bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Practical Approach for the Modeling of Foamy Oil Drive Process
Authors: Shen Chonghui 
Published: May 2015

Abstract
Cold heavy oil production exploits the mechanism of enhanced solution gas (or foamy-oil) drive to achieve an economic oil flow rate and ultimate recovery. Understanding the dynamics of foamy-oil drive and being able to simulate the process make it possible to evaluate the potential of cold production more realistically.
A generic kinetic model based on known solution gas exsolution and evolution process has been proposed and tested. The sequence of gas exsolution in foamy-oil drive can be described by the following four major steps and corresponding (first-order) mechanisms: Supersaturation from pressure drawdownBubble nucleation under super-saturationBubble growth under molecular diffusionBubble coalescence from film drainage
The effects of dispersed gas on the gas phase mobility has been modeled with a simple viscosity mixing rule by assigning a much higher viscosity to the dispersed gas component. The benefits of this approach is that the apparent low mobility of the gas phase in the foamy-oil drive process can be attributed to the viscosity change, instead of rate dependent relative permeability. Therefore, a “normal” relative permeability can be used for a wide range of rate conditions.
The proposed dynamic model has been validated with the history matches of both the volume draw down and the pressure draw down laboratory test data. The validation reveals that one can use a set of consistent dynamic parameters to match the results of various tests under different draw down rates.
The dynamic model has been implemented in a commercial reservoir simulator (CMG-STARS) with available options.
Steam Circulation Strategies in the Fengcheng SAGD Project to Achieve Enhanced Conformance and Production: A Case Study
Authors: Wu Yongbin , Li Xiuluan , Liu Xueqi , Li Jun , Zhao Rui , Yang Liu , He Wanjun , Gao Liang 
Published: May 2015

Abstract
A sizable number of heavy oil reservoirs that are developed by SAGD in Xinjiang Oilfield in China are heterogeneous and shaly. Particularly the distribution of shale barriers between the horizontal segments of injector and producer has significant impact on the steam chamber development. Conventional steam circulation approach does not consider the location of shale barriers, where poor or no steam chamber develops after converting to SAGD production mode consequently. In order to achieve uniform heat communication, the practical methods of operation during SAGD circulation phase are presented, and the application performances in Fengcheng SAGD project are also discussed.
In this work, the steam circulation is divided into 3 phases: (1)Low pressure circulation phase(Pinj=Pr+0.2MPa); (2)High pressure circulation phase(Pinj=Pfrac-0.5MPa); (3)Partial-SAGD phase, which include 3 cases: case1 where the shale barriers or low permeability sections are located around heel, only the short tubing of injector injects, while the producer continues circulation by long tubing injection and short tubing production; case2 where the shale barriers are located around toe, only the long tubing of injector injects, while the producer continue circulation by long tubing injection and short tubing production; case 3 where the shale barriers are located around the middle of the horizontal segment, the long tubing and short tubing of injector inject simultaneously, while the producer continue circulation by long tubing injection and short tubing production. Other parameters of injection and production are also optimized.
The phase-by-phase steam circulation strategy is particularly effective for SAGD projects with low permeability sections and shale barriers distribution between the horizontal segments. During 2013-2014, 18 wellpairs in Fengcheng SAGD project have been carried out the strategies from this paper and converted into SAGD production phase. Uniform conformance along horizontal sections of the wellpair was achieved, and the oil production rate is 1.5-2 times higher than wellpairs using conventional circulation approaches.
Real-Time Seismic Surveillance of Thermal EOR at Peace River
Authors: Lopez J. L. , Wills P. B. , Follett J. R. , Barker T. B. , Xue Y. , Przybysz-Jarnut J. K. , Potters J. H. , van Lokven M. , Brouwer D. R. , Berron C. 
Published: May 2015

