Combustion Kinetics of Athabasca Bitumen from 1D Combustion Tube Experiments

There are two basic requirements for heavy-oil recovery processes: first, mobilize the bitumen, and second, have a drive mechanism deliver the mobilized bitumen to a production wellbore. In situ combustion has the potential to be an important heavy-oil recovery method. Before design of in situ combustion recovery processes can start, it is necessary as a first step to understand the kinetics of various complex chemical reactions and determine kinetic constants associated with the reactions. Even with modern reservoir simulation capabilities, this is a significant challenge. In this research, an Athabasca bitumen combustion tube experiment, conducted by the ISC Research Group at the University of Calgary, was history matched by using a reservoir thermal simulator to determine a set of kinetic parameters as well as the transport parameters for the system. The main results of the history match was a match of air injection rate, bitumen and gas production volumes, average product gas compositions, temperature profiles along the tube through time, and pressure. Gridding sensitivities were examined to determine if the derived kinetic and transport parameters were dependent on gridblock size. The results revealed that the grid was refined enough to sufficiently capture thermal, mass transfer, and reaction length scales. After this single match was achieved, the same constants were used to successfully predict several other combustion tube experiments. The results suggest that the fuel (coke) for high-temperature oxidation (HTO) originates mainly from low-temperature oxidation (LTO) and not from thermal cracking. This implies that the major control on HTO is upstream oxygen transfer into the LTO region. If LTO does not occur, then a relatively small amount of coke is deposited in the matrix due to thermal cracking and this may be insufficient to start or sustain HTO.     

Design of Hybrid Steam-In Situ Combustion Bitumen Recovery Processes

Given enormous capital costs, operating expenses, flue gas emissions, water treatment and handling costs of thermal in situ bitumen recovery processes, improving the overall efficiency by lowering energy requirements, environmental impact, and costs of these production techniques is a priority. Steam-assisted gravity drainage (SAGD) is the most widely used in situ recovery technique in Athabasca reservoirs. Steam generation is done on surface and consequently, because of heat losses, the energy efficiency of SAGD can never be ideal with respect to the energy delivered to the sandface. An alternative to surface steam generation is in situ combustion (ISC) where heat is generated within the formation through injection of oxygen at a sufficiently high pressure to initiate combustion of bitumen. In this manner, the heat from the combustion reactions can be used directly to mobilize the bitumen. As an alternative, the heat can be used to generate steam within the formation which then is the agent to move heat in the reservoir. In this research, alternative hybrid techniques with simultaneous and sequential steam-oxygen injection processes are examined to maximize the thermal efficiency of the recovery process. These hybrid processes have the advantage that during ISC, steam is generated within the reservoir from injected and formation water and as a product of oxidation. This implies that ex situ steam generation requirements are reduced and if there is in situ storage of combustion gases, that overall gas emissions are reduced. In this research, detailed reservoir simulations are done to examine the dynamics of hybrid processes to enable design of these processes. The results reveal that hybrid processes can lower emitted carbon dioxide-to-oil ratio by about 46%, decrease the consumed natural gas-to-oil ratio by about 73%, reduce the cumulative energy-to-oil ratio by between 40% and 70% compared to conventional SAGD, and drop water consumption per unit oil produced. However, oil recovery is between 25% and 40% below that of SAGD. Design of successful hybrid steam–oxygen processes must take into account the balance between injected steam and amount of injected oxygen and combustion gas products that dilute injected and in situ-generated steam in the depletion chamber by lowering its partial pressure, and thus its saturation temperature which in turn impacts production rates and recovery.     

