bluuebunny/crossref_metadata_2025 huggingface dataset:
Climate change and disruptions to global fire activity
Authors: Moritz Max A. , Parisien Marc-André , Batllori Enric , Krawchuk Meg A. , Van Dorn Jeff , Ganz David J. , Hayhoe Katharine
Published: June 2012

Future disruptions to fire activity will threaten ecosystems and human well‐being throughout the world, yet there are few fire projections at global scales and almost none from a broad range of global climate models (GCMs). Here we integrate global fire datasets and environmental covariates to build spatial statistical models of fire probability at a 0.5° resolution and examine environmental controls on fire activity. Fire models are driven by climate norms from 16 GCMs (A2 emissions scenario) to assess the magnitude and direction of change over two time periods, 2010–2039 and 2070–2099. From the ensemble results, we identify areas of consensus for increases or decreases in fire activity, as well as areas where GCMs disagree. Although certain biomes are sensitive to constraints on biomass productivity and others to atmospheric conditions promoting combustion, substantial and rapid shifts are projected for future fire activity across vast portions of the globe. In the near term, the most consistent increases in fire activity occur in biomes with already somewhat warm climates; decreases are less pronounced and concentrated primarily in a few tropical and subtropical biomes. However, models do not agree on the direction of near‐term changes across more than 50% of terrestrial lands, highlighting major uncertainties in the next few decades. By the end of the century, the magnitude and the agreement in direction of change are projected to increase substantially. Most far‐term model agreement on increasing fire probabilities (∼62%) occurs at mid‐ to high‐latitudes, while agreement on decreasing probabilities (∼20%) is mainly in the tropics. Although our global models demonstrate that long‐term environmental norms are very successful at capturing chronic fire probability patterns, future work is necessary to assess how much more explanatory power would be added through interannual variation in climate variables. This study provides a first examination of global disruptions to fire activity using an empirically based statistical framework and a multi‐model ensemble of GCM projections, an important step toward assessing fire‐related vulnerabilities to humans and the ecosystems upon which they depend.
Linkages Between Clinical Practices and Community Organizations for Prevention: A Literature Review and Environmental Scan
Authors: Porterfield Deborah S. , Hinnant Laurie W. , Kane Heather , Horne Joseph , McAleer Kelly , Roussel Amy
Published: June 2012

Objectives. We conducted a literature review and environmental scan to develop a framework for interventions that utilize linkages between clinical practices and community organizations for the delivery of preventive services, and to identify and characterize these efforts.

Methods. We searched 4 major health services and social science electronic databases and conducted an Internet search to identify examples of linkage interventions in the areas of tobacco cessation, obesity, nutrition, and physical activity.

Results. We identified 49 interventions, of which 18 examples described their evaluation methods or reported any intervention outcomes. Few conducted evaluations that were rigorous enough to capture changes in intermediate or long-term health outcomes. Outcomes in these evaluations were primarily patient-focused and did not include organizational or linkage characteristics.

Conclusions. An attractive option to increase the delivery of preventive services is to link primary care practices to community organizations; evidence is not yet conclusive, however, that such linkage interventions are effective. Findings provide recommendations to researchers and organizations that fund research, and call for a framework and metrics to study linkage interventions.
Fast-SAGD vs. SAGD: A Comparative Numerical Simulation in Three Major Formations of Alberta’s Oil Sands
Authors: Dang Cuong T. , Chen Zhangxin John , Nguyen Ngoc T. , Bae Wisup
Published: June 2012

Among of the new inventions on thermal recovery, Fast-SAGD was introduced as the next generation of SAGD with greater amounts of bitumen and lower injected steam. However, there are still many suspicions about the successful of this technology such as the incremental bitumen recovery of Fast-SAGD is from the SAGD production well or combined with the offset well? It is very difficult to conclude that Fast-SAGD is better than conventional SAGD when numerical simulation of two processes was conducted in different well pattern as well the amount of operated well.

