bluuebunny/crossref_metadata_2025_split huggingface dataset:
Environmental Impact of Bitumen Extraction with Thermal Recovery
Authors: Morrow A. W. , Mukhametshina A.. , Aleksandrov D.. , Hascakir B.. 
Published: June 2014

AbstractThe continuous and growing demand for energy and carbon based products requires the extraction of massive bitumen resources. Due to extremely high viscosities of bitumen, the most effective bitumen extraction methods are thermal enhanced oil recovery (EOR) methods such as In-situ Combustion (ISC), Steam Assisted Gravity Drainage (SAGD), Steam Flooding (SF), and Hot Water Injection (HWI) which are known as environmentally unfriendly bitumen extraction methods. In this study, we investigated the environmental impact of in-situ bitumen extraction by ISC, SAGD, SF, and HWI, experimentally. The original oil, water, and rock, produced oil and water, and spent rock samples originated from each recovery method were analyzed through Fourier Transform Infra-Red (FTIR) spectroscopy, Inductive Coupled Plasma – Mass Spectroscopy (ICP-MS), pH, viscosity, and API gravity measurements. The environmental impact was investigated according to the amount and content of produced water and gas samples and the quality of oil to reduce the impact during bitumen refining. The experimental results showed that while with ISC, the least amount of water is produced; the produced water requires more severe treatment due to its high metal and sulfur contents, and low pH level. On the other hand, since the amount of the produced water for SAGD, SF, and HWI is higher, the produced water management poses handling problems. The oil production from ISC results in the greatest recovery with upgraded oil which will reduce the environmental impact for oil processing when compare to SAGD, HWI, and SF. While all processes produced more or less the same amount of gases, SAGD and SF have additional gas production due to steam generation. As conventional resources decline, it is essential to address environmental challenges to produce from these massive oil sand resources. In this study, the environmental impacts of bitumen extraction with thermal EOR were examined extensively.
NCG Co-Injection at Hangingstone Demonstration Project – Case Study and Analysis
Authors: Doan Luong T. , Harschnitz Brian , Shiga Norihiko , Pennacchioli Enzo , Park Bob 
Published: June 2014

Abstract
The application of NCG co-injection into matured SAGD development has been well documented. At several commercial development projects1–3, it has become the standard operating practice to improve the SOR of the patterns and total project.
At the Hangingstone Demonstration Project, JACOS had implemented the first NCG co-injection pilot in 2007 at Phase 1 wells (A-B wells), which was reported by Wang4. Since November 2010, continuous co-injection started at Phases 1 & 2 wells (A-E wells), but was temporarily shut-in in September 2011 due to several interruptions of the gas supply. We used this opportunity to re-establish a base case steam injection scenario only; stable steam injection and reservoir withdrawal took effect for the next 8 months. Co-injection restarted in June 2012 to again improve the thermal efficiency of the Phases 1 & 2 development. As a consequence, two distinctive NCG co-injection periods could be observed. The second and third periods took place between November 2010–September 2011, and between June-December 2012; respectively for the A-E well pairs (Phases 1 & 2).
Our NCG co-injection experience to-date revealed that: 1) Bitumen production is not compromised, 2) The steam oil ratio (SOR) can be reduced, 3) When NCG co-injection ceased, the gas previously in the chamber – observed via temperature observation well – could no longer be detected, 4) Lower emission intensity of CO2 gas from steam generation can be achieved, 5) The steam injected (CWE) was balanced against the water produced, and 6) Allocation of steam to new well(s) or non-thermally matured wells can maximize overall field production.
These positive results led to propose expanding the desired NCG co-injection into Phases 3 & 4 wells (H-Q well pairs), where some of the well pairs had been operating since November 2001 and at different stage of thermal maturity. The design of this NCG co-injection expansion along with field issues associated with implementation will also be discussed.
Oil Drainage Characteristics during the SAGD Process to Explain Observed Field Performance
Authors: Ito Yoshiaki 
Published: June 2014

