bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Phase Behavior of Heavy Oil and Propane Mixtures
Authors: Mancilla-Polanco A. , Schoeggl F. F. , Johnston K. , Richardson W. D. , Yarranton H. W. , Taylor S. D. 
Published: February 2017

Abstract
The phase behavior of heavy oil and propane mixtures was mapped from temperatures ranging from 20 and 180°C and pressures up to 10 MPa. Both vapour-liquid (VL) and liquid-liquid (LL) regions were observed. Saturation pressures (VL boundary) were collected in a Jefri 100 cm3 PVT cell and blind cell apparatus. The propane content at which a propane-rich light phase and a heavy pitch phase formed (LL boundary) were visually determined with a high pressure microscope while titrating propane into the bitumen. High pressure and high temperature yield data were measured using a blind cell apparatus. Here, yield is defined as the mass of the indicated component(s) in the heavy pitch phase divided by the mass of bitumen in the feed. A procedure was developed and used to measure pitch-rich and propane-rich phase compositions in a PVT cell.
Pressure-temperature and pressure-composition phase diagrams were constructed from the saturation pressure and heavy pitch phase onset data. High pressure micrographs demonstrated that, at lower temperatures and propane contents, the heavy pitch phase appeared as glassy particles while at higher yields and temperatures it appeared as liquid phase. Propane-free pitch yields as high as 70 wt% of the bitumen were observed. The propane contents of the pitch phase at 50°C and 2 MPa, 50°C and 5 MPa, and 130°C and 10 MPa (all for a feed of 50 wt% propane) were 22 ±0.4 wt%, 26 ±0.4 wt% and 2 ±1 wt%, respectively.
The ability of a cubic equation of state to model the data was explored. The model with temperature dependent binary interaction parameters (BIP) matched the saturation pressures and the LL boundaries at one pressure. However, the model could not match the effect of pressure on the LL boundary. The model also underpredicted yields at high dilution and could not match the LL phase compositions.
Successful 1st Eocene Carbonate Reservoir Steamflood Pilot Mitigates Key Technical Uncertainties for Full Field Development of Wafra Field, PZ Kingdom of Saudi Arabia & Kuwait: Part 2 Simulation Model Validation
Authors: Kumar Raushan , Brown Joel , Lolley Chris , Barge David , Bartlema Ruurd 
Published: February 2017

Abstract
This paper describes the key learnings from detailed data analysis and the application of a probabilistic workflow to achieve a validated dynamic simulation model of the large scale pilot (LSP) that was successfully completed in the 1st Eocene reservoir in the Wafra field, PZ. The development of the validated dynamic simulation model was a key success measure identified for the pilot to assist in the broader Wafra full field steamflood development decision making process.
The pilot consisted of sixteen 2.5 acre inverted 5 spot patterns (16 injectors and 25 producers) with associated steamflood and production facilities. In the execution of this work, detailed analysis of production, pressure, temperature, oil viscosity and geochemical data was conducted to develop key insights into the pilot behavior.
A 1st Eocene LSP steamflood model was successfully validated with production and injection data through the primary and steamflood periods. The validation method took into account uncertainties in static and dynamic properties. A probabilistic methodology using design of experiments on uncertainty parameters, combined with error-filters on multiple responses of rates, pressure and temperature was used in the study. The confidence in the final validated model was high with excellent agreement achieved between pilot and model data. The validated model also captured regional behaviors observed in the production data analysis. The validated model captured both pre-steam and post-steam behavior in the pilot. The successful execution of this work has resulted in an estimate of carbonate steamflood recovery possible in the 1st Eocene reservoir in Wafra.
Successful 1st Eocene Carbonate Reservoir Steamflood Pilot Mitigates Key Technical Uncertainties for Full Field Development of Wafra Field, PZ Kingdom of Saudi Arabia & Kuwait: Part 1 Steamflood Results
Authors: Brown Joel , Lwin Al , Barge David , Al-Mutairi Ghanim , Al-Gamdi Saleh , Kumar Raushan , Littlefield Brian 
Published: February 2017

