bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Gel-Foam System for Water Shutoff Purposes in Wormhole Reservoirs
Authors: Asghari K. , Taabbodi L. , Dong M. 
Published: December 2007

Abstract
Oil reservoirs in the Lloydminister region, Canada, are produced through the process of Clod Heavy Oil Production with Sand (CHOPS). Implementation of CHOPS in these fields causes the formation of wormholes, which leads to production of excessive water and abandonment of the wells. In order to reduce the excess water production from wormholes, variety of techniques have been suggested and tested with minimal success. Blocking the wormholes by the means of clay, polymer-gel systems, and gel-foams are among the proposed methods. This paper presents the results of a series of experiments conducted in order to develop and test the applicability of a new gel-foam system for blocking wormholes in oil reservoirs. As a result, a new gel-foam system was invented that creates stable foam in wormholes for the duration of gelation time. The composition of the gel-foam was based on polyacrylamide cross linked with chromium(III), plus a mixture of solutions of two commercially available surfactants. These commercially available surfactants were tested at various concentrations and ratios to develop the most stable gel-foam system. An experimental set up was designed and built which allowed for two layers of unconsolidated sand as the matrix separated by a high permeability wormhole between them. The effect of various sizes of wormholes on the performance of this gel-foam system was tested. All experiments were conducted at atmospheric pressure and constant temperature of 30°C, with some experiments in the presence of residual oil. For all the experiments the residual resistance factors to the flow of water in high permeability pathways were in the range of 25 to about 200. The results obtained are clear indication of the effectiveness of this newly developed gel-foam system for blocking wormholes and other high permeability pathways in reservoirs.
Investigation of the Vapex Process in High-Pressure Fractured Heavy-Oil Reservoirs
Authors: Rostami B. , Azin R. , Kharrat R. 
Published: December 2007

Abstract
In this work, the vapour extraction (VAPEX) process was studied in a multiple block, dual porosity fractured system. The performance of this process is compared with a conventional, non-fractured system under similar rock and fluid properties, bulk volume, pore volume, hydrocarbon volume, and injected pore volume of solvent and solvent injection rate. At early stages of the VAPEX process in fractured system, the solvent-oil interfaces form and develop from all sides of the matrix, and the oil chamber, rather than solvent chamber forms and shrinks in the center of each block. Also, at later stages of the process, the solvent zones from all neighboring blocks combine and form an integrated solvent zone, which is similar to that in the conventional systems.
The results showed that in low-permeability carbonate reservoirs, the fracture network provides communications for solvent flow through which the solvent can flow faster and form solvent fingers at early stages, which can reach the blocks located at farther distances from injection well. It was found that the solvent breakthrough starts at he same time in both low-permeability non-fractured system and fractured system. This is because the solvent flows directly through drained areas towards producer in both systems.
Further, effect of solvent injection rate on heavy oil recovery in the fractured system was studied in two cases: different injection rate at the same injection time, and different injection rate with the same injected pore volume. It was found that the solvent injection rate should be optimized for a specific system in order to control the solvent breakthrough and to avoid extra operation time and cost.
Application of Resin System for Sand Consolidation, Mud-Loss Control, and Channel Repairing
Authors: Wasnik A. , Mete S. , Ghosh B. 
Published: December 2007

Abstract
This paper describes a method of sand consolidation and channel repairing by using a Resin system, the system comprises of a resin (a mixture of elastomers UF, MF and a suitable plasticizer) and a hardener (a mixture of two mild Lewis Acids). The hardener controls curing time. The role of plasticizer is to impart flexibility and impact resistance to otherwise brittle natured UF-MF resin. Surface bonding between Sand and resin has been enhanced with a special additive, if required.
This paper also describes a methodology of placing a chemical casing during or after drilling a caving prone shale zone, strong enough to prevent sloughing of shale and withstands mechanical shocks during drilling, which would facilitate drilling with reduced mud weight and without reduction of hole size.
Experimental results on resin development and mechanical parameters of sand consolidation and Chemical casing of different mineralogy have been presented. The compressive strength of the consolidated sand and shale is found to be extremely high to withstand the overburden pressure and mechanical impacts during drilling. The designed application methodology is described in detail.
This system would be extremely economic as it can be applied directly after perforation if required, saving rig time and reducing completion cost compared to Gravel pack, liner placement and Screens, with the added advantage of no hole size reduction and better sand consolidation as compared to other methods. The developed chemical system is 1/3 the cost of epoxy resins, reported earlier for similar application and the components are environment friendly and easy to handle because of their water solubility.
In-Situ Bitumen Overview and Activity Update in the Province of Alberta
Authors: Sadler K. , Davis P. 
Published: December 2007