Abstract
The general concept of the SAGD process is that a steam chamber first expands to the top of the reservoir and thereafter continues to grow by lateral expansion. Consistent with this concept is the expectation that the steam oil ratio (SOR) rises as the SAGD operation matures, driven by expanding contact area and heat losses between the steam chamber and the overburden.
However, analysis of a number of successful SAGD projects, with operating histories of 10 years or more indicates that there is clear evidence that observed performance can deviate significantly from the performance predicted by the above concept. One particularly interesting set of observations shows a declining or unchanged SOR at the mature stage. An examination of this SOR behavior and several other unexpected SAGD performance characteristics detected in the field are presented.
It is proposed that the above field performance characteristics are consistent with the interpretation that the steam chamber does not rise to the top of the reservoir prior to expanding laterally. In these cases oil production is achieved by two different mechanisms: one is expansion of the steam chamber and the other is drainage of oil from the layer above the steam chamber. A simulation method and the results of a number of history matching studies are presented to explain the oil and gas flow in the layer above the steam chamber and its contribution to observed SAGD performance.
Oil Recovery Mechanisms in Bitumen-Bearing Carbonate Rocks
Authors: Bryan J. , Kantzas A. 
Published: June 2014

Abstract
Bitumen-bearing carbonate reservoirs, dominated by the 406 billion barrel resource in the Grosmont formation, will provide billions of barrels of recoverable oil for the Province of Alberta. A small contribution to this development was an extensive series of initial laboratory experiments that were conducted for multiple producers under a variety of conditions. The experiments include measuring oil recovery to varying water and steam processes, both separately and in combination with each other. Displacement procedures included both washing/soaking and direct floods with temperatures ranging up to 260°C. These laboratory tests were conducted over a six year period.
As this research was conducted across several producers independently, a planned statistical design was not addressed through this process. Rather, the experiments are exploratory in nature, examining the primary recovery mechanisms contributing to production performance and ultimate recovery of bitumen in these heterogeneous systems. It has been shown that bitumen can be readily recovered from fractured and connected open porosity that is accessible to steam through a gravity drainage process. Furthermore, carbonates at elevated temperatures become more water wet, and water imbibition can play a significant role in accessing recovery from the oil-bearing rock matrix. The impact of imbibition is significant, and wet steam proves a much more efficient displacing medium than dry steam. The recovery of oil from lab-scale models also shows a significant impact of thermal expansion and gas drive, which can lead to significant oil displacements at early times, particularly in areas where the localized open porosity network is extensive. Bitumen recovery from carbonate systems is achieved through a combination of these processes: thermal expansion, gas drive, gravity drainage of oil out of connected open porosity, and imbibition of water into the rock matrix.
Field Trial Outcomes of a Permanent Magnet Drivetrain for Progressing Cavity Pumps
Authors: Cochran Jamie , Franks Spencer 
Published: June 2014

Abstract
This paper details the findings and outcomes of field trials of a new artificial lift technology.
The technology is a submersible permanent magnet drivetrain for a progressing cavity pump which was tested for cyclic steam stimulation heavy oil applications in the San Joaquin Valley, California. The drivetrain has been designed to provide sufficient torque with high efficiency within a small package, enabling optimum placement within the wellbore.
The effectiveness of steaming and the geothermal temperature variance at the reservoir is investigated using multiple data points over time. The impact of operating the artificial lift system at different speeds is explored, including interpretations of specific downhole events during the trials. Field trial data, from field installations is presented, from which key findings are shown. This paper will present a study into the relationship between progressing cavity pump performance, temperature, oil cut and fluid viscosity.
The effect on the well production and performance with respect to events and activity in surrounding wells was also analysed using surface and downhole data collected during the trials.
Remote Monitoring of SAGD Operations with Satellite based InSAR
Authors: Henschel Michael D. , Shen Luyi , Shipman Todd , Lehrbass Brad , Aubé Guy 
Published: June 2014

