bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effects of Rock Mechanical Properties and Deformational Behavior on Caprock Integrity in Thermal Operations
Authors: Li Qiuguo , Rivero Jose 
Published: February 2018

Abstract
As a critical input in determining the maximum steam injection pressure, caprock integrity assessment in thermal operations has become increasingly important because of the potential severe consequences of a caprock integrity breach on the environment, safety and project economics. Because of the complex thermo-poro-mechanical coupling of the thermal stimulation process, numerical simulation is required in evaluating caprock integrity.
Thermal stimulation of heavy oil reservoirs significantly alters the pore pressure and in-situ stresses not only in the reservoir, but also in the caprock. Rock mechanical properties also change with temperature, pore pressure, stresses and rock deformation. Accurate characterization of reservoir and caprock mechanical properties and constitutive behavior is critically important in caprock integrity analysis. Through geomechanical and fluid flow coupled simulation of a steam-assisted gravity drainage (SAGD) case using commercially available reservoir simulator and finite element geomechanical simulator, this paper discusses the physical processes that occur in thermal operations, including stress and strain change, rock volume change, and rock failure, in both the reservoir and the caprock. The effects of rock elastic and strength properties, constitutive model, coefficient of thermal expansion, thermally induced pore pressure, and steam injection pressure on reservoir deformation and caprock integrity will be explained through simulation cases.
Lessons Learned from Extending Run Life for Hundreds of ESPs in a Heavy Oil Environment
Authors: Mogollon M. , Arguelles A. , Rodriguez A. , Anaya O. , Miranda S. , Velasquez E. , Villalobos J. 
Published: February 2018

Abstract
Electric submersible pump (ESP) applications with heavy oil pose substantial technical challenges: decreased pump head capacity, increased power requirements, and poor cooling capacity. This paper shares experiences, lessons learned, equipment standardization exercises, and improvements performed in a field with heavy oil (13º API to 15ºAPI) to extend mean time between failures (MTBF) in more than 3,000 days in a high ESP population with an average of 500 wells. To achieve production goals and extend ESP run life, the project tracks five elements of the ESP life cycle: design, optimization, failure analysis, monitoring, and equipment standardization.
As the field evolved, ESPs faced the challenges such as: increased production with increasing water cuts to higher flow rates in horizontal completions with high dogleg severity. Chronological performance of pump mean time between failure is shown before and after improvements. The ESP lifecycle is used as the basis to analyze several factors that caused either total system failure or inability to meet production expectations. This paper explains the implications of each factor and how they affect ESP components, through case studies of representative or repetitive failures and examples of how they were remediating without incurring the expense of oversizing the ESP equipment or completion.
This paper shares lessons learned in a five-year, dynamic heavy oil project and includes practical tools to improve ESP run life and optimize well production, which are applicable across the industry and around the world.
On Temperature Fall-Off Interpretation in Circulation Phase of Steam-Assisted Gravity Drainage Process
Authors: Irani Mazda , Ghannadi Sahar 
Published: February 2018

Abstract
Steam-assisted gravity drainage (SAGD) is the method of choice to extract bitumen from Athabasca oil sand reservoirs in Western Canada. Bitumen at reservoir condition is immobile due to high viscosity and its saturation is typically large that limits the injectivity of a steam at in-situ condition. In a current industry practice, steam is circulated within injection and production wells. In theory wells, should be converted to SAGD production mode once bitumen at interval is mobile and communication is established between the injector and the producer. Operators try to use temperature fall-off data to predict successful conversion time. Although the bitumen heating sounds simple approach recently three wells fails after steam injection due to steam break-through or sand production. And they are periodically returned to circulation to ramp up production rates and heal the hot spots. Most such failures are associated with early conversion to full SAGD. This paper presents a method to describe physics based initial steam injection timing and describes different Suncor assets viscosity variation with temperature and a proper interval temperature for initiation of steam injection in SAGD process. In this study an analytical tool is developed using time-of-flight (ToF) concept to match the temperature fall-off data. The tool is used to discuss successful and failed cases in Suncor McKay River asset.
Dimethylether-A Promising Solvent for ES-SAGD
Authors: Haddadnia Ali , Zirrahi Mohsen , Hassanzadeh Hassan , Abedi Jalal 
Published: February 2018