This paper presented a comparative evaluation between conventional SAGD and Fast-SAGD in three typical formations (McMurray, Clearwater, and Bluesky) of Alberta's Oil Sand. Three reservoir models with over one hundred numerical simulations under various operation conditions were developed to achieve the most unprejudiced comparison between two recovery processes. The simulation results proved that significantly recoverable bitumen was originally produced from offset well in Fast-SAGD system and leads to higher recovery factor. But, there is only slight increase in cumulative oil recovery when two processes were performed in same pattern with similar number of production wells. The result also indicated that the difference of 10kPa between steam injection pressure and reservoir pressure in literature is not enough for both SAGD and Fast-SAGD operations. And then, this study presented a numerical investigation for evaluating the potential applicability of Fast-SAGD recovery process under complex reservoir conditions such as shale barriers, thief zones with bottom and/or top water layers, overlying gas cap and fracture systems in Clearwater formation.
Potential Application of Thermal Processes To Improve Extra Heavy Oil Recovery: A Simulation Numerical Study from Orinoco Oil Belt, Boyaca Area
Authors: Urdaneta M. C. , Castellanos E. , Askoul Y. E.
Published: June 2012

This study aims to evaluate a wide variety of thermal processes in Boyacá area, located in Guárico state in the Southern flank of the Orinoco River, Basin of Venezuela, which holds an extension of 1247 km2 of extra heavy oil with an API Gravity between 4–8 (API: 4–8), porosities between 25–32% and permeabilities of 2–15 Darcies. Block 06 produced through 7 wells, two of which did not produce, while others two produced by Cyclic Steam Stimulation (CSS) as a test. Results from these tests indicate success in one well which had an accumulated oil production of 26179 STB in one cycle. Synthetical correlations were used in order to estimate fluid and rock properties, considering data obtained from nearby blocks. Geoestatistical model resulted from a refinement of the entire Boyacá area. This new model was classified in three ranges of continuous net sand thickness. First step involved an analysis of this block using."screening criteria" to determine which thermal process was appropriated to apply. As a result, steams flooding based technologies were recommended due to their power to increase the recovery factor in heavy and extra heavy oil reservoirs, providing the required heat content of steam (1200BTU/lb). A following step was building sector models in order to simulate the production history in one of the CSS wells, to simulate each thermal process and to optimize operational parameters. Subsequently, CSS and SAGD (Steam Assisted Gravitational Drainage) were simultaneously simulated. According to these simulations, it is feasible to maximize the recovery of this block up to 30% using this kind of technology. Furthermore, the best economical indicators were obtained through a combination of CSS+SAGD resulting in a net present value of 1521 M$, internal return rate of 15%, operational costs of 16 $/Bbl for an economical horizon of 20 years.
Errors and Repeatability in VSARA Analysis of Heavy Oils
Authors: Wu Wenhui , Saidian Milad , Gaur Stuti , Prasad Manika
Published: June 2012

Increasing demands for world energy resources have accelerated the development of unconventional resources, especially of heavy oil reservoirs. Yet, the recovery of heavy oils remains challenging mainly due to variations in their viscosity. It is well known that chemical components of heavy oil control fluid properties, such as density, viscosity and shear modulus. Open column liquid chromatography is used to separate the Saturate, Aromatic, Resin, and Asphaltene (SARA) fractions. Although SARA fractions are a common method to report heavy oil compositions, they can have over 20 % errors. In this work we discuss potential error sources and establish a best-practice methodology to reduce the errors, which results in developing a modified SARA method (VSARA) to determine the composition of heavy oil. Experimental results show that the evaporative components of heavy oils, Volatile (V) fractions, are a major source of error in SARA fraction estimates. By tracking weight changes at every step of the SARA fractionation, errors are greatly reduced. Based on the comparison between SARA and VSARA results, VSARA fractions have a significantly lower error (within a 5% range) than SARA fractions alone. Multiple measurements for a single sample by different operators revealed that VSARA measurements are repeatable. Structural differences between the fractions have been verified using Fourier Transform Infra-Red (FTIR) spectroscopy, which shows the reliability of the proposed SARA method. We also compare our VSARA analyses with viscosity and show that viscosity of heavy oils correlates with resin and asphaltene fractions at concentrations above 25%; below 25%, it is uncorrelated. Since heavy oil composition can change with depth, viscosity can be expected to vary as well. Accurate information of changes in the VSARA fractions can be used to evaluate viscosity and viscosity heterogeneity in heavy oil reservoirs, select appropriate recovery methods, populate reservoir models with viscosity heterogeneity, and thus predict reservoir productivity more accurately.
New Solution Polymer for SAGD Production Optimization
Authors: Behles Jacqueline A. , Hoster David E. , Picott Juan Carlos , Sartori Larry , Pancoast Jeffry D. , Grinevich Jason R.
Published: June 2012