Abstract
Surface deformation, measured from space, provides a means to remotely monitor Enhanced Oil Recovery (EOR) activities. Using Interferometric Synthetic Aperture Radar (InSAR) to measure surface deformation allows for a common measuring stick with no access issues. Currently surface deformation is measured using many alternative approaches, some of which are less economical and not feasible at the regional scale when compared to InSAR. Information collected from InSAR could be used to develop an informed planning mechanism.
Space based SAR data from January 2009 to August 2011 was examined over a SAGD site in Alberta, Canada. The data was extracted from the satellite archives and advanced InSAR processing techniques were applied to measure the surface deformation over the site.
The InSAR results show the extreme variability in the ground conditions that are to be expected in the region. The surface deformation was measured using a combination of corner reflectors and infrastructure targets. The highly variable ground conditions make monitoring of subtle deformation signals (2.5 – 5 cm/yr) difficult to measure without the use of installed targets. The challenges of InSAR monitoring without installed targets are addressed to emphasize the importance of on-site ground control points.
Furthermore, the surface changes observed with the InSAR results are related to reservoir changes. Geomechanical simulation is dependent on many rock physics parameters and complex geological frameworks. History matching with InSAR observation provides enhanced prediction and estimation of reservoir growth, which can inform decisions related to reservoir performance and caprock integrity.
This paper is a result of a collaboration between the Alberta Energy Regulator, MDA Geospatial Services Inc. (MDA), and the Canadian Space Agency (CSA) to examine the requirements for rapid-turnaround measurement of ground deformation over enhanced oil recovery sites in the Alberta Oil Sands. Funding for this effort was partially provided by the CSA.
Steam Flow Tests for Comparing Performance of Nozzle, Tube, and Fluidic Diode Autonomous ICDs in SAGD Wells
Authors: Least Brandon , Greci Stephen , Huffer Ryan , Rajan Raj V. , Golbeck Hart 
Published: June 2014

Abstract
Many operators are considering installation of flow-control devices (FCDs) in horizontal wells to improve steam-oil ratios (SOR) in steam-assisted gravity drainage (SAGD) recovery processes in heavy oil/bitumen reservoirs. The flow-control devices are used to help balance both the steam injection and fluid production in order to increase the oil recovery efficiency and use the full length of the horizontal wells. SAGD injector and producer horizontal wells are typically 3 to 6 meters apart, vertically. Because of this proximity, steam breakthrough to the producer well is possible. In order to reduce the steam loss following a steam breakthrough, operators typically try to slow the total rate of production.
This paper will discuss the testing of passive inflow control devices (ICDs) and an autonomous inflow control device (AICD) in a steam-flow test loop along with testing results to help control the breakthrough of steam. Heated water flow through the ICDs and AICDs was used as the baseline case. Saturated steam simulating steam flow conditions (pressure and temperature) in a SAGD environment was flowed through the devices at two different temperatures, and the resulting flow rates were recorded at several pressure differentials.
The laboratory flow testing has helped demonstrate how the ICDs and AICDs can either help prevent steam breakthrough from occurring or limit the rate of steam breakthrough in the zones of concern. By limiting the flow rate of steam breakthrough, the flow control devices will also help to protect the sand screen from erosion caused by high velocity flow.
Russkoe High Viscous Oil Field - Production And Performance Optimization
Authors: Lachugin D. S. , Edelman I. Y. , Shandrygin A. N. , Aksenov M. A. , Lachugina Y. V. , Abramochkin S. A. , Davidovskiy A. D. 
Published: June 2014