On the Impact of Permeability Heterogeneity on SAGD Steam Chamber Growth

Evolution of steam assisted gravity drainage (SAGD) steam chambers in heavy oil and bitumen reservoirs is tied to uniformity of steam pressure and quality along the length of the perforated interval of the well and reservoir geology and fluid properties adjacent to the well. If the reservoir geology has poor permeability at an interval along the wellpair, then steam delivery to and fluids production from the reservoir is not uniform. If the steam is well distributed throughout the injection well, then the key factor for a uniform steam chamber along the wellpair is reservoir geology. This is especially important in highly heterogeneous, variable thickness reservoirs where geology and reservoir oil composition may vary significantly over the length of a wellpair. Heterogeneity of a growing SAGD steam chamber is related to heterogeneity of the underlying geology. In this study the oil sands models are geostatistically populated to model spatial heterogeneity of permeability. The temperature profile (chamber growth), steam chamber height, conductive, convective, and total heat fluxes have been examined in each case. The results reveal that the length scales of steam chamber growth depend on the permeability heterogeneity. This provides a means to decide length scales for placement of in-well control devices in steam injectors in SAGD.     

A Simple Way to Model Nonsynchronous Generation of Oil and Gas from Kerogen

Many kinetic models for oil and gas generation use the same kinetics for generation of both oil and gas. In these models, gas is generated at precisely the same time as oil, despite agreement among geochemists that oil generation in nature largely precedes gas generation. Here we present a method for deriving separate kinetics for oil generation and gas generation from the available kinetics for total hydrocarbon generation. The method is based on published data in which oil kinetics are compiled separately from gas kinetics, but it is generalized to be applicable to any of the main kerogen types (I, IIa, IIb, or III), or to any mixtures of those types. Application of this new nonsynchronous model shows that the traditional synchronous models overpredict gas generation by about a factor of two within the oil window, and conversely severely underpredict late gas generation. The nonsynchronous model may predict gas generation several tens of million years later than does the synchronous model. The errors inherent in the synchronous models can be of significance in exploration decisions.     

Optimization of SAGD Well Elevation

The application of steam-assisted gravity drainage (SAGD) to recover heavy oil sands is becoming increasingly important in the northern Alberta McMurray Formation because of the vast resources/reserves accessible with this mechanism. Selecting the stratigraphic elevations of SAGD well pairs is a vital decision for reservoir evaluation and planning. The inherent uncertainty in the distribution of geological variables significantly influences this decision. Geostatistical simulation is used to capture geological uncertainty, which is used can be transformed into a distribution of the best possible well pair elevations. A simple exhaustive calculation scheme is used to determine the optimum stratigraphic location of a SAGD well pair where the recovery R is maximized. There are three basic steps to the methodology: (1) model the uncertainty in the top continuous bitumen (TCB) and bottom continuous bitumen (BCB) surfaces, (2) calculate the recovery at all possible elevation increments within the TCB and BCB interval, and (3) identify the elevation that maximizes R. This is repeated for multiple TCB/BCB pairs of surfaces to assess uncertainty. The methodology is described and implemented on a subset of data from the Athabasca Oilsands in Fort McMurray, Alberta.     

Bitumen Prices and Structural Changes in North American Crude Oil Markets

In an earlier report, changes in bitumen prices at Hardesty, Alberta, Canada, were modeled as the responses to changes in monthly prices of Hardesty light/medium crude oil for the period 2000–2006 with a simple error correction econometric model. This note re-examines that price relationship for the period 2009–2014. Over the period 2006–2014, there was also rapid growth in North American light oil production from low-permeability carbonate, sandstone, and shale reservoirs. During that period, Canadian raw bitumen production grew by more than 12% per year and there was significant geographical diversification in its markets. Results of the statistical analysis showed that the change in the dynamic relationships between bitumen prices and Hardesty light oil prices probably reflected, in part, the maturation of bitumen markets and closer integration with North American light oil markets. The analysis also examines the dynamic relationships between bitumen prices and West Texas Intermediate and Brent international benchmark crude oil prices. Ideally, if bitumen prices are found to be closely related to a widely traded benchmark crude oil, the benchmark crude oil price forecasts could be used as a basis for predicting bitumen prices. However, neither of international benchmark crude oils tested had high explanatory power.     

