bluuebunny/crossref_metadata_2025_split huggingface dataset:
Approaches for CO2 Capture and Sequestration Inspired by Biological Systems
Authors: Ameur Z. Ouled , Gupta S. , Siegler Hector De 
Published: May 2016

Abstract
In this study, several process alternatives for the permanent sequestration of carbon dioxide (CO2) as solid carbonates are evaluated. Although the formation of mineral carbonates is thermodynamically favourable, it does not occur significantly due to kinetic limitations and the formation of products that hinder the evolution of the process. Several biological organisms, including corals, have developed different mechanisms for accelerating the process and managing undesirable products. In this report, we propose biomimicking approaches to precipitate solid carbonates while limiting the amount of energy required or using the produced by-products to generate valuable materials.
A few processes alternatives are described and evaluated in this study. In all these explored cases CO2 mineralization requires divalent cations such as Ca++ or Mg++. These could be sourced from sea water or land based silicates containing these cations. Sea-water based source results in two attractive options, namely: 1. electrochemically assisted precipitation of carbonates with production of sales of Cl2 or HCl; 2. electrochemically assisted precipitation of carbonates and production of Vinyl Chloride Monomer (VCM) and polymerization into Polyvinyl Chloride (PVC), with sales of PVC; the land based source results in further in options 3, and 4: 3. electrochemically assisted precipitation of carbonates with in-situ mining of silicates; and 4. ammonia assisted precipitation of carbonates with in-situ mining of silicates. This study explores the technical feasibility of these options further.
A Robust Automatic Well Gauging System for Heavy Oil Operations
Authors: Jones J. A. , Hammond B. R. , Keser D. 
Published: May 2016

Abstract
Gauging oil and water rates from heavy oil wells has historically been a difficult task. Heavy oil offers several unique problems that hinder that task. These include oil density close to the associated water density which hinders gravity separation, high viscosity which inhibits flow and proper instrumentation function, high sand production with bad implications for well testing facilities, and a tendency to form difficult oil/water emulsions. An automatic well test (AWT) system has been developed over time to overcome the problems associated with gauging thermal, heavy oil wells. This system selects a well from a group of wells with a valving system operating in hot/cold, high/low viscosity, sandy conditions and employs a test vessel that can handle high/low gross/net, sand, variable temperature, and gas if present. Tests with this system are not only reliable and much cheaper; they are done much more frequently.
A Study of Sealability Evaluation Criteria for Casing Connections in Thermal Wells
Authors: Xie Jueren , Matthews Cam , Hamilton Andrew 
Published: May 2016

Abstract
The severe loading conditions experienced by the casing strings in thermal wells used in Cyclic Steam Stimulation (CSS) and Steam Assisted Gravity Drainage (SAGD) operations pose a significant challenge in terms of the casing connection sealability performance and integrity. The industry has recently developed standards and protocols for assessing and qualifying connection sealing performance for such applications. The comprehensive programs include both Finite Element Analysis (FEA) evaluations and a series of full-scale physical tests. The FEA evaluations are required to determine the worst-case connection design scenarios, in terms of geometry, material properties and make-up torque, for fabrication of the specimens to be assessed in the physical tests. The scope of the FEA work includes analyzing the connection sealability performance under selected load cases representative of the intended field service conditions. A suitable minimum sealability criterion is required to assess the adequacy of the predicted connection sealing performance for the specific application.
This paper presents the results from an experimental metal-to-metal seal investigation and describes their use to establish a simplified sealability criterion for premium casing connections. The leakage response of several different seal samples was determined as a function of contact stress level for differential gas pressures of 3.3, 7.4, 12.1 and 16.5 MPa, corresponding to Application Severity Levels (ASL) of 240, 290, 325 and 350 per ISO/PAS 12835. The test results were used to characterize the relationship that existed between the leakage rates recorded in the tests and the selected control variables: differential pressure; seal length; tubular size; and seal contact stress level. The paper also demonstrates the use of the proposed sealability evaluation criterion in conjunction with the FEA results established for a 244.5 mm, 59.5 kg/m L80 premium connection subjected to thermal cycle loading.
Effect Of Geomechanics On Optimization Of Solvent Assisted SAGD SA-SAGD in Oil Sands Reservoirs
Authors: Abbasi Asl Y. , Chalaturnyk R. 
Published: May 2016

