bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Study on Geomechanical Dilation during Injection
Authors: Wang Xinkui , Chalaturnyk Rick , Huang Haibo , Leung Juliana 
Published: May 2015

Abstract
The SAGD process can be achieved only after the thermal and hydraulic communication between the injection well and the production well has been established during the start-up operation. The start-up operation involves interactions of geomechanical responses and multiple phase flow behaviors in the inter-well formation. Such interaction would have an impact on SAGD in terms of recovery performance. This paper presents an experimental study on investigating the mechanisms and mechanics of geomechanical dilation and fundamentals during cold-water injection.
A triaxial experimental program has been designed and conducted to verify geomechanical dilation through experimental measurements. A series of reconstituted water-wet/bitumen sand specimens were prepared with different fluid saturation and almost identical void ratio. Reclaimed/cleaned tailings sand from oil sands mining operations was used to prepare artificial specimens, which are representative of McMurray Formation oil sands. A water-wet or bitumen sand core plug was then tested in an environmental chamber to simulate reservoir boundary conditions in terms of stress state, temperature, and pore pressure. A series of experiments were carried out in a triaxial cell under either initial isotropic or initial anisotropic stress state. Experimental results highlight the promising potential to dramatically enhance effective permeability to water and porosity in the dilated zone with pore pressure injection at modest levels of stress anisotropy.
The lab-scale experimental data provides supports on development of numerical models for predicting SAGD start-up performance and on proactive utilization of the dilation as start-up process for in-situ oil sands development.
Geo-Mechanics of a Sugar-Cube Box: Cyclic Injection and Production in a Fractured Carbonate at the Saleski Pilot
Authors: Yang Daniel , Xu Jinze 
Published: May 2015

Abstract
Since 2012, horizontal wells at the Saleski pilot are operated with cyclic steam injection and production, recovering bitumen from the naturally fractured Grosmont carbonate reservoir. Steam has been injected in a continuous matter similar to SAGD, as well as in cyclic alteration with production from individual wells. Injection pressure is 50-60% of the overburden stress.
The Grosmont reservoir is a highly fractured carbonate rock with excellent reservoir properties (i.e. high fracture permeability and porosity). The targeted producing horizons in this reservoir are Grosmont C (20 m pay) and D (30 m pay) unit, which are separated by a laterally extensive, 1-2 m thick Marl.
The initial injectivity, which is superior to bitumen saturated sand reservoirs, can be explained by either high initial water mobility in the fractures or large system compressibility, or a combination of both.
Since the Grosmont C unit is highly fractured, it can be characterized as a box filled with sugar cubes. The ‘stiff’ cubes can locally be displaced if the fractures are allowed to drain. Geo-mechanical simulations with deterministic fractures allow the calculation of the system compressibility and Young's Modulus, based on variations of fracture and matrix properties. Results indicate that the fracture properties dominate the system characterization.
Using these insights, initial injectivity of a pilot well is matched with a reservoir model and a coupled geo-mechanical reservoir model to quantify the roles initial water mobility, matrix displacement and temperature play during cyclic operation of a naturally fractured reservoir.
Effects of Lithofacies and Reservoir Heterogeneity on Improved Oil Recovery Processes
Authors: Nguyen T. B. , Dang T. Q. , Chen Z. , Nghiem L. X. 
Published: May 2015

Abstract
A comprehensive understanding of reservoir geology plays an important role in the success of oil/gas recovery processes. Several emerging IOR (improved oil recovery) techniques have been proposed in the past decades with promising results. However, a systematic study of reservoir heterogeneity on these advanced processes has yet been presented in the literature. This paper provides one of the first comparative evaluations of the effects of reservoir heterogeneity on various IOR processes such as water flooding, CO2 flooding, Low Salinity Waterflooding (LSW) and CO2 LSWAG for a wider and more successful implementation of these projects. Since several weaknesses exist in the current simple and unrealistic models, detailed geostatistic models are employed in this study to provide a more realistic and unbiased evaluation of reservoir heterogeneity.
We first present an innovative approach that allows us to capture the critical effects of geological heterogeneity. This new approach involves the integration of geological software, a reservoir simulator and a robust optimizer in a closed-loop for generating multiple geologically driven realizations and uncertainty assessment of different recovery processes. Then a series of numerical simulations have been conducted to investigate the influences of fining- and coarsening-upward sequences on oil recovery. Finally, we evaluate the uncertainty range of reservoir heterogeneity using a large number of geological realizations with significant differences on porosity and permeability distributions. The effect of the Kv/Kh (aspect) ratio is also addressed in this study.
The simulation results indicate that the lithofacies has a dominant effect on oil recovery in all recovery processes. The coarsening-upward distribution demonstrates superior performances over the fining-upward distribution. However, it is observed that the differences on oil recovery from two stratified reservoir models are not similar in all injection methods. Although the lithofacies distribution has a slight effect on the conventional waterflooding, this effect becomes significant in CO2 flooding and more drastical in LSW and CO2 LSWAG. This observation is very important for maximizing oil recovery by taking into account the crucial effects of reservoir geology in these emerging technologies that have never been considered in the past. Additionally, the heterogeneity of lithofacies also affects the flow direction and injectivity of displacing fluids, and, consequently, influences the ultimate oil recovery factor.
Reservoir heterogeneity plays a critical role in the successes of IOR processes but it has never been comprehensively quantified, especially for some emerging techniques. Thus the results from this paper are very important to overcome the current challenges in capturing the importance of geological uncertainties in the current and future IOR/EOR projects.
On the Accuracy of Surface Movement Measurement over a SAGD Operation in Northern Alberta through Effective Survey Design
Authors: Henschel Michael D. , Sato Shinya , Lehrbass Brad , Deschamps Benjamin 
Published: May 2015