Steam-assisted gravity drainage (SAGD) has become a method of choice for in-situ production of bitumen for oil sands projects in Alberta, Canada. Fluid production using SAGD results in the formation of a high water cut complex emulsion requiring the use of both reverse emulsion breakers and emulsion breakers in order to produce saleable oil to the pipeline and clean water for reuse or steam generation. As a facility grows and adds more well pairs to the system, maintaining the water quality from the separation vessels becomes increasingly important to growing the daily bitumen production. The enclosed paper will detail the development of a new solution polymer designed to treat the produced complex emulsion. Through an improved synergy with the demulsifier, the newly developed reverse emulsion breaker reduced the required levels of demulsifier to treat the fluids while maintaining or improving the system water qualities observed.
Study on Evaluation Method of Water Flooding Development in Offshore Heavy Oilfield of Semi-depletion Reservoir: A Case Study in Bohai Bay
Authors: Luo Xianbo , Zhao Chunming , Liu Ying
Published: June 2012

SZ36-1oil field belongs to medium heavy oilfield, with severe heterogeneity and water flooding development. Injection/production ratio is less than one because of the low supplying ability of water source well and high injection pressure of injection well. In view of present situation and combining with other search results, a series of theory formulas, such as water cut - degree of reserve recovery relation, water storage - degree of reserve recovery relation and water drive index - degree of reserve recovery relation, are derivated based on Tong standard water flooding curve and material balance rule to evaluate flooding development in heavy oil field of low injection/production ratio. Actual curves are drawn according to production data of SZ36-1oil field I stage. Compared actual curves with theory curves, water flooding development results are evaluated combing with aciding, profile control and polymer injection and so on. The research results offer theory reference to remaining oil distribution distribution of SZ36-1 oil field I stage.
Experimental Analysis of Heavy Oil Recovery and CO2 Storage by Alternate Injection of Steam and CO2 in Deep Naturally Fractured Reservoir
Authors: Naderi Khosrow , Babadagli Tayfun
Published: June 2012

Steam injection in heavy-oil containing naturally fractured reservoir aims at heating matrix to reduce the viscosity and enhance gravity drainage. This technique, however, is not feasible in deep reservoirs. Hydrocarbon solvent injection is also impractical due to low gravity of oil, heterogeneity, and retrieval of solvent diffused into matrix. A hybrid application of these two techniques was tested for deep reservoir conditions earlier (Steam Over Solvent Injection in Fractured Reservoirs Method -SOS-FR) and proved success if applied suitably. The cost of hydrocarbon solvent and greenhouse gas concerns, however, entail investigations on other techniques and materials.

The use of CO2 in this type of process as solvent was considered and tested in this paper. Several issues are highly critical in this process. Like other hydrocarbon solvents used under non-isothermal conditions, the recovery process is highly sensitive to pressure and temperature as they determine the miscibility level. Also important is the capability of CO2 to extract matrix oil. Our earlier studies with light oil showed that heavier ends can be extracted if enough time is allowed for CO2 to interact with matrix oil. The same needs to be investigated for heavy-oils. Another dilemma was inverse proportionality of CO2 solubility with temperature. Steam (or heating) is inevitable to condition oil and decrease its viscosity before CO2 injection but temperature should be critically adjusted not to sacrifice CO2 solubility of oil.

To clarify all these points and determine optimal application conditions (duration of each cycles and CO2 soaking time), we conducted a series of experiments by soaking core samples saturated with heavy oil into steam first followed by CO2. In the third cycle, steam (or hot water) was injected again to produce upgraded oil in the matrix. The experiments were performed under static conditions (soaking sandpacks and sandstone samples into steam or CO2 chambers) at different temperatures and pressures to determine optimal application conditions for mutual goals; heavy oil recovery and CO2 storage in the matrix. Finally, the results were compared to those of experiments with hydrocarbon solvents from technical point of view including storage benefits of CO2.
A Comparative Study of Alkaline Flooding and Alkaline/Surfactant Flooding for Zhuangxi Heavy Oil
Authors: Pei H. H. , Zhang G. C. , Ge J. J. , Ding L. , Tang M. G. , Zheng Y. F.
Published: June 2012