Abstract
It is generally accepted that solvent-steam injection in heavy oil/bitumen reservoirs outperforms steam only injection in terms of oil recovery rate, ultimate oil recovery and steam oil ratio. Important parameters in SA-SAGD design are solvent selection, injection strategy and solvent retention in situ. The role of geomechanics in optimum application of SA-SAGD, however, remains largely unexplored.
Recent studies suggest that solvent transport, solvent dilution effect and the temperature distribution around the edge of the steam chamber have major control over SA-SAGD performance. Solvent-steam injection significantly alters the temperature distribution around the chamber edge compared to steam only processes (SAGD). The temperature redistribution, in addition to the altered pore pressure, produces geomechanical effects such as porosity and permeability alteration, relative permeability changes and residual saturation alterations which in turn, influence solvent-steam-oil phase behavior and solvent transport and retention, among others. These chains of events affect the steam chamber growth and the solvent distribution, which affect optimum solvent selection and solvent-steam injection scenarios. These geomechanical considerations are of particular interest for bitumen deposits, both oil sands and carbonates, where chemical, thermal and fluid pressures can impose significant volume changes within the reservoir especially in shallower, lower confining stress settings.
The role of geomechanics in SA-SAGD was explored numerically using a sequentially coupled modeling approach with STARS (CMG) and FLAC (Itasca). A 2D homogenous oil sands reservoir geomodel at a shallow depth was considered for the purpose of this paper. Studies were conducted at two scales: 1) edge of steam chamber and 2) reservoir scale including underburden and overburden. The results of these numerical studies revealed geomechanics considerations directly affect the optimum solvent type selection and injection strategy during high pressure SA-SAGD processes. These studies provide valuable direction for further detailed mechanistic studies (both numerically and experimentally) and provide valuable input to the challenges of optimizing SA-SAGD processes in oil sands.
Clay-Asphaltene Interaction During Hybrid Solvent-Steam Injection Into Bitumen Reservoirs
Authors: Coelho R. , Ovalles C. , Hascakir B. 
Published: May 2016

Abstract
The goal of solvent-steam-flooding is enhancing bitumen recovery by the simultaneous development of miscibility and reduction of oil viscosity. Though this strategy reduces greenhouse gas emissions, solvents are expensive. Additionally, bitumen recovery performance is affected by oil/solvent/clay/asphaltene interactions on pore-scale. The solvent dose and type must be optimized to maximize recovery, while minimizing environmental impacts and operational costs. To investigate the performance of solvent-steam processes, six core flooding experiments were conducted on a Canadian bitumen sample with 8.8°API and 54,000 cP. Propane-steam flooding was tested and compared to steam-flooding. The effect of reservoir clays is studied by repeating experiments without clay addition. Three propane flowrates were tested to examine the impact of solvent dosages. After the experiments, asphaltene, clay, viscosity, and water content in produced oil were measured. Propane-steam flooding increased recovery factors, accelerated production, and had higher quality oil than steam-flooding. The lowest propane flowrate (1:9 vol/vol) improved oil recovery by 23%, indicating that higher solvent concentration may not be needed. This work reveals that bitumen microscopic displacement efficiency is enhanced by up to 88% with the addition of solvent to steam flooding. It is proposed that pore-scale interactions, solvent flowrate, and clays also highly influence produced oil quality and oil recovery rates.
SAGD Production Observations Using Fiber Optic Distributed Acoustic and Temperature Sensing: "SAGD DAS - Listening To Wells to Improve Understanding of Inflow"
Authors: MacPhail Warren , Kirkpatrick James , Banack Ben , Rapati Bryan , Asfouri Alex Ali 
Published: May 2016

