bluuebunny/crossref_metadata_2025 huggingface dataset:
Novel Nanoparticle-Based Drilling Fluid with Improved Characteristics
Authors: Zakaria Mohammad F. , Husein Maen , Hareland Geir
Published: June 2012

The success of drilling operations is heavily dependent on the drilling fluid. Drilling fluids cool down and lubricate the drill bit, remove cuttings, prevent formation damage, suspend cuttings and also cake off the permeable formation, thus retarding the passage of fluid into the formation. Typical micro or macro sized loss circulation materials (LCM) show limited success, especially in formations dominated by micropores, due to their relatively large sizes.

In the current work, a new class of nanoparticle (NP) loss circulation materials has been developed. Two different approaches of NP formation and addition to oil-based drilling fluid have been tested. All NPs were prepared in-house either within the oil-based drilling fluid (in-situ), or within an aqueous phase (ex-situ), which was eventually blended with the drilling fluid. Under low pressure low temperature API standard test, more than 70% reduction in fluid loss was achieved in the presence of NPs compared to only 9% reduction in the presence of typical LCMs. The filter cake developed during the NP-based drilling fluid filtration was thin, which implies high potential for reducing the differential pressure sticking problem and formation damage while drilling. Moreover, at the level of NPs added, there was no material impact on drilling fluid viscosity and the fluid maintained its stability for more than 6 weeks.
Effect of Nanoparticles on Oil-Water Flow in a Confined Nanochannel: A Molecular Dynamics Study
Authors: Wu Jianyang , He Jianying , Torsæter Ole , Zhang Zhiliang
Published: June 2012

Nanotechnology has contributed to the technological advances in various industries, such as medicine, electronics, biomaterials and renewable energy production over the last decade. Recently, a renewed interest arises in the application of nanotechnology for the upstream petroleum industry; such as exploration, drilling, production and distribution. In particular, adding nanoparticles to fluids may drastically benefit enhanced oil recovery and improve well drilling, such as changing the properties of the fluid, wettability alternation of rocks, advanced drag reduction, strengthening sand consolidation, reducing the interfacial tension and increasing the mobility of the capillary-trapped oil. In this study, we focus on the fundamental understanding of the role of nanoparticles on the oil-water binary mixture in a confined nanochannel. A series of computational experiments of oil-water-nanoparticle flow behaviour in confined clay nanochannels are carried out by molecular dynamics simulations. Three sizes of nanochannels and different numbers of nanoparticles are considered. The results show that the pressure to drive the oil-water binary mixture through a periodic confined channel increases dramatically with the reduction of the channel size. In the absence of nanoparticles the pressure increases with the propelled displacement. Interestingly, an opposite behavior is observed in the oil-water system mixed with a small amount of nanoparticles: the pressure decreases with the increase of the displacement. The findings from molecular dynamics simulations may elucidate the role of nanoparticles on the transport of oil in nanoscale porous media, although the exact mechanisms remain to be further explored.
Nanotechnology to Improve Sealing Ability of Drilling Fluids for Shale with Micro-cracks During Drilling
Authors: Li Gongrang , Zhang Jinghui , Zhao Huaizhen , Hou Yegui
Published: June 2012

Shale wellbore instability is a complex difficulty encountered during drilling all over the world. And the most important factor to determine shale wellbore stability is the distribution and expansion of micro-cracks in hard brittle shale. The usual ways to avoid collapse of shale wellbore mainly include increasing the inhibition of drilling fluid filtrate, improving the quality of drilling fluid cake and sealing the pores and micro-cracks near the wellbore surface. However, the shale wellbore collapsing difficulty was not solved effectively in field, which mainly because that the effective sealing is difficult to achieved in the case of crack width is unknown. Furthermore the drilling fluid cake is more difficult to be formed on shale sections because of the filtration rate is very low compared to sand sections under the same differential pressure.

A kind of nanomaterial has been applied to achieve a sealing film rapidly, improve the sealing strength of the cake and reduce the mud cake permeability, which have been verified through the use of sound wave propagation speed, the pressure transmission experiment and cake strength. The technology had also been used in Well Exp1, which exhibited a smooth borehole and the borehole enlargement rate was below the wells in the same block.
Investigation of the Effect of Water Based Nano-Particles Addition on Hysteresis of Oil and-Water Relative Permeability Curves
Authors: Parvazdavani M.. , Masihi M.. , Ghazanfari M. H. , Sherafati M.. , Mashayekhi L..
Published: June 2012

