Opposite Contributions of Types I and II Organic Matter to Nanoporosity in Lacustrine Shale

Natural Resources Research - Nanoporosity is a key factor for evaluating shale oil/gas potential and recovery. Organic matter (OM) can be a primary host of nanopores in shale. The Triassic Yanchang...     

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.     

Deep-Lacustrine Shale Heterogeneity and Its Impact on Hydrocarbon Generation,Expulsion, and Retention: A Case Study from the Upper Triassic Yanchang Formation,Ordos Basin,China

The Chang-7 shale of the Upper Triassic Yanchang Formation was deposited in a deep-lacustrine environment in the southwest part of the Ordos Basin. It is characterized by a strong lithological heterogeneity, consisting primarily of pure shale and sandy laminated shale. This study explored the impact of sandy laminae in the thick pure shale on hydrocarbon generation, retention, and expulsion, which were rarely considered in previous studies. Based on core observation, thin section, and geochemical analysis, the hydrocarbon generation, retention, and expulsion characteristics were obtained for both pure shale and sandy laminated shale. In general, the Chang-7 shale stays at low mature to mature thermal evolution stage and has good hydrocarbon generation potential. It contains mainly Type II kerogen with an average total organic carbon (TOC) of 2.9% and average (S₁?+?S₂) of 8.2 mg/g. Compared with sandy laminated shale, pure shale contains more retained liquid hydrocarbon and has a higher amount of asphaltene and nitrogen–sulfur–oxygen (NSO) polarized components, indicating a relatively weak hydrocarbon expulsion process. The middle part of a thick pure shale retains more liquid hydrocarbon and has higher percentages of asphaltene and NSO polarized components than that of the top and basal part of the shale where sandy laminae occur. The difference in hydrocarbon retention capacity is interpreted to have been primarily caused by the comparatively higher reservoir quality of the sandy laminated shale, having higher amount of brittle minerals and larger pores than the pure shale. Polymer dissolution and nanopore adsorption are also key factors in hydrocarbon retention and component partition. Based on this study, we suggest that sandy laminated shale, which receives most of the hydrocarbon from adjacent pure shale, should be the current favorable shale oil exploration targets. Even though pure shale contains high hydrocarbon potential, its development is still pending improved technologies, which could solve the challenges caused by complicated geological conditions.

     

Quadrangle-grid velocity–stress finite difference method for poroelastic wave equations

A quadrangle-grid velocity–stress finite difference method, based on a first-order hyperbolic system that is equivalent to Biot's equations, is developed for the simulation of wave propagation in 2-D heterogeneous porous media. In this method the velocity components of the solid material and of the pore fluid relative to that of the solid, and the stress components of three solid stresses and one fluid pressure are defined at different nodes for a staggered non-rectangular grid. The scheme uses non-orthogonal grids, allowing surface topography and curved interfaces to be easily modelled in the numerical simulation of seismic responses of poroelastic reservoirs. The free-surface conditions of complex geometry are achieved by using integral equilibrium equations on the surface, and the source implementations are simple. The algorithm is an extension of the quadrangle-grid finite difference method used for elastic wave equations.     

Determining Wettability of Fractured Carbonate Reservoirs

Wettability plays a pivotal role in oil recovery processes in reservoirs owing to the fact that it has a direct impact on the proportion of oil recovery. Reservoir rocks are a complex of a variety of mineral types, and each mineral may have a different wettability. Typically most aquifer materials such as quartz, carbonate, and dolomite are water-wet prior to oil migration. Some oil recovery processes are designed to alter the wetting preference of the oil formation to be more oil-wet. There are three techniques used in the laboratory for the characterization of the capillary pressure properties of core samples: mercury injection, centrifuge, and porous plate. This article provides an in-depth review of wettability. It also entails a case study from one of the Iranian carbonate reservoirs and measurements, which have been carried out for selected samples to clarify the nature of the wettability of reservoir rock. Samples were chosen from three wells of oil field which is composed of limestones and dolomites, rarely inter-bedded by shales, and their wettability was measured by Amott–Harvey method, which is one of the main methods for measuring wettability. After cleaning and drying the samples, measurements were carried out. According to the results, it can be said that the range of Amott–Harvey index for these samples is between ?0.48 and ?0.8. In Amott–Harvey method, if IAH varies from ?1 to ?0.3, the rock is oil-wet. Therefore, it can be concluded that the reservoir is oil-wet.     

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.     