Abstract
Performance optimization of steam assisted gravity drainage (SAGD) well pairs requires awareness of unique and sometimes complex downhole processes. Reservoir monitoring tools commonly used to characterize the downhole pressure and temperature environments include thermocouples, pressure gauges, and discrete or distributed fiber-optic sensors. Distributed temperature sensing (DTS), the most common fiber-optic measurement used for SAGD reservoir monitoring, has been widely adopted for SAGD production monitoring due to its ability to accurately measure a wide variety of temperatures in harsh environments. High-measurement density along the entire SAGD well length has proven to be useful for both production optimization (Krawchick et al. 2006) and well-integrity applications.
Though DTS monitoring is a primary downhole measurement tool for thermal production, other sensors may further characterize the nature of SAGD well performance when used in conjunction with DTS. Alone, temperature and pressure measurements may not yield a complete understanding of the inflow contribution in SAGD production wells. For instance, the effects of complex heat transfer may mask reservoir temperatures. Additionally, high temperatures are not always indicative of inflow and cooler liner temperatures may not signify the absence of production contribution. Distributed acoustic sensing (DAS), which is used to measure acoustic frequency and intensity in 1-m intervals along the length of a fiber-optic line, is another downhole measurement tool currently being evaluated for its ability to provide additional downhole wellbore information. Although DAS has been commonly used to characterize the acoustic environment in hydraulically fractured horizontal wells (MacPhail et al. 2012, Holley et al. 2015), it has not been extensively applied in SAGD well pairs. This paper shares select DAS and DTS monitoring data from a pilot well, the results of which improved the operator's understanding of the nature of the SAGD production.
In late 2012, Devon Canada installed DTS multi-mode fiber in several production wells at SAGD assets in the McMurray Oil Sands. Single-mode fiber utilized for DAS were deployed in conjunction with multi-mode fiber, allowing simultaneous logging of DTS and DAS data throughout the wellbore. Temperature and acoustic datasets were obtained at different representative flow conditions, including stable production, rate step-down, early time shut-in, and well startup. The combined analysis of DTS, DAS, and surface production data shows that DAS was able to identify steam flashing and qualitatively define production inflow contribution and gas/liquid composition. Due to the complex, bi-directional flow in the trial well, some of these conclusions would not have established without the observations obtained from DAS monitoring.
Modification of Butler's Unsteady-State SAGD Theory to Include the Vertical Growth of Steam Chamber
Authors: Keshavarz Mohsen , Harding Thomas G. , Chen Zhangxin John 
Published: May 2016

Abstract
Steam-Assisted Gravity Drainage (SAGD) is a widely used thermal recovery technique in western Canada. Use of numerical simulators, although successful in history-matching and performance prediction of the process, is extremely time consuming for field-scale optimization purposes. Therefore, analytical and semi-analytical models are desirable tools for quick field-wide performance forecast.
The first theoretical study of SAGD was conducted by Butler et al. (1981). An elegant analytical model was developed to estimate the oil production rate of a laterally spreading steam chamber, assuming a steady-state mode of thermal conduction beyond the advancing steam front. This model has been the basis for all other SAGD analytical/semi-analytical studies. The model was later modified by Butler and Stephens (1981) and Butler (1985) to overcome the shortcomings of the steady-state heat transfer assumption.
The majority of the analytical models of SAGD to date, assume that steam chamber has reached the over-burden from the start of the process and that it can only grow sideways. In real applications, however, steam chamber will rise vertically during its early stages of development. Therefore, these models are not capable of capturing the physics of the vertical growth phase adequately and their estimations of the oil production rate and steam oil ratio (SOR) may be questionable.
A uniform steam chamber development during the vertical growth is crucial to an efficient SAGD process during the rest of the project's lifetime. Therefore, it is important to have a reliable estimation of the performance of this phase. In this work, the unsteady-state SAGD model of Butler (1985) has been modified to include the vertical growth phase. Darcy's law and material balance were combined to estimate the oil production rate and steam chamber growth. Energy balance was then used to estimate SOR.
Validation of the estimations for oil production rate, steam chamber shape and SOR from this new model against the results of fine-scale numerical simulation indicates that the model has successfully captured the primary physics of the vertical growth phase. The model also predicts a more accurate in-situ distribution of thermal energy and SOR compared to the original model of Butler (1985). A closed form solution is possible for oil production rate, chamber height and SOR under some simplifying assumptions during the vertical growth phase; however, a numerical approach is required beyond this phase. The mathematics are simple enough to allow coding with simple computer programs to yield quick realistic field-scale performance predictions.
Convective SAGD Process
Authors: Sood Arun 
Published: May 2016