Abstract
Co-injection of solvent with steam is one of the promising methods to recover bitumen. The major operational cost for these projects is related to steam generation, water treatment and solvent. Propane and butane have shown desirable performance as solvent. In this work, we introduce dimethyether (DME) as an alternative solvent because of its lower cost compared to propane and butane.
We evaluate the capability of DME as a solvent for bitumen recovery processes. To investigate the performance of solvents, a series of experiments were conducted using a 2D sand-pack saturated with Athabasca bitumen. In these experiments, co-injection of steam with DME was compared with steam and steam/butane injections. The steam injection was conducted at 1 MPa and solvent concentration of 5 vol.% was tested in solvent/steam co-injection experiments. The cumulative bitumen production and bitumen production rate for each scenario were measured and compared with SAGD.
Experimental results revealed that using butane and DME as the additives to steam will improve the bitumen recovery. DME showed a performance close to butane. Since the cost of DME is lower than butane, it can be expected that production cost with DME injection is lower than butane. Considering that vapour pressure and density of DME are close to LPG products, its handling and transportation is as easy as LPG. Moreover, availability of DME is another advantage compared to butane. DME can be produced from natural gas or from renewable sources such as waste, wood, and agricultural products using well-established processes. A mobile production unit can be used to convert the produced solution gas to DME, which can reduce the methane emission and the costs of solvent injection.
Factors Affecting Electromagnetic Wave Penetration in Heavy Oil Reservoirs
Authors: Morte M. , Bloom E. , Huff G. , Dean J. , Hascakir B. 
Published: February 2018

Abstract
Electromagnetic waves as a viable means of introducing heat energy to reservoirs to allow for transmission of heavy or extra-heavy oil have been gaining prominence and notoriety in recent years due to its applicability to a wide variety of reservoirs. However, how reservoir properties affect the electromagnetic wave penetration is not well defined. This study investigates the impact of different reservoir rock and fluid combinations on the electromagnetic wave penetration and also introduces the dependency of dielectric properties on pressure. Several different reservoir rock samples (quartz rich, carbonate rich) with varying lithology and porosity were used in this study. The contribution of the fluid type was investigated by saturating the cores with water as well as measuring the responses on dry cores as a control. Air and water saturated rock samples were irradiated electromagnetically at varying frequencies (200 MHz to 6 GHz) under pressure. Frequency dependent dielectric properties were measured for each sample utilizing a coaxial dielectric probe and a vector network analyzer. Dielectric constant (ε′), loss index (ε″), and loss tangent of test mediums were utilized to generate the penetration depth of each sample as a function of frequency. The loss index and dielectric constant comprise the complex permittivity which is the foundation for microwave absorbance and penetration depth. Penetration depth is highly frequency dependent and exhibits an exponential decay where as the wave travels further into the sample more energy is gradually absorbed by the material and thus the energy content of the wave continually diminishes. With lower frequencies, higher penetration depth was obtained for all samples where less energy has been dissipated and absorbed by the formation. The utilization of both water and air represent both a very effective absorber of microwaves as well as a material transparent to microwaves respectively. Therefore, the dry cores (air saturated) realized greater penetration depths as less attenuation occurred due to the transparent nature of the saturating fluid. The quartz rich sandstone achieved lower penetration depths than the limestone core utilized which is indicative of greater capability of the sandstone samples to absorb microwave energy. Reservoir properties will affect the dielectric response of the material and so it becomes necessary to account for the presence of pressure due to overburden while taking laboratory measurements. The pressurized samples for both the sandstones were found to cause disparity between the control experiments when saturated with water. Introducing pressure of the water saturated sandstone samples effectively lowers the loss tangent resulting in a decreased capability to absorb microwave energy.
Three Approaches to Predicting ESP Pump Failures During SAGD Operations
Authors: Fedenczuk Leon , Graham John , Pehlke Trent 
Published: February 2018