Geologic and Economic Criteria for Siting Clean-Coal Facilities in the Texas Gulf Coast, USA

The Texas Gulf Coast (TGC) contains the greatest number of favorably co-located CO₂ sources and sinks in Texas that favor new potential clean-coal facilities. Areas in the TGC with clean-coal potential were delineated by mapping spatial linkages between coal- and lignite-bearing formations and geologic and infrastructure factors that include proximity to existing fields from mine-mouth power plants for enhanced oil recovery (EOR), length of new pipelines to transport CO₂ from new clean-coal facilities to either EOR fields or to brine formations for deep storage, proximity to centers of electric load, and depth to subsurface coal for enhanced coalbed methane recovery. Other factors include thickness of brine formations for deep storage of CO₂, groundwater and surface-water availability, and proximity to railroads for haulage of western U.S. coal feedstock. Geospatial analysis of maps portraying the distribution of these factors, together with data on volumes of oil recoverable from miscible CO₂ flooding of oil fields, indicates that optimal areas for new clean-coal sites in the TGC are in east and southeast Texas. CO₂ pipeline networks linking these sites to EOR fields are integral components of systems that can typically recover 5–50 million stock tank barrels from miscible CO₂ flooding from each EOR field. Many of these fields with EOR potential (for example, Neches, Long Lake, Conroe, and Livingston) have a great potential for stacked CO₂ storage, in which multiple reservoir zones can undergo EOR development and deeper zones in the field can accommodate excess CO₂ from EOR operations.     

Conventional and Unconventional Hydrocarbon Resource Potential Evaluation of Source Rocks and Reservoirs: A Case Study of the Upper Xiaganchaigou Formation,Western Qaidam Basin,Northwest China

The Paleogene upper Xiaganchaigou Formation (E₃²) is the most important source rock and reservoir in the Qaidam Basin. However, there are few studies on the processes of hydrocarbon accumulation in this formation; therefore, its hydrocarbon resource potential has not been estimated reasonably. This paper evaluates the hydrocarbon generation properties in light of an improved hydrocarbon generation and expulsion potential model. According to the geochemical characteristics of source rocks and the petrological features of reservoirs, the potentials of different resource types, including conventional oil, tight oil and shale oil, are quantified by combining the buoyancy-driven hydrocarbon accumulation depth (BHAD) and the lower limit for movable resource abundance. The results show that the source rocks are characterized by a large thickness (more than 1000 m), moderate organic matter content, high marginal maturity and a high conversion rate (50% hydrocarbons have been discharged before R_o?=?1%), which provide sufficient oil sources for reservoir formation. Moreover, the reservoirs in the Qaidam Basin consist mainly of low-porosity and low-permeability tight carbonates (porosity of 4.7% and permeability less than 1 mD). The maximum hydrocarbon generation, expulsion, retention and movable retention intensities at present are 350?×?10⁴ t/km², 250?×?10⁴ t/km², 130?×?10⁴ t/km² and 125?×?10⁴ t/km², respectively. The thresholds of hydrocarbon generation, expulsion and BHAD were 0.46% R_o, 0.67% R_o and 0.7% R_o, respectively. Moreover, the dynamic evolution process of hydrocarbon accumulation was divided into three evolution stages, namely, (a) initial hydrocarbon accumulation, (b) conventional hydrocarbon reservoir and shale oil accumulation and (c) unconventional tight oil accumulation. The conventional oil, tight oil and movable shale oil resource potentials were 10.44?×?10⁸ t, 51.9?×?10⁸ t and 390?×?10⁸ t, respectively. This study demonstrates the good resource prospects of E₃² in the Qaidam Basin. A comprehensive workflow for unconventional petroleum resource potential evaluation is provided, and it has certain reference significance for other petroliferous basins, especially those in the early unconventional hydrocarbon exploration stage.

     

