bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effects of Asphaltene Content and Solvent Concentration on Heavy-Oil Viscosity
Authors: Luo P. , Gu Y. 
Published: December 2007

Abstract
During a solvent-based heavy oil recovery process, significant viscosity reduction is achieved through sufficient solvent dissolution and possible asphaltene precipitation. In the second viscosity reduction mechanism, the heavy oil is in-situ upgraded as the asphaltene content in the produced heavy oil is greatly lowered. In this paper, the respective and synergistic effects of asphaltene content and solvent concentration on heavy oil viscosity are studied by measuring viscosities of heavy oil samples with different asphaltene contents and/or solvent concentrations. More specifically, a deasphalted heavy oil sample is obtained by using the standard ASTM method to extract asphaltenes from a crude heavy oil. Then reconstituted heavy oil sample is prepared by adding the extracted asphaltenes into the deasphalted heavy oil at a different asphaltene content each time and its corresponding viscosity is measured at the atmospheric pressure. It is found that the viscosity of such prepared heavy oil is sensitive to the asphaltene content. In particular, the viscosity of the deasphalted heavy oil is reduced by 13.7 times in comparison with that of the original heavy oil at T=23.9°C. This indicates that high asphaltene content results in high viscosity of the heavy oil. On the other hand, the viscosities of propane-saturated heavy oil samples with different asphaltene contents are measured at high pressures. As the equilibrium propane concentration reaches certain value, the viscosity of the crude heavy oil-propane system is reduced by almost two orders. This result shows that solvent dissolution plays a dominant role in heavy oil viscosity reduction. When the equilibrium propane concentration is high enough, all the three reconstituted heavy oil-propane systems have extremely low viscosities. In this case, effect of asphaltene content on heavy oil viscosity becomes negligible.
A New Semiautomatic PVT Apparatus for Characterizing Vapex Systems
Authors: Freitag N. P. , Sayegh S. G. , Exelby R. 
Published: December 2007

Abstract
Knowledge of fluid properties is critical to the design of Vapex projects and other enhanced oil recovery processes that use solvent vapor extraction, yet very few pertinent data exist in the published literature. This paper describes a new apparatus for the efficient and accurate measurement of the physical and phase behaviour properties of mixtures of heavy oils and solvents such as propane and butane. The apparatus combines advanced capabilities that make it superior to conventional designs: The automated functions improve the speed at which the data are acquired and reduce operator error. Inline density and viscosity measurements add the capability of multi-phase detection. High-pressure filtration permits measurement of asphaltene and wax precipitation at reservoir conditions. Dual gasometers allow accurate measurements of gas solubility over a wide range of solvents and reservoir pressures. Sub-ambient temperature control makes it suitable for Canadian operations.
The apparatus was tested against published measurements for the n-hexadecane-carbon dioxide system, and then used to gather a comprehensive suite of data at two isotherms for a Lloydminster heavy oil-propane system. Random scatter in the resulting data was very small. The equipment is well suited to the acquisition of fluid property measurements for both field design and correlation purposes.
With the improvements in both the precision of measurements and the speed of operation offered by the new equipment, it was possible to test some assumptions used in measuring vapor-liquid equilibrium in heavy oil-solvent systems. The results suggested that a noticeable uncertainty may be associated with conventional methods used to determine saturation pressures in these systems.
Advanced Electrostatic Technologies for Dehydration of Heavy Oils
Authors: Thomason W. H. , Blumer D. J. , Singh P. , Cope D. P. , Zaouk M. 
Published: December 2007