Abstract
This paper presents a novel approach to a time scale discretization when predicting ESP pump failures at different scales. This study proves that models can be used to formalize failure predictions, prevention, and lead to optimizing the ESP's replacement and/or maintenance. The target parameters reflected two different time scale ranges. In the first approach ‘Time to Failure’ and its corresponding ‘Active Time to Failure’ were predicted. The second case excluded time periods when a well was off-line for other reasons than failure. These two targets (modeling parameters) represented low frequency events and were developed using geological or/and well geometry parameters. The Total Time to Failure model (Production Period model) based on a combined trajectory and geology data set showed acceptable and stable performance. A corresponding model with wellhead parameters summarized across each production period was introduced to complement the large scale analysis.
A second group of models of higher resolution was designed to detect failures in real time. In these cases estimations for the probability of a failure at a specific time using the most recent wellhead data while excluding well's non-active time periods related to workovers and other non-productive time periods.
These models used pre-processed wellhead data from a few selected wells and pads. Well data required pooling large amounts of data and developing a parameter summarization in time periods based on uninterrupted Motor Current Time Periods. These discrete time periods represented events with or without a failure depending on a reason for the current value to be zero. The probability of a pump failure was estimated using two approaches. In the first approach only the last two ‘periods’ that corresponded to non-failure and failure periods respectively were used. The second approach involved all non-failure periods leading to each corresponding failure period. The first approach overestimated the failures while the second approach overestimated the non-failure events.
Initial probability models predicted events with a relatively high success rate. However, more data and additional data transformations are required to verify the practicality of our approach. More refined sub-period estimates in each Current Time Periods may help in developing improved models.
Christina Lake Early Rise Rate Solvent Aided Process Pilot
Authors: Chen Sam , Seib Brent , Ben-Zvi Amos , Robinson Travis 
Published: February 2018

Abstract
Solvent Aided Process (SAP) combines benefit of using steam with solvents and has the potential to substantially improve SAGD performance with lower energy intensity and impact on the environment. Cenovus has been developing a SAP since 1996 and has conducted a few successful pilots (Senlac 2002, Christina Lake A0101 2004-2005, Christina Lake A0202 2009-2016). Cenovus has planned to implement a SAP in the Narrows Lake development when that project is sanctioned.
The general practice for SAP is to co-inject solvent with steam after the SAGD peak rate is reached as steam is most effective for the vertical growth of steam chamber. However, by injecting solvent during the rise rate phase, there could be a large facility saving by not requiring an additional solvent line to each wellhead. Rather, solvent can be added to the steam header immediately after steam leaves the steam generation plant and distributed to all wells, regardless of their vintage. To de-risk the addition of solvent at the steam header, Cenovus implemented an early rise rate phase SAP pilot at Christina Lake A0201 well pair. The objective of this field pilot was to investigate the effects of butane injection during the SAGD early rise rate phase.
This paper describes the implementation and results of the Christina Lake A0201 early rise rate SAP pilot. Presented in this paper are the results of this field test showing that no adverse effects on SAGD performance were observed when injecting solvent during the rise rate phase. This paper also shows the history match of field production data using CMG CMOST simulation.
The findings of this investigation add to the knowledge base of information related to the optimal solvent injection timing in a SAP process. Insights into performing SAP history matches are also presented based on the simulation study that was undertaken.
Phase Behaviour and Viscosity of Bitumen-CO2/Light Hydrocarbon Mixtures at Elevated Temperatures: A Cold Lake Case Study
Authors: Eghbali Sara , Dehghanpour Hassan , Dragani Jarrett , Zhang Xin 
Published: February 2018

