bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Importance of PVT to the Steam Solvent Process
Authors: Fan Shuanshi , Li Sijia , Xin Hua 
Published: June 2012

Abstract
Steam based thermal processes are major technologies for bitumen and heavy oil recovery. They are energy intensive, high water demand and huge CO2 emission. When such technologies are applied to the reservoir with thief zones, the economics are even worse. In order to increase the efficiency, people are trying to add solvent into steam to reduce the operation pressure and temperature so the economics. The mechanism of adding solvent into is further reducing the viscosity of bitumen or heavy oil an addition to thermal effects. That means the solvent should be dissolved into oil as soon as they meet each other at the interface. The boiling point of the solvent should be near that of steam. When it is to far from steam, it stays either liquid being produced without reacting with oil or gas stopping the heat exchange of steam. In this paper, PVT of some pure and commercial solvents is reviewed and potential operation pressure and temperature are discussed. This can help engineers to select solvent and design the process properly.
A Quarter Century of Progress in the Application of CO2 Immiscible EOR Project in Bati Raman Heavy Oil Field in Turkey
Authors: Sahin Secaeddin , Kalfa Ulker , Celebioglu Demet , Duygu Ersan , Lahna Hakki 
Published: June 2012

Abstract
The Bati Raman field is the largest oil field in Turkey containing approximately 1.85 billion barrels of initial oil in place at an average depth of 4300 ft. The oil is heavy (12° API) with high viscosity and low solution gas. Primary recovery between 1961 and 1986 was less than 2% of OOIP.
The commercial CO2-EOR project began in 1986 and is still active. With the implementation of the CO2 flood, the recovery is expected to potentially reach up to 10% of OOIP.
The reservoir rock is naturally fractured carbonate where the heterogeneities and the unfavorable mobility ratio of CO2 and crude caused inefficient sweep. The solubility of CO2 in the oil, which is highly sensitive to reservoir operating pressure, was a significant factor for the success of the CO2 flood. Currently, the injected agent is increasingly bypassing the remaining oil and the production is curtailed by excessive high gas/oil ratio (GOR) severely jeopardizing recovery. These conditions prompted the use of applications of the conformance-improvement systems in the wells in western part of the field.
Successful applications of fracture plugging polymer gel system intended for the conformance improvement were carried out in the years of 2002 and 2004. Also, to improve the recovery by a better sweep (or displacement), a chemically augmented water injection process was proposed in the areas having relatively lower reservoir pressure. Chemicals were tested for wettability alteration and IFT reduction to select the best performing ones. After an economic analysis, a field trial of the water alternating gas (WAG) injection process with caustic was put into progress in 2010.
Optimized application cases were determined by tuning the total gas injection rates of the field, proration of the individual well rates according to the GOR, investigation of infill drilling, and alteration of the gas injection pattern, based on the results of the simulations carried out in different time frames of the project history.
The Bati Raman immiscible CO2 injection project has been acknowledged as one of the most unique and successful enhanced oil recovery (EOR) applications in the history of fractured heavy-oil carbonate reservoirs. This paper presents a comprehensive overview of this project after a quarter century of experience.
Study of Sharp Drop in Production Rates of Horizontal Wells in Unconsolidated Rock of Heavy Oil Reservoir
Authors: Ivantsov N. , Stepanov S. 
Published: June 2012

Abstract
This article describes the results of a theoretical and numerical study of the problem of a sharp drop in production rates of horizontal wells in one of Western Siberia fields represented by reservoirs consisting of poorly consolidated rock and saturated with heavy oil. The under gas cap oil rim is developed by depletion by horizontal wells. The reduction of the production rates is analyzed from different perspectives among which the most appropriate idea is elastoplastic deformation of the rock with its subsequent destruction in the bottomhole zone. Based on the analysis of the stress-strain state and theoretically justified rock ultimate strength, it is shown that actual bottomhole pressures lead to brittle fracture of the rock and, as a result of related processes, to particles movement and sharp increase in the skin factor.
The Challenges in Processing Heavy Oil
Authors: Georgie Wally , Smith Colin 
Published: June 2012