Abstract
Effective oil/water separation continues to be a major challenge in heavy oil (HO) production operations and often involves high capital costs (large, heated vessels) and high operation costs (heat, fouling, upsets, chemicals). Application of new electrostatic dehydration technologies has the potential to have a major impact in reducing these costs. A systematic evaluation of four electrostatic dehydration technologies was performed using lab, bench scale, and pilot scale (40 gallons) testing. Four heavy oils ranging from 8 to 21 API were used. Performance criteria measured were effective emulsion separation rate (vessel throughput), separated oil and brine quality, water droplet size distribution for inlet and outlet emulsions, and comparison with field data (as available) for older electrostatic technologies. Traditional bottle tests were performed for reference. A 2 to 4 fold increase in emulsion treating rate was observed for some of the heavy oils using the newer electrostatic technologies relative to the traditional Alternating Current (AC) method with the same output quality of crude and brine. Relative cost data per barrel of emulsion processed were developed from system cost estimates and throughput data developed in the pilot tests. Treatment with acid to bring the separated brine into a 6 to 6.5 pH range had a very beneficial effect on the oil/water separation for some of the heavy oils with high TAN.
Plugging Channels Technique Without Abandoned Adjacent Layers
Authors: Pei X. , Li Q. , Liu Y. , Zhang S. , Ren S. , Li Q. , Cheng M. 
Published: December 2007

Abstract
This paper analyses the reasons that lead to channeling of the oil and water wells in the Daqing Oilfield. Considering the developed layers' adjustments in the future, a new kind of chemical plugging technique is introduced to shut off the channels without abandoned adjacent layers. To realize the aim of both protecting the adjacent layers and plugging channels, the following steps are usually adopted. First, the channeling intervals should be perforated by a special perforating gun. Second, circulating the channels by a high velocity flush to make sure the agent can be squeezed into it easily. Finally, run the plugging string that carries the agent to the desired depth, increase the pressure to squeeze the agent into the channel, and then waiting for the solidification. Up to now, 12 wells have been treated by this technique. The channeling intervals' thickness is between 1.97 and 38.7 feet. The plugged channels can resist 2175.5psi pressure and the treatments' success ratio was 100%. Applications and excellent results proved that the technique can mitigate contradictions between different layers in the water-flood and polymer-flood area, and it can realize the goal of separate zone injection or separate zone oil production in the Daqing Oilfield.
Application and Study of Fine-Silty Sand Control Technique Using Fiber-Complex High-Pressure Pack in Sebei Gas Reservoir
Authors: Zhou F. , Zong Y. , Liu Y. , Yang X. , Xiong C. , Zhang S. , Sun L. , Wang J. , Li J. , Guang Z. 
Published: December 2007

Abstract
Sebei Gas Field in Qinghai is the fourth largest gas field in China. The reservoirs here are of unconsolidated Quaternary siltstones and pelitic siltstones, alternating gas and water layers and with serious sand production. The grain size of the sands is very fine, so it is very difficult to realize sand control, a cosmopolitan puzzle. We have succeeded in applying a series of techniques of comprehensive sand control with fiber-complex high-pressure packing but without any screen pipe. The technology includes the reservoir pretreatment, the fiber- complex technique and the high pressure packing. As for the reservoir pretreatment, the soft fibers, of which the branched chains are with positive electrical charges, are used to adsorb the fine silty sand particles to form big aggregations for sand stabilization. As for the fiber-complex technique, the 3-dimensional reticular fiber and resin-coated sand complex are adopted for sand retention. As for the high pressure packing, the formation is not fractured while the fiber composites are packed to form screen pipe-like barrier around the cement sheath to perform sand control without any screen pipe used, eliminate any damage to the near wellbore zone and increase the gas bleeding area. This technique can achieve the dual purpose of sand control and production stimulation. This technique system had been applied in Well Se 7-1-4 in Sebei Gas Field with remarkable results achieved. After such sand control treatment, the output without sand production increased on average to 2.1 times of the output before. This paper presents mainly the relevant theory, experimental study, operation design and field application of the fine silty sand control technique using the fiber-complex high-pressure packing without any screen pipe.
Steam and Solvent Coinjection Test: Fluid Property Characterization
Authors: King R. W. , Zhao L. , Huang H. , McFarlane R. A. , Gao J. 
Published: December 2007

