bluuebunny/crossref_metadata_2025_split huggingface dataset:
Investigation and Characterization of Fine Solids Isolated From a Froth Treatment Plant
Authors: Yang X. , Wang S. , Tran T. 
Published: December 2007

Abstract
Froth produced by hot-water extraction process usually contains about 60 wt% bitumen, 30 wt% water and 10 wt% solids. Water and solids are further removed in froth treatment process to obtain the acceptable bitumen product with minimal amount of hydrocarbon loss to tailing stream. Fine solids are known to play an important role in this three-phase separation, but little work has been done to characterize the fine solids and to investigate how their composition affects solids-bitumen interaction. In this work, several fine solids were isolated from the different streams in a froth treatment plant. The composition and properties of fine solids were characterized by Dean Stark Soxhlet extraction, PAS-FTIR, elemental analysis, and particle size distribution. It was found that composition and properties of the solids isolated from different sources are dramatically different. The solids that are more difficult to separate from hydrocarbon phase contained a significantly higher value of Fe element. Fe minerals in these solids were determined to be siderite. Besides siderite, kaolinite is another major component in the separated solids. The composition and particle size determine the interactions between solids and bitumen. The interaction between fine solids and bitumen adversely influences the bitumen/water/solids separation, affecting the quality of bitumen and resulting in hydrocarbon loss to tailings.
Analysis of a Macroscopic Nucleation Model for Simulation of the Solution-Gas Drive in Heavy Oils
Authors: Zaleski S. , Franco F. , Chraibi M. , Tardy P. 
Published: December 2007

Abstract
We present two versions of a Darcy-scale model for simulation of the solution gas drive in heavy oils.
Presence and behaviour of a foamy-oil effect appears to be critical to the cold production process. This process is not a well-understood production mechanism because a wide range of different petrophysical parameters and experimental factors interact in a rather complex way. Over the past few years, a number of efforts have been made, in many institutions, in order to understand and model the solution gas-drive mechanism in primary heavy oil recovery. Conventional simulations succeed in matching actual field productions but are not reliable for prediction forecast purposes (large uncertainties on recovery factors). We present an evolving nucleation and flow model for solution gas drive in heavy oil.
The model is built at the Darcy scale and involves the effect of capillarity on bubble flow and phase change. An ad hoc simulation tool is built to analyze carefully the properties of the model. The tool allows to reproduce laboratory experiment across a sample rock. In the limit of infinitely slow depletion, an asymptotic theory is constructed that allows to predict analytically the pressure difference across a sample. The theory predicts a pressure gradient at first order without additional calculation, and the gradient appears, at first order, independent on the gas formation (degassing) kinetics. No saturation gradient is predicted at first order. The results are compared to numerical simulations and experiment, and good agreement is found in cases where the pressure gradient is known.
In a second version of our model we introduce the effect of capillarity on bubble growth. Capillarity delays bubble growth by stabilizing small bubbles under a certain critical radius. This new term leads to nucleation fronts propagating rapidly through the sample.
It appears more difficult to predict a saturation gradient. The causes of this difficulty are analyzed.
Study on Developing Low Permeability Reservoir With Waxy Oil By Cyclic Steam Stimulation
Authors: Yitang Z. , Bingyu J. , Xiuluan L. , Guangzhi L. , Dehuang S. , Yunting X. , Lianjie S. 
Published: December 2007