Abstract
Co-injection of CO2 or light hydrocarbons with steam in the SAGD process may improve SAGD efficiency and lead to lower greenhouse gas emissions through reduced Steam Oil Ratios (SORs). Various additives are postulated to have differing effects on bitumen recovery, depending on the nature of the reservoir, the operating conditions, and the API gravity of the oil. A PVT study was conducted to investigate the phase behaviour of CO2-, C3-, and C4-bitumen systems at varying concentrations, representing the edge of a SAP steam chamber with the expected temperature range of 70°C to 160°C.
A produced and dewatered bitumen sample was collected from the Cenovus Osprey Pilot in the Cold Lake oil sands region and characterized. Constant Composition Expansion (CCE) experiments were conducted on solvent-bitumen systems in the temperature range of 70°C to 160°C. Filtration tests were also conducted at high temperature and reservoir pressure to investigate the effect of solvent type and concentration on asphaltene precipitation. A Peng-Robinson Equation of State (PR-EOS) model was calibrated to measured data for CO2-, C3-, and C4-bitumen systems. Viscosity of the bitumen saturated with CO2, C3, and C4 was measured with an electromagnetic-based viscometer elevated temperatures. Phase equilibrium calculations were performed using the calibrated EOS to predict the solubility of the solvents in bitumen. A correlation was fitted to the measured viscosity data to predict the liquid phase viscosity as a function of solvent solubility and temperature for each solvent.
From the CCE tests, two equilibrium phases (i.e., liquid and vapour) were observed for the C3- and CO2-bitumen systems. Three equilibrium phases were observed for the C4-bitumen system at high C4 concentrations. These three phases include a bitumen-rich heavy oil phase, a solvent-rich lighter oil phase, and a vapour phase. Due to the extracting/condensing mechanism and asphaltene precipitation, the bitumen-rich phase formed in C3-bitumen system was lighter than the one in C4-bitumen system. Filtration tests showed more asphaltene precipitation by C3 and C4 dissolution than CO2. Moreover, C3 has more potential for asphaltene precipitation than C4.
Viscosity measurements showed that dissolution of C3 and C4 in bitumen resulted in greater viscosity reduction than CO2 dissolution. This difference was more pronounced at lower temperatures. The highest C4 solubility in bitumen and C4 potential for forming a C4-rich liquid phase showed stronger condensing and extracting effect of C4 than C3 and CO2 in solvent-bitumen interactions. Moreover, C4 lead to more bitumen swelling than C3 and CO2. EOS predictions and viscosity measurements indicated that increasing the solvent concentration in a solvent-bitumen system beyond a defined Threshold Solvent Concentration (TSC) has an insignificant effect on solvent solubility and bitumen viscosity reduction.
Sand Control Testing for Steam Injection Wells
Authors: Fattahpour V. , Mahmoudi M. , Roostaei M. , Wang C. , Kotb O. , Nouri A. , Sutton C. , Fermaniuk B. 
Published: February 2018

Abstract
Injector wells in thermal field developments in Western Canada are usually completed by slotted liners. The purpose of liner installation is preventing sand production after a shut-in, keeping a stable wellbore, and providing an appropriate steam distribution. The objective of this paper is to quantify the role of slot width and slot density on the sanding performance of the liner in cycles of injection and shut-in in a SAGD injection well, through a series of laboratory sand control tests.
A large-scale sand retention testing facility was developed and employed to conduct a series of tests on slotted liner coupons with different slot widths and densities. These tests were tailored to simulate steam injection and backflow during the shut-in. Three representative particle size distributions for the McMurray Formation were used in this study ranging from coarse to fine sand. The experimental set-up allows to measure the amount of produced sand.
Since the produced sand in steam injection wells is not usually cleaned out, the acceptable threshold for sand production in the injector should be more conservative than the same for producer wells. Testing results indicate that the sand control performance of the liner is governed by the slot width and density, and formation particle size distribution. Results indicate a negligible amount of produced sand with gas backflow for a properly designed liner even at very high gas velocities.
Historically, there has been little attention to the sand control design for injector wells. This work highlights the significance of slot density and slot width in the sand control performance for steam injection wells. The paper provides the basis for the proper design of an effective sand control in SAGD injectors.
Cold Solvent Process For Heavy Oil Recovery
Authors: Sood Arun , Gupta Subodh 
Published: February 2018