It has been shown that one kind of poly silicon particles with sizes ranging from 10–500 nm, can be used in oilfields to enhance the oil recovery of water injection by 15–20%. The contributing mechanism might be reducing the interfacial tension which appears through improving relative permeability of the oil-phase. However, fundamental understanding of how hysteretic behavior of relative permeability curves affected by nanosilica particles remains a topic of debate in the literature. In this study, water as well as water dispersed nanosilica particles floods was performed on sandstone rock sample saturated by light crude oil supplied from one of Iranian oil reservoir, and the relative permeability curves for both oil and water/ water dispersed nanosilica particles phases were determined for two successive cycles of imbibitions/drainage processes. The results revealed that the hysteresis in relative permeability of both oil and water phases decreased as the dispersed silica nano particles were used in the tests, and the hysteretic behavior of relative permeability curves decreased as the injection proceeds into the 2nd cycle of injection. Moreover, the relative permeability of non-wetting phase changes significantly while the changes for wetting phase is not much considerable. This work illustrates for the first time the role of dispersed silica particles on hysteretic trend of two-phase oil-water relative permeability curves.
An Impact of Nanotechnology on the Next Generation of Neutron Porosity LWD Tools
Authors: Nikitin Anton , Korjik Mikhail
Published: June 2012

Neutron porosity logging is one of the most fundamental techniques used to perform the estimation of reservoir hydrocarbon reserves. Together with resistivity and gamma-gamma density measurements, these three constitute the "triple combo" well logging suite that is used to log almost all wells. In the case of classical neutron porosity measurement, two neutron detectors are used to measure the flux of thermal neutrons created by the fast neutrons emitted by a chemical neutron source in the process of their interaction with the formation. The obtained flux ratio depends on the hydrogen concentration and enables the determination of porosity.

Currently, almost all available neutron porosity logging-while-drilling (LWD) tools use He-3 detectors to detect neutrons downhole due to their mechanical robustness and the absence of the limitations to operate at high temperatures. Unfortunately, the lack of sufficient quantities of the He-3 isotope caused by the depletion of its stockpile accumulated during the Cold War makes this material unavailable to well logging industry for the next 3 to 5 years. Among all other available neutron detection technologies, only Li-6 scintillation detectors do not have limitations on neutron detection efficiency that would prevent them from consideration for LWD applications.

The key component of Li-6 scintillation detector is the scintillation material containing Li-6 isotope. To be used as detectors for neutron porosity LWD tools based on pulsed neutron generators (PNG), such material should be able to operate at high temperature and enable large neutron detector constructions. In this paper we present new Li-6 scintillation nanostructured glass-ceramics that perform substantially better than all available Li-6 scintillation materials. It is this performance improvement provided by nanostructured nature of obtained material which enables its use in the neutron detectors of PNG-based neutron porosity LWD tools.
Application of Nanotechnology in Drilling Fluids
Authors: Hoelscher Katherine Price , De Stefano Guido , Riley Meghan , Young Steve
Published: June 2012

The potential to confidently apply water-based drilling fluids in unconventional shale formations has been studied using engineered nanoparticles to minimize shale permeability through physically plugging the nanometer-sized pores. This paper discusses the development of nanoparticle technology and testing protocols developed using Marcellus and Mancos as shale candidates. In addition, new methods to better understand the plugging mechanism are currently under evaluation.

Nanoparticles in this study are specifically designed to physically plug the nanometer-sized shale pores, thereby reducing pressure transmission in the shale. Silica nanoparticles are commericially available and can be engineered to meet all specifications needed for the purpose. The particle size can vary between 5 and 100 nanometers (nm) and. The right sizes of nanoaprticles can be selected and in combination with a correct fluid loss package can minimize the fluid rock interaction. Surface treatment on the nanosilcia particle has been discovered to have a major influence on the final performance. It was revealed that appropariately sized nanoparticles with surface treatments compatible with ions present in drilling and formation fluids is required for effective plugging.

Marcellus and Mancos shales were used in the development phase due to their wide industry interest and geological similarity. The authors examined an in-house method, still under development, using the Shale Membrane Test that is intended to provide quantitative plugging and filter cake measurements using various shale samples.
Nanotechnology for Oilfield Applications - Hype or Reality?
Authors: Friedheim Jim , Young Steve , De Stefano Guido , Lee John , Guo Quan
Published: June 2012

Nanotechnology has been successfully applied to a variety of products including electronic circuitry, material composites, medical and even consumer goods. Other than a few crossovers, the utility of nanotechnology in the oilfield is still a subject of discussion as well as debate. Noted efforts by universities and consortiums into such areas as nanosensors, nanomarkers or the more esoteric nanobots to provide valuable data regarding the reservoir are of great focus due to their large potential return on investment, but have yet to yield substantive products. By contrast, efforts into drilling applications of nanotechnology such as drilling fluids are less known.