Abstract
A large-scale steamflood pilot test has been successfully completed in the 1st Eocene reservoir. The 1st Eocene is a multi-billion-barrel heavy oil carbonate reservoir in the Wafra field, located in the Partitioned Zone (PZ) between the Kingdom of Saudi Arabia and Kuwait. The pilot was the first multi-pattern steamflood in a carbonate reservoir in the Middle East.
The pilot consisted of sixteen 2.5-acre inverted 5-spot patterns with associated steamflood and production facilities. The primary objective of the pilot was to identify and mitigate technical and economic risks and uncertainties in carbonate steamflooding to assist in the broader Wafra Steamflood full-field development decisions. In the execution of the pilot, performance measures were developed to assess steamflood success in a carbonate reservoir. These success measures included key metrics that were prerequisites for the full field steamflood development of the field. In September 2013, the pilot reached a key milestone and success measure when steam zone development was assessed in the pilot area. Another key success measure was the successful validation of pilot results using thermal reservoir simulation.
The 1st Eocene reservoir in Wafra field, PZ is a challenging asset, with the potential for large reserve additions, in which steamflood technology and learnings from conventional steamflood fields are being leveraged. In this paper, we will share the steamflood results achieved in the pilot with focus on the accomplishment measures set for the project and the progress made in identifying and mitigating key uncertainties in carbonate steamflooding.
Applying Ball-Activated Completion Technology to SAGD Tubing Deployed Outflow Control Devices to Eliminate Well Intervention
Authors: Webb P. D. , Gauthier J. , Skeates C. 
Published: February 2017

Abstract
Outflow Control Devices (OCDs) are commonly used in SAGD horizontal injection wells to enhance steam distribution in the well and facilitate uniform heating of the reservoir. Multiple devices are positioned in the tubing string across the horizontal portion of the well to create the desired steam distribution. Most OCD designs incorporate a sliding sleeve which is run in the closed position to allow steam to be circulated through the well. Circulation continues until sufficient injectivity can be achieved, allowing for bullhead steam injection. Post circulation, the sliding sleeves require coiled-tubing intervention to shift the sleeves open, activating the OCD. The subject method applies existing technology from horizontal multistage ball-activated completions to tubing deployed SAGD OCDs to eliminate the requirements for the initial coiled-tubing well intervention.
The ball-activated OCDs are activated by pumping degradable balls from surface to land in the OCD. Once landed, the tubing is pressured up to the predetermined shifting pressure, the sliding sleeve shifts open, and the ball disengages from the seat and continues to the end of the tubing string. This process is repeated with progressively larger balls for all the installed OCDs.
Product qualification has been completed to ensure SAGD service requirements are achieved. This includes ball degradation tests in boiler feed water, flow loop ball shift testing at ambient and elevated temperature, and mechanical tool shifting tests. The results of this testing are shared.
Through the elimination of the coiled-tubing intervention, significant operational efficiencies and cost savings are anticipated. In addition, the expected efficiency gain will minimize well down-time, resulting in less reservoir cooling and impact to production.
Effects of Concentration-Dependent Diffusion on Mass Transfer and Frontal Instability in Solvent-Based Processes
Authors: Yuan Qingwang , Zhou Xiang , Zeng Fanhua , Knorr Kelvin D. , Imran Muhammad 
Published: February 2017