Study on Phase Behavior of CO2/Hydrocarbons in Shale Reservoirs Considering Sieving Effect and Capillary Pressure

The phase behavior of fluid is essential for predicting ultimate oil recovery and determining optimal production parameters. The pore size in shale porous media is nanopore, which causes different phase behaviors of fluid in unconventional reservoirs. Nanopores in shale media can be regard as semipermeable membrane to filter heavy components (sieving effect) in shale oil, which leads to the different distributions of fluid components and different phase behaviors. In addition, the phase behavior of fluid in nanopores can be significantly altered by large capillary pressure. In this paper, the phase behavior of fluid in shale reservoirs is investigated by a new two-phase flash algorithm considering sieving effect and capillary pressure. Firstly, membrane efficiency and capillary pressure are introduced to establish a thermodynamic equilibrium model that is solved by Rachford–Rice flash calculation and Newton–Raphson method. The capillary pressures in different pore sizes are calculated by the Young–Laplace equation. Then, the influences of sieving effect and capillary pressure on phase behavior are analyzed. The results indicate that capillary pressure can suppress the bubble point pressure of fluid in nanopores. The distributions of fluid components are different in various parts of shale media. In the unfiltered part, density and viscosity of fluid are higher. Finally, it is found that the membrane efficiency can be improved by CO₂ injection. The minimum miscibility pressure for shale oil–CO₂ system is also studied. The developed model provides a better understanding of the phase behavior of fluid in shale oil reservoirs.

     

Improved Minimum Miscibility Pressure Prediction for Gas Injection Process in Petroleum Reservoir

Determination of gas–oil minimum miscibility conditions is one of the important design parameters to improve the displacement efficiency of the hydrocarbon reservoir during enhanced oil recovery with gas injection. In this work, a support vector regression (SVR) model is developed using experimental data to estimate the minimum miscibility pressure (MMP) for various reservoir fluids and injection gases. Experimental MMP data taken from the reliable literature were used as input. Each data point input includes methane and intermediate components mole percent, plus fraction properties and reservoir temperature related to reservoir fluid and CO₂, H₂S, N₂ and intermediate mole fractions, and intermediate properties of the injected gas. Experimental MMP is regarded as the model output. The database contains 135 datasets, from which 125 datasets were used for model development, and the rest were used for model evaluation. Genetic algorithm was implemented to optimize the SVR model parameters. The proposed data-driven model was verified by statistical validation data. The model results illustrate a correlation coefficient (R²) of 0.999. In addition, the SVR results demonstrate the proposed model to be a fast tool and a robust approach to map input space to output features. The SVR model was compared to popular data-driven MMP estimation models as well. This comparison presents an acceptable accuracy relative to this estimation model. Finally, the presented model was evaluated against a comprehensive theoretical model of slim tube compositional simulation on a trusted literature dataset.     

Volatility of Bitumen Prices and Implications for the Industry

Sustained crude oil price increases have led to increased investment in and production of Canadian bitumen to supplement North American oil supplies. For new projects, the evaluation of profitability is based on a prediction of the future price path of bitumen and ultimately light/medium crude oil. This article examines the relationship between the bitumen and light crude oil prices in the context of a simple error-correction economic-adjustment model. The analysis shows bitumen prices to be significantly more volatile than light crude prices. Also, the dominant effect of an oil price shock on bitumen prices is immediate and is amplified, both in absolute terms and percentage price changes. It is argued that the bitumen industry response to such market risks will likely be a realignment toward vertical integration via new downstream construction, mergers, or on a de facto basis by the establishment of alliances.     

A global kinetic spatial data structure for a marine simulation

This paper proposes a new Free-Lagrange method based on the kinetic Voronoi diagram for fluid simulation. The objective here is to combine the advantages of an adoptive mesh structure with the advantages of kinetic mesh maintenance, and demonstrate their value for dynamic simulation. Despite the theoretical advantages of the Free-Lagrange method, its use has been handicapped with the reconstruction of topology after each time step that considerably reduces the efficiency of the method. In addition, the use of fixed time steps causes problems such as overshoots and undetected collisions. In order to demonstrate the ability of the proposed model to solve these problems, the method is applied to a dam-breaking problem and global tides. With the results obtained from these numerical experiments, the validity of the global kinetic data structure is approved. In particular, the method is found to be more efficient than existing methods. In addition, qualitative comparison of physical results with analytical solutions demonstrates the similarity of the results and confirms the physical validity of the proposed method. Further investigations with real-world data and the complete equation of motion are suggested to compare it with other numerical methods.     