This paper will review recent works on the application of nanotechnology in shale stabilization, high-temperature tolerance and viscosity modification. This paper will also discuss results from projects which utilize graphene (and graphene derivatives), carbon nanotubes (CNT), nanosilica and other nanochemistries to achieve and enhance the performance of drilling fluids in the applications mentioned above. Further discussion will address some of the concerns and pitfalls of sourcing and using commercial "nano" products as well as review current HS&E perspective on this new area of chemistry for the oilfield.
Evaluation of the Hybrid Process of Electrical Resistive Heating and Solvent Injection through Numerical Simulations
Authors: Zhu Zuojing , Zeng Fanhua
Published: June 2012

Electrical Resistive Heating (ERH) has been proposed as a thermal recovery method for heavy oil reservoirs with low environmental impact. ERH could potentially be an alternative to steam-related processes in the reservoirs which are not suitable for steam injection methods due to low incipient injectivity and formation incompatibility. Meanwhile, Vapor Extraction (VAPEX) has been tested as an environmentally sustainable oil recovery method in both lab scale and field scale. However, the field test results showed that this process is not efficient and economical due to low mass transfer and low horizontal well efficiency. This paper presents a hybrid process of ERH with Solvent Injection. The hybrid process could enhance horizontal well efficiency and overall oil production rate, with less environmental impact than other steam-related thermal processes. Numerical simulations were conducted to evaluate this process via CMG’s STARS. Well pattern similar to that in classical SAGD process is used. The electrode is placed along with the producer or injector and solvent is injected from the injector. This process has three features which contribute to the enhanced oil flow: (1) the heat from producer establishes good communication between the injector and the producer by reducing viscosity; (2) the in-situ generated heat through ERH along with the horizontal wellbore is insusceptible to reservoir heterogeneity. Thereby the horizontal well conformity can be improved; (3) the solvent can reduce the viscosity of the heavy oil in unheated zone where the ERH can not reach; while it can also assist viscosity reduction of heavy oil in the heated zone. The factors affecting this hybrid process, such as electrode placement, voltage, well distance and heterogeneity effect, lateral pattern and water saturation, were also discussed in this paper. The simulation results showed that this hybrid process can improve the oil rate 2 to 5 times over VAPEX.
Nanoparticle-Associated Surfactant Micellar Fluids: An Alternative to Crosslinked Polymer Systems
Authors: Crews James B. , Gomaa Ahmed M.
Published: June 2012

Hydraulic fracturing has become an increasingly important completion method to allow reservoirs to become economically producible and to improve the rate of hydrocarbon production. Crosslinked polymer fluids have been the most commonly used fracturing fluid. These fluids exhibit exceptional performance to initiate and propagate a fracture and carry proppant into the reservoir during a treatment. However, crosslinked polymer fluids can leave a significant amount of polymer in the fracture once a treatment is completed. Decades of improving oxidative, enzyme and other breakers for the polymer fluids has only marginally improved the amount of polymer residue left within the fracture. The result has been wells with subpar hydrocarbon recovery rates and in many geographic areas the return of large volume waterfracs.

Over the past two decades surfactant-based fluids have been developed as a low-damage alternative. However, surfactant-based systems have had major limitations for hydraulic fracturing. This paper will introduce improved fluid technology that uses nanoparticles, internal breakers and low molecular weight surfactants to achieve the performance of crosslinked polymer fluids but leaves little to no gel residue. Nanoparticles have been found that uniquely associate thread-like micelles into 3-deminsional network that imparts wall-building leak-off control and fluid efficiency. The system also utilizes internal breakers that reside within the micelles and go wherever the fluid goes to insure complete viscosity reduction. The nanoparticle enhanced surfactant-based fluid technology may allow a wide range of hydraulically fractured reservoirs to produce at higher sustained rates than presently achievable, particularly for wells highly sensitive to fracture conductivity damage.

This paper will present laboratory data that shows how uniquely charged nanoparticles improve surfactant-based fluid rheology and leak-off control properties. The mechanisms for the observed performance enhancements also will be discussed.
Effect of Nanoparticle Transport and Retention in Oilfield Rocks on the Efficiency of Different Nanotechnologies in Oil Industry
Authors: You Z.. , Aji K.. , Badalyan A.. , Bedrikovetsky P..
Published: June 2012

A mathematical model is presented for nanoparticle transport and retention in oilfield rocks under net repulsion condition. The model accounts for the particle capture rate proportional to the accessible suspension flux, the inlet concentration and outlet dilution effects. A new formulation for experimental study in engineered porous media allows excluding other mechanisms of particle retention except straining. The laboratory coreflooding tests show good agreement with the modeling results. The developed model allows calculating different particle concentrations in suspension and in deposit. It allows estimating depth penetration of nanoparticles and their propagation/accumulation in each reservoir point.
Effect of MgO Nanofluid Injection into Water Sensitive Formation to Prevent the Water Shock Permeability Impairment
Authors: Habibi Ali , Heidari Mohammad A. , Al-Hadrami Hamoud , Al-Ajmi Adel , Al-Wahaibi Yahya , Ayatollahi Shahab
Published: June 2012

Fines migration is the major reason for productivity decline known as formation damage in oil reservoirs. Sandstone formations are sensitive to brine salinity alteration which disturbs equilibrium condition in porous media. Because of nonequilibrium condition fines migration occurs during various operations. Nanoparticles seem to be good candidates to strengthen the attractive forces between fines and pore wall due to very small size, high specific surface area and electrical surface charge.