Abstract
Mass transfer plays a key role in affecting the efficiency of solvent-based processes in enhanced oil recovery. The mass transfer is usually very slow because of the pure molecular diffusion. However, it can be greatly enhanced by frontal instability when solvent is injected to displace oil. Under unfavorable mobility contrast, the interface between two fluids may become very convoluted as displacements continue. This therefore increases the contact area and leads to more efficient mixing. It is necessary to accurately simulate the detailed frontal instability and its propagation with time in order to investigate its effect on the mass transfer.
Most of previous numerical simulations assumed a constant diffusion coefficient (CDC) in solvent-based processes. However, experimental studies on the mixing between two miscible fluids indicated that the diffusion coefficients actually vary with concentration or viscosity. Moreover, some numerical simulations with commercial simulators also showed that using the CDC may result in very high and unrealistic values when matching the oil production rate.
In present study, a concentration-dependent diffusion coefficient (CDDC) is considered in which the diffusion coefficient is exponentially proportional to concentration. Highly accurate nonlinear numerical simulations are conducted to simulate the frontal instability under unfavorable mobility ratio between solvent and oil. The effect of injection rate and mobility contrast on frontal instability and mass transfer is examined, and the breakthrough time for the CDDC case is discussed. For better comparisons, the CDC case is presented to more clearly show the effects of CDDC.
Comparative Study of SAGD and Solvent and Water Assisted Electrical Heating: Effect of Shale Layers
Authors: Ma Mingxu , Rabiei Faradonbeh Moosa , Hassanzadeh Hassan , Harding Thomas G. , Zanon Stefan 
Published: February 2017

Abstract
Bitumen recovery using solvent and water assisted electrical heating has shown promise to be more efficient than the current thermal recovery method of steam assisted gravity drainage (SAGD). Solvent and water assisted downhole electrical heating has potential to eliminate large steam generation plant and water treatment facilities and greatly reduce the capital and operating costs during oil sands development. It is demonstrated that in this process, a hot vapor chamber analogous to that created in SAGD is formed using downhole heaters and injection of a moderate volume of water and liquid solvent as working fluids.
In this work, a kinetic model was integrated into reservoir simulation model to describe aquathermolysis and thermal cracking of bitumen at reservoir conditions. The solubility of gases in both oil and water were included in the simulation. Solvent and water assisted electrical heating was then modeled for oil sand reservoirs with shale layers and the performance was compared with SAGD process. Various distributions of shale layers were introduced through experimental design using different lengths and distances to injector.
Results indicated that production rates by SAGD were greatly affected by shale layers. Production rates were reduced when the steam chamber reached a low-permeability shale layer, especially if the shale layer was wide and close to the injector. However, production rates by solvent and water assisted electrical heating were quite steady even if a vapor chamber met a shale layer. This process led to a box-shaped vapor chamber which was able to grow horizontally and bypass shale layers quickly. In addition, it was found that production rates by SAGD were high in the early stage but declined over time whereas production rates by solvent and water assisted electrical heating were steady and did not change much over the life of the process.
Numerical Prediction of H2S Production in SAGD: Compositional Thermal-Reactive Reservoir Simulations
Authors: Ayache Simon V. , Preux Christophe , Younes Nizar , Michel Pauline , Lamoureux-Var Violaine 
Published: February 2017

Abstract
Nowadays EOR methods such as thermal techniques are widely used to recover the viscous hydrocarbons from heavy oils and bitumen reservoirs. One of the thermal methods is the Steam-Assisted Gravity Drainage (also called SAGD), which consists in injecting steam into the reservoir to melt the viscous oil and allow its mobility. The melted oil falls by gravity to the production well. The injected hot steam, once it reaches the heavy oils/bitumen, induces chemical reactions called aquathermolysis. These reactions generate gases such as hydrogen sulfide (H2S) or carbon dioxide (CO2). The H2S is known to be highly toxic and corrosive. Hence it needs to be given a particular attention when it is produced at the surface. Reservoir models have been built to simulate thermal effects during a SAGD process but only few publications in the literature deal with the aquathermolysis reactions occurring in reservoirs where steam is injected.
This paper focuses on building a reservoir simulation model to forecast the H2S production. The example of the Hangingstone heavy oil field in Canada has been chosen. This simulation model is based on a compositional PVT description for heavy oil/bitumen and on a recently developed sulfur-based compositional kinetic model to describe the aquathermolysis reactions. The description of the heaviest components found in heavy oils/bitumen is made through a SARA decomposition.
The reactive model that describes the aquathermolysis reactions is firstly presented. Then a section of this paper is dedicated to the building of a PVT model for heavy oil. Another chapter presents the 2D heterogeneous reservoir models used for the simulations. Finally the simulations results are presented. A sensitivity analysis has been performed to investigate the effect of the rock conductivity and the pressure/temperature of the injected steam on the H2S production. The different simulations have given consistent results with production data in terms of H2S production at surface. This shows that both the fluid description and the aquathermolysis kinetic model used in the study are relevant for the prediction of H2S production in the context of steam injection.
Measurements of Permeability Change in Inter-Bedded Shale at Elevated Temperatures
Authors: Oldakowski K. , Sawatzky R. P. 
Published: February 2017

