bluuebunny/crossref_metadata_2025_split huggingface dataset:
Multiphase Flow Measurements: Vankor Experience
Authors: Semenov A.A. , Bakhitov R.R. , Abramochkin S. A. 
Published: February 2011

Abstract
Provision for oil, gas, and water surface rate measurements from every production well is one of the most required issues for effective field development control. Several types of multiphase rate measurement units are available with various principle of measurement of the total producing liquid rate and the volume cuts for gas and water. Due to oil degassing during production, gas and water breakthroughs, and subsequently high liquid rates (up to 1600 m3/day), this task has become absolutely non-trivial for the Vankor wells.
Preliminary, cyclone-based gas-separators have been considered in the field as the means for primary phase separation and consequent measurement of the each phase rate using Coriolis-based mass metering units. However, due to the narrow operating range of both the cyclone separators and Coriolis mass-metering units, correct rate measurements were failed to achieve and such obstacle was confirmed by multiple comparison measurements with a stock tank.
A mobile measurement unit with Venturi tube and using electrical principle for measuring gas and watercut has been used in the field. Due to the necessity for calibration to reference rate measurement units, use of extensive input PVT properties, and diverse relationship between electrical properties of the gas-liquid fluid and volume fractions for gas and water, the use of this unit could not help in increasing the accuracy of liquid rate measurements over 15% and covering the full production range of wells.
Another unit type for multiphase flow rate measurements uses Venturi tube and radioactive source for gas and watercut. The introduction of the unit at the field allowed one to increase the accuracy of liquid rate (within 5% for several wells), gas-oil ratio, and watercut measurements significantly. It delivered an opportunity to increase a material balance model and carrying out a full-scale dynamic model history matching of the Vankor field.
Coalbed Methane Artificial Lift Challenges from Alberta's Mannville Coal
Authors: Johnson B. A. 
Published: February 2011

Abstract
In developing the Doris Mannville Coal Bed Methane (CBM) gas field near Fort Assiniboine, Alberta, the Nexen exploitation team encountered many unforeseen artificial lift challenges using Electric Submersible Pumps (ESPs). High failure rates and short pump run times made forecasting of production volumes and reserves difficult, while high operating costs driven primarily by downhole servicing reduced the economic viability of the project.
The root cause of the high pump failure rate was attributed in most part to the unanticipated volume of produced coal fines and reservoir solids in the produced water stream. The production of these solids, coupled with lower than expected water production rates, led to a re-evaluation of the field's artificial lift strategy. Following a thorough artificial lift evaluation, a change from an ESP to a reciprocating rod pump (Pump Jack) system was initiated.
The largest anticipated benefit of reciprocating rod pumping systems over ESP artificial lift systems were:
Increased minimum flow path area through the system, reducing the frequency of solids plugging, leading to longer pump run times. Reduced well servicing costs with reciprocating rod pumps through elimination of services required solely by ESPs. Elimination of pump failures due strictly to electrical shortages by changing from an electrical/mechanical (ESP) to a straight mechanical (Pump Jack) downhole system. Improved operating efficiency by matching artificial lift design with actual water production rates.
The change in artificial lift strategy made an immediate impact on pump failure rates in the Doris field. This paper will present the resulting increased pump run times, sustained production rates and drastically lower operating costs that has made reciprocating rod pumping systems the artificial lift method recommended by Nexen to exploit Alberta's Mannville coal for CBM.
Key Parameters in Steam Chamber Development
Authors: Baker R. O. , Rodrigues K. , Sandhu K. S. , Jong E. S. 
Published: February 2011