Abstract
There are numerous flow assurance and processing challenges associated with the production of heavy oil. These challenges are generally addressed in the early stage of the development and include; sizing of separators, internal design of the vessels, the process vessel configuration and the optimum means of handling solids and water. A critical aspect of the design is the accuracy and the reliability of the fluid characterization data. Numerous operators can attest to the difficulties in processing heavy oil and many make attempts to minimize the impact of these issues in the design stage. However, there are critical factors associated with produced fluid characterization data that are regularly either overlooked or misinterpreted. It is the importance of this data reliability and accurate interpretation that is the subject of this paper.
The high viscosity and low gravity of heavy oil is usually the principle concern of the design team in addressing process components and operational practices. However, there are numerous horror stories associated with flow assurance issues that should have been taken into consideration during detailed design. The impact of asphaltenes, paraffin, naphthenates, inorganic scale deposition and emulsion stability are a few of the more common challenges that can, and should, be addressed prior to detailed design. The impact of these constituents on processing and operations can make or break the economics of the development, particularly when taking into account the long-term OPEX associated with chemical treatment cost if these constituents are not adequately addressed.
In addition, brown field development of heavy oil and the subsequent processing through an existing infrastructure will create other challenges, especially if the existing production infrastructure is designed to handle mid and high API gravity crude.
By following some fairly rigorous, but necessary, guidelines on data accumulation and interpretation most if not all of these problems can adequately be addressed during detailed design and the development of operating procedures. Therefore a holistic approach in assessing the design of these facilities will be crucial to maintaining a low CAPEX and OPEX for processing heavy oil effectively. This paper aims to outline the different aspects associated with these challenges and will cover design, operation, monitoring and, where relevant, upgrades and retrofit issues.
Flow Loop for X-Ray CT Imaging of Sand Transport
Authors: London M. , Cameron S. , Pierce G. 
Published: June 2012

Abstract
Two closed circuit flow loops have been constructed for X-ray CT imaging of multiphase flows. A 3rd generation helical scanner provides 3D images with a voxel size as small as 0.35×0.35×0.30mm. By "folding" the loops, flows have been imaged over a 16m section of 3.8 cm (1-1/2") pipe. In future, larger bores could be accommodated with a shorter overall length, dictated by the aperture and weight limit of the scanner.
Sand slurry flows have been imaged in both laminar and turbulent regimes (using silicone oil and water, respectively) over a range of velocities reflective of typical in situ pressure gradients. Flowing sand concentrations up to 20% by volume were achieved by adjusting the total sand content in the loop.
With proper calibration the CT images provide detailed, quantitative measures of sand concentration and, indirectly, the partitioning between moving and settled regions of the flow. The flowing density profiles vary significantly with the sand content and flow velocity, indicative of changing sand transport mechanisms. Fluctuations over the observable length of the loop show evidence of settling overlaid on the flow-induced resuspension. The effects of the end loops on both aspects of sand transport are considered.
Implementing Lean Manufacturing Principles in New Well Construction
Authors: Charles Steven R. , Deutman Robert , Gold David K. 
Published: June 2012

Abstract
The Aera Energy LLC (Aera) Development Team has drilled and completed, each year since 2000, about 1,000 oil producers and water/steam injectors, and constructed the associated surface facilities. Such a high activity level, which involves some 800 contractors and hundreds of pieces of mobile oilfield equipment, leads to unsurpassed congestion and logistical complexity, requiring a different approach from traditional planning and execution methodologies. In 2001, Aera turned to the manufacturing industry for ideas. The company realized that drilling and constructing a well is not just a step in delivering a commodity; it is manufacturing a new well. The decision was made to implement Lean principles in the development process. Some of the Lean principles that were adopted were: moving from large batches of wells to near single-piece flow; just-in-time execution of planning and implementation activities; relentless focus on continuous improvement through mapping of work processes and eliminating the identified waste; designing and constructing oilfield equipment that is right-sized for the application needed; and creation of a very transparent system of visual tools that shows the status of key indicators at any point in time. The transition to Lean has paid off. The desired high release rate of wells has been maintained despite significant oil price volatility. The safety performance of the Aera Development Team and its contractors improved continuously and the injury frequency was reduced by a factor of 10. The drilling and completion cost (on a per-foot basis) for the most common well type was held flat in nominal terms between 1997 and 2011, while industry costs more than doubled over the same period. In 2011, Aera was the first oil company to receive the Manufacturing Excellence Award from the Association for Manufacturing Excellence. The award recognizes "demonstrated excellence in their operations" and has a primary focus "to acknowledge continuous improvement, best practices, creativity, and innovation." This paper describes the Lean journey including the culture change that was needed, the obstacles that had to be overcome, examples of Lean implementation (e.g., tools, processes, results), and the critical success factors to successfully implement Lean in new well construction.
Elimination of Surface Casing Vent Flow and Gas Migration in the Lloydminster Area
Authors: Macedo Kevin G. , Schneider Jason W. , Sylvestre Chuck J. , Masroor Qasim 
Published: June 2012