Abstract
The geomechanical response of a reservoir to the Steam Assisted Gravity Drainage (SAGD) process involves changes in stress, deformation (strain), and permeability. For example, in many SAGD operations the steam injection pressure is greater than the initial reservoir pressure. As the local pore pressure is elevated by steam injection the effective stress in the reservoir is reduced. This may bring local shear failure and dilation of the reservoir material if the change in effective stress is large enough, particularly where the initial stress environment is anisotropic. In turn, dilation can result in substantial permeability enhancement. A better understanding of the interdependence between stress, deformation and permeability could help in improving the design of SAGD operations to take advantage of the effects of dilation, particularly on vertical permeability barriers such as zones of inter-bedded shale (IBS).
This paper presents the results of experiments investigating changes in the permeability of IBS samples under pressure and temperature conditions similar to those that exist during SAGD operations. The IBS samples used in the tests were cut from cores that had been obtained from a relatively shallow depth (∼ 160 m) at the Dover site in the Athabasca region. The samples consisted predominantly of quartz (∼ 70%), with a clay content of just over 20%. Experiments were performed at both ambient temperature (∼ 22°C) and elevated temperature (∼ 200°C). Elastic properties (Young's modulus, Poisson's ratio) and shear strength parameters (cohesive strength, friction angle) for the IBS samples were also measured at both ambient temperature and elevated temperature.
The experiments were performed in a triaxial cell, under conditions in which the pore pressure and the axial and confining (radial) stress were controlled. The measured increases in permeability caused by a reduction in effective stress were significant at low effective stress. At ambient temperature, the permeability increased by as much as a factor of 15,000 to a level in the range of 1-5 millidarcies (md). At elevated temperature, the permeability increase was even larger, by another order of magnitude, to a level in the range of 10-50 md. The triaxial compression tests indicated that the elastic properties and shear strength of the IBS samples were also sensitive to temperature. The samples became much stiffer (higher Young's modulus) and stronger at elevated temperature.
The study presented here was focused on measurements of permeability change under conditions representative of SAGD in IBS samples obtained from one site, a relatively shallow one. Further tests should be undertaken to investigate permeability change in IBS samples that originate from different sites and different depths, to search for broader trends in the permeability behaviour of IBS under SAGD conditions.
A Practical Approach to the Use and Design of Flow Control Devices in SAGD
Authors: Lastiwka Marty , Bailey Chris , James Bruce , Zhu Da 
Published: February 2017