Abstract
There is a large amount of reserves associated with heavy oil worldwide and as a result SAGD is reaching technological maturity and its implications on the future of the petroleum industry are considerable. Most of the theory of SAGD was developed in idealized lab models and flow simulations without accounting for much heterogeneity as well as operational effects.
Currently there are a large number of wells in SAGD projects with available production, injection, and pressure data that needs to be analyzed. In addition, there are thousands of pressure and temperature measurements, 4D seismic surveys, and tiltmeter surveys. It is essential to examine all of this available data and explore important factors like areal coverage of the steam chamber, vertical sweep, and residual oil saturations within the steam chamber, as well as the role that heterogeneity plays in the development of the steam chamber. It is our opinion that some of the empirical field case observations cannot be easily explained by conventional reservoir engineering, or even by current thermal simulation techniques.
By closely examining available production, injection, pressure, seismic, temperature logs for two different SAGD projects, this paper will show that there is a good correlation between the volume of the steam chamber (Vstm) as calculated by vertical temperature observation well data and seismic data, compared to the steam chamber size as indicated by oil recovery. When we use seismic data for estimating areal coverage and vertical observation wells for vertical coverage or sweep, it appears that the oil saturation slowly decreases in the steam chamber and displacement efficiency is slowly increases with time. This paper attempts to use all the available seismic data and data from observation wells in not just a qualitative analysis of the steam chamber, but to develop a method to analytically determine quantitative estimates for volumes of the steam chamber, areal displacement efficiency of the steam chamber, and remaining oil saturation in the steam chamber over time. Invesitgating available data from different observation wells along SAGD well pairs will show that steam chamber shape is far from uniform.
A New Method To Simultaneously Measure In-Situ Permeability and Porosity Under Reservoir Conditions: Implications for Characterization of Unconventional Gas Reservoirs
Authors: Cui X. , Bustin R. M. , Brezovski R. , Nassichuk B. , Glover K. , Pathi V. 
Published: February 2011

Abstract
Accurate estimation of gas-in-place is crucial for successful evaluation and exploitation of unconventional gas reservoirs, such as shale gas, coalbed methane, and tight gas. However, gas effective porosity, one of the most important parameter in estimating gas in-place, is commonly measured on crushed samples of cores or cuttings at ambient pressure although many studies have shown that the porosity and permeability of reservoirs rocks decrease with increasing effective stress, and thus the pore volume/porosity measured on crushed samples at ambient (zero stress) conditions will be larger than porosity measured under in-situ reservoir stress conditions. Normally the stress-dependence of porosity is simply accounted for by a correction factor based on the linear poro-elastic deformation, which is likely an over-simplification.
In present study, we developed a new protocol for simultaneously measuring stress-dependent In-Situ Permeability and Porosity (ISPP) that provides a method for routine characterization of effective porosity and permeability under simulated reservoir conditions. Our new method can significantly reduce the uncertainties of porosity introduced by testing crushed samples under ambient conditions, testing time, and the need for good quality core samples that are usually unavailable.
Preliminary test results indicate that the stress dependence of porosity (or pore compressibility) of fine grained reservoir rocks follows a unique trend of each tested sample, which cannot be simply adjusted from ambient porosity by a universal factor. Physical and numerical sample tests suggest that our ISPP method can obtain permeability similar to the normal pressure Pulse-Decay Permeability (PDP) technique if samples are homogeneous or transversely layered along their axes. Otherwise, our ISPP method likely tests the geometrical average permeability of longitudinally layered samples instead of the weighted arithmetical average permeability tested by the PDP method.
Overall, our approach of simultaneously measuring effective porosity and permeability under reservoir conditions offers intrinsically consistent porosity-permeability data to characterize unconventional reservoirs. Our study also reveals that utilization of different methods to test samples in different orientations and different sizes is necessary to rigorously characterize the hierarchical permeability and porosity of heterogeneous and microporous unconventional reservoir rocks.
Optimization of Hydrocarbon Additives With Steam in SAGD for Three Major Canadian Oil Sands Deposits
Authors: Mohebati M. Hosseininejad , Maini B. B. , Harding T. G. 
Published: February 2011