Abstract
An innovative way to improve the effect of developing low permeability reservoir with waxy oil by CSS is presented in this paper. The mechanism and feasibility of developing a specific waxy and low permeable reservoir by steam injection, Chaoyanggou reservoir in Daqing oil field, has been investigated. The results show that injecting high temperature steam into reservoir can not only reduce the viscosity of waxy oil, but also lead to the thermal expansion of the underground fluid and the distillation of the crude oil. The combining effect can improve sweep efficiency and enhance oil recovery efficiency. The effect of steam soak in two wells in Chaoyanggou oil field was first investigated by numerical simulation. Results demonstrated that using huff and puff method to develop waxy and low permeable reservoir is promising. After laboratory experiments and feasibility studies, a two-well field tests have been conducted in Chaoyanggou region using CSS technology. Encouraging results have been obtained from the field tests.
Understanding Reservoir Architectures and Steam Chamber Growth at Christina Lake, Alberta, by Using 4D Seismic and Crosswell Seismic Imaging
Authors: Zhang W. , Youn S. , Doan Q. 
Published: December 2007

ABSTRACT
The Christina Lake Thermal Project, located 170 km South of Fort McMurray, Alberta, uses steam-assisted gravity drainage (SAGD) technology to recover bitumen from the McMurray formation. The bitumen reservoir at Christina Lake is approximately 400m deep, and is delineated by over 300 vertical wells and extensive 3D seismic coverage. The McMurray formation can be informally subdivided into three units - Lower, Middle and Upper. The Middle unit contains the major bitumen bearing reservoir, while the Lower unit is generally water bearing and the Upper unit typically contains gas with some residual bitumen saturation. SAGD at Christina Lake was first implemented in 2001 (Phase 1, Figure 1). The currently developed project area is covered by time-lapse surface 3D seismic and crosswell seismic.
The 3D survey was acquired using mega-bin geometry, with a bin size of 12.5 m by 12.5 m. A baseline survey was conducted in 2001 followed by two repeat surveys in 2004 and 2005. In addition, six crosswell seismic profiles were acquired by placing both sources and receivers in vertical wellbores. The goal of the survey is to better understand reservoir architecture by detecting lithology changes, including predicting the occurrence of mudstone stringers and their lateral and vertical distribution. Crosswell seismic data in this project have provided about one metre vertical resolution in the McMurray Formation, detected mudstone stringers, and indicated significant reservoir heterogeneity, all of which helped to more accurately characterize the reservoir and better predict reservoir performance under thermal operations. Results of the six profiles provide encouraging insight into the potential of crosswell seismic technology. Although there is a need for future research in several areas, crosswell seismic has the potential to complement and enhance the interpretation of surface 3D seismic.
Analysis of both 4D and crosswell data showed that steam chamber growth and oil recovery are strongly influenced by reservoir geology. Steam chamber growth is especially affected by the presence of low permeability facies in the vicinity of the SAGD well pairs. In each case to date, less than 100% of the well length contributes to oil production. These findings have significant impacts on the planning of future developments.
Status of Heavy-Oil Development in China
Authors: Shouliang Z. , Yitang Z. , Shuhong W. , Shangqi L. , Xiuluan L. , Songlin L. 
Published: December 2007

Abstract
China has significant heavy oil deposit of more than 1.9 billion tons of oil reserve in place (OOIP) with four major heavy oil producing areas, which are Liaohe Oil Field, Xinjiang Oil Field, Shengli Oil Field and Henan Oil Field. China has many types of heavy oil reservoirs such as single-layer, multi-layer, thick-blocked reservoir with wide range of oil viscosity from 100 cp to 100,000 cp and depth from 200m to more than 2000m.
Heavy oil has been produced for many years in China. However, the commercial heavy oil development was initial in 1982, when the first cyclic steam injection pilot test was successful in Liaohe Oil Field. In 1993, the heavy oil production had reached 10 × 106 tons per year. From then on, the annual heavy oil production has kept the level of 10~13 × 106 tons for more than 10 years.
The development manners of heavy oil reservoir are cyclic steam stimulation (CSS), steamflooding, waterflooding. CSS is the major manner, widely used in traditional-heavy, extra-heavy and super-heavy oil reservoir in China with the annual production more than 85% of total heavy oil production. CSS has become a mature industry technology, which includes high-efficient steam injection, artificial lifting, sand controlling, re-entry drilling, steam surveillance and so on. Steamflooding is successful in developing shallow heavy oil reservoir such as Karamy oil reservoir, including high-temperature profile conformance, surveying and steam measurement technologies.
This paper reviews the distribution of heavy oil resources, status of heavy oil development, trends and also the challenges faced in improving utilization of the resources in China.
Monitoring of Diffusion of Heavy Oils With Hydrocarbon Solvents in the Presence of Sand
Authors: Salama D. , Kantzas A. 
Published: December 2007