In this experimental study, several tests were performed using Berea sandstone (8 wt% clays) cores (3 in. length and 1.5 in. diameter). MgO nanoparticles were stabilized in the water uniformly using surface active agent and ultrasonication. Total dimensionless energy of interaction between nano particles in the suspensions was calculated based on the DLVO theory. Various core flooding tests were conducted to determine the effect of MgO nanofluid injection as clay stabilizer at different brine salinities on the cores with the permeability from 600-100 md. The pressure drop across the core was measured.

The results indicated that the MgO nanofluid could fix fines effectively where brine salinity became lower than CSC. Besides, measured zeta potential and total energy of interaction calculation confirmed that repulsive force became dominant at the specific concentration of the complex nanofluid which ensures its stability for long time during core flooding tests. Thus, MgO nanofluid significantly prevented water shock problem. Also, no significant reduction in permeability was noticed in any of core flood tests.
Enhancing Flow Assurance Using Co-Ni Nanoparticles For Dewaxing Of Production Tubing
Authors: Haindade Zishaan , Bihani Abhishek D. , Javeri Saket , Jere Chaitanya
Published: June 2012

The most frequent problem encountered in day to day oil well production is the deposition of paraffin or wax inside the production tubing. The solution to this problem is frequent scraping and hot oil operation with help of Coiled Tubing Unit (CTU) thereby increasing the non productive time. The following paper proposes an alternative technique for dewaxing of production tubing.

The technique involves the use of Co-Ni nanoparticles along with an exclusive polymer to be pumped inside the annulus between production tubing and casing at the time of well commissioning. The nanoparticles remain suspended in the polymer filled inside the annulus throughout the life of the well. The application of magnetic field across the casing causes the nanoparticles to vibrate and get heated. This increase in temperature is transferred to the tubing by convection. The increase in temperature causes the wax to melt and is produced along with the oil stream.

This technique will make the frequent scraping and hot oil jobs obsolete thereby saving time and money. The technique eliminates flow assurance problems encountered due to paraffin deposition inside the production tubing.
Evaluation on the EOR Potential Capacity of the Synthesized Composite Silica-Core/ Polymer-Shell Nanoparticles Blended with Surfactant Systems for the HPHT Offshore Reservoir Conditions
Authors: Nguyen Phuong-Tung , Do Bao-Phuong Huu , Pham Duy-Khanh , Nguyen Hai-An , Dao Duy-Quang Pham , Nguyen Ba-Dung
Published: June 2012

The authors introduce the synthetic process and the evaluation results for surfactant/polymer inorganic nanocomposite specially designed for the enhanced oil recovery (EOR) process in the high temperature and high brine-hardness offshore reservoirs. The SiO2 nanoparticles (NPs) were introduced to the polymer matrix through the core-shell encapsulation-polymerization. New core-shell NPs were blended with surfactants in different ratios. The monodisperse particles, with the size of 50nm to 100nm identified by transmission electron microscopy (TEM), were investigated on their properties and morphology by IR spectroscopy, and thermal degradation (TGA). The blends of NPs and surfactants in brine were aged in one month in Dragon Southeast reservoir conditions to evaluate on the capacity as EOR agent. The results show that the nanocomposites produced IFT reduction and viscosity enhancement at critical concentration, high thermostability and salt-tolerance. These improved properties of core/shell NPs were suitable for producing high sweep volume and increasing crude oil displacement efficiency. The core flooding experiment was performed at 92°C on the fractured-granite core model and brine blend of 800 ppm of surfactants and 200 ppm of core-shell NPs was injected in 0.25 PV. After water flooding, the oil saturation was reduced into 30% and by the core-shell NPs injection, the oil was displaced in 6.2% additionally. The obtained results shown the capacity of using the core-shell NPs as a really good EOR agent for HTHP offshore reservoirs.

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Nano-Enhancement of Barrier Coatings for Improved Downhole Performance of Oilfield Materials
Authors: Welch John C. , Newman Caleb , Gerrard David , Mazyar Oleg A. , Mathur Vipul
Published: June 2012

The oil and gas industry is continuously looking for robust material and tool designs that provide greater operational flexibility in aggressive environments. Coating systems, engineered at the nanometer scale, exhibit enhancements that can address these needs.

Our study of nano-engineered coatings started with simple polymer-polymer self-assembled systems, to which was added nano-sized clay or one of several carbon-based nano materials. We evaluated application of different cross linker treatments. To evaluate the variables involved in preparation of the coating systems we quantified thickness and contact angle, and we performed micrographic and scanning electron microscope analysis of standard coated substrates. When applied to copper coupons we determined a 91% reduction of corrosion after four hours, 60% after 24 hours, and 13% after ninety hours in a hydrogen sulfide gas blend. Nano-engineered coatings applied to common oilfield elastomeric materials produce a 40x delay in swelling and decrease in transmission of carbon dioxide gas by 73%. All of the above are lab results, and the comparisons were made to baseline commercially available rubber compounds without nano-enhancement.