Abstract
The Alberta Energy and Utilities Board regulates all energy-related operations, including bitumen and heavy oil recovery activities, in the province of Alberta. With the high petroleum commodity prices in recent years, activity and investment levels in this sector have increased dramatically and are forecast to increase even more in the foreseeable future. New and innovative technology is moving rapidly from the laboratories to field implementation to increase recovery rates, improve operational efficiencies and reduce costs.
This paper presents a brief overview of the current regulatory process for the in situ thermal bitumen recovery sector. There is a discussion on the major regulatory issues associated with the in situ bitumen recovery projects. A summary of the bitumen reserve statistics and production forecasts, broken down to the recovery technologies, is also provided.
Advances in Oil and Water Saturation Measurements Using Low Field NMR
Authors: Bryan J. , Mai A. , Hum F. , Kantzas A. 
Published: December 2007

Abstract
Low field nuclear magnetic resonance (NMR) relaxometry has been successfully used in the past to perform in-situ estimates of oil and water content in unconsolidated oil sand samples. This work has intriguiging applications in the oil sands mining and processing industry, in the areas of ore and froth characterization. Studies have previously been performed on a database of ore and froth samples from the Athabasca region in northern Alberta, and preliminary results have been encouraging. In this paper, supporting data is presented and refinements suggested to the previous algorithms, to improve the oil and water saturation predictions.
A suite of real and synthetic samples of bitumen, water, clay and sand have been used to investigate the physical interactions of the different components on the NMR spectra. An automated algorithm is used to separate the oil and water NMR signals, and this algorithm is tested against samples both from this zone and from other heavy oil fields. Moreover, preliminary observations regarding spectral properties indicate that it may be possible in the future to estimate the amount of clay in the samples, based upon shifts in the NMR spectra. NMR estimates of oil and water content are fairly accurate, thus enhancing the possibility of using NMR for both in-situ oil sands development and in the oil sands mining industry.
Heavy-Oil Fluid Testing With Conventional and Novel Techniques
Authors: Goodarzi N. , Bryan J. , Mai A. , Kantzas A. 
Published: December 2007

Abstract
In this paper, we propose the combined utilization of x-ray tomography and magnetic resonance techniques for quantification of heavy oil fluid properties. The design of these systems is presented along with preliminary results combined with conventional measurements. The objective is to understand the PVT behavior of a viscous heavy oil from a reservoir that has undergone primary production. Methane is dissolved into the oil at ambient temperature and elevated pressure. The pressure is later slowly depleted and the oil PVT properties are recorded. Specifically, this paper details measurements of oil density, formation value factor, and solution gas-oil-ratio as a function of pressure. The incremental benefit of the proposed nucleonic techniques is that they provide more detailed information about that oil, compared to conventional PVT measurements. This improves our understanding of the foamy oil response.
Mapping Reservoir Volume Changes During Cyclic Steam Stimulation Using Tiltmeter-Based Surface-Deformation Measurements
Authors: Du J. , Brissenden S. J. , McGillivray P. , Bourne S. , Hofstra P. , Davis E. J. , Roadarmel W. H. , Wolhart S. L. , Marsic S. , Gusek R. , Wright C. A. 
Published: December 2007