Abstract
Mass transfer of solvents in bulk heavy oil and bitumen was monitored successfully using X-ray Computer Assisted Tomography (CAT). Concentration gradients were obtained from analysis of bulk density maps as a function of location and time. Analysis of the data using Fick's Law provided apparent diffusion coefficients, which were consistent with previously published data using different solvents and different oils.
A second series of experiments was then performed whereby the heavy oil was mixed with sand at a level that is similar to what expected in heavy oil reservoirs. There was no connate water in the system. Different solvents were then placed on top of the oil/sand mixtures and the diffusion of the solvent into the sand pack was observed. X-ray CAT was used to monitor density and concentration profiles. Oil concentration profiles in solvent were clearly observed but the solvent concentration in the sand pack proved to be more challenging. The same Fickian approach that was used in bulk oil systems was applied to predict apparent diffusion coefficients for the liquid volume portion of the experiment. Preliminary results showed that the apparent diffusion coefficients are of the same order of magnitude as in the bulk oil systems.
Improved Steamflood Analytical Model
Authors: Chandra S. , Mamora D. D. 
Published: December 2007

Abstract
The Jones (1981) steamflood model incorporates oil displacement by steam as described by Myhill and Stegemeier, and a three-component capture factor based on empirical correlations. The main drawback of the model however is the unsatisfactory prediction of the oil production peak: usually significantly lower than the actual. Our study focuses on improving this aspect of the Jones model.
In our study, we simulated the production performance of a 5-spot steamflood pattern unit and compared the results against those based on the Jones model. Three reservoir types were simulated using 3-D Cartesian black oil models: Hamaca (9°API), San Ardo (12°API) and that based on the SPE fourth comparative solution project (14°API). In the first two field cases, a 45x23x8 model was used that represented 1/8 of a 10-acre 5-spot pattern unit, using typical rock and reservoir fluid properties. In the SPE project case, three models were used: 23×12×12 (2.5 ac), 31×16×12 (5 ac) and 45×23×8 (10 ac), representing 1/8 of a 5-spot pattern unit.
To obtain a satisfactory match between simulation and Jones analytical model results of the start and height of the production peak, the following refinements to the Jones model were necessary. First, the dimensionless steam zone size AcD was modified to account for decrease in oil viscosity during steamflood and its dependence on the steam injection rate. Second, the dimensionless volume of displaced oil produced VoD was modified from its square-root format to an exponential form.
The modified model gave very satisfactory results for production performance up to 20 years of simulated steamflood, compared to the original Jones model. Engineers will find the modified model an improved and useful tool for prediction of steamflood production performance.
Effects of Heavy-Oil/Solvent Interfacial Tension on Gravity Drainage in the Vapor Extraction (Vapex) Process
Authors: Yang C. , Gu Y. 
Published: December 2007