Abstract
Heavy oil and bitumen are expected to become increasingly important sources of fuel in the coming decades. There are extensive deposits in Alberta that could be a principal source of fuel in the coming century. The Athabasca Oil Sands, the largest petroleum accumulation in the world, the Cold Lake oil deposit, and the Lloydminster reservoir are all major Canadian oil sands deposits. SAGD, which has shown considerable promise in all three of these major deposits, remains an expensive technique and requires large energy input. Energy intensity of SAGD and the environmental concerns make it imperative to find new oil extraction technologies.
Co-injecting hydrocarbon additives with steam offers the potential of lower energy and water consumption and reduced greenhouse gas emission by improving the oil rates and recoveries. In a previous paper by the same authors(Hosseininejad Mohebati, Maini et al. 2009), it was shown that the selection of a suitable hydrocarbon additive and the effectiveness of this hybrid process are strongly dependent on the operating conditions, reservoir fluid composition, the heavy oil viscosity, and the petrophysical properties of the reservoir. Among these factors, the heavy oil viscosity which is the most prominent difference between these three reservoirs could be a very important parameter in the performance of this hybrid process. Therefore, it is important to evaluate the effect of oil viscosity on solvent assisted SAGD.
Extensive numerical studies in a 3D model by means of a fully implicit thermal simulator were conducted to evaluate the efficiency of each hydrocarbon additive in Athabasca, Cold Lake and Lloydminster reservoirs. Varying mole percents of hexane, butane and methane were co-injected with steam in with different values of heavy oil viscosity. The effect of oil viscosity on the performance of each solvent was compared in terms of oil production rate and cumulative steam oil ratio.
Policy and Regulation in the Face of Uncertainty: The Case of Disruptive Markets for Unconventional Natural Gas in North America
Authors: Moore M. C. 
Published: February 2011

Abstract
Energy markets are inherently capital intensive, and operate under the constraints of a wide range of uncertainty and risk, from project and construction, to regulatory approvals and on to market supply and demand characteristics. They reflect deliberate, long term system scale, engineering design and anticipated rates of financial return. As a consequence, the role of policy and regulatory review and approvals plays a significant role in risk profiles.
Since 1990, the substitution of gas-fired combustion for other thermal energy resources has met several key objectives including lower capital cost, lower net air emissions profiles and faster ramp rates. Reports of declining reserves of Natural Gas in North America caused this model to be re-examined recently.
However, recent technology advances have made the extraction of natural gas from so-called unconventional sources cost effective, and extended estimates of affordable supplies several decades in the future. The impact of trend may disrupt reliance on coal and nuclear for base-load electricity resources, displace some hydroelectric facilities used for load firming, and even defer the need for some alternatives such as renewable.
Recent evidence of potential seismic and water quality hazards from hydraulic stimulation of geothermal and tight gas resources suggest that the existing regulatory approval model may be unprepared to deal with the uncertainty and risk associated with these activities. Regulators may decide to either defer decisions to the future, impose uneconomic mitigation measures designed to reduce risk to nearly zero, or simply deny projects on the basis of incomplete or difficult technical presentations or solutions.
Since energy development and consequent risk assessment is highly probabilistic in nature, the deterministic process of regulatory hearings includes an inherent bias against new or innovative, typically unproven technologies and processes. This paper explores the issues that must be addressed within the structure of the regulatory process in order to fairly evaluate the potential of new unconventional gas and alternative technologies in meeting future supply needs in the electricity system.
A Comparative Simulation Study of Addition of Solvents to Steam in SAGD Process
Authors: Ardali M. , Mamora D. D. , Barrufet M. 
Published: February 2011