Abstract
Surface deformation measurements have been used for years in oilfields to monitor production, waterflooding, waste injection, steam flooding, and Cyclic Steam Stimulation (CSS). They have been proven to be a very effective way to monitor the field operations and save money for operators wishing to avoid unwanted surface breeches, casing failures and excessive subsidence due to production. This paper demonstrates that more information can be extracted from surface deformation measurements by inverting the surface deformation for the volumetric deformation at the reservoir level, so the aerial distribution of volumetric deformation can be identified. First, a poroelastic model is presented to calculate the deformation due to the volumetric change in the reservoir. Then, a linear geophysical model is formulated to invert for the reservoir volumetric deformation from the measured surface deformation (or tilt). Constraints are added into the procedure as necessary to better resolve the inversion problem. After each inversion, the theoretical surface deformation (displacement, tilt, reservoir compaction and volumetric strain) can be calculated from the inverted volumetric deformation distribution which best fits the measured deformation data (or tilt) at the surface. The technique of mapping fluid flow using surface deformation was applied to real data from a cyclic steam injection project.
Experimental Observations of Miscible Displacement of Heavy Oils With Hydrocarbon Solvents
Authors: Salama D. , Kantzas A. 
Published: December 2007

Abstract
The increased interest in secondary production (or post-cold production) of heavy oil and the current rise of oil prices has renewed interest in solvent-based methods for heavy oil recovery. Although the Vapor Extraction (VAPEX) process is the most heavily favored process for potential field application, other methods are also worth investigating. Moreover, the relative merit of mass transfer and viscous mechanisms in the overall recovery efficiency remains a topic of debate in the literature.
This paper is a small part of a greater effort to study mass transfer phenomena in heavy oil/bitumen solvent systems. A series of core flooding experiments were performed whereby liquid solvents (octane, pentane) displaced heavy oil (12Pa.s). Different configurations and displacement rates were employed and heavy oil recovery factors were determined. Solvent concentrations in the effluent oil-solvent mixtures were accurately evaluated using the non-intrusive Nuclear Magnetic Resonance (NMR) technique and conventional density measurements.
Mass transfer analysis was performed in an effort to determine dispersion coefficients.
Effect of Formation Damage to Production Performance in Heavy-Oil Reservoir via Steam Injection After Waterflooding
Authors: Xiao G. , Zhimin D. , Yu F. , Lang L. , Xingguo Z. , Jin H. 
Published: December 2007

Abstract
Heavy oil reservoirs of steam-injection development after water-flooding have normally experienced many different production processes, such as cold production, water-flooding, steam buff and puff, and steam flooding. Some complex phenomena and effects may occur in the non-isothermal recovery processes, for example, distillation, decline in in-situ oil viscosity, water gravity segregation, steam overlap, the development of wormholes, forming foaming oil, thermal expansion effect of formation fluid and rock, and reversed wettability. Simultaneously, formation damage induced by clay swelling, external particles invasion, fines generation, migration, sanding and asphaltene precipitation may happen, which can lead to variations in formation permeability and porosity and significantly reduce oil production rate and even lead to its complete loss. Traditional model for simulating heavy oil reservoir production behavior has not allowed for the influence of formation damage on heavy oil reservoir and has neglected dynamic changes in formation porosity and permeability. Thereby, it becomes unreliable to design and adjust development plan and forecast production performance in heavy oil reservoir via steam-injection after water-flooding. In this paper, a 3-D, 3-phase, compositional thermal simulator NUMSIP (Numerical Model for Steam Injection Processes) has been reworked and further developed, considering formation damage induced by clay swelling, fines migration and asphaltene precipitation. Based on the laboratory experiments, formation damage was determined and our in-house new simulator has been successfully applied in Liudong Section heavy oil reservoir in Xinjiang Oil Field. The objective of this work was to investigate and illustrate how much formation damage impacts heavy oil reservoir production performance and the work also suggests dynamic changes in porosity and permeability should be considered globally to correctly predict production performance in heavy oil reservoir via steam-injection after water-flooding.
An Exact Downscaling Methodology in Presence of Heterogeneity: Application to the Athabasca Oil Sands
Authors: Ren W. , Mclennan J. A. , Cunha L. B. , Deutsch C. V. 
Published: December 2007