Abstract
Permanent reservoir monitoring solutions, if of high enough sensitivity and low enough cost, can be used to tackle the many problems faced by seismic monitoring onshore and thereby increase the profitability of such IOR/EOR projects. Here we focus on thermal EOR monitoring using a SeisMovie® system provided by CGG, installed in one of the production pads in Peace River, and recording data since May 2014. The daily seismic data are integrated with other surveillance data to monitor steam conformance and provide options to adjust injection and production schedules to optimize recovery.
Production of Gases During Thermal Displacement Tests
Authors: Butron Jessica , Bryan Jonathan , Yu Xiaoli , Kantzas Apostolos 
Published: May 2015

Abstract
During laboratory testing of thermal processes (hot water and steam displacement of bitumen) a consistent observation has been the production of very high gas volumes with produced oil and water. These gases are many times more in volume than what is expected from solution GOR and what is observed in the field. This paper presents an ensemble of experimental results of thermal displacement tests in oil sand and bitumen bearing carbonate rocks. The focus of analysis of these tests deals with the generation of non-condensable gases.
Various laboratory core floods are run over a temperature range of 160 – 200°C+. Tests are run on native-state oil sand and carbonate samples, containing original saturations of bitumen and connate water. Cores are exposed to either hot water or steam, in linear flooding configurations or soaking conditions. The output from these tests is a measurement of produced gas volumes and compositions as a function of either soaking time or volumes of water/steam injected through the core. Tests were conducted on McMurray oil sand, Grand Rapids oil sand, and carbonate systems.
During thermal displacements and at temperatures as low as 160°C, gases are generated. The gases are predominantly CO2 and H2 with traces of CH4 (which is usually seen early in the experiments) and other low carbon hydrocarbons. The last ones are usually at the noise level of the analytical instruments. What is significant is that at the lower temperatures there is no apparent generation of H2S and that supports the fact that the gas generation process is not aquathermolysis driven. The generation of gases is apparent in bitumen rich and bitumen free samples. This supports the assumption that the generation of gases is geochemical in nature, as well as through organic decomposition.
The conclusion of the analysis indicates that the generation of such gases is caused by the combined effects of water/oil and water/solids reactions. Gas generation is affected by the system conditions and in general higher gas volumes are produced at lower P/Psat. Gas production is also strongly affected by surface contact between water and solids, which leads to lower apparent gas generation rates in carbonates compared to oil sands, and higher gas production from floods compared to soaking tests. The effect of such reactions in the exploitation of clay bearing sands and carbonate rocks is that the generation of extra gases will affect the thermodynamics (partial pressures), heat transfer (insulation) and relative permeability curves of the intended processes (SAGD, CSS, SAGD-solvent).
Enhanced Viscosity Formulations For Steam Foam Applications: Impact On Performances In Bulk And Porous Media
Authors: Cuenca Amandine , Lacombe Emie , Chabert Max , Morvan Mikel , Delamaide Eric 
Published: May 2015

Abstract
Heavy oil extraction is mostly based on thermal EOR processes. Warming up the reservoir reduces oil viscosity, makes it more mobile and in turn enhances heavy oil recovery. The most prominent thermal heavy oil EOR method relies on steam injection. This recovery process consumes high quantities of fresh water and energy to produce the steam, and heat loss due to reservoir heterogeneities and thief zones must be minimized. For that purpose, steam foams can be used to decrease steam mobility and improve its utilization by a better distribution in the reservoir. Selection of appropriate products for steam harsh temperature conditions poses several challenges regarding chemicals stability and foam durability. We have shown in previous papers that synergistic association of thermally stable surfactants can highly improve high temperature foaming performances. Here, we extend these results to specific surfactant formulations designed to provide enhanced bulk viscosity. These formulations are intended to compensate for the strong decrease of water viscosity with temperature. This is expected to enhance steam foams lifetime and in turn provide a better steam mobility control in application conditions.
Bulk foam half-life is highly dependent on experimental conditions, in particular on the initial state of the foam in terms of quality and bubble size. This is even truer for steam foams that are also highly sensitive to possible temperature gradients. An optimized experimental setup has been developed to evaluate high temperature foam half-life obtained with standard and enhanced viscosity formulations. We couple these measurements with rheology and mobility reduction evaluation in sandpack experiments.
Based on these various parameters, we try to extract correlations between bulk steam foam half-life, bulk viscosity and mobility reduction in porous media.
This paper describes the characteristics of newly developed enhanced viscosity surfactant formulations, and also provides data regarding impact of viscosity on high temperature foam stability and mobility reduction.
Methodology for In-Well DTS Verifications in SAGD Wells
Authors: Hiscock B. , Hinrichs L. , Banack B. M. , Rapati B. 
Published: May 2015