Abstract
The vapor extraction (VAPEX) process is a promising technology for recovering heavy oil and bitumen resources in an economically viable and environmentally friendly way. Although a number of laboratory experiments have been conducted to study the VAPEX process, the oil recovery mechanisms by gravity drainage in this process are not well understood yet. In this paper, both experimental and theoretical approaches are adopted to study the effects of gravity and the capillary force on gravity drainage in the VAPEX process. First, the interfacial tensions between a heavy oil sample and four different solvents (methane, ethane, propane, and carbon dioxide) are measured at different pressures below their respective vapor pressures by applying the axisymmetric drop shape analysis (ADSA) technique for the pendant drop case. Then, the Bond number, which is defined as the ratio of gravity to the capillary force, is calculated for the VAPEX process in a heavy oil reservoir and in a physical model of sand pack, respectively. It is found that the measured interfacial tension between the heavy oil and a solvent is reduced almost linearly with pressure for the four heavy oil-solvent systems tested. Correspondingly, the Bond number increases with pressure. An increased Bond number indicates relatively large effect of gravity on the VAPEX process and thus enhanced oil recovery.
New Completion Developments for the Production of Heavy and Extra-Heavy Oil in Eastern Venezuela
Authors: Brunings C. , Quijada W. , Grisoni J. C. 
Published: December 2007

Abstract
PDVSA San Tome along with a local manufacturer, have developed two different types of completion that have reduced cost and increase production while making the down hole completion operations simpler and faster.
Intelligent Completion. This type of completion was designed to be able to complete multiple production zones trough a single well bore, taking care of the need to monitor and control the production of each one of the zones individually as required by Venezuelan government.
For well MEL-226, the completion included two sleeves, one zone isolator and one tubing hanger, all of which were hydraulically set in a single trip, the packers were specially designed to allow passage of hydraulic fluid internally. This well was completed in sands zones R4 and T with electro submersible pump (ESP) and is producing 2,500 BPD of 11.5 API, which is 50% more production than conventional single zone completion in this area.
Hydraulic Set Steam Injection and Production Packer. The requirements for this "Injector/Producer" tool was needed to save on well intervention and rig time. The tool had to be set in highly deviated or horizontal sections. It had to allow the pumping of Nitrogen for casing insulation protection, and it required an integrated expansion joint to allow the thermal expansion of the pipe.
After using mechanical models, a 100% hydraulic packer called CB-TIET was designed and more than sixty units were installed, obtaining significant savings on rig time (20,000 $/well) and allowing five days of early production. Likewise, an Injector-Producer packer and steam injection ports were tried to improve the steam distribution throughout the horizontal section of a well located at the Bare Oilfield.
Impact of Operational Parameters and Reservoir Variables During the Startup Phase of a SAGD Process
Authors: Prada J. W. Vanegas , Cunha L. B. , Alhanati F. J. S. 
Published: December 2007

Abstract
This paper highlights how numerical simulation can be used as a tool to optimize the start-up phase of a SAGD process. During start-up, the main objective is to create a uniform communication path between the two wells by first circulating steam in both the injector and the producer well and then imposing a differential pressure between them. The dynamics of this process leads to important temperature and pressure transients that should be carefully considered when developing a start-up strategy. Usually, this start-up strategy aims at minimizing the time in which the well pair can be converted to full SAGD operation without causing any adverse effects on the long-term process performance.
A fully coupled wellbore/reservoir thermal simulator was used to conduct a sensitivity analysis, in which the effects of steam circulation rate, tubing diameter, tubing insulation and bottom hole pressure were investigated. The effects of the pressure differential between the wells, and the timing of imposing such pressure differential, were also looked at. To better account for the interaction between the processes happening in the wellbore and in the reservoir, the discretized wellbore was placed inside a hybrid reservoir grid. Aiming at investigating the influence of vertical and horizontal permeability, reservoir pressure, initial oil/water saturation and fluid properties, the start-up strategy was examined for three different cases representing the main heavy oil production areas in Alberta, Canada: Athabasca, Cold Lake and Peace River.
Temperature Distribution in Natural Gas/Condensate Pipelines Using a Hydrodynamic Model
Authors: Sadegh A. A. , Adewumi M. A. 
Published: December 2007