Wave propagation in fluid-saturated media: waveform and spectral analysis

A new numerical approach to the solution of waves propagating in a fluid-saturated medium, using Biot's theory as a foundation, has important implications for oil reservoir management and earthquake prediction. A numerical scheme is developed using an exponential transformation that explicitly treats the petrophysical and fluid properties of the medium within the framework of a generalized model. The scheme accounts for wave dissipation and velocity modifications. The numerical solution is used to perform numerical experiments to study the dynamic behaviour of waves in a fluid-saturated medium at well-logging frequencies (15 kHz). The results from the numerical experiments indicate that the degree of saturation by a high-viscosity fluid (HVF) such as oil, the temperature and the porosity of a medium strongly influence the spectral power distribution, frequency content and the velocity of waves propagating through the medium. An increase in HVF saturation causes enhanced attenuation of the low-frequency components, and increases the seismic velocity. An increase in porosity, however, enriches the low-frequency components and decreases the seismic velocity. A spectral quantification procedure is suggested and used to obtain information about the petrophysical and fluid properties of the medium from the spectral characteristics of the transmitted waveform. The procedure involves segmentation of the energy or power distribution of the transmitted waveforms into specified energy bands. The energy or power in these bands is then estimated. The extracted quantification variables are found to have strong correlations with the degree of HVF saturation, and the temperature and the porosity of the medium.     

Two-dimensional modelling of subduction zone anisotropy with application to southwestern Japan

We present a series of 2-D numerical models of viscous flow in the mantle wedge induced by a subducting lithospheric plate. We use a kinematically defined slab geometry approximating the subduction of the Philippine Sea plate beneath Eurasia. Through finite element modelling we explore the effects of different rheological and thermal constraints (e.g. a low-viscosity region in the wedge corner, power law versus Newtonian rheology, the inclusion of thermal buoyancy forces and a temperature-dependent viscosity law) on the velocity and finite strain field in the mantle wedge. From the numerical flow models we construct models of anisotropy in the wedge by calculating the evolution of the finite strain ellipse and combining its geometry with appropriate elastic constants for effective transversely isotropic mantle material. We then predict shear wave splitting for stations located above the model domain using expressions derived from anisotropic perturbation theory, and compare the predictions to ∼500 previously published shear wave splitting measurements from seventeen stations of the broad-band F-net array located in southwestern Japan. Although the use of different model parameters can have a substantial effect on the character of the finite strain field, the effect on the average predicted splitting parameters is small. However, the variations with backazimuth and ray parameter of individual splitting intensity measurements at a given station for different models are often different, and rigorous analysis of details in the splitting patterns allows us to discriminate among different rheological models for flow in the mantle wedge. The splitting observed in southwestern Japan agrees well with the predictions of trench-perpendicular flow in the mantle wedge along with B-type olivine fabric dominating in a region from the wedge corner to about 125 km from the trench.     

Numerical Model of Two-Phase Flow in Dissolvable Porous Media and Simulation of Reservoir Acidizing