Abstract
In steam assisted gravity drainage (SAGD), temperature instrumentation is widely used to understand steam placement across openhole liners in producer and injector wells. The accuracy of temperature readings is crucial when monitoring wellbore integrity and optimizing production. While distributed temperature sensing (DTS) on fiber-optic cables has been widely used in temperature monitoring, challenges consistently exist regarding accuracy.
Several trials over a 2-year period were completed to quantify the accuracy of DTS systems. Each trial employed different operating conditions and instrumentation:
Case Study 1: Dual-laser DTS and thermocouples were permanently deployed in a newly drilled SAGD producer. The well was heated from geothermal to 240°C. Newly deployed thermocouples were compared against newly deployed fiber-optic cables. Case Study 2: Dual-laser DTS temperature measurements were compared across a 1 dB point loss at a maximum optical budget of 13 dB. Case Study 3: Dual-laser DTS vs. single-laser DTS vs. new thermocouples comparisons were made. Case Study 4: Thermocouples and dual-laser DTS for a mid-life SAGD injector and producer were compared for accuracy after two years of operation. Case Study 5: An independent temperature log containing dual-laser DTS was used to quantify the thermocouple temperature discrepancy on a SAGD producer in operation for 7 years.
The results of these case studies allowed Devon to determine several important learnings, as well as a troubleshooting methodology for evaluating DTS accuracy. When properly installed and calibrated, dual-laser systems are accurate up to ±2°C over the full range of SAGD operating temperatures for stable operating conditions. During the trial period, DTS was shown to maintain accuracy for 2 years.
When comparing the accuracy of temperature systems, it is recommended to compare against other known metrics during falloffs. New thermocouples are still considered the most accurate measurement; however, legacy thermocouples are susceptible to drift. Independent temperature logs have proven to be a valuable tool for assessing legacy instrumentation accuracy for thermocouples and DTS.
Design, Testing, and Field Performance of Steam-Injection Flow-Control Devices for Use in SAGD Oil Recovery
Authors: McChesney Ryan , Felten Frederic , Hobbs Scott , Edlebeck John 
Published: May 2015

Abstract
To promote efficient recovery of bitumen hydrocarbons using the steam assisted gravity drainage (SAGD) process, it is vital that steam be used effectively because steam generation constitutes one of the largest operational expenses during the SAGD process. To optimize this process, steam-injection flow-control devices (FCDs) have been developed. These devices are designed to enhance the operator's ability to distribute steam along the wellbore and to cease steam injection at a particular injection point if necessary, as the steam chamber matures. This paper discusses the design and capabilities of FCDs.
The project initiated with a design requirement of two core components— the axial distribution of steam exiting the device and a device to incorporate a sliding sleeve mechanism. The basis for FCD design decisions was developed initially by reviewing worst-case operating conditions FCDs could encounter and then using this information as the operating envelope criteria that the design should meet. SAGD completion tools are required to endure everything from temperature fluctuations and corrosive formation fluids to erosive wet steam and severe wellbore trajectories. To design a tool that would survive the erosive effects of varying steam quality, the critical velocities and erosive mechanisms were defined. API RP 14E provides a conservative basis to determine the maximum allowable fluid velocity in a given system, but several studies have sought to push the boundaries of acceptable fluid velocities. The most conservative nozzle exit velocities were used to limit risks to casing. The risks caused by high velocities in the nozzle inside/inner diameter (ID) to the injection tool were mitigated through the use of computational fluid dynamics (CFD) analyses and material selection/treatment.
Because of the high temperatures under which SAGD operates, consideration of mechanical property degradation and possible deformation had to be considered, specifically to the collet of the sliding sleeve. To prevent diminishing performance during the operational lifetime, FCDs that use sliding sleeves with collet mechanisms require a robust design that recognizes and addresses maximum stress loads and limits plastic deformation at peak temperatures. The testing of the sliding sleeve was conducted throughout a wide range of temperatures where the forces to shift the sleeve were monitored and compared to previous finite elements analyses (FEA) for compliance.
ISO 14998 Annex D provided the basis for function testing of the FCD (i.e., cycling the sleeve and pressure testing at temperature). All pressure and function testing was performed at or above the operating temperature, and pressure and results were qualified to ISO 14998 V1. Field performance is discussed in the paper.
Detailed History Matching of a SAGD Well Pair Using Discretized Wellbore Modeling
Authors: Nguyen K. N. , Doan L. T. , Kato K. 
Published: May 2015