Abstract
Over the past few years, an increasing number of operators in steam assisted gravity drainage (SAGD) in situ recovery of bitumen in the Alberta Oil Sands are becoming interested in the use of flow control devices (FCDs). Initial field trials by some operators of these devices have shown promise in improving steam chamber conformance, reducing incidences of steam breakthrough, high vapour production, and in addressing liner reliability concerns related to steam jetting.
While the application of FCDs is well-established in the conventional oil and gas industry to control gas and water coning, there are still a number of questions on how to implement FCDs optimally in SAGD. One major difference in the application of FCDs in SAGD compared to the conventional oil and gas industry is the high temperature environment with steam and elevated erosion risk.
The purpose of this paper is to present some practical considerations for the selection of FCDs and optimal completion FCD design for SAGD applications. In the first section, a discussion is presented on how to compare the performance of different flow control devices. Most devices have not been tested for SAGD, and there is a need for more comprehensive testing. The focus of the second section is on practical considerations for the installation of FCDs in a SAGD injection and production wells.
Downhole Remote Monitoring System for SAGD Observation Wells through Fiber Optic DTS
Authors: Zaini Faiz , Keough Daniel 
Published: February 2017

Abstract
As steam-assisted gravity drainage (SAGD) producers continue to look for methods for enhancing oil recovery, understanding the dynamics at play in the evolution of the steam chambers becomes critical. Steam thief zones introduce operational risks affecting the economic recovery of the bitumen. Sensitive reservoirs need careful monitoring to avoid compromising cap rock integrity and to detect steam breakthrough.
A need exists for real-time, spatially sensitive temperature monitoring in production, injection, and observation wells. Although such monitoring has been used in production and injection wells for decades, operators of SAGD observation wells (with typical two to six per pad) mostly used either piezometers for single-point pressure and temperature measurements and/or multiple-point thermocouple bundles. Distributed temperature sensing (DTS) application in these remote environments has been limited by availability of infrastructure with temperature-controlled environment and power supply in close proximity to the wellhead, which most DTS interrogation equipment requires.
In this paper we introduce and demonstrate the installation of a new stand-alone, low-power DTS solution to address the specific needs of remote observation wells within a northern Alberta SAGD field. An acquisition system with extended working temperature range and small geometry form is installed within enclosures equipped with temperature-control devices and zonal certification. Downhole temperature data is transmitted continuously over a cellular network to a secure server with data-trending software for ease of viewing.
The system was installed in February 2015 and the downhole temperature data accessible through web browser download during the field trial period.
Impact, Mitigation and Optimization Strategies When Low Oil Prices Alter Long Term SAGD Project Implementation
Authors: Nourozieh Hossein , Ranjbar Ehsan , Kumar Anjani , Card Colin C. 
Published: February 2017

Abstract
Steam assisted gravity drainage (SAGD), as a commercially proven high ultimate recovery process for heavy oil and bitumen, is energy intensive and the process is estimated to be economic when oil prices are above certain level. Under conditions were oil price is below the economic threshold of the project, steam injection can be reduced and or completely stopped for a period of time; and can resume thereafter when conditions change. Although the process performance and efficiency may get impaired compared to the continuous steam injection case, it is still essential to evaluate and optimize the operating strategy after steam injection is re-initiated.
This study, thus, aims at providing insights about impact of steam injection interruptions on SAGD project performance. Optimization strategy of SAGD process in cases, where steam injection is interrupted, is also discussed. Field scale simulation of the process has been conducted with actual reservoir models of different geological formations to investigate the optimum operating strategy. An economic model is employed to evaluate the impact of operating strategy on the net present value (NPV) of the project. The parameters such as initial steam injection period, shut-in period, steam injection rate during the re-initiation period etc. are optimized for Athabasca type oil sand reservoirs.
The results indicate that there are several key mechanisms in the life cycle of a SAGD process that must be considered in the simulation model to reflect the field scale behavior and obtain the optimum operating strategy; otherwise, due to the mechanistic simplicity of the models, the results might be at best semi-quantitative and directional. Among all the mechanisms, the impact of temperature on the basic petrophysical properties of reservoir rocks, such as relative permeability, has been found to play an important role in the oil recovery and significantly affects the optimization results. Despite the complex behavior of the SAGD process, when the process is interrupted, there would be an optimum shut-in period in which the oil recovery can be maximized. The optimum length of interruption depends on the initial period of steam injection.