Abstract
Geostatistical realizations are often built at an arbitrary scale based on available data and computational resources. In certain settings, it may be necessary to downscale the realizations for flow simulation and local resource assessment. This is especially important in the Athabasca Oilsands where accurate flow simulation often requires numerical models with a very fine grid size. Flow simulation is undertaken for selected areas and realizations. It is intractable to construct the original geostatistical models at the fine scale. It is desirable to construct finer scale models that reproduce the original realizations exactly.
Approximate downscaling is always possible with geostatistical methods; however, it is of interest to create fine scale models that exactly reproduce the large scale models to ensure consistency and avoid potential biases. Direct block sequential simulation is developed to generate fine scale realizations that exactly reproduce block data.
A comprehensive case study is shown from the Athabasca Oilsands. Geostatistical realizations are constructed over 100s of square kilometers at a large scale. These realizations are locally downscaled to 20m by 2m by 2m for flow simulation around particular SAGD well pairs. The fine scale realizations are constructed such that they exactly match the initial coarse scale realizations. An approximate downscaling method is also used. The 3-D models and flow simulation results were compared to show the difference made by the exact downscaling method.
Water-Assisted Flow of Heavy Oil and Gas in a Vertical Pipe
Authors: Bannwart A. C. , Vieira F. F. , Carvalho C. H. M. , Oliveira A. P. 
Published: December 2007

Abstract
The three-phase water-assisted flow of heavy crude oil with free gas (air) in a vertical glass pipe, at near atmospheric pressure and temperature conditions, is investigated, for possible applications to the articial lift of heavy oil. Water is injected so as to avoid oil-wall contact and reduce friction. The oil phase was a w/o emulsion with a viscosity of 5,040 mPa.s and a density of 971 kg/m3. For each combination of oil-water-gas flow rates, the flow pattern was determined using a high speed camera and the pressure gradient was measured with a differential pressure transducer. The results are presented in the form of flow maps based on superficial velocities and total pressure gradient plots, allowing comparisons with well known correlations. The main conclusion indicates the great viability of the water-assisted flow technique. Significant amounts of heavy oil have been discovered in offshore Brazil.
Integrated Well-Completion Strategies With CHOPS To Enhance Heavy-Oil Production: A Case Study in Fula Oilfield
Authors: Wang X. , Zou H. , Li G. , Nie C. , Chen J. 
Published: December 2007

Abstract
Fula oil field is composed of unconsolidated sandstones, buried as deep as 3500ft, with high porosity (31%) and permeability(2 Darcy), producing viscous oil with 19-21°API on the south flank of Muglad Basin. It is well-known that under proper conditions formation flow characteristics can be improved by non-thermal massive sand production and foamy oil behavior, referred to CHOPS.
Integrated well completion strategies with CHOPS were used to increase heavy oil production. Limited sand influx provides a means for effective sand control while eliminating the need for conventional sand control processes. The principle of limited sand flux is ‘coarse sands controlled and finer sands produced’, which is using the screen liner to inhibit 0.5mm or larger sands flowing into the wellbore, in addition, the rest smaller solids can be produced to the surface by viscous oil.
Experiments were conducted to study the capability of lifting sands by crude oil. It showed that the sand of 0.9mm can be allowed to move up with heavy oil to the surface while 510 mPa.s of viscous oil is lifted in 3 1/2 in tubing. Using progressing cavity pump deliberately initiated sand influx but only 15% solids were controlled to form wormhole to improve permeability of the pay zone.
This paper describes initial field test results of the new system that 20 heavy oil wells were equipped with PCP which is helpful for handling sanding effectively. The sand cuts range from 0.1 to 12% by volume. Average oil rate of each well is up to 580bopd from 175bopd before CHOPS. The best well can produce as much as 1200 BOPD. Oil production has reached to 2,450,000 bbl/y with attractive result.
Optimized Abandonment Procedures Improved Success and Results in Central California Heavy-Oil Field
Authors: Glessner D. , Dean M. , Haire M. , Bour D. 
Published: December 2007