Abstract
Surface movement over a Steam Assisted Gravity Drainage (SAGD) operation can be related to production and injection. The amount and location of surface change can indicate the location of thermal dilation within the reservoir and may provide an indication of conformance. While the deformation expected in a SAGD operation is related to the depth of the reservoir and the stratigraphy, the typical ground movement is approximately 2-5 cm/year. This represents a relatively slow inflationary process over the ground. The movement may be confused with changes that are related to seasonal ground changes including water level changes in muskeg, for instance.
This work provides a description of the accuracy of Interferometric Synthetic Aperture Radar (InSAR) measurement techniques including corner reflectors and advanced point and neighbourhood algorithms designed for the measurement of ground movement in Northern Alberta. The paper will describe the application of these methods to measuring surface movement above a SAGD operation. Specifically, this article describes methods for the determination of the accuracy of ground movement estimates as derived from InSAR. An effective survey design is critical to the monitoring of ground movement. The location and availability of measurement points is crucial to the use of high resolution Synthetic Aperture Radar (SAR) satellites for monitoring. The design and implementation of a survey includes an understanding of the relationship between available infrastructure and the ground signal to be expected. However, a critical aspect of monitoring is a verification of the accuracy of the measurement provided. By using repeated observations and even a combination of satellites, we show how the measurement of accuracy can be provided on an operational basis.
This work provides a novel description of the calculation of accuracy of ground movement using emerging techniques in multiple-track / multiple-satellite observation of enhanced oil recovery operations.
Improvement of the Recovery Factor Using Nano-Metal Particles at the Late Stages of Cyclic Steam Stimulation
Authors: Farooqui Jamal , Babadagli Tayfun , Li Huazhou Andy 
Published: May 2015

Abstract
Cyclic steam stimulation (CSS) has recently re-gaining attention as an alternative to the current applications, such as SAGD or CHOPS. However, low recovery factor and excessive water production are critical problems to tackle. These late-stage experiences require a revisit to the options of recovery improvement and reduction of water production at the mid- and late-stages of the cycles. This research proposes a new approach for this purpose and investigates the effects of nano-metal particles introduced into the reservoir on the recovery factor after several cycles of steam injection. We begin with CSS experiments on heavy-oil saturated sandpacks studying and clarifying the influence of the nanoparticle presence on the efficiency of the process. It is confirmed that the use of nanoparticle in the first place increases the oil recovery factor along with a higher water production. Then, one run of experiment is performed by introducing the nanoparticle in the sixth cycle of CSS treatment. It is found that a substantial increase in the recovery factor is achieved in such a simulated CSS experiment, which cannot be achieved by injecting steam alone. This experimental study on the addition of nickel particles to improve the recovery factor and extend the life of CSS process will not only add value to nano-technology use in the oil industry from a physics point of view, but will also provide insight into the operating parameters for better late- stage CSS project development.
Thinking Beyond the Conventional - A Case Story of Using a Surface Read out Wireline Device while Ranging to Reduce Risk of Failure During Drilling of a Sagd Well in Hot Zone
Authors: Ray Jeremy 
Published: May 2015

Abstract

Objectives/Scope
In the SAGD industry, it has become more common for operators to drill into active or pre-heated oil- sands zones. These hot zones provide for a challenging environment to drill a single well, let alone use electronics for active ranging technology for accurate wellbore placement.
This paper will discuss the intent of a new head tension-compression device and the process leading from extending conventional thinking into using it as a solution for a challenging wellbore environment. Through a case story, the challenges proposed by a client in Western Canada will be examined, as will the lessons learned from the unconventional solution.