Abstract
Steam assisted gravity drainage (SAGD) is demonstrated as a proven technology to unlock heavy oil and bitumen in Canadian reservoirs. One of the long-term concerns with the SAGD process is high energy intensity and related environmental impacts. Addition of potential alkane solvents to steam in processes such as ES-SAGD can reduce the high use of energy and green-house emissions in SAGD. However, the principal challenge is the high cost of the solvents. As a result, the economic viability of solvent assisted processes highly depends on the original reservoir and fluid properties and the operating strategy used to co-inject the solvents.
The main objective of this study is to compare the simulation results of addition of potential solvents to steam in two different types of reservoirs, cold lake and Athabasca. Propane, Butane, Pentane, Hexanes and Heptanes with different proportions from 1%-20% by weight have been co-injected with the steam. The simulations carried out in absence and presence of initial solution gas to find out the effect of solution gas on performance of SAGD and solvent assisted SAGD processes.
Simulation results show that initial solution gas reduces the oil recovery especially in Athabasca reservoir. A varying thickness non-condensable gas layer impedes heat transfer from the condensing steam to bitumen zone. Hydrocarbon additives create a high oil phase mobility zone resulting in production acceleration. Solvents heavier than butane are considered suitable candidates for Athabasca type and butane gave better results in Cold Lake type reservoir under operating conditions of this study. In addition, a detailed study is carried out on the properties of different phases such as phase mobility, saturation and viscosity at the steam solvent-oil interface to have a better understanding of the effect of presence hydrocarbon additives in the steam chamber.
Mass Diffusion Parameters in Presence of Interface Resistance in Gas-Bitumen Systems
Authors: Etminan S. Reza , Pooladi-Darvish M. , Maini B. , Chen Z. 
Published: February 2011

Abstract
Measurement of gas diffusivity in reservoir fluids is of interest for numbers of applications, and among different methods, the pressure decay method has received special attention due to its simplicity. In this technique, a quiescent oil column is brought in contact with diffusing gas from the top and the rate of change of gas pressure in the gas cap is recorded. The interpretation of the results is based on a solution of a forward problem, which invokes a complicated boundary condition. In this work, an analytical solution is presented for the most general form of the boundary condition, which takes into account all parameters including gas solubility, diffusion and a possible surface resistance. Effect of resistance against mass diffusion is usually neglected in modeling. One objective of this paper is to better understand the role of the skin resistance, because its inclusion could increase the degree of freedom of the backward problem, and could lead to misleading results (despite a good match of the measurements). Diffusion coefficients are needed for analysis and design of solvent based and gas injection recovery techniques. This parameter improves the prediction of compositional reservoir simulators.
Our mathematical solution reveals that depending on the permeability of the interface and magnitude of mass diffusion coefficient; the behavior of gas concentration at the interface and bitumen body changes. It was found out that once the film resistance is larger, the concentration at the interface exceeds the saturation concentration at the early time of diffusion and then it gets back to it as diffusion proceeds into the bitumen body.
It is expected that this new analytical solution would lead to improved interpretation of pressure decay tests and more accurate estimation of mass transfer parameters.
Considerations for the Implementation of the New Underground Injection Control Program for Carbon Dioxide Geologic Sequestration
Authors: Koplos J. , Nogi J. , Kobelski Bruce 
Published: February 2011

Abstract
In July 2008, the U.S. Environmental Protection Agency (EPA) issued a proposed rule under the authority of the Safe Drinking Water Act (SDWA) regarding the geologic sequestration (GS) of carbon dioxide. The proposed rule recommends the addition of a new class of injection well, Class VI, to EPA’s existing Underground Injection Control (UIC) Program to address the unique nature of carbon dioxide injection and to ensure the protection of underground sources of drinking water (USDWs) from carbon dioxide injection-related activities.
The proposed GS Rule builds upon the existing UIC regulatory framework established under the SDWA. The final rule, anticipated in late 2010 or early 2011, will apply to owners and operators of permitted Class VI injection wells for the subsurface injection of carbon dioxide for long-term underground storage.
States interested in obtaining approval for primary enforcement responsibility ("primacy") for the new Class VI program will apply for primacy to EPA with either a new UIC program application or a UIC program revision (depending on a particular state’s existing UIC primacy status). Any state that chooses not to apply for primacy, or that has not yet received approval for their proposed Class VI program, will have the UIC Class VI program administered by EPA until such time as the state has an approved Class VI program.
EPA is developing multiple technical and programmatic guidance documents for UIC Directors and proposed Class VI injection well owners and operators to assist in meeting the new GS rule requirements. In addition, EPA will be conducting nationwide training workshops for UIC Directors on primacy application and on the technical and programmatic elements of GS Rule and its implementation. EPA is also planning for a series of webcasts focused on technical aspects of the GS rule for interested owners, operators, field service providers, UIC permit reviewers, and others to be involved in GS activities. EPA anticipates that these guidance documents, implementation tools, trainings, and other outreach efforts will assist Class VI injection well owners and operators, as well as state UIC Directors, in meeting the new GS Rule requirements.
Real-Time Completion Optimization Of Multiple Laterals In Gas Shale Reservoirs: Integration of Geology, Log, Surface Seismic, and Microseismic Information
Authors: Ramakrishnan H. , Yuyan Rioka , Belhadi J. 
Published: February 2011