Abstract
As part of a study of steam and solvent co-injection processes for MacKay River reservoir, a number of fluid properties of MacKay River bitumen-solvent mixtures were measured for three candidate diluents (referred to as Solvents 1, 2 and 3) at conditions relevant to the co-injection process under consideration. They include viscosities of bitumen-solvent mixtures for Solvent 1 and 2, densities of bitumen-Solvent 2 mixtures of different solvent content and liquid-vapor phase behaviour of the bitumen-Solvent 2-water mixture at a given mixing ratio.
The results showed that the effectiveness of solvent-dilution on oil viscosity became less prominent as temperature increased. The differences among the diluents in lowering the viscosity of MacKay River bitumen were insignificant. At elevated temperatures and above the solvent saturation pressures, increasing solvent loading in the bitumen-Solvent 2 mixture from 10.7 vol% to 19.5 vol% reduced the density of the mixture by only 3 - 5%. At 1750 kPag, the bitumen-Solvent 2-water fluid mixture containing 5.8wt% of solvent and 58wt% of water remained as two liquid phases at temperature up to 165 °C. The mixture formed a three-phase system (one vapor phase and two liquid phases) at 195 °C, with only 6.8wt% of the solvent dissolved into the oil. Small quantities of C10+ components from the bitumen were also detected in vapor phase.
Mixture viscosities were calculated and fitted to a linear-logarithmic mixing rule. A good match with the measured viscosity was achieved at all temperatures below the bubble point of the mixture. K-values of the solvent pseudocomponents were determined using HYSYS and fitted to the correlation to estimate K-value as a function of temperature and pressure.
Case Study of Ultralightweight Slurry Design Providing the Required Properties for Zonal Isolation in Devonian and Mississippian Central Appalachian Reservoirs
Authors: Kulakofsky D. , Snyder S. , Smith R. , Mork K. , Coors D. 
Published: December 2007

Abstract
As the global demand for energy increases, operators are being forced to drill in increasingly challenging environments. In the northeastern United States, that often means exploring unconventional reservoirs such as the Devonian Shale or lower-pressured sandstone reservoirs such as the Big Injun or Berea sands (and drilling through the associated Sunbury Shale). Economic limitations in these areas often require operators to attempt single-stage production cement jobs with associated fills of 3,000 ft or more. Achieving zonal isolation above these low-pressure zones requires low-density cements that are pushing the limits of current cementing technology. If the cement is made light enough to circulate, but cannot withstand the stress of fracturing or other downhole conditions, the initial seal will only be temporary. If cement cannot be successfully circulated or fails to function shortly after placement, this can have a great impact on drilling costs usually designed with very tight economic constraints and can cause delays in production delivery because of required remedial work. Most of these wells require stimulation treatments to become economical producers. If zonal isolation is not initially achieved, remedial work may not be enough to effectively isolate the downhole formations, resulting in a complete loss of the well or zones within the well. Historically, lightweight slurries have been applied in these reservoirs in an attempt to successfully achieve zonal isolation in both single- and multiple-stage cement jobs; however, previous cement solutions were found to be lacking in one way or another. Problems ranged from price to poor bonding results, poor zonal isolation, or more typically designed cement fills not being attained.
As cementing solutions become more advanced in technology, the associated costs often increase. When choosing a cementing solution, the operator should balance price with the potential well productivity and the cost of using a cheaper solution. In this case study, we examine various examples where an effectively priced, high-quality, low-density cement was used to overcome numerous cement challenges, delivering zonal isolation that can allow effective post-cementing stimulation treatments that result in a positive return on investment (ROI).
Feasibility Study of Autoignition Process in Heavy-Oil Reservoirs
Authors: Razaghi S. , Kharrat R. , Price D. , Vossoughi S. , Rashtchian D. 
Published: December 2007