Our results demonstrated that nanotechnology can be very effectively used to significantly modify properties of commonly used oilfield materials. Reduced corrosion can extend the life of downhole electronics and motors. The oil swelling rate can be drastically reduced to give operators a greater flexibility in setting the packers and reducing intervention. These findings can be used to design new packers, sealing elements and other elastomeric components used in downhole environment. This paper will present our recent lab results along with a postulated mechanism on how nanotechnologies can impact material performance in downhole applications.
Rapid Estimation of Heavy Oil Viscosities Using a Novel Predictive Tool Approach
Authors: Bahadori A. , Nouri A.
Published: June 2012

The viscosity of heavy oils is a critical property in predicting oil recovery. Viscosity plays an important role in reservoir simulations as well as in predicting the easiness of fluid flow, selecting a production approach, and predicting oil recovery. In this work a simple-to-use predictive tool has been developed to predict the viscosity of heavy oil as a function of temperature as well as a simple correlating parameter that can be used for heavy oil characterization. The reported results are the product of analysis of many heavy oils data collected from the open literature for various heavy oil fields around the world. The tool developed in this study can be of immense practical value for petroleum engineers to have a quick check on the viscosity of heavy oil without opting for any experimental trials. In particular, petroleum and production engineers would find the proposed correlation to be user-friendly with transparent calculations involving no complex expressions.
Enhancement of Well Productivity Using a Technique of High-Frequency Induction Treatment
Authors: Valiullin Rim , Sharafutdinov Ramil , Ramazanov Ajrat , Shilov Aleksandr
Published: June 2012

One of the principal challenges of enhancing efficiency of production and injection wells is improving permeability of collector formations. The main changes of collection properties take place in the bore zone of the formation and are connected with the well construction and operation, which brings about a reduction in recipience of injection wells and flow of production ones. The oil production industry of the recent years has seen employment of various techniques of heat treating the bore zone of the formation to boost oil recovery. One of such techniques involves a high-frequency induction exposure. However, theoretical fundamentals of the application of the induction impact are practically non-existent at present, and no assessments of the induction heating efficiency have been made to compare it to other kinds of heat applications. The paper presents the results of mathematically modeling the process of an induction impact upon the formation. It investigates regularities of the formation of a resulting thermal field. Also presented in the paper is the efficiency of the induction heating of the formation versus heating using electric (resistance) heaters. It has been demonstrated that the use of an induction heater brings about an increase in the heating depth and a reduction of the duration of bore zone treatment by the factor of five or six if compared with using an electric resistance heater. The paper exhibits some results of experimental and methodological works on the use of induction treatment, as well as some examples of a geophysical support of the process of treating the formation bore zone.
Perforation Optimization for Regulating Production Profile of Horizontal Wells in Heterogeneous Reservoirs
Authors: Wang Haijing , Li Xiaoqing , Xue Shifeng
Published: June 2012

Horizontal wells which are characterized by large drainage area, small pressure drawdown and high production rate are more influenced by reservoir heterogeneity and wellbore pressure loss than vertical wells. These factors may lead to unequilibrium development and premature water breakthrough, resulting in shortened production period, reduced production and ultimate recovery. Perforated completion is a widely used completion technology of horizontal wells. As the only flow channel between the formation and the wellbore, perforation plays an important role on the inflow performance. This paper aims to develop a perforation optimization method for regulating production profile of horizontal wells in heterogeneous reservoirs.

Based on an improved evaluation approach of permeability heterogeneity, a reservoir/wellore coupling model of perforated horizontal wells in heterogeneous, anisotropic parallelepiped reservoirs is presented, and hence a perforation density optimization method aiming at regulating production profile is proposed. The example optimization shows that, the lower perforation density has a wider pressure regulating range. With the increase of perforation length, both the converged pressure drop and pressure regulating range decrease. To obtain an ideal production profile, the perforation density in low-permeability region should be higher than that in high-permeability region. The stronger the near-well permeability variability, the greater the density range and the proportion of low density are. The smaller the density, the greater the impact of rounding error is, and hence the less satisfactory the regulating effect is. This study provides a theoretical basis for the perforated completion design of horizontal wells in heterogeneous, anisotropic reservoirs.
Phase Behaviour of C3H8-n-C4H10-Heavy Oil Systems at High Pressures and Elevated Temperatures
Authors: Li Huazhou , Yang Daoyong
Published: June 2012