Assessment of Alaska’s North Slope Oil Field Capacity to Sequester CO2

The capacity of 21 major fields containing more than 95% of the North Slope of Alaska’s oil were investigated for CO₂ storage by injecting CO₂ as an enhanced oil recovery (EOR) agent. These fields meet the criteria for the application of miscible and immiscible CO₂-EOR methods and contain about 40 billion barrels of oil after primary and secondary recovery. Volumetric calculations from this study indicate that these fields have a static storage capacity of 3 billion metric tons of CO₂, assuming 100% oil recovery, re-pressurizing the fields to pre-fracturing pressure and applying a 50% capacity reduction to compensate for heterogeneity and for water invasion from the underlying aquifer. A ranking produced from this study, mainly controlled by field size and fracture gradient, identifies Prudhoe, Kuparuk, and West Sak as possessing the largest storage capacities under a 20% safety factor on pressures applied during storage to avoid over-pressurization, fracturing, and gas leakage. Simulation studies were conducted using CO₂ Prophet to determine the amount of oil technically recoverable and CO₂ gas storage possible during this process. Fields were categorized as miscible, partially miscible, and immiscible based on the miscibility of CO₂ with their oil. Seven sample fields were selected across these categories for simulation studies comparing pure CO₂ and water-alternating-gas injection. Results showed that the top two fields in each category for recovery and CO₂ storage were Alpine and Point McIntyre (miscible), Prudhoe and Kuparuk (partially miscible), and West Sak and Lisburne (immiscible). The study concludes that 5 billion metric tons of CO₂ can be stored while recovering 14.2 billion barrels of the remaining oil.     

Specific Storage Volumes: A Useful Tool for CO2 Storage Capacity Assessment

Subsurface geologic strata have the potential to store billions of tons of anthropogenic CO₂; therefore, geologic carbon sequestration can be an effective mitigation tool used to slow the rate at which levels of atmospheric CO₂ are increasing. Oil and gas reservoirs, coal beds, and saline reservoirs can be used for CO₂ storage; however, it is difficult to assess and compare the relative storage capacities of these different settings. Typically, CO₂ emissions are reported in units of mass, which are not directly applicable to comparing the CO₂ storage capacities of the various storage targets. However, if the emission values are recalculated to volumes per unit mass (specific volume) then the volumes of geologic reservoirs necessary to store CO₂ emissions from large point sources can be estimated. The factors necessary to convert the mass of CO₂ emissions to geologic storage volume (referred to here as Specific Storage Volume or ‘SSV’) can be reported in units of cubic meters, cubic feet, and petroleum barrels. The SSVs can be used to estimate the reservoir volume needed to store CO₂ produced over the lifetime of an individual point source, and to identify CO₂ storage targets of sufficient size to meet the demand from that given point source. These storage volumes also can then be projected onto the land surface to outline a representative “footprint,” which marks the areal extent of storage. This footprint can be compared with the terrestrial carbon sequestration capacity of the same land area. The overall utility of this application is that the total storage capacity of any given parcel of land (from surface to basement) can be determined, and may assist in making land management decisions.     

Unconventional Energy Resources: 2013 Review

This report contains nine unconventional energy resource commodity summaries and an analysis of energy economics prepared by committees of the Energy Minerals Division of the American Association of Petroleum Geologists. Unconventional energy resources, as used in this report, are those energy resources that do not occur in discrete oil or gas reservoirs held in structural or stratigraphic traps in sedimentary basins. These resources include coal, coalbed methane, gas hydrates, tight-gas sands, gas shale and shale oil, geothermal resources, oil sands, oil shale, and U and Th resources and associated rare earth elements of industrial interest. Current U.S. and global research and development activities are summarized for each unconventional energy commodity in the topical sections of this report.     

Unconventional Energy Resources: 2011 Review

This report contains nine unconventional energy resource commodity summaries prepared by committees of the Energy Minerals Division (EMD) of the American Association of Petroleum Geologists. Unconventional energy resources, as used in this report, are those energy resources that do not occur in discrete oil or gas reservoirs held in structural or stratigraphic traps in sedimentary basins. These resources include coal, coalbed methane, gas hydrates, tight gas sands, gas shale and shale oil, geothermal resources, oil sands, oil shale, and uranium resources. Current U.S. and global research and development activities are summarized for each unconventional energy commodity in the topical sections of this report. Coal and uranium are expected to supply a significant portion of the world’s energy mix in coming years. Coalbed methane continues to supply about 9% of the U.S. gas production and exploration is expanding in other countries. Recently, natural gas produced from shale and low-permeability (tight) sandstone has made a significant contribution to the energy supply of the United States and is an increasing target for exploration around the world. In addition, oil from shale and heavy oil from sandstone are a new exploration focus in many areas (including the Green River area of Wyoming and northern Alberta). In recent years, research in the areas of geothermal energy sources and gas hydrates has continued to advance. Reviews of the current research and the stages of development of these unconventional energy resources are described in the various sections of this report.     