In this study, a comparative study of alkaline flooding and alkaline/surfactant flooding was conducted for Zhuangxi heavy oil with viscosity of 325 mPa·s at 55 °C. The results of core flooding tests show that, the tertiary oil recovery of alkaline-only flooding with the alkaline concentration in the range of 0.4–1.0 wt% can reach 22% – 31% OOIP. The coexistence of the surfactant and alkali can reduce the IFT between the heavy oil and aqueous phase to an ultralow level. However, the tertiary oil recovery of alkaline/surfactant flooding are lower than those of alkaline-only flooding. Further flood study via glass-etching micromodel tests demonstrates that injected alkaline-only solution can penetrate into the oil phase and creates some discontinuous water droplet inside the oil. The subsequent formation of droplet flow tends to reduce the mobility of the water phase and damp viscous fingering, leading to the improvement of sweep efficiency. While for alkaline/surfactant flooding, because of the addition of the surfactant, these systems exhibit better capacity in emulsification and IFT reduction, the viscous oil can be break up into fine droplets and entrained along with the flowing aqueous phase. Therefore, viscous fingering phenomena are occurred during the displacement, resulting in its relatively lower oil recovery. Comparing the results of alkaline flooding and alkaline/surfactant flooding, improving the sweep efficiency by the droplet flow in alkaline flooding is more effective than lowering IFT by alkaline/surfactant flooding for heavy oil recovery.
Modeling of Steam-Liquid Flow Inside and Around SAGD Wells During Startup Stage
Authors: Doan Q. , Doan M. , Ali S. M.
Published: June 2012

Canada’s oil sands deposits in northern Alberta are estimated to contain more than 1.35 trillion barrels (~215 billion m3) of bitumen. Such a large resource base constitutes the world’s second largest oil reserves (behind only Saudi Arabia’s), even allowing for (relatively) low recovery factors. In-situ recovery technologies for these deposits, in view of the extremely viscous bitumen typically existing in them, commonly require thermal heating and/or solvent dilution to mobilize the bitumen and enable it to be produced. SAGD and CSS are currently two technologies accounting for the bulk of in-situ bitumen production in Canada.

The SAGD process, utilizing two long parallel horizontal wells (upper well for steam injection, lower well for production), involves typically three sequential stages: Start-Up (Circulation), (proper) SAGD, and Wind-Down (or Blow-Down). In the Start-Up stage, steam is circulated through the two horizontal wellbores for sufficient time duration to create communication between them, prior to converting to SAGD operation. During this stage, complex heat and mass transfer phenomena occur in counter-current flow in the tubing and annulus (or tubing), and between the wells and adjacent reservoir. This paper first reviews briefly the common approaches currently utilized to model the Start-Up stage for a SAGD well pair. Next, it presents simulation results of transient steam-liquid flow inside SAGD wells, and temperature changes at the inter-wells midpoint reservoir, for a case typical of Athabasca SAGD project. Discussion – based on the distribution of steam quality, pressure and temperature losses along the axial well length – is provided, as is the estimation of the duration for effective SAGD circulation for the cited example.
Optimal Design of Low Temperature Air Injection for Efficient Recovery of Heavy Oil in Deep Naturally Fractured Reservoirs: Experimental and Numerical Approach
Authors: Mayorquin-Ruiz Jose Ramon , Babadagli Tayfun
Published: June 2012

Low temperature air injection (LTAI) can be a possibility if injected air diffuses into matrix effectively to oxidize oil in it creating enhanced gravity drainage of lower viscosity oil. However, early breakthrough of air with partial consumption of oxygen due to the highly conductive nature of the reservoirs is a concern. Once it is controlled by proper injection scheme and consumption of air injected through efficient diffusion into matrix, LTAI can be an alternative technique for heavy-oil recovery from deep NFR.

Limited number of studies on light oils showed that this process was highly dependent on oxygen diffusion coefficient and matrix permeability. In this process, oil production is governed by drainage and stripping of light oil components has a greater effect on recovery than the swelling of oil.