Phase behaviour of C3H8-n-C4H10-heavy oil systems at high pressures and elevated temperatures has been experimentally and theoretically investigated. Experimentally, a versatile pressure-volume-temperature (PVT) system is utilized to determine the liquid-vapour phase boundary (i.e., saturation pressure lines) and swelling factors of C3H8-n-C/H10-heavy oil systems with varying compositions at high pressures up to 5030 kPa and elevated temperatures up to 396.15 K. The viscosities of the corresponding solvent(s)-saturated heavy oil systems are measured by using a customized-capillary viscometer at 298.85 K. Theoretically, the volume-translated Peng-Robinson equation of state (PR EOS) with a modified alpha function is used to model the experimental phase behaviour of C3H8-n-C/H10-heavy oil systems. Two binary interaction coefficient (BIP) correlations, respectively developed for the C3H8-heavy oil system and n-C4H10-heavy oil system, are incorporated into the volume-translated PR EOS model. The two BIP correlations together with the volume-translated PR EOS are found to be capable of predicting the phase behaviour of the C3H8-n-C4H10-heavy oil systems with a good accuracy. In addition, comparison of five commonly used mixing rules indicates that the Lobe’s mixing rule is the most appropriate to predict the viscosity of heavy oil diluted by C3H8 and/or n-C4H10.
A Mechanism of Gas Production in SAGD
Authors: Canas Christian
Published: June 2012

The dissolution of gas in both water and bitumen as a mechanism contributing to gas production in SAGD is studied. The contribution of this mechanism to the production of gas in SAGD is evaluated through the implementation of appropriate thermodynamic models into a series of numerical simulations in order to more accurately represent the physics of gas behavior inside the SAGD chamber. Methane, carbon dioxide and hydrogen sulphide are considered.

It is observed from the numerical simulation results that the production of a gas in SAGD is directly proportional to the solubility of that gas in the liquid phases being produced. Additionally, these results lead to the conclusion that gas dissolution is an important mechanism in gas production.

Results from this study also confirm the findings observed by other researchers that gas will accumulate at the front and top of the SAGD chamber, thus reducing SOR and oil production rates. The degree of such accumulation of gas depends, among other operational and reservoir conditions, on the solubility of that gas in the liquid phases under the temperature and pressure conditions inside the steam chamber.
Reducing the CO2 Footprint: Employing Cogeneration to Improve the Energy Efficiency of Thermal Oil Recovery Projects
Authors: Welch Mike
Published: June 2012

Thermal recovery technologies such as Cyclic Steam Stimulation, Steam Assisted Gravity Drainage and Steam Flood are extremely energy intensive, requiring the combustion of fossil fuels to produce the steam and resulting in emissions of carbon dioxide and other pollutants. Newer technologies such as Solvent Extraction may also require the injected medium to be heated to maximise oil recovery from the reservoir.

Thermal projects often generate the heat and power required in separate facilities, with the electricity often being supplied from remote central generation facilities. In many cases it may be possible to integrate a cogeneration plant into the process. Using a single, suitably sized on-site Cogeneration facility, a locally available fuel can reliably provide both the power and heat required for the project, achieving overall energy efficiency to levels in excess of 75%, while helping to reduce the global CO2 footprint of the Oil & Gas industry and reducing reliance on imported electrical power. The design of Cogeneration plant can also help ensure maximum availability and uptime of production facilities.

In most cases the heat produced by a Cogeneration plant is a by-product of electricity production, but it is also possible to utilise waste heat from some processes to produce useful energy. Waste gases from processes are also potential fuels for a Cogeneration plant, helping to reduce or eliminate gas flaring, and improve environmental performance across the whole oil production chain.

There are numerous different ways to configure a Cogeneration plant depending on the type of fuel available and the ratio between power and heat required by the project. This paper will examine some of the different Cogeneration plant configurations and fuel options using Gas or Steam Turbines, or a combination of both, that could be applied to a thermal recovery project to maximise energy efficiency and plant availability.
Reservoir Identification and Hydrocarbon Classification with Logging Data in Bituminous Sandstone in Tarim Basin
Authors: Jun Zhao , Xinzhong Qi , Bin Yu , Weizhong Chen
Published: June 2012

Because of the complicated pore structure and complex relation of oil and water, especially owing to the existence of high-viscosity oil and bitumen in the formation it makes the resistivity difference between oil and water zones very low. So it is very difficulty to identify the oil and water with logging data. By applying the capillary pressure curves, lithological- electrical experiments and relative permeability curves the Silurian reservoir classification was studied in combination with the reservoir fractal characteristic and a classification model was established by using non-linear method to identify the reservoir types. On the basis of classifying reservoir types a improved normal distribution method was presented to distinguish oil and water zones. Then with core data the different parameter interpretation models concerning to varying reservoir types were founded. By used in practice it was proved to be effective to improve the veracity of log interpretation for bituminous reservoir in Tarim basin.
The Well-Wormhole Model of CHOPS: History Match and Validation
Authors: Istchenko C. M. , Gates I. D.
Published: June 2012