Mathematical model of porous media dissolution coupled with two-phase flow is proposed. The model is based on the conception of dissolvable porous medium with deformable mass-variable porous skeleton. Model can be used for simulation of coupled chemo- and hydrogeomechanical processes which are difficult to examine experimentally. Acidizing of calcite oil reservoir is used as an example of the process. Water solution of hydrochloric acid and oil are two fluid phases of the model with several components. Dissolvable porous media is treated as deformable mass-variable solid phase. Change in mass of the solid phase is caused by hydrochloric acid dissolving the calcite part of the solid phase. Dissolution is supposed to be congruent; kinetics is governed by the Nernst law. Software for numerical solution of the model is developed. It uses AmgCL parallel library for high-performance computing in order to deal with large algebraic systems on the each time step of calculations. The library uses algebraic multigrid methods for preconditioning and parallel iterative solvers. NVidia CUDA framework is used as a backend to perform GPGPU calculations, because it proved to be faster than OpenCL framework on this problem. Numerical experiments on the basis of data set from real reservoirs are conducted with the developed software. Good correlation between field and calculated data is achieved. Numerical experiments for different configurations of heterogeneous layer are performed. Acidizing of layers with highly permeable conduit and with random distribution of permeability is modeled.     

Reserve Growth in Oil Fields of West Siberian Basin, Russia

Although reserve (or field) growth has proved to be an important contributing factor in adding new reserves in mature petroleum basins, it is a poorly understood phenomenon. Although several papers have been published on the U.S. fields, there are only a few publications on fields in other petroleum provinces. This paper explores the reserve growth in the 42 largest West Siberian oil fields that contain about 55% of the basin's total oil reserves.The West Siberian oil fields show 13-fold reserve growth 20 years after the discovery year and only about 2-fold growth after the first production year. This difference in growth is attributed to extensive exploration and field delineation activities between discovery and the first production year. Because of the uncertainty in the length of evaluation time and in reported reserves during this initial period, reserve growth based on the first production year is more reliable for model development. However, reserve growth models based both on discovery year and first production year show rapid growth in the first few years and slower growth in the following years. In contrast, the reserve growth patterns for the conterminous United States and offshore Gulf of Mexico show a steady reserve increase throughout the productive lives of the fields. The different reserve booking requirements and the lack of capital investment for improved reservoir management and production technologies in West Siberia are the probable causes for the difference in the growth patterns.The models based on the first production year predict that the reserve growth potential in the 42 largest oil fields of West Siberia for a five-year period (1998–2003) ranges from 270–330 million barrels or 0.34–0.42% per year. For a similar five-year period (1996–2001), models for the conterminous United States predict a growth of 0.54–0.75% per year.     

Measuring and Simulating Co(II) Sorption on Waste Calcite,Zeolite and Kaolinite

Sorption of cobalt (CoII) ions from aqueous solution by waste calcite, kaolinite and zeolite was investigated in a series of batch experiments. The sorption capacity of the sorbents was a function of the initial solution pH, contact time and sorbent/sorbate ratio. For these three sorbents, the kinetic and isotherm experimental data were well fitted to pseudo-second-order and Langmuir equations, respectively. The maximum sorption capacity (mg g^?1) of Co(II) was 4.67, 3.76 and 2.23 for waste calcite, zeolite and kaolinite, respectively. Desorption experiments showed that the desorption capacities were in the order of zeolite?>?kaolinite?>?waste calcite. The equilibrium and kinetic results indicated that waste calcite had the best performance for the removal of Co(II) compared to zeolite and kaolinite. To simulate and predict Co(II) sorption mechanisms, the surface complexation and cation exchange models in PHREEQC program were used. The model results suggested that the main mechanisms of Co(II) sorption on waste calcite and zeolite were surface complexation and cation exchange, respectively. In the case of kaolinite, the model predicted that both mechanisms were involved in the sorption of Co(II), but the surface complexation was the predominant mechanism.

     

Analysis of Fault Permeability Using Mapping and Flow Modeling, Hickory Sandstone Aquifer, Central Texas

Reservoir compartments, typical targets for infill well locations, are commonly created by faults that may reduce permeability. A narrow fault may consist of a complex assemblage of deformation elements that result in spatially variable and anisotropic permeabilities. We report on the permeability structure of a km-scale fault sampled through drilling a faulted siliciclastic aquifer in central Texas. Probe and whole-core permeabilities, serial CAT scans, and textural and structural data from the selected core samples are used to understand permeability structure of fault zones and develop predictive models of fault zone permeability. Using numerical flow simulation, it is possible to predict permeability anisotropy associated with faults and evaluate the effect of individual deformation elements in the overall permeability tensor. We found relationships between the permeability of the host rock and those of the highly deformed (HD) fault-elements according to the fault throw. The lateral continuity and predictable permeability of the HD fault elements enhance capability for estimating the effects of subseismic faulting on fluid flow in low-shale reservoirs.     