Abstract
A hydrodynamic model for predicting the flow of natural gas and condensate in transmission pipelines has been developed. This steady state model was used to study the temperature profile along a transmission pipeline. The model is based on formulating the problem in terms of mass, momentum, and energy balance equations. Thermodynamic properties are determined using flash and thermo-physical properties calculators based on a Volume Translated Peng-Robenson EOS (VTPREOS).
This new model will provide gas transmission engineers with a versatile tool for modeling multiphase flow in pipelines. It will also provide approximations to the parameters of most importance to them specifically, the impact of temperature and terrain effects on liquid dropout. Liquid formation is a major concern for transmission companies due to the significant decrease in gas flow capacity, inaccuracy in metering, and potential damage to instrumentation and equipment. This model simply tells the field engineer where and how much liquid will form. This information is valuable for locating and sizing liquid collection tanks, and in the design of a cost effective pigging schedule.
The results of the systematic numerical studies showed that the temperature of the gas decreased from the inlet condition to that of the surrounding temperature within 3 miles of the inlet. In addition a temperature rise of up to 5 degrees Fahrenheit was observed when an undulating terrain was simulated (in downhill flow).
Recent Advances in Aphron Drilling Fluids
Authors: Growcock F. B. , Belkin A. , Fosdick M. , Irving M. , O'Connor B. , Brookey T. 
Published: December 2007

Abstract
Aphron drilling fluids are being used globally to drill through depleted reservoirs and other under-pressured zones. The primary features of these fluids are their unique low-shear rheology and aphrons (specially designed pressure-resistant microbubbles of air). However, how aphron drilling fluids work is not well understood, which limits acceptance of this technology, along with efforts to optimize the system's performance. Recently a study was undertaken under the auspices of the U.S. Department of Energy to gain some understanding of the workings of aphron drilling fluids. Those results are presented here.
Various laboratory techniques were applied to determine the physicochemical properties of aphrons and other components in the fluid and how they affect flow through permeable and fractured media. These included wettability and surface tension, bubble stability, radial and dynamic flow visualization, and fluid displacement tests.
One key discovery was that aphrons can survive compression to at least 4000 psig, whereas conventional bubbles do not survive long past a few hundred psig. When drilling fluid migrates into a loss zone under the drill bit, aphrons move faster than the surrounding liquid phase and quickly form a layer of bubbles at the fluid front. At the same time, the shear rate of the fluid continually decreases and the viscosity is rapidly rising. The combination of the bubble layer and the rapidly increasing viscosity of the liquid severely curtails fluid invasion. Another key finding of the study is that aphrons show little affinity for each other or for the mineral surfaces of the pore or fracture; consequently, the seal they form is soft and their lack of adhesion enables them to be flushed out easily during production.
Depleted wells which are very expensive to drill underbalanced or with other remediation techniques can now be drilled overbalanced. This study has provided a sound technical basis for the success of aphron drilling fluids and is providing guidance on the way to run these fluids in the field to optimize their performance.
Determination of Effective Drainage Area for Tight Gas Wells
Authors: Cox S. A. , Sutton R. P. , Stoltz R. P. , Knobloch T. 
Published: December 2007

Abstract
Early quantification of the well's ability to effectively drain the productive reservoir will result in improved economic performance. The effective drainage area of a tight gas well is primarily controlled by reservoir geometry, rock and fluid properties and well completion efficiency. This paper will present theoretical effective drainage areas for wells completed in blanket sands (radial drainage) and channel sands (linear drainage). The work will focus on the relationship between reservoir geometry, effective gas permeability, porosity and fracture half-length for dry-gas reservoirs.
The relationship of effective gas permeability and fracture half-lengths on the effective drainage area will be presented as a result of this work. Typical Appalachian Basin producing reservoir properties will be incorporated into the simulation work tailoring this analysis to those producing environments. The cases presented in this paper will include permeability ranging from 0.01 md to 1 md, reservoir geometries ranging from radial flow to channel widths from 250 ft to 1000 ft and fracture stimulation half-lengths up to 300 ft. For consistency, all stimulation cases will be based on an assumed 200 md-ft fracture conductivity.