In the present study, static laboratory tests were performed by immersing heavy-oil saturated porous media into air filled reactors to determine critical parameters on recovery; diffusion coefficient and gravity drainage rate. A data acquisition system was established for continuous monitoring of pressure at different temperatures. Also analyzed was the possibility of hydrocarbon gas additive to air to enhance diffusion into matrix. A numerical model of air diffusion into a single matrix was created to obtain diffusion coefficient through matching the lab results. Then, sensitivity runs were performed for different matrix properties and composition of injected gas (air and hydrocarbon).

It is imperative that enough timing is required for diffusion process before injected air filling to fracture network breakthrough. This implies that huff and puff type injection is an option as opposed to continuous injection of air. The optimal design and duration of the cycles were also tested experimentally and numerically for a single matrix case.
Impact of Non-Condensable Gas on SAGD Performance
Authors: Liu Yang , Xi Changfeng , Liu Shangqi , Liu Chunze
Published: June 2012

Non-Condensable Gasses (NCG) are gasses such as carbon dioxide, hydrogen sulphide, methane and nitrogen which can be present in a SAGD steam chamber but do not condense into the liquid phase to any large degree. Recent theoretical and laboratory work has shown that these gasses can enhance the thermal efficiency of SAGD without a significant reduction in productivity. There has been considerable discussion, both positive and negative, regarding the behavior of these gases in the steam chamber. Benefits to SAGD productivity have been suggested by some, while other authors have projected impacts on bitumen recovery.

This paper highlights how numerical simulation can be used as a tool to analyze the impact of NCG in SAGD through modification of K-value based on thermodynamic theory. As the simulated bitumen production rates were much less than those found in the field. It is necessary to adjust physical properties so as to make the gas more soluble, e.g. by artificially modifying the K values. The author has developed a method of modeling the effects of NCG in a steam zone using the new modified K value table. This paper will present the results of these simulations with and without modification of K-value and predict impact of NCG on SAGD performance.
Impact of the Distribution of Calcite Concretions on Performance of SAGD
Authors: Gates I. D. , Wang J. Y. , Robinson B. , Bunio G.
Published: June 2012

Carbonate-cemented concretions in Grand Rapids oil sand reservoirs are common with length scales up to several meters wide and high. The concretions can be found embedded in unconsolidated oil sands distributed irregularly within the formation. From a Steam-Assisted Gravity Drainage (SAGD) recovery process point of view, calcite concretions are nonproductive rock which can interfere with the growth of steam chambers. However, depending on the length scales of the spatial distribution, sizes, and shapes of the concretions, thermal dispersion can occur which can potentially enhance heat transfer within the oil sands formation. Thus, although calcite concretions are heat sinks that reduce the oil in place, they could potentially aid in steam chamber conformance. Heterogeneity of the SAGD steam chamber depends on the heterogeneity of the underlying geology. Here, the impact of spatial distributions and size of concretions on the performance of SAGD is examined. The temperature distribution (chamber growth) and steam chamber height and shape are examined. The results reveal that steam chamber growth and conformance is impacted by the presence of calcite concretions. Concretion nearer the SAGD wellpair have the largest impact since they interfere with steam chamber growth from the earliest stages of the process and the impact grows throughout the process yielding cold spots along the wellpair. This provides a means to decide length scales for placement of wellpairs to optimize chamber conformance and SAGD performance.
An Evaluation of Air Injection as a Follow-Up Process to Cyclic Steam Stimulation in a Heavy Oil Reservoir
Authors: Lei H. , Wang J. Y. , Gates I. D.
Published: June 2012

The majority of bitumen and extra heavy oil is produced by steam-based recovery processes yet these methods are energy intensive and emit large amounts of greenhouse gas to the atmosphere. Not only is the emissions intensity high due to steam generation, but also the water handling and treating facilities required for these recovery methods is expensive both to purchase and install but also to operate. A lot of focus of research has been on reduced steam processes, such as thermal-solvent techniques, as well as in situ combustion technologies such as Air Injection. Here, air injection is evaluated as a follow-up process to Cyclic Steam Stimulation in a deep thick heavy oil reservoir. The reservoir simulation model is obtained from a history-match to existing cyclic steam stimulation (CSS) field data. The results demonstrate that an additional 33% oil recovery is reached by using an air injection follow-up process. This gives a total recovery factor equal to about 55%. Based on incremental cumulative energy-to-oil ratio, the results suggest that air injection follow-up processes should be considered for post-CSS operations but that further improvement of the energy intensity is needed.
A New Mathematical Model for Colloidal Flow in Rocks: Accounting for Pore Geometry and Network Topology in Bimodal Media
Authors: You Z.. , Bedrikovetsky P..
Published: June 2012