Abstract
A solvent process for heavy oil recovery is described in which an infill injection well is used to inject a cold solvent into neighboring steam chambers once they merge. Simulation results are presented summarizing acceleration in oil recovery and the beneficial impact on energy consumption.
Approximately 60% of injected energy in SAGD process is retained in the reservoir. If a cold solvent is injected into a SAGD formation, it will use the stored energy to vaporize and spread within the steam chamber, while at the same time effectively cooling it. An infill injection well is drilled near the top of the rich pay zone and half way between two neighboring SAGD well pairs. Once the steam chambers merge, cold solvent is injected targeting the outer peripheries of the steam chamber. A small amount of non-condensable gas can also be added to help with pressure maintenance. Cooling of steam chamber enhances solubility of solvent in the bitumen phase and accelerates recovery. Once a secondary peak oil rate is observed due to the cold solvent, proportion of non-condensable gas to solvent in the injected fluid is steadily increased and eventually steam injection is completely ceased and the process switches to blow down phase with 100% non-condensable gas injection.
Simulation results show that injection of liquid propane and traces of non-condensable gas through the infill injection well provides pressure support and immediately reduces the amount of steam injection required through the primary SAGD injection well by 40-60%. This is followed by a steady increase in oil production rate aided by the viscosity reduction due to propane solubility. A secondary oil production rate peak, comparable to the original peak observed with steam, is achieved. A variation of this process was also simulated for mature SAGD formations, where cold propane injection is accompanied by total steam injection cessation, showing advantageous results.
Cold Solvent Process separates out injection of solvent from steam resulting in a much simpler facility design. No additional energy is used to vaporize the solvent at the wellhead. Unlike steam/solvent co-injection processes, solvent is delivered to the cold bitumen interface directly and extracts useful energy from the residual heat in the rock matrix.
Organic Alkali as a Steam Additive for Improved SAGD: Experimental Study of Emulsion Phase Behavior and Viscosity
Authors: Baek Kwang Hoon , Argüelles-Vivas Francisco J. , Okuno Ryosuke , Sheng Kai , Sharma Himanshu , Weerasooriya Upali P. 
Published: February 2018

Abstract
Water is the most dominant component in steam-based oil recovery methods, such as steam-assisted gravity drainage (SAGD). The central question that motivated this research is whether in-situ bitumen transport in SAGD can be substantially enhanced by generating oil-in-water (o/w) emulsion, in which the water-continuous phase acts as an effective bitumen carrier. As part of the initial stage of the research project, the main objective of this paper is to present the ability of organic alkali to form oil-in-water (o/w) emulsions that are substantially less viscous than the original bitumen.
Experimental studies were conducted for emulsion phase behavior and viscosity for mixtures of Athabasca bitumen, organic alkali, and NaCl brine. Experimental variables included brine salinity, alkali concentration, water-to-oil (WOR) ratio, temperature, and sample-aging time.
The phase behavior study indicated that conditions conducive to o/w emulsions are low alkali concentrations at salinities below 1,000 ppm. At a WOR of 7:3, a single phase of o/w emulsion was observed for 0.5, 1.0, 2.0 and 5.0 wt% alkali with no NaCl, and 0.5 wt% alkali at a salinity of 1,000 ppm at 373 K. At lower temperatures, 323 K and 298 K, flocculation of emulsions in these samples resulted in separation between the bitumen-rich and water-rich o/w emulsions. However, essentially all bitumen content was measured from the bitumen-rich o/w emulsion. The oil contents in these emulsions were more than 70 vol.% at 298 K and 57 vol.% at 323 K. Viscosities of these o/w emulsions ranged between 85 cp and 115 cp at 1.0 s−1, and between 31 cp and 34 cp at 10.0 s−1 at 323 K. At 298 K, they ranged between 105 cp and 250 cp at 1.0 s−1 and between 48 cp and 74 cp at 10.0 s−1. Results in this research show that, in comparison with the original bitumen, bitumen-rich o/w emulsions were 3 to 4 orders of magnitude less viscous at 298 K, and 2 orders of magnitude less viscous at 323 K.