Abstract
In steam assisted gravity drainage (SAGD) process, accumulation of non-condensable gases at the edges of the steam chamber creates a resistance to heat transfer between hot steam and cold bitumen, thus slowing down growth of the steam chamber. Efficient removal of these gases from the steam chamber can substantially accelerate the recovery process.
Typical practice in SAGD is to use steam splitters and strive for a relatively uniform pressure in the horizontal part of the well, which allows for even distribution of injected steam into the reservoir. In convective SAGD process, a significant pressure gradient is deliberately created along the horizontal length of the injector well by tailoring the well completion design. Enhanced flow resistances can be fashioned by using finned tubes, static mixers, flow constrictions or simply using tube sections with varying diameters. A complementary placement of resistances in the producer well prevents short-circuiting of steam. Pressure gradients created in the injector well are translated on to the reservoir, thus allowing for a sweep of non-condensable gasses from the steam chamber.
In reservoir simulation studies, a novel convective SAGD process has shown significant improvement in oil production, with 20% higher peak production rates as compared to traditional SAGD while facilitating removal of non-condensable gases in excess of 90% from the steam chamber over the life of the well. Since fluids in the reservoir can now also move along the length of the wells, convective SAGD demonstrates a distinct advantage over traditional SAGD in heterogeneous reservoirs as horizontal barriers to flow can now be overcome with time.
Currently, a field pilot is being pursued at Foster Creek to test the validity of convective SAGD process.
On the Performance of SAGD in Athabasca Point Bar Deposit Reservoir With Top Water
Authors: Austin-Adigio Maureen E. , Wang J. , Gates Ian D. , Alvarez Jose M. 
Published: May 2016

Abstract
As efforts are made to exploit and recover bitumen resources in Canada, challenges presented by increasingly more complex reservoirs in the Athabasca area continue to pose a challenge to the application of the Steam-Assisted Gravity Drainage (SAGD) technology. Several studies have been done to investigate the impact of heterogeneities/complexities such as shale barriers, lean zones, top and bottom water on the performance of the SAGD process. However, the literature is deficient especially in point bar deposits with top water zones. This study examines by using thermal reservoir simulation the impact on the SAGD performance in a point bar deposit reservoir where an overlying top water and an inclined heterolitic strata (IHS) is present. The results show that where the top water is unconfined and the steam injection pressure is higher (4,000 kPa) than that of the top water zone, there is a huge loss in thermal energy but the top water does not inhibit the steam chamber development. But when compared to a relatively lower steam injection pressure (1,800 kPa), the top water continuously drains into the reservoir and reduces the size of the steam chamber. The confined top water case behaves very similar to a point bar reservoir without top water at high steam injection pressures and when compared to a relatively lower steam injection pressure, the top water does not significantly impact the SAGD performance. The IHS zone may constitute some nuisance to the steam chamber development but also helps to delay the drainage of the top water into the basal sand when steam is injected underbalance. Finally, under proper steam injection pressure condition, the top water production can be considerably delayed.
A New Foamy Oil-Assisted Methane Huff-N-Puff Method for Enhanced Heavy Oil Recovery in Thin Reservoirs
Authors: Sun Xiaofei , Dong Mingzhe , Zhang Yangyu , Li Mingzhong 
Published: May 2016