Methods, Procedures, Process
When drilling SAGD well pairs, it is common practice to have an active ranging device placed in the “target” wellbore to aid in accurate well placement. The active ranging devices are electronic in nature and are limited to temperature exposure for reliable performance. Collaborating with the operator, a secondary measurement provided by an e-line device was used in conjunction with field proven magnetic ranging equipment in order to provide real-time feedback to surface with the purpose of mitigating risks due to the high temperatures. The diagnostic device was used to monitor the effects of pumping fluid into the wellbore in order to cool sufficiently and thus protect the sensitive electronics in the active ranging device.
The case story presented in this paper will discuss the adaptation of an existing head tension- compression sub to work in conjunction with active ranging technology, providing real-time readings to surface. These real-time readings not only measure the tension and compression of the downhole toolstring but also temperature.

Results, Observations, Conclusions
To date, this system has been used in a number of operations for operators in Western Canada in active thermal zones. Operations have successfully monitored the temperature real-time for the protection of the downhole devices in addition to evaluating the cooling methods of pumping fluids from surface.
This system now enables operators to consider further e-line interventions in wellbores with high risk of exposure by providing real time diagnostic data to allow for better decision making at surface, which will reduce risk of failure. For many operators drilling in pre-heated oil-sands formations this has proven a cost effective and desired system.

Additive information
The use of this diagnostic sub is now a proven solution to place in the target well in conjunction with active ranging technology.
Optimization of CO2 Flooding Strategy to Enhance Heavy Oil Recovery
Authors: Huang Tuo , Yang Huaijun , Liao Guangzhi , Zeng Fanhua 
Published: May 2015

Abstract
CO2 flooding is one of the most promising techniques to enhance both light and heavy oil recovery. In light oil recovery, the production pressure in CO2 flooding in general keeps constant in order to maintain the miscibility of injected CO2 and crude oil; while in heavy oil recovery, a depleting pressure scheme may be able to induce foamy oil flow, thus the oil recovery could be further enhanced. In this work, different pressure control schemes were tested by 1-D core-flooding experiments to obtain an optimized one. Numerical simulations were then conducted to history match all experimental data to understand the mechanisms and characteristics of different CO2 flooding strategies.
For the core-flooding experiments, 1500mD sandstone cores, formation brine and a heavy oil sample with a viscosity of about 869.3 cp at reservoir condition (55 °C and 11 MPa) were used. Before each CO2 flooding test, early stage water-flooding was conducted until the water cut reached 90%. Different CO2 injection rates and production pressure control strategies were tested through core-flooding experiments. Experimental results indicated that a slower CO2 injection rate (2ml/min) led to a higher recovery factor from 31.1% to 36.7%, compared with a high CO2 injection rate of 7ml/min; for the effects of different production strategies, a constant production pressure at the production port yielded a recovery factor of 31.1%; while a pressure depletion with 47.2KPa/min at the production port yielded 7% more oil recovery; and the best pressure control scheme in which the production pressure keeping constant during CO2 injection period, then depleting the model pressure with the injector shut-in yielded a recovery factor of 42.5% of the initial OOIP.
Numerical simulations were conducted to history match the experimental results. The same oil relative permeability curve was used to match the experimental results to all tests. Different gas relative permeability curves were obtained when the production pressure schemes are different. A much lower gas relative permeability curve and a higher critical gas saturation was achieved in the best pressure control scheme case compared to other cases. The lower gas relative permeability curve indicates that foamy oil was formed in the pressure depletion processes. Through this study, it is suggested that the pressure control scheme can be optimized in order to maximize the CO2 injection performance for enhanced heavy oil recovery.
Enhanced Thermal Well Integrity Through The Use Of A New Cement Tensile Strength-enhancing Fiber
Authors: Iremonger Simon S. , Bolt Mitchell , Lawrence Sally C. 
Published: May 2015

Abstract
Cement plays a vital role in maintaining the long term integrity of oil and gas wells by forming a robust and impermeable barrier and ensuring zonal isolation by restricting the flow of fluids between different geological zones. In-situ thermal stimulation methods such as SAGD place the casing cement under extreme stresses due to the rapid temperature increases that occur during initial steam stimulation. The prevailing mentality in the industry for many years was that compressive strength alone was a satisfactory predicator of a cement's ability to withstand downhole stresses. However, the stresses induced in a SAGD well are often not compressive, but rather radial in nature due to the large thermal expansion of the casing during heat up, making tensile failure of the cement more prevalent. This problem is compounded by the fact that the tensile strength of conventional oil well cements is typically only 8 – 12% of the maximum compressive strength. To best mitigate the risk of cement failure, cement with a higher tensile strength is a better choice.
In this paper a new fiber based tensile strength-enhancing cement additive for thermal oil well applications, such as those used in SAGD, is described. At an optimized loading of 0.5% by weight of blend (BWOB) the fibers gave a 20% improvement in tensile strength under mild temperatures (25–50 °C) and over 35% improvement in tensile strength at 250 °C. This significant enhancement in tensile strength occurs without significant detrimental effects on other mechanical or slurry properties. The stability of the additive is demonstrated by a full mechanical property evaluation (tensile strength, compressive strength, Young's modulus) after long-term high temperature exposure (one month at 250 °C). Extensive field testing with fiber-containing blends demonstrated that the fibers could be readily dry bulk blended on a multi-tonne scale, and successfully pumped with existing conventional dustless mixing systems. The significant enhancement in tensile strength, without sacrificing any other performance parameters, is expected to substantially improve well integrity in the demanding environments encountered in SAGD.
A Parametric Study of the Hydrodynamic Roughness Produced by a Wall-Coating Layer of Oil during the Pipeline Transportation of Heavy Oil-Water Mixtures
Authors: Rushd S. , Sanders S. 
Published: May 2015