Abstract
There are many areas in the Western Canadian Sedimentary Basin that present challenges with surface casing vent flows (SCVFs). Substantial resources have been invested in understanding the causes of these SCVFs, developing remediation processes for wells impacted by SCVFs and creating products to prevent SCVFs from occurring. Despite these efforts, SCVFs remain an issue in the industry. The first priority of the energy company and service company is to operate in a safe manner with high regard for the environment. A secondary goal is to be cost efficient to maximize production. In order to satisfy these goals and priorities, working together to understand the challenges becomes critical. A clear understanding of the challenges provides an opportunity for the service company to tailor cement blend performance with the goal of eliminating the presence of SCVFs and reducing the costs associated with the remediation process.
This paper presents a case study in the Celtic field, located approximately 80 kms northeast of Lloydminster, Saskatchewan, Canada. A higher frequency of SCVFs was observed in the wells when increased bottom circulating temperatures, influenced by a nearby active steam chamber, were reported while drilling. At the elevated temperatures, cement blend modifications were made to allow for adequate placement with the new wellbore parameters. The cement blend underwent a review and optimization process with respect to the new wellbore parameters.
Findings showed that a substantial difference between the circulating and gas formation temperatures created ideal conditions for SCVFs to occur. The prolonged setting of the cement at low temperatures was believed to be the main challenge to overcome. A unique cement additive was used to accelerate the setting of the slurry at relatively low temperatures while ensuring it would still be pumpable in a high temperature environment. After incorporating the new additive into the cement blend, the operating company immediately saw an elimination of the SCVF in subsequent wells.
This paper will review the steps taken to reduce and eliminate SCVF issues in the Celtic area, some parameters and characteristics of a well that impact SCVF, and steps that can be taken in the cement blend design to mitigate SCVF issues.
Numerical Simulation Study on Gravel-Packing Layer Damage by Integration of Innovative Experimental Observations
Authors: Li Y. , Li M. , Qin G. , Wu J. , Wang W. 
Published: June 2012

Abstract
Sand control is vitally important to operation integrity in producing heavy-oil from unconsolidated reservoirs. Among various sand exclusion technologies, the open-hole gravel pack (OHGP) has been widely used in horizontal well completions. It is thus critical to quantitatively evaluate gravel packing layer damage and understand its mechanisms.
In this paper, we propose an integrated study to quantitatively evaluate gravel packing damage based on the real-world scenarios and, thus provided design criteria for gavel packing. We have designed an experimental system that can measure the core pressure at multiple points in gravel layers at high pressure condition as well as track sand migration. Preliminary results indicate that pore structure of gravel packing layer changes and the permeability decreases with sand migration and plugging. Sand volume fraction, fluid viscosity, and sand radius are the main factors that cause gravel packing layer damage.
We have developed a numerical model based on experimental observations. The numerical model considers liquid-solid fluid flow processes, sand migration and plugging in gravel layer. Numerical simulation studies are then performed on the gravel damage at different sand volume fraction, fluid viscosity, and sand radius. The simulated results are in agreement with experimental results. The numerical simulation studies on real-world scenarios are under investigation and we will report the numerical results in later reports.
Post SAGD In-Situ Combustion: Potentials and Challenges
Authors: Javad S. , Oskouei P. , Moore R. G. , Maini B. , Mehta S. A. 
Published: June 2012

Abstract
In Situ Combustion, ISC, is a process with strong potential to compliment Steam Assisted Gravity Drainage by extending the economic life of the SAGD pattern and hence improving the ultimate recovery. Implementing In-Situ Combustion, as a follow-up process to SAGD can improve recovery from the pattern by displacing residual oil from the steam chamber and more importantly by recovering oil from the wedge zones. Theoretically the temperature and residual oil saturation within the SAGD chamber are high enough to initiate and sustain the combustion process by switching from steam to air injection; however laboratory investigations of the hybrid process have shown that the in situ combustion behavior within the steam zone has some special features which must be considered.
Injection of air into the SAGD injection well is the desired option from an economic view point, however laboratory tests showed that the combustion zone tended to be more stable when air was injected at a location higher up in the chamber. This behavior relates to the fact that the combustion reactions were primarily occurring within the vapor phase, hence gravity plays a dominant role controlling the distribution of air flux within the chamber as well as the drainage of oil and water out of the combustion zone. Laboratory tests also confirmed the importance of promoting air flux across the walls of the original steamed chamber.
Experimental Study of the Mechanisms in Heavy Oil Waterflooding Using Etched Glass Micromodel
Authors: Mei S. , Bryan J. , Kantzas A. 
Published: June 2012