Abstract
Heavy oil is an important part of the energy resource in the world. With today's increasing demand for energy resources, heavy oil recovery is under great attention. Heavy oil deposits in Middle East are in fractured carbonate-type reservoirs that have not been studied in the literature.
One of the important factors in the feasibility of in situ combustion (ISC) on a heavy oil reservoir to sustain fireflood is the auto-ignition temperature under reservoir conditions.
In this study, the kinetic model of different heavy oil samples from South West Iran mixed with silica sand or crushed carbonate rock and clay were studied using Thermogravimetric Analyzer (TGA) and Differential Scanning Calorimeter (DSC) techniques. The reactions were carried using air enriched with different percentages of oxygen.
Two sets of experiments for the combustion of crude oil samples were carried out by TGA equipment for the determination of auto-ignition temperature. In the first, the system was operated non-isothermally with a linear temperature rise 10°C/min; while in the second the reaction was conducted isothermally at different temperatures. In both kinds of experiments the CO, CO2, hexane and propane in the exhaust gases from the TGA, were measured by an Infrared Analyzer (IR).
Based on the TGA runs performed, it is concluded that auto ignition was related to the percentage of enriched air for both the silica sand and carbonate rock in the presence of clay. In addition, as expected in DSC run under non-isothermal Low Temperature Combustion (LTC) and High Temperature Combustion (HTC) reactions clearly reveal exothermic peaks.
A Successful Case Study on Development of a Giant, Highly Fractured Carbonate Heavy-Oil Reservoir in Iran
Authors: Tabibi M. , Mirkalaei S. M. Mousavi 
Published: December 2007

Abstract
The increasing demand for energy in the world and the current status of the oil price are two important issues that drive the industry to re-look the unconventional sources witch can be form of heavy/ extra-heavy black oil and/or exist in deep, over pressured fractures carbonate source rocks. Exploration and production from these kinds of reservoirs, in the past, have not been economically feasible. In this communication, a successful case study on a heavy/extra-heavy oil field is presented and the techniques and challenges behind the exploration and production from highly fractured carbonate Bangestan reservoirs are discussed. The field is a giant structure located in the South West Iran and in the coast of Persian Gulf. It's a symmetrical anticline with 90 Km length and 16 Km width in the surface with about 3.6 billions barrels of initial oil in place and 10-16° API heavy oil. The pressure is 1408 psi at 1119 mdd (measured drill depth) and heavy oil didn't naturally flow to the surface. Exploration of the field carried out for evaluation of gas reservoirs in 1959 and a total of 5 wells have been drilled on this structure, wells number 6 and 7 were drilled in 1984 & 1985 for heavy oil evaluation in shallower formation. A 3D seismic and Side View Seismic Location (SVSL) carried out on this field. The swabbing operation then was performed for one well to identify property of rock and fluid in order to design pilot surface facility. The challenges and techniques employed on this field development including geological study, drilling operation, reservoir characterization and various techniques of production summarized in this paper and optimized production method to lifting this heavy oil to surface is described.
Heavy-Oil Uncertainties Facing Operators in the North Sea
Authors: Morton K. L. , Osman M. S. , Kew S. A. 
Published: December 2007

Abstract
Rising oil price and demand has led to increased effort to develop reservoirs in the North Sea that were previously considered uneconomical by major operators. The recent DTI ‘Promote’ licensing initiative has encouraged smaller oil companies to apply for exploration/appraisal acreage on a limited financial commitment basis for two years before initiating a more traditional work program.
Companies using this option to develop heavy oil reservoirs in the North Sea, many of which were discovered in the 70's, face a number of uncertainties traditionally associated with heavy oil. These include the determination of density and live oil viscosity at reservoir temperature where no clear correlation exists and the determination of reservoir properties from a limited range of historical data. In the offshore environment heavy oil developments are further complicated by the high front-end costs, limited reservoir size and uncertainty in geology and productivity. Only four of the heavy oil fields discoveries on the UK Continental Shelf (UKCS) have reached development and we review these fields to illustrate the challenges.
Many of the reservoir and fluid uncertainties can be addressed with modern logging and analysis methods and recommendations for data gathering campaigns in these environments are provided. The technological challenges of an offshore heavy oil development can be met with advances in sand control, ESP technology and EOR techniques. Combined together these solutions provide more accurate production forecasts, which help the economics of developing the resource to be better understood.
The proposed appraisal and development of a heavy oil field situated in Block 9/3b is used as a case study to highlight the challenges faced by operators in the development of heavy oil fields in the North Sea. Re-evaluation of historical data was used to develop a range of production forecasts that fully capture the potential and risk of the development.
Uncertainty Assessment Using Experimental Design and Risk Analysis Techniques, Applied to Offshore Heavy-Oil Recovery
Authors: Prada J. W. V. , Cunha J. C. , Cunha L. B. 
Published: December 2007

