions between the interacting functional groups on different crude oil molecular components. Here we examine the impact of low molecular weight multiheteroatom species (LMWMH) as molecular Velcro linking high molecular weight moieties together by multiple interactions. Most species tested showed only a viscosity reducing dilution effect whereas THF/aniline as an additive showed an additional viscosity reducing effect particularly at low volume fraction of the additive. Considering that this additive is soluble in water and therefore easily transportable to the subsurface bitumen makes it a promising candidate for enhanced in situ bitumen viscosity reduction and thus improved in situ bitumen mobility.
Reservoir Characterization and Flow Simulation of a Low-Permeability Gas Reservoir: An Integrated Approach for Modeling Tommy Lakes Gas Field
Authors: Deng H. , Alfarhan M. , White L. S. , Oldow J. S. , Aiken C. L. , Aguilera R. 
Published: February 2011

Abstract
The Tommy Lakes field is located in northeastern British Columbia, Canada; and is one of the largest Middle Triassic gas pools within the Western Canada Sedimentary Basin (WCSB). The major gas production formation (Halfway/Doig reservoirs) at Tommy Lakes field corresponds to shoreface sands with permeabilities ranging between 0.1 and 3 md, and porosities of 3 to12%. For the purpose of production optimization and field development, a full field reservoir model was developed with the integration of advanced reservoir characterization, hydraulic fracture modeling, and history matching techniques.
This study presents an integrated workflow for modeling the low permeability Doig gas reservoir. A stochastic geostatistical reservoir model was developed based on concepts emanating from an outcrop analog analyzed with terrestrial LiDAR technology and 60 wells that represent the fundamental rock characteristics, structure, facies proportions and petrophysical properties of the Doig Anomalously Thick Sandstone Bodies (ATSB). Structural tops were interpreted from well logs and permeability/porosity relationships established from quantitative log analysis and core-log calibration. Facies were identified in cored intervals and were further grouped into 4 lithofacies. An artificial neural network was used for training the logs of key wells (GR, NPHI, RHOB) and populating the facies distribution of uncored wells. Facies-based log-derived porosity, permeability, shale volume and water saturation were assigned to grid blocks using sequential Gaussian simulation (SGS). Finally, the Monte-Carlo simulation approach was used to rank the key variables affecting OGIP in the uncertainty and optimization process.
Flow based techniques were used for up-scaling reservoir properties into the coarse simulation grid. The full field simulation model was calibrated with buildup data and hydraulic fracture modeling of single wells. Production of the Doig channel from comingled wells was allocated systematically in order to achieve a good match of the gas production history and bottomhole pressures. Sensitivity analysis of fracture half length and its impact on ultimate gas recovery was investigated. This concludes with an integrated development strategy.
It is concluded that integration of multiple domains leads to a valid full field reservoir model which is critical in developing an integrated strategy, predicting reservoir performance and optimizing gas production.