Abstract
This case-history paper presents the development background and detail of optimized procedures followed to plug and abandon wells in a cyclic-steam well in central California. Improvements that resulted in the success are detailed and explained.
Abandonment processes included identification, using tilt-meter events, of holes in casing and/or casing parting. Temperature surveys and/or radioactive surveys confirmed and located depth of the hole in the casing. Specific procedures were then followed to abandon the well below the part, at the part, and then above the part in the casing. Inspection and testing of the casing were also conducted to help ensure that additional holes were not present in the casing before the abandonment was complete. In the rare instances that additional holes were found, they were squeezed off separately with cement. Key to the success of this procedure was squeezing thixotropic cement instead of setting balanced plugs across zones of interest. This method allowed for short turn-around times to resume operations and helped ensure that the cement remained where it was originally placed.
PDA Program for Small Producing Companies
Authors: Cook J. R. 
Published: December 2007

Abstract
Current technologies create the possibility of gathering oil field data through the use of Personal Digital Assistance (PDA). PDA can provide a convenient means of transferring and storing data.
The problem that many small production companies experience is in the cost of creating or purchasing a system that utilizes PDAs.
This paper identifies the needs of production companies and describes a program, which can be used by production companies.
Geology and Geometry: A Review of Factors Affecting the Effectiveness of Hydraulic Fractures
Authors: Willis R. B. , Fontaine J. , Paugh L. , Griffin L. 
Published: December 2007

Abstract
Thousands of wells are hydraulically fractured in the Appalachian Basin each year with little clear understanding of what the resulting fracture actually looks like. A number of variables exist in the subsurface including natural fractures, permeability variations, in-situ stresses, faults, etc. that can influence the ultimate dimensions and orientation of the created fracture. It is necessary that the stimulation design team understand the impacts that these features can have on the path a hydraulic fracture takes in the subsurface. The created fracture and its conductivity ultimately dictate a well's productivity and drainage area.
This paper will outline the basics of how in-situ stresses affect the orientation of propagating hydraulic fractures and how some geological characteristics can impact the process. Some discussion will be presented on the current technologies being used to understand fracture geometry. These include microseismic imaging and tiltmeter surveys.
The Effect of Using a Lightweight Proppant in Treatment of a Low-Permeability, Dry Gas Reservoir: A Case Study
Authors: Posey D. , Strickland B. 
Published: December 2007

Abstract
The Mesaverde formation is a low permeability gas sandstone reservoir and a primary completion target in the San Juan Basin of northwest New Mexico and southwest Colorado. In over 50 years of Mesaverde development activity, varying completion and stimulation techniques have been tried in an effort to find the optimum method for enhancing long-term production. Initially, production and economic analysis indicated that high rate slickwater jobs using 20/40 mesh sand (specific gravity = 2.65) proved most effective. One attribute of the slick water approach is that the relatively heavy fracturing sand falls rapidly through the low-viscosity water and forms a bank of proppant over a very limited percentage of the total fracture area created with the hydraulic fluid (water.) As the field matured, reservoir pressure depleted and drilling cost escalated, the need arose for a different stimulation approach creating more extensive area open for fracture flow and reservoir drainage enhancement. To address this need, a lightweight proppant (specific gravity = 1.25) was substituted in lieu of fracturing sand with the idea of placing a partial mono-layer of proppant across a very large percentage of the total fracture area. This paper is a case study of six recent offset Mesaverde completions comparing the productivity of wells stimulated with all 20/40 mesh sand, all lightweight proppant and a hybrid approach utilizing a stage of lightweight proppant followed by a stage of 20/40 mesh sand. Post-fracture hourly flow rates and wellhead pressures were analyzed in all cases to access effectiveness. Wells treated with all lightweight proppant were found to have the most sustained well productivity and stimulation effectiveness.