Abstract
The Russkoe oil and gas field was discovered in 1968. It is one of the biggest and complex fields in Russia. It has yet to be put to production, however the development is already concerned by a number of geological and operational issues, such as high crude viscosity, remote location (beyond the Polar Circle), considerable heterogeneity, compartmentalization of poorly cemented sandstones as well as the presence of extensive gas cap, bottom water, and thick permafrost zone.
OJSC "Tyumenneftegaz", a subsidiary of Rosneft, has been responsible for the pilot works to seek operational solutions for full-field development. Intensive pilot wells drilling and testing have been performed since 2007 in different zones of the field. In 2009-2012 23 wells, including 16 horizontal ones, were drilled in these pilot areas. Additionally cold and hot water injection tests have been conducted in one of the pilot areas. The main goal of these studies was to learn and reduce geological risks and to find an effective system for full-field development.
The article presents the data and results of pilot operations as well as the methods and equipment for monitoring of the pilot works including multi-phase measurements of flow rates of producers using Vx tool, measurements of flow rates of injectors, tests of injectivity/inflow profiles in horizontal sections using DTS and PLT systems, measurements of bottom hole pressure dynamics and parameters of PCPs and ESPs using high precision metering systems.
Effectiveness of different control and monitoring methods and of different production technologies has been analyzed. As a result applicability of these methods for the development of viscous oil fields under difficult weather conditions has given using the example of the Russkoe field.
Field Upgrading Of Bitumen To Produce A Synthetic Crude Oil With Improved Properties
Authors: Till Andrew , Rees Andrew , Schleiffer Andreas 
Published: June 2014

Abstract
Crude bitumen extracted from the Canadian oil sands has a high viscosity, so typically it does not flow at normal pipeline temperatures. After extraction the bitumen can be mixed with a diluent (refined naphtha, condensate or SCO) before being pumped by pipeline to a refinery for processing. Alternatively the bitumen can be processed to either improve the viscosity, produce a higher value synthetic crude oil (SCO), or fully finished products before export. These additional costs can significantly impact the overall economics of bitumen extraction.
The Veba Combi-Cracking™ (VCC™) process is a proven slurry based hydrogen addition technology able to process refinery residues, heavy crude oil and even coal. Commonly found in a refinery environment it is also ideally suited to field upgrading, since it can be tailored to produce directly marketable products, a high quality synthetic crude oil, or simply provide viscosity reduction for easy transportation.
This paper shows that the VCC™ technology is ideally suited to field upgrading of bitumen. With an Athabasca Bitumen feedstock the VCC™ process can achieve greater than 90% conversion of asphaltenes, and a 95% overall conversion of the 524°C+ material to desirable products, in a single pass. This paper also shows an improvement in overall efficiency and minimisation of undesirable products when compared to other common field upgrading processes. With simple changes to the flowsheet it is capable of producing high quality finished products (Naphtha: 1 ppm S, Diesel: &lt;10 ppm S, Cetane &gt;45, VGO: &lt;100 ppm S, Metals &lt;1 ppm), a fully upgraded syncrude, or alternatively provide significant viscosity reduction (example heavy crude VR reduced from 145, 800 cSt to 3.0 cSt) for export by pipeline.
Opportunities and Challenges of Cyclic Steam Stimulation (CSS) Development in Seal's Cadotte Area
Authors: Jamaloei B. Y. , Singh A. , Solberg A. 
Published: June 2014

Abstract
Murphy's Seal asset in Peace River Oil-sands renders a strong incentive for application of EOR techniques. A combination of primary depletion and thermal/non-thermal EOR techniques (polymer flood, Cyclic Steam Stimulation (CSS), and Vertical Steam Drive (VSD)) are currently being pursued or evaluated by Murphy Oil to increase Seal's production. High oil viscosity in Seal's Cadotte does not allow for primary development and non-thermal EOR schemes in this area. Hence, Cadotte has been considered for application of CSS and VSD. This study highlights the opportunities and challenges of Cadotte's CSS development using pilot results, history-match/forecast, optimization and uncertainty analysis.
The impacts of reservoir features that complicate Cadotte's CSS development are quantified through history-match/optimization, sensitivity analysis and uncertainty assessment. These features include a presence of multiple PVT regions and water pockets, varying rock dilation, fracturing, and pay-zone thickness variation. Reservoir simulation, Latin hypercube designs, and response surface methodology are used to conduct the history-match, optimization, sensitivity analysis and uncertainty assessment.
Because the underlying geology in Seal is complex, one focus of this study is to isolate the effect of geological complexities on CSS development by conducting the history-matching/forecast using a layer-cake model updated by 3-D seismic and log analyses.
By accounting for geological and reservoir/operation variances, this integrated study helps determine optimum CSS development in Cadotte. It also sheds light on how to screen reservoir/operation parameters for successful application of CSS in geologically-complex reservoirs with a varying PVT behavior.
Experimental and Numerical Studies of the Reservoir Permeability and Drainage Height Effects on the Solvent-Diluted Heavy Oil Gravity Drainage
Authors: Lin Lixing , Ma Hongze , Zeng Fanhua , Gu Yongan 
Published: June 2014