Econometric and learning curve estimation of U.S. potential oil supply

This study employs (1) a simple econometric model to generate a time series of drilling footage to the year 2040 and (2) learning models to estimate the oil reserve additions from that drilling, given scenarios of oil price and projected U.S. population. Reserve additions are estimated separately for the lower 48 states and Alaska regions by estimating separate drilling footage and learning models for each region. Generally, the estimates of potential supply from undiscovered oil fields and from extensions of known fields are more optimistic than recent estimates by others. For a $1989 price of about $20/barrel (bbl), which is similar to recent prices, the potential supply of oil is estimated to be approximately 60.7 billion bbl, with 95-percent confidence bounds of 54.3 and 67.1 billion bbl. For a price of $25.50/bbl, potential supply is estimated to be approximately 82 billion bbl, with 95-percent confidence bounds of 74.5 and 89.5 billion bbl. Although estimates of potential oil supply for the entire United States are more optimistic than other recent estimates, the part of that supply estimated to be forthcoming from Alaska is smaller than other recent estimates: 2.3 and 3.3 billion bbl for prices of about $20 and $25.50 per barrel, respectively. Thus, reserve additions from the lower 48 states through development drilling and through improved recovery and production technologies will become increasingly important to future U.S. oil supply.     

Recovery Factors of Oil Resources in China

This paper provides a new method to estimate recovery factors of oil resources. The China National Petroleum Assessment (2003–2007) (CNPA 2007) evaluates in-place oil resources and applies the recovery factor (RF) to estimate recoverable oil resources. The RF of oil resources plays an important role in the CNPA 2007. Based on the geological features, 24 types of oil assessment units are defined, such as the Mesozoic rift unit, the Mesozoic and Cenozoic foreland unit, etc. Through the recovery factor statistics of oil reserves (discovered) in different accumulations, as well as the potential analyses of enhanced petroleum recovery, appropriate RF valuing standards of oil resources (discovered and undiscovered) in different assessment units are developed. Calculation methods of oil resource RFs are established, including the appraisal standards, scoring, and calculation steps of oil resource RFs. Through the case studies, the valuing and appraisal standards of oil resource RFs are verified. Robust appraisal standards allow the RF method to be a valuable tool to effective assessment of China’s recoverable oil resources.     

Kinetics of Cd Release from Some Contaminated Calcareous Soils

Contamination of soils with heavy metals may pose long-term risk to groundwater quality leading to health implications. Bioavailability of heavy metals, like cadmium (Cd) is strongly affected by sorption and desorption processes. The release of heavy metals from contaminated soils is a major contamination risks to natural waters. The release of Cd from contaminated soils is strongly influenced by its mobility and bioavailability. In this study, the kinetics of Cd desorption from ten samples of contaminated calcareous soils, with widely varying physicochemical properties, were studied using 0.01 M EDTA extraction. The median percentage of Cd released was about 27.7% of the total extractable Cd in the soils. The release of Cd was characterized by an initial fast release rate (of labile fractions) followed by a slower release rate (of less labile fractions) and a model of two first-order reactions adequately describes the observed release of Cd from the studied soil samples. There was positive correlation between the amount of Cd released at first phase of release and Cd in exchangeable fraction, indicating that this fraction of Cd is the main fraction controlling the Cd in the kinetic experiments. There was strongly negative correlation between the amount of Cd released at first and second phases of release and residual fraction, suggesting that this fraction did not contribute in Cd release in the kinetic experiments. The results can be used to provide information for evaluation of Cd potential toxicity and ecological risk from contaminated calcareous soils.