Geochemical Characteristics of Oil from Oligocene Lower Ganchaigou Formation Oil Sand in Northern Qaidam Basin,China

Oil from the Oligocene oil sands of the Lower Ganchaigou Formation in the Northern Qaidam Basin and the related asphaltenes was analyzed using bulk and organic geochemical methods to assess the organic matter source input, thermal maturity, paleo-environmental conditions, kerogen type, hydrocarbon quality, and the correlation between this oil and its potential source rock in the basin. The extracted oil samples are characterized by very high contents of saturated hydrocarbons (average 62.76%), low contents of aromatic hydrocarbons (average 16.11%), and moderate amounts of nitrogen–sulfur–oxygen or resin compounds (average 21.57%), suggesting that the fluid petroleum extracted from the Oligocene oil sands is of high quality. However, a variety of biomarker parameters obtained from the hydrocarbon fractions (saturated and aromatic) indicate that the extracted oil was generated from source rocks with a wide range of thermal maturity conditions, ranging from the early to peak oil window stages, which are generally consistent with the biomarker maturity parameters, vitrinite reflectance (approximately 0.6%), and T_max values of the Middle Jurassic carbonaceous mudstones and organic-rich mudstone source rocks of the Dameigou Formation, as reported in the literature. These findings suggest that the studied oil is derived from Dameigou Formation source rocks. Furthermore, the source- and environment-related biomarker parameters of the studied oil are characterized by relatively high pristane/phytane ratios, the presence of tricyclic terpanes, low abundances of C₂₇ regular steranes, low C₂₇/C₂₉ regular sterane ratios, and very low sterane/hopane ratios. These data suggest that the oil was generated from source rocks containing plankton/land plant matter that was mainly deposited in a lacustrine environment and preserved under sub-oxic to oxic conditions, and the data also indicate a potential relationship between the studied oil and the associated potential source rocks. The distribution of pristane, phytane, tricyclic terpanes, regular steranes and hopane shows an affinity with the studied Oligocene Lower Ganchaigou Formation oil to previously published Dameigou Formation source rocks. In support of this finding, the pyrolysis–gas chromatography results of the analyzed oil asphaltene indicate that the oil was primarily derived from type II organic matter, which is also consistent with the organic matter of the Middle Jurassic source rocks. Thus, the Middle Jurassic carbonaceous mudstones and organic rock mudstones of the Dameigou Formation could be significantly contributing source rocks to the Oligocene Lower Ganchaigou Formation oil sand and other oil reservoirs in the Northern Qaidam Basin.

     

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.     

Origin of early overpressure in the Upper Devonian Catskill Delta Complex, western New York state

The Upper Devonian Rhinestreet black shale of the western New York state region of the Appalachian Basin has experienced multiple episodes of overpressure generation manifested by at least two sets of natural hydraulic fractures. These overpressure events were thermal in origin and induced by the generation of hydrocarbons during the Alleghanian orogeny close to or at the Rhinestreet's ～3.1 km maximum burial depth. Analysis of differential gravitational compaction strain of the organic‐rich shale around embedded carbonate concretions that formed within a metre or so of the seafloor indicates that the Rhinestreet shale was compacted ～58%. Compaction strain was recalculated to a palaeoporosity of 37.8%, in excess of that expected for burial >3 km. The palaeoporosity of the Rhinestreet shale suggests that porosity reduction caused by normal gravitational compaction of the low‐permeability carbonaceous sediment was arrested at some depth shy of its maximum burial depth by pore pressure in excess of hydrostatic. The depth at which the Rhinestreet shale became overpressured, the palaeo‐fluid retention depth, was estimated by use of published normal compaction curves and empirical porosity‐depth algorithms to fall between 850 and 1380 m. Early and relatively shallow overpressuring of the Rhinestreet shale likely originated by disequilibrium compaction induced by a marked increase in sedimentation rate in the latter half of the Famennian stage (Late Devonian) as the Catskill Delta Complex prograded westward across the Appalachian Basin in response to Acadian tectonics. The regional Upper Devonian stratigraphy of western New York state indicates that the onset of overpressure occurred at a depth of ～1100 m, well in advance of the Rhinestreet shale's entry into the oil window during the Alleghanian orogeny.     