Abstract
Solvent-based enhanced heavy oil recovery techniques are promising alternatives to thermal-based methods. A better understanding of the solvent-diluted heavy oil gravity drainage is important to practical field-scale applications of the solvent-based heavy oil recovery processes. In particular, the transmissibility, which is defined as the product of the absolute permeability k and pay-zone thickness h of an oil reservoir, is an important parameter to affect the solvent-diluted heavy oil gravity drainage. In this paper, a series of experimental tests were conducted in a visual high-pressure physical model to study the permeability effect. The physical model was packed with the Ottawa sands of different sizes to obtain different absolute permeabilities in the range of k = 7–54 Darcy. The original heavy oil sample collected from the Lloydminster area in Canada was used to saturate the sand-packed physical model and pure propane was used to extract the heavy oil. The drainage height effect was studied by performing the solvent-diluted heavy oil gravity drainage tests in another visual physical model with a different drainage height. The produced heavy oil and solvent were collected and recorded in each test. The produced oil samples obtained at different times were flashed and the flashed-off heavy oil viscosities were measured. It was found that heavy oil was produced much faster in a higher permeability physical model with a larger drainage height. A new correlation was developed to take account of the reservoir permeability and drainage height effects (i.e., the transmissibility effect) on the heavy oil production. In addition, the average produced solvent–oil ratio (SOR) was determined to be in the range of 0.3–0.6 g solvent/g heavy oil. The average SOR was increased as the reservoir permeability and drainage height were decreased. It was also found that the produced heavy oil viscosity was reduced significantly. Furthermore, numerical simulations were undertaken by using CMG STARS module to match the experimental results. This study provides much-needed physical and practical understanding of the solvent-based heavy oil recovery.
Screen-Inflow-Design Considerations with Inflow Control Devices in Heavy Oil
Authors: Oyeka Onyema , Felten Frederic , Least Brandon 
Published: June 2014

Abstract
Inflow control devices (ICDs) improve oil recovery because of their capability to delay water and gas breakthrough. ICDs also can be applied to heavy oil reservoirs to help overcome the higher mobility of water, and therefore, are now frequently used in Canada's Steam-Assisted Gravity Drainage (SAGD) heavy oil market to improve steam/oil ratio. Unfortunately, upstream flow behavior of ICDs is often ignored; however, flow through the screen-basepipe annulus can induce higher-than-expected pressure losses, and since these losses (not experienced with water) also reduce efficiency and lower performance, special attention should be given to flow-path characteristics.
This paper examines pressure drops through the screen basepipe annulus of a direct wrap-on-pipe-type screen before entering the ICD. Using Computational Fluid Dynamics (CFD) simulations, the axial flow through the screen-basepipe annulus of a direct-wrap screen was simulated for three fluids. In addition, several flow rates and multiple-rib-wire-height wire types were used to cover a broad range of operations. The results of the simulations and analyses support the hypothesis that taller ribs would result in a lower pressure drop through the annulus. These simulations and analyses will show that increasing the rib height will cause the overall pressure drop in the annulus to decrease, often by as high a factor as four.
These results will help determine optimum screen/base-pipe annulus spacing during screen design.