Abstract
The increasing complexity in the development of heavy oil fields is directly associated with the uncertainties in the fluid and reservoir characterization, particularly, in offshore scenarios where difficulties for well testing and fluid and core sampling are present. A probabilistic analysis, instead of a deterministic one is the natural way to face these expected uncertainties. The approach proposed in this work uses experimental design techniques to determine the parameters that have large contribution into the Net Present Value (NPV) of the prospect being analyzed. In the example presented NPV is estimated based on the accumulated oil production response of a flow simulator over a period of 30 years. An uncertainty analysis was done using information about the probabilities of the uncertain parameters. The decision tree technique was used to map all possible outcomes and then to estimate the Expected Monetary Value. A program was written to manage the input/output files of a commercial black-oil reservoir simulator in order to run a total of 1,728 simulations and estimate the NPV for each one of those parameter combinations. In a second analysis, the uncertainty density distribution was derived based on the histogram of the NPV results, assuming that the values of the uncertain parameters cover the entire range of variability.
This procedure was applied to a synthetic case in which the uncertain parameters selected were: porosity, absolute and relative permeability, area of accumulation and exploitation scheme (horizontal or vertical wells).
Wellbore Hydraulics in a SAGD Well Pair
Authors: Das S. 
Published: December 2007

Abstract
In SAGD process a pair of horizontal wells is drilled at the base of a heavy oil and bitumen reservoir, vertically one above the other. Steam is injected into the upper well and the heated and mobilized bitumen drains to the bottom producer and is withdrawn either by natural lift or artificial lift. Uniform distribution of steam along the entire length of the well bore is very important for the uniform growth of the steam chamber. This is very important to make the entire length of the well productive.
Pressure drop along the length of the injector and producer may cause steam break through in one segment and build up of liquid level between the wells. Generally steam is injected at the heel and the toe of the well and is distributed along the entire length primarily through slotted liner. It is expected that this will provide a higher quality steam at the toe end of the well. However, with out proper design the counter current heat transfer between the two streams may result in delivering a poor quality to the toe. In the producer it is necessary to withdraw fluid from the toe and heel. In a concentric design this may cause serious lifting problem if the tubulars are not designed properly and the split between the streams is not right. This paper presents the issues related to SAGD well bore design.
Ranking Oil Viscosity in Heavy-Oil Reservoirs
Authors: Seccombe J. , Bonnie R. J. M. , Smith M. , Akkurt R. 
Published: December 2007

Abstract
The Milne Point field in Alaska produces from the Kuparuk, Schrader, and Ugnu formations. The Kuparuk formation contains light oil, while the Schrader and Ugnu contain heavy oil. The ranges of viscosities are 200 to 10,000 cp in the Ugnu, 20 – 200 cp in the Schrader, and about 3 cp in the Kuparuk.
Over 200 wells have been completed in the Kuparuk and Schrader formations at Milne Point. The Ugnu contains the largest oil in place in the field; however, it has not been developed yet due to the high oil viscosities. To date, only one well has been completed in the Ugnu.
BP is engaged in new studies to find a way to make the Ugnu commercial. This paper discusses an attempt to identify lower-viscosity "sweet spots" within the Ugnu using nuclear magnetic resonance (NMR) measurements.
In 2004, full suites of logging while drilling (LWD) and wireline data were acquired in two newly drilled wells. The primary goal was to compare viscosity predictions from NMR log measurements to geochemical measurements made on fluids extracted from core plugs. For the first time, on a foot-by-foot basis, using LWD NMR, lower viscosity sweet-spots were identified in the viscous Schrader formation and in the very heavy oil in the Ugnu formations.