Quantitative analysis of the impact factors of conventional energy carbon emissions in Kazakhstan based on LMDI decomposition and STIRPAT model

Quantitative analysis of the impact factors in energy-related CO₂ emissions serves as an important guide for reducing carbon emissions and building an environmentally-friendly society. This paper aims to use LMDI method and a modified STIRPAT model to research the conventional energy-related CO₂ emissions in Kazakhstan after the collapse of the Soviet Union. The results show that the trajectory of CO₂ emissions displayed U-shaped curve from 1992 to 2013. Based on the extended Kaya identity and additive LMDI method, we decomposed total CO₂ emissions into four influencing factors. Of those, the economic active effect is the most influential factor driving CO₂ emissions, which produced 110.86 Mt CO₂ emissions, with a contribution rate of 43.92%. The second driving factor is the population effect, which led to 11.87 Mt CO₂ emissions with a contribution rate of 4.7%. On the contrary, the energy intensity effect is the most inhibiting factor, which caused–110.90 Mt CO₂ emissions with a contribution rate of–43.94%, followed by the energy carbon structure effect resulting in–18.76 Mt CO₂ emissions with a contribution rate of–7.43%. In order to provide an in-depth examination of the change response between energy-related CO₂ emissions and each impact factor, we construct a modified STIRPAT model based on ridge regression estimation. The results indicate that for every 1% increase in population size, economic activity, energy intensity and energy carbon structure, there is a subsequent increase in CO₂ emissions of 3.13%, 0.41%, 0.30% and 0.63%, respectively.     

An Analysis of Environmental and Economic Impacts of Fossil Fuel Production in the U.S. from 2001 to 2015

The production and burning of fossil fuels is the primary contributor to CO₂ emissions for the U.S. We assess the impact of producing coal, crude oil, and natural gas on the environment and economic well-being by analyzing state-level data from 2001 to 2015. Our findings show that coal production has led to more CO₂ emissions and no significant benefit to economic well-being. Crude oil production has a non-significant impact on CO₂ emissions but is related to a lower poverty rate, a higher median household income, and a higher employment rate. Natural gas withdrawals have a positive impact on median household income. We discuss these findings in the context of current U.S. energy policies and then provide directions for future research.     

Fluid inclusions as constraints in a three‐dimensional hydro‐thermo‐mechanical model of the Paris basin,France

Fluid inclusion homogenization temperatures and three‐dimensional hydro‐thermo‐mechanical modelling were combined to constrain fluid flow, solute and heat transport in the Paris basin, France, focusing on the two main petroleum reservoirs i.e. the Dogger and the Triassic (Keuper) formations. The average homogenization temperatures of two‐phase aqueous inclusions in different samples range from 66 °C to 88 °C in the Dogger calcite cement, from 106 °C to 118 °C in the Keuper dolomite cement and from 89 °C to 126 °C in the Keuper quartz and K‐feldspar cements. The maximum homogenization temperatures for inclusions in the Keuper quartz and K‐feldspar cements were 17–47 °C higher than present‐day temperatures in the boreholes at similar depths. Processes that might explain higher temperatures in the past were examined through numerical simulations and sensitivity tests. A warmer climate in the Late Cretaceous–Early Tertiary resulted in a temperature rise of only 8 °C. Late Cretaceous chalk had a thermal blanketing effect that resulted in simulated temperatures as high as 15–20 °C above the present day ones. An additional 300 m deposition and subsequent erosion of chalk, not taken into account so far, has to be considered to simulate the high palaeo‐temperatures recorded by fluid inclusions in both reservoirs. In view of the simulated thermal history of the basin, in the Keuper, an age of about 85 Ma is consistent with quartz/K‐feldspar temperatures and an age of about 65 Ma is in agreement with the precipitation temperature of the dolomite cement. Our models suggest an age of about 50 Ma for the Dogger calcite cementation.     

Subsurface Sequestration of CO<Subscript>2</Subscript> in the U.S: Is it Money Best Spent?

The continuously decreasing average coal rank (heating value), inadequate investment, and ever stricter air-emission controls have caused the average efficiency of electricity generation from coal in the U.S. to plummet to a mere 32% by the year 2008. The U.S. gas-fired powerplants are 30% more efficient than the coal-fired ones, with average efficiency of 43% in 2008. Replacing each 1,000 MW _e generated by an average coal-fired powerplant with an average gas-fired powerplant would avoid today 7 million tonnes of CO₂ emissions, 1.2 million tonnes of toxic ash, and significant issues with water contamination. The parallel upgrades to the more efficient supercritical steam turbines would decrease current emissions by up to 50% (from the current average plant efficiency of 32% to over 45%). The CO₂ captured in the new combined-cycle powerplants might be used to enhance oil recovery in local fields, where feasible. The CO₂ enhanced oil recovery (EOR) can never become the main sink for the gigantic CO₂ volume generated each year by electric powerplants. Currently, EOR could absorb only 1% of that volume.     

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.