Abstract
In western Canada, there have been more than 300 heavy oil waterflooding projects. Most of these projects displayed good economical and efficient variability even though they were operated in marginal pools. Although waterflooding of heavy oil has almost 50 years history, its mechanisms, especially in the situation of high oil water viscosity ratio, are still not well understood. In the situation of high viscosity ratio, fractional flow theory does not work because of severe water fingering and other mechanisms that are different from conventional waterfloods. The operation strategies of heavy oil waterflooding, such as water injection rate, injection pressure and VRR, are still under controversy.
In a water-wet environment, waterflooding (water displacing oil) represents a process of water imbibition. In this paper, the water imbibition mechanisms and their effects on the heavy oil recovery are studied using a water-wet micromodel. The effects of time, viscosity ratio and water injection rate on the imbibition rate are also studied. The imbibition rate of water was found to be proportional to the reciprocal of the square root of time, and inversely related to oil viscosity. The effects of injection rate on imbibition rate are complicated. At low injection rates, waterflooding becomes more efficient, and significant volume of oil is produced discontinuously. Images of the imbibition process were recorded and analyzed from visual micromodel studies. Water broke through quickly because of water fingering, and a considerable portion of recovery comes from post-breakthrough production of oil, under high water cuts. In the cases of low rate water injection, water imbibed into the original oil region perpendicularly to the water channel. In this stage, capillary imbibition was a key factor. Water film thickening and snap-off were the two main mechanisms that made water imbibition work. Emulsification was also another important mechanism observed, with W/O emulsions primarily being formed.
Stability of In Situ Combustion Process to the Air Injection Stoppage
Authors: Turta Alex 
Published: June 2012

Abstract
Unlike steam injection for heavy oil recovery, in situ combustion (ISC) process requires an extra-step, namely initiation of the process, the so called ignition operation. During ignition, an ISC front is generated near the air injection well and, thereafter, this front is propagated towards production wells.
Air injection interruptions can be un-intentional or intentional, including one-day-per-month scheduled interruptions for cleaning oil from air lines exiting the compressors.
Regarding air injection interruptions a question arises: can the process be resumed without initiating a new ignition operation? The paper attempts to provide clear answers to this question.
The paper reviews information on more than 6 cases of air injection stoppage in the field, involving well instrumented dry ISC projects, conducted either in patterns or in a line drive system. Most of the cases are from Suplacu de Barcau (Romania) project, which is the world’s biggest ISC commercial project. The duration of air injection interruptions ranged from a few hours to 36 days. Performance before and after interruptions are analyzed in terms of changes in air injectivity, effluent gas composition and oil production.
To support various field observations, essential results from simulation of the dry ISC process are also included; Temperature distributions during air injection stoppage were determined analytically for a linear system and numerically, for a radial system. In both cases a specific characteristic of the temperature re-distribution was noted, namely the move/shift of the peak temperature inside the former burned out zone. Some additional conclusions regarding the stability of the process as function of elapsed time since the initiation of the process were also formulated. Stability of the process was investigated for air injection interruptions of up to 90 days.
Finally, a case is presented involving a pressure cycling ISC process; stability performance of the Morgan ISC project (Alberta, Canada) during its 6-year field piloting is discussed. In this project, interruptions of air injection of up to 21 months occurred. Inherent limitations in evaluating the stability performance are reviewed given the very complicated nature of this dry ISC process in which reservoir pressure was cyclically increased and oil was allowed to flow through the burned out zones during the air injection
Identification of SSC (Sulfide Stress Cracking)-Susceptible Wells and Risk Prediction
Authors: Chakrabarty Tapan , Smith Richard J. 
Published: June 2012

Abstract
Hydrogen sulfide (H2S) generated by aquathermolysis—a high-temperature reaction of condensed steam (water) with sulfur-bearing bitumen in the reservoir rock—may increase the risk of sulfide stress cracking (SSC) in cyclically steam stimulated (CSS) wells. In a given field, H2S levels and wellbore conditions vary significantly among wells and so do their SSC-susceptibility. Identifying the SSC-susceptible wells is important in terms of reducing SSC risk by allocating resources and implementing pro-active intervention measures to the SSC-susceptible wells. A comprehensive research program, with a dedicated instrumented CSS well as the centerpiece, has been undertaken by Imperial Oil Resources with the objectives of characterizing H2S evolution in the wellbore and developing a tool for identifying the SSC-susceptible wells. The research includes laboratory and field tests, and statistical, phase behaviour and kinetic modelling. The SSC-susceptible zone for Cold Lake CSS has been established from Cyclic Slow Strain Rate (CSSR) laboratory tests incorporating CSS fluid chemistry, stress-strain environments, casing metallurgy, and variable temperature and H2S partial pressure. A statistical logistic model matches the experimental CSSR data well. The instrumented well data validate the phase behavior model, which in turn explains the measured H2S profile in the wellbore. An aquathermolysis kinetic model has been developed for the instrumented well and validated with data from nine other CSS wells. The research has led to the development of an engineering tool for identifying the wells at the risk of falling into the SSC-susceptible zone.