Abstract
Multidisciplinary data integration combined with the deployment of proper technology is key to optimizing shale gas completions. This paper focuses on the real-time completion optimization of multiple laterals drilled from the same well pad in shale gas reservoirs. These laterals are spaced as closeas a few hundred feet laterally with varying vertical landing points. Though these laterals do expose more of the nanodarcy permeability shale rock and increase contact area through fracture stimulation—resulting in more efficient drainage—the challenge remains to optimize the stimulation treatment to maximize coverage around each designated lateral. The optimization process involves perforation and stage placement, sequential stimulation of these laterals, fluid and proppant schedules, treatment rates, and application of diversion technology when appropriate to achieve effective stimulation along these laterals and between the wells.
In a comprehensive multiwell completion case history from the Barnett Shale, geologic, well, and surface seismic information was integrated with log measurements using Petrel reservoir modeling software. This integrated understanding was coupled with live microseismic data, enabling reliable real-time decisions during stimulation to optimize stimulation coverage and proppant placement around these laterals. Opportunities in making changes to original designs were seized when injectivity problems were encountered early in the treatment process. This approach was executed successfully to gain injectivity and, later, to increase the conductive fracture area, allowing the frac to be managed in real time.
Observed fracture pressure responses and production from these pad wells validated the approach. Ultimately, an optimal horizontal stimulation was achieved by leveraging favorable rock properties to create a larger fracture surface contact area, thereby maximizing gas production potential and recovery.
The integrated approach presented here can be applied to any single well or multilateral shale gaswells.
Biofuels: Green Energy for the Century?
Authors: Odizuru-Abangwu Ijeoma 
Published: February 2011

Abstract
Energy demand and usage is continuously increasing with the development of emerging economies like China and India. Present sources of energy, largely fossil fuels, are not sufficient to meet these increasing needs. Fossil fuels (oil, gas and coal) are associated with pollution and emission of greenhouse gases, which are harmful to the environment. As a result, global warming and climate change have taken centre stage in world summits; notable is the December 2009 United Nations Climate Change conference in Copenhagen.
With increasing concerns on global warming and its attendant effects on climate change, there is a gradual shift of technologies towards greener options. The use of fossil fuels is further bedevilled with its scarcity and access issues, hence, a conscious shift towards renewable energy. Renewable energy options include solar, wind, geothermal and biomass. These energy options are critical to the protection of the environment and energy sustainability. Currently, the biggest contribution to the world's renewable energy mix is biomass. Biofuels is becoming increasingly important for transportation because it is providing the much-needed green option to fossil fuels. A recent publication stated that it could reduce carbon emissions by as much as 50-60%.
Biofuels are fuels derived from organic sources (biomass). This paper discusses the sources of biofuels and its classifications into first, second and third generation biofuels. It also gives an overview of associated technologies used in conversion of biomass to biofuels and raises awareness on its economic, environment and technical benefits, as well as issues and challenges surrounding its use as a green energy option.