Abstract
In the water lubricated pipeline transportation of heavy oil and bitumen, a thin oil film typically coats the pipe wall, which is often referred to as ‘wall fouling'. A detailed study of the hydrodynamic effects of wall fouling is critical to the design and operation of oil/water pipelines, as the viscous layer can increase the pipeline pressure loss (and pumping power requirements) by 15 times or more.
In this study a parametric investigation of the hydrodynamic effects caused by the wall coating of viscous oil was conducted. A custom-built rectangular flow cell was used as the principal apparatus. The controlled parameters include the thickness of the wall coating layer, oil viscosity and water flow rate. For each test condition, the pressure loss across the test section was measured and the hydrodynamic effect of the wall coating on the pressure loss was determined. A novel procedure using CFD simulations was developed to determine the hydrodynamic roughness. The procedure was also applied for a set of pipeloop test results published elsewhere. The effects of wall coating thickness and water flowrate on the hydrodynamic roughness were evaluated. The most significant outcome of this analysis is a new correlation for the hydrodynamic roughness produced by a wall-coating layer of viscous oil.
The knowledge gained from the current research will be beneficial for designing, operating and troubleshooting pipeline systems in which a viscous wall coating is produced, including water lubricated bitumen transport in the oil sands industry, CHOPS and SAGD surface production/transport lines. The methodology can also be extended to the analysis of any unknown hydrodynamic roughness.
Experimental Evaluation of H2S Yields during Thermal Recovery Processes
Authors: Lin Riyi , Song Duopei , Wang Xinwei , Yang Daoyong 
Published: May 2015

Abstract
Experimental techniques have been developed to quantitatively evaluate in-situ H2S generation as a function of solution alkalinity, SO42− concentration, and carrier gas during thermal recovery processes. Experimentally, well-designed laboratory tests have been conducted to quantify the in-situ generation of H2S in a surface passivation reactor. The reaction gases were analyzed by using a gas analyzer, while the pH values were measured by using a glass electrode after adding anions or cations into the solution. Solution alkalinity is found to restrain the formation of H2S after subtracting the amount of H2S that neutralizes alkali in the solution. H2S production increases with increasing SO42− concentrations, more evidently at a high temperature. As temperature increases, using either carbon dioxide or nitrogen as carrier gas increases the H2S production; carbon dioxide as a carrier gas, however, yields more H2S up to 57.6% than nitrogen at temperature of 200-280°C. It is suggested that effect of pH of the formation water be taken into account while predicting the produced acid gas rates.
Impact of Flow Control Devices on SAGD Performance from Less Heterogeneous to Strongly Heterogeneous Reservoirs
Authors: Su Yi , Gates Ian 
Published: May 2015

Abstract
Steam Assisted Gravity Drainage (SAGD) has proven itself to be a commercial success in McMurray oil sands reservoirs. In this process, steam delivered into the reservoir mobilizes bitumen which then flows under gravity to the production well. A countercurrent flow situation results where steam rises and bitumen and condensate drains within the reservoir. Given the vertical and horizontal flow within the reservoir, SAGD performance is strongly affected by reservoir heterogeneity. In the field, poor SAGD performance commonly arises from two challenges: first, steam breakthrough from the injector to the producer and second, non-uniform chambers along the length of the well pairs. Flow control devices (FCDs) offer the potential to improve SAGD performance but it remains unclear how to place and design these devices to maximize steam conformance and minimize steam-to-oil ratio. Here, to understand the behavior of FCDs in SAGD operations, detailed reservoir simulations, including wellbore hydraulic modeling, are conducted in a simple clean sand model and a detailed point bar model dominated by inclined heterolithic strata. The study includes the use of FCDs on the injector only, the producer only, as comparisons to conventional well completions cases. The results indicate that SAGD performance improved by using FCDs with better control of steam breakthrough between the wells.