Cold Heavy Oil Production with Sand (CHOPS) is a non-thermal heavy oil recovery technique used primarily in the heavy oil belt in western Alberta and eastern Saskatchewan. Under CHOPS, typical recovery factors are between 5 and 15% with average ~10%. This leaves ~90% of the oil in the ground after the process becomes uneconomic. CHOPS exhibits an enhancement in production rates compared to conventional primary production, which is explained by formation of high permeability channels known as wormholes. The formation of wormholes has been demonstrated to occur in both laboratory experiments and field tracer studies. The ability to model growth of wormholes does not currently exist in commercial reservoir simulators. Here, wormholes are modelled as multi-lateral wells, which grow dynamically in the reservoir, using existing wellbore features. A module was coupled to CMG STARS™ to dynamically grow wormholes in the reservoir taking foamy oil flow, sand failure, and sand production into account. Here, we present on the results of history matches against field data to tune model parameters. The history-matched model reasonably predicts production trends of field CHOPS operations. The results provide a methodology to model CHOPS and predict under uncertainty where the wormholes will tend to grow into the reservoir. This provides a tool for placing new wells in the reservoir that will most likely not be in direct contact with existing wormholes. Multiple realizations of the reservoir can be used to mark the region of the reservoir that undergoes wormhole formation. The model can then be used for follow-up EOR processes such as cycle solvent injection as well as field scale optimization.
Suffield Area, Alberta, Canada – Caen Polymer Flood Pilot Project
Authors: Liu Jenny (Zhengyu) , Adegbesan Kenny , Bai Jiang (Jen)
Published: June 2012

The Suffield Caen reservoir contains 17°API heavy oil and the pool has been under waterflooding since 1996 with water cut of 96%. Primary and secondary oil recovery is 15 – 20% of OOIP. A major problem encountered in waterflood was poor sweep efficiency and high water cut caused by high water/oil mobility ratio, as water quickly broke through the reservoir owing to fingering effects. It is known that sweep efficiency during waterflood can be improved significantly by increasing the viscosity of injected water by use of polymer solution, thus generating a more favorable mobility ratio and enhancing oil recovery. The results of reservoir simulation studies suggested that polymer flood would achieve incremental recovery factor of 7 – 12%, and coreflood results indicated that 29 –32% of incremental recovery is achievable by 0.5 pore volume (PV) of polymer injection.

Core floods including polymer, surfactant/polymer(S/P) and alkali/surfactant/polymer (A/S/P) were conducted through lab experiments and eventually polymer flood was selected as a pilot project to improve oil recovery for the Caen reservoir on the basis of polymer, S/P and A/S/P core flood results and project economic evaluation.

Polymer injection started in the reservoir 15 months ago and a very positive response has been seen as oil cut has increased to 10% from 5% and oil production rose to 600 bbl/d from 400 bbl/d. Therefore, the polymer flood pilot project is continually implemented and the polymer flood is planned to extend to similar reservoirs in the Suffield area.

There is a large amount of conventional heavy oil resaves in the West Canada Basin, so far the primary recovery factor is only 10%, there is a big potential to enhance oil recovery by polymer flood. This polymer flood pilot project provides valuable experiences and guidance to field application.
Experimental Evaluation of Heated Vapex Process
Authors: Haghighat Parnian , Maini Brij B.
Published: June 2012

Incorporating some heat injection along with the solvent injection appears to be the most viable option for improving the oil drainage rate of Vapex in extra-heavy oil formations. This study was aimed at quantifying the potential increase in Vapex drainage rate that can be obtained by increasing the formation temperature.

The experimental phase of this study involved conducting Vapex experiments in a large high-pressure physical model, packed with 250 Darcy sand, using propane as the solvent. The physical model was warmed up to 40, 50 and 60 °C and propane was injected at the same test temperature but different injection pressures to observe how injection pressure affects oil drainage rate at elevated temperatures.

In the experiments at elevated temperatures but without increasing the injection pressure, higher rate of oil production was achieved in the early stages of the process. However, stabilized rate of oil production did not show pronounced improvement due to lower solubility of propane in the oil at higher temperatures. Increasing injection pressure along with increasing the test temperatures was successful in accelerating the oil production.

The oil, used in these experiments, was found to become mobile with the increase in temperature even without solvent dissolution. As a result, the total rate of oil production appeared to be controlled by two mechanisms. First, by solvent dissolution and oil mobilization at the boundaries of the vapor chamber and second by pure free fall gravity drainage beyond the vapor chamber wherever gravity head was sufficient to push the mobile oil toward the production well.