Abstract
Circulation of steam during the start-up of a well pair is required for the SAGD process where there is limited fluid mobility, as it helps establish communication for flow between the injector and producer well. The majority of the modeling encountered to date for the circulation period either assumed a source/sink constraint, used a horizontal discretized wellbore model with sand face coupling, or used a pseudo-steady state wellbore flow model only. The above methodologies do not take into account 1) the heat transfers and pressure behavior among the different tubing strings, 2) the change in conditions from sand face to wellhead, and 3) the fluid interaction between the wellbore and reservoir.
Using a thermally-coupled wellbore-reservoir simulator, a discretized wellbore model was constructed to allow a detailed history matching for the circulation period of the M-well pair at the Hangingstone Demo pilot. The history-matched circulation period helped better understand the effects of hydraulics, heat transfers between tubing strings and the impact of fluid losses on reservoir heating. This knowledge will help Japan Canada Oil Sands Limited (JACOS) design the operating philosophy for the Hangingstone Expansion wells. The paper will discuss how the matching was achieved along with the observations made.
SAGD Liner Evaluation and Liner Test Design for JACOS Hangingstone SAGD Development
Authors: Spronk E. M. , Doan L. T. , Matsuno Y. , Harschnitz B. 
Published: May 2015

Abstract
JACOS’ Hangingstone Demonstration Project has been in operation since 1999. The company has used the 10,000 bbl/D facility as a foundation for learning and refining SAGD processes and operations. The 24 operational well pairs, with 15 years of production has provided valuable insight into the performance of different liner completion types and operational control mechanisms. Data from the Demo project has provided the basis for a liner test strategy and liner design for application at JACOS’ Phase 1 Hangingstone Expansion project. First steam is expected in late 2016.
All of the 24 operating well pairs at the Demo project have concentric tubular designs, but varying liner completion types. One well pair is completed with MeshRiteTM, 13 well pairs with wire wrap screens and 10 well pairs are completed with slotted liners of varying slot sizes. With a relatively strong surveillance program, the flow distribution (inflow), subcool control, hydraulics and operability for each of the well pairs were carefully analyzed. The performance of wells with MeshRite, wire wrap screen and slotted liners will be presented. The analysis provided insight into what was successful in the field and provided a strong basis for the test design.
As part of the expansion project, field performance data from the six phases of the Demo project, coupled with particle size analysis, flow testing and thermal performance analysis, guided JACOS to select slotted liners for all injector wells. For the producers, 27 wellbores were completed with wire wrap screens and five wellbores with MeshRite liners, for a total of 32 well pairs. This comprehensive study incorporated field learnings, operational successes, and a comparison between the flow test observations and field observations. Finite element analysis and specialized drilling mud contributed to liner installation success for the Hangingstone Expansion.
Well Integrity Evaluation Using Distributed Temperature Sensing (DTS) on an Operating SAGD Injector Well Influenced by Neighboring Steam Chambers
Authors: Thompson Scott , Bello Alejandro , Medina Max , Greig Thomas 
Published: May 2015