Abstract
A considerable portion of heavy oil resides in thin formations. In such reservoir environments, thermal recovery methods tend to be neither effective nor economical, due to significant heat loss and water resource requirements. The methane huff-n-puff process for enhancing heavy oil recovery in thin formations is an alternative that has the advantages of availability of resources and economic efficiency. However, the principal problem with such a process is the high mobility of the gas phase, relative to the oil phase, during the production cycle. In order to overcome this limitation, this paper presents a new enhanced methane injection technique, called the foamy oil-assisted methane huff-n-puff method (FOAM H-n-P). In this process, an oil-soluble foaming agent and methane are injected in a cyclic manner, but in two separate slugs. The methane provides the solution gas drive energy, and the presence of the foaming agent promotes the formation of an in situ foamy oil by trapping the released gas, which significantly enhances the effectiveness of the solution gas drive mechanism. A new experimental procedure was developed to prove that the selected foaming agent has an effective foaminess in conventional heavy oil, and to investigate, quantitatively, the effects of various process parameters on foamy oil stability in the FOAM H-n-P process. A series of experiments were conducted to evaluate FOAM H-n-P performance and to examine the effect of various foaming agent injection parameters on oil recovery. The experimental results show that foaming oil stability increases with greater foaming agent concentration, greater initial heavy oil height, a higher degree of gas bubble dispersiveness, and smaller dispersed gas bubble size. The FOAM H-n-P process can substantially improve heavy oil recovery performance. The most efficient case increases oil recovery by 43.29% OOIP, compared to the traditional methane huff-n-puff process. The above knowledge will have significant importance for the development of heavy oil resources in thin reservoirs.
Application of Low Salinity Micellar Emulsion In Chemical EOR of Heavy Oil
Authors: Sim Steve S. , Wassmuth Fred R. , Bai Jiang 
Published: May 2016

Abstract
In phase behavior studies of conventional oil for chemical EOR, formation of a single phase homogeneous emulsion system can be achieved only with formulations containing relatively high concentrations of synthetic surfactant. Application of the single phase micellar emulsion in chemical EOR has not been successful economically due to high cost of surfactant and surfactant loss in the reservoir. The economic picture could be much better when this technology is applied for recovery of high TAN heavy oils which can release the required amount of surfactant (petroleum soap) in-situ upon contact with the ASP solution.
This paper describes the successful formulation of an ASP system which can generate a single phase (Winsor type IV) micellar emulsion when mixed with a viscous high TAN (2.0 mg KOH/g) heavy oil. This ASP system contains commercial HPAM and NaOH in low salinity water. The micellar emulsion system, which is thermodynamically stable under very low salinity conditions, can contain as much as 33% of crude oil before transition to a Winsor type I system with a separate excess oil phase. Viscosity of the oil-in-water micellar emulsion varies with its oil content and is generally much less than 1/10 of the parent crude oil. The petroleum acid, which is a key component in the formation of the micellar emulsion, has been successfully isolated from the crude oil. Analytical results of the acid, by means of FTIR, NMR, LC-mass-spectroscopy and elemental analysis, will be presented.
The effectiveness of this ASP system in mobilization of capillary trapped heavy oil has been demonstrated with a Berea coreflood test. To ensure that adequate mobility control was present during displacement of the viscous heavy oil, separate sand-pack tests were also conducted for selection of candidate ASP solutions based on in-situ resistance factors. As a result, excellent incremental oil recovery (67% OOIP) and outstanding production rate (30% OOIP in 1 PV) were achieved during displacement of the viscous heavy oil (10,000 mPa.s) from Berea core. Residual oil saturation of the post-test core was &lt; 7% Pore Volume.
To our knowledge, application of micellar emulsion generated from natural petroleum soap in chemical EOR of heavy oil has not been investigated extensively. Results from this study can lead to better understanding and improvement of this chemical EOR technology for heavy oil.