The results of this these tests define the upper limit of oil rates achievable with heated solvent injection. They can also be used to assess the applicability of Vapex to naturally warm reservoirs such as in Venezuela and reservoirs with mobile oil in place.
A Condensation Temperature Model for Evaluating Early-period SAGD Performance
Authors: Zhu L. , Zeng F. , Zhao G.
Published: June 2012

This paper proposes a new methodology using condensation model to evaluate the early-period SAGD by interpreting the temperature falloff data in injector or producer obtained from fiber optics or thermal couples after the wells are shut-in. Based on the non-condensation model proposed before, the condensation model also assumes a circular hot-zone shape since in the early stage of SAGD operation, and characterize the system as composed of a steam-zone of steam temperature, a cold-zone of reservoir temperature and a transition-zone in between as the initial temperature distribution. Besides, the condensation model incorporates the effect of steam condensation on the condensation-front. The movement of steam condensation-front is calculated to account for the steam-zone shrinkage. Sensitivity analysis over this models indicates that the sizes of steam-zone, transition-zone and the observing location directly affect the temperature behavior at observation point. Synthetic case study shows that the temperature falloffs from condensation model and from simulation are in good agreement and suggests that condensation model can be used to estimate the chamber size at the early stage of SAGD. As is known, it is important to obtain an even steam chamber distribution along the horizontal wellbore to shorten the ramp-up time so that maximized economics can be achieved. In reality, the reservoir heterogeneity, the wellbore undulation and the operation condition make the steam chamber conformance impossible. Because of the ready-to-use temperature data and the semi-analytic solution, the condensation model proposed in this paper can provide quick and reliable estimation of the steam chamber size to help the engineers to monitor and optimize the chamber development thereafter.
Real-Time Imaging of SAGD Steam Conformance By Using White Noise Reflection Processes
Authors: Leskiw Chris
Published: June 2012

4D seismic imaging requires extensive time to setup, implement, and process to provide information on the progress of recovery efforts such as estimates of the size and shape of reservoirs and their internal artifacts. Conventional seismic imaging results in a resolution on the order of tens of meters. As an alternative, white noise reflection processes use sub-noise signals to image reservoirs and can potentially do this at scales below 1 meter.

Both simulations and lab experiments show that reflections from white noise processes can be used advantageously to localize discontinuities and track their movement through media. For example, for steam-based oil sands recovery processes, it is critical to have an understanding of the steam conformance to improve the efficiency of the recovery process. White noise signaling technologies can be used to monitor the spatial distribution of fluids e.g. a steam chamber interface, and objects e.g. shale layers and concretions, at higher frequencies resulting in finer resolution in real-time compared to conventional methods.

The results demonstrate that acquisition and ranging of discontinuities in the laboratory can be achieved at the centimeter scale. The methods are extended to concurrent use of multiple transducers to improve directionality and triangulation of discontinuities.
History Match of the Liaohe Oil Field SAGD Operation - A Vertical- Horizontal Well Reservoir Production Machine
Authors: Bao Y. , Wang J. Y. , Gates I. D.
Published: June 2012

With the decline of conventional oil production, developing and producing heavy oil resources efficiently is becoming more important. The Liaohe Heavy Oil Field steam operation is unique – it started with cyclic steam stimulation (CSS) operation that transitioned into a continuous steam-assisted gravity drainage (SAGD) operation. With respect to oil production in China, this field is considered critical for heavy oil production and technology development. Cyclic steam injection was initially done through vertical wells. This had the benefit that it provided a good start-up of depletion chambers in the reservoir. These chambers then grew under gravity drainage after continuous steam injection (through the vertical wells) and continuous production through a set of horizontal wells was started. Controlled and deliberate transition from CSS to a gravity drainage process with the objective of optimizing energy intensity (GJ injected per unit volume oil produced) with control enabled through production and thermocouple data is a smart field operation which we refer to as a Reservoir Production Machine (RPM). In this paper, as a first step to understand the operation and its impact on the reservoir, we have history matched the CSS operation based on the injection and production data from field. The use of vertical steam injection wells (formerly the CSS wells) in combination with horizontal production wells operated in a SAGD mode of operation is explored. The history-matched model can be used to develop automated RPM technologies to optimize not only energy intensity but also emissions intensity.
Effects of Gravity, Foaminess and Pressure Draw Down on Primary Depletion Recovery Factor in Heavy Oil Systems
Authors: Alshmakhy A. , Maini B.
Published: June 2012

The unusually high primary recovery factors observed in many heavy oil reservoirs are often attributed to foamy oil flow, i.e. the non-Darcy flow involving formation and flow of gas-in-oil dispersion. It occurs when the wells are produced aggressively at high drawdown pressures that lead to conditions in which the viscous forces become strong enough to overcome the capillary forces in pushing dispersed bubbles through pore throats. The role of gravitational forces in generating such dispersed flow has not been adequately studied. This work was aimed at evaluating the contribution of gravitational forces in primary depletion of heavy oil formations under foamy flow conditions.

Primary depletion tests were conducted in a 200 cm long sand-pack that was held in either horizontal or vertical orientation. The results of horizontal depletion tests were compared with the depletion tests conducted with the sand-pack in vertical direction. Vertical depletions showed better recoveries at slower depletion rates compared to horizontal depletions.

The recovery factors of both horizontal and vertical depletions were correlated against the average drawdown pressure available to move the oil. It was found that the recovery factor show a strong dependence on the average drawdown pressure. It was also found that the curve of recovery factor versus average drawdown pressure moves slightly towards higher recoveries in the presence of an added foaming agent which increases the oil foaminess.