Abstract
Temperature fall-off logs are routinely performed on a number of operating wells at Statoil's Leismer field to monitor well integrity. So far, all wells have demonstrated normal temperatures in formations overlying the steam chamber, less than steam temperatures, and with fall-offs according to typical heat conduction. However, one injector well did not fall-off as expected after a 24 hour shut-in; instead showed temperatures exceeding 200°C in formations above the steam chamber. An investigation was launched and a multidisciplinary team evaluated possible causes for the high temperatures.
A review of 4D seismic data showed that a neighbouring steam chamber was intersecting the wellbore. This led to the hypothesis that the high temperatures were the result of wellbore heating from the neighbouring steam chamber, and a follow-up, extended temperature fall-off log confirmed the hypothesis. The extended logging period confirmed that temperatures outside casing did fall-off, albeit at a slower rate than other wells, due to the heating effect of the neighbouring steam chamber. The temperature log measurements indicate that heat from an intersecting steam chamber can cause a counter-intuitive segregation of steam and water in the wellbore, with condensed liquid water held above steam in the upper section of the well. This case study highlights strategies for interpreting downhole temperature anomalies using temperature logs and 4D seismic, and also the benefits of a well integrity investigation with strong cross-discipline collaboration.
Numerical Assessment of the Maximum Operating Pressure for Anisotropic Caprock in SAGD Projects
Authors: Rahmati Ehsan , Nouri Alireza , Fattahpour Vahidoddin , Trivedi Japan 
Published: May 2015

Abstract
This paper investigates the effect of anisotropic behavior of caprock shales on the caprock failure pressure in SAGD projects. Shales and mudstones exhibit strong anisotropy at the micro and macro scales. However, the anisotropic behavior has been neglected in the existing published works on this subject.
In this research project, a coupled hydro-thermo-mechanical model was developed for the assessment of caprock integrity in thermal operations. A transversely isotropic constitutive model in the elastic range was combined with an anisotropic failure criterion to capture the intrinsic anisotropy of the cap shale. The coupled tool was validated against field data and employed in a study to determine the effect of shale anisotropic behavior on the pressure associated with caprock breach.
Results display the effect of shale anisotropy on caprock response in terms of deformations, stresses and failure pressure. The assumption of isotropic shale behavior in caprock integrity assessment for a case study resulted in the overestimation of the failure pressure by about 10%.
Existing numerical models for evaluating the integrity of caprocks during thermal operations employ isotropic constitutive laws. These models are believed to be deficient in capturing strongly anisotropic response of shales and mudstones. The research described in this paper incorporated elasto-plastic shale anisotropy in the caprock failure analysis model for the first time. The paper demonstrates the importance of capturing shale anisotropy in the accurate prediction of caprock breach pressure in SAGD projects.
Ecosystem services and energy crops – spatial differentiation of risks
Authors: Bastian Olaf , Lupp Gerd , Syrbe Ralf-Uwe , Steinhäußer Reimund 
Published: May 2015

AbstractThe increased cultivation of energy crops has a variety of economic, social and environmental effects, which can be assessed using the concept of ecosystem services (ES). Among the various instruments for regulating energy crop cultivation, reducing the impacts on ecosystems and landscapes, and moving sustainable land management forward, the ES concept is a useful tool since it includes economic, ecological and social aspects. The methodological approach is exemplified by a case study in the district of Gorlitz, Germany. It started with an indicator-based analysis of the present state of landscape functions or services, focusing on the “supply” part of ES assessments. The results were interpreted in light of an ecological risk assessment concerning intensified agriculture in general and the increased cultivation of energy crops in particular: on the one hand for the present situation, and on the other, for three different future scenarios. It was possible to project the results onto reference units (biophysical units), and to reveal spatial differences in carrying capacity or sensibility as a result of increased energy crop cultivation. The demand side of ESs was assessed on the basis of semi-structured interviews and standardized questionnaires.