A new stochastic model for suspension/colloidal transport in porous media is developed accounting for the retention mechanism of size exclusion. The medium is modelled by two-pore-size network with triangular pore shape. The micro scale model is established using distribution functions and the macro scale equation system is generalised. The analytical solution is obtained for deep bed filtration of distributed particles in bimodal media. Comparison between model prediction and experimental data shows good agreement, which validates the proposed model.
Controlled Electrolytic Metallics-An Interventionless Nanostructured Platform
Authors: Salinas Bobby J. , Xu Zhiyue , Agrawal Gaurav , Richard Bennett
Published: June 2012

Completion devices such as fracturing balls, discs, and plugs are often used for downhole fluid and pressure control. Current polymer material must be milled away, flowed back or otherwise removed before production. Severe deformation of currently used materials that prevent flowback have been reported, requiring costly intervention operations to either remove or replace the tools and resulting in higher operational inefficiency. Using controlled electrolytic metallic (CEM) material eliminates this possibility. The new material is inherently designed for in-situ digestion in downhole environments at a controlled customizable rate.

Conventional degradable materials have a well-known tradeoff between dissolution rate and mechanical strength, which limits their utility. Increasing the dissolution rate often lowers the mechanical strength of the material below an acceptable threshold for many downhole applications. Using a reactive material with a blended nanostructured coating of ceramic and/or metallics provides the strength for initial operation and the ability to control the rate of corrosion later in the product's operation cycle. CEM materials have three times the strength of their base material and the corrosion rate can vary by a factor of several hundred, as compared to the base material. Corrosion rate could be further accelerated in HCl, thus providing operational flexibility. Experiments in various fluids and temperatures validate the corrodibility of CEM material.

This paper will present the chemistry and layering of the nanoscale coating within the grain structure, the unique material properties, and lab testing data of this truly interventionless nanostructured material technology.
CFD Investigation of Flow and Heat Transfer of Nanofluids in Isoflux Spirally Fluted Tubes
Authors: Salama Amgad , Azamatov Abdulaziz , El Amin M. F. , Sun Shuyu , Huang Huancong
Published: June 2012

In this work, the problem of flow and heat transfer of nanofluids in spirally fluted tubes is investigated numerically using the CFD code Fluent. The tube investigated in this work is characterized by the existence of helical ridging which is usually obtained by embossing a smooth tube. A tube of diameter of 15 mm, 1.5 mm groove depth and a single helix with pitch of 64 mm is chosen for simulation. This geometry has been chosen for simulation because it has been investigated experimentally for pure fluids and would, therefore, provide a verification framework with our CFD model. The result of our CFD investigation compares very well with the experimental work conducted on this tube geometry. Interesting patterns are highlighted and investigated including the existence of flow swirl as a result of the existence of the spirally enhanced ridges. This swirl flow enhances heat transfer characteristics of this system as reported in the literatures. This study also shows that further enhancement is achieved if small amount of nanoparticles are introduced to the fluid. These nanoparticles (metallic-based nanoparticles) when introduced to the fluid enhances its heat transfer characteristics.
Stabilizing Nano Particle Dispersions in High Salinity, High Temperature Downhole Environments
Authors: McElfresh Paul , Wood Marodi , Ector Daniel
Published: June 2012

Nanoparticle dispersions (NPDs) are an emerging new technology in the oil and gas industry which can be applied to EOR, well remediation, and formation damage removal to stimulate hydrocarbon production using the unique properties that colloidal particles possess. Nanoparticles have a high surface area to volume ratio allowing a greater efficiency for chemical interactions to occur. However, nanoparticle dispersions are often difficult to stabilize in harsh downhole environments. The dispersion can quickly become unstable and agglomerate when the fluid is subjected to changes in pH, or encounters increased salinity and/or temperature. Agglomeration renders the fluid ineffective, and at worst can cause severe damage to the formation. The development of highly concentrated nanoparticle dispersions stable in high TDS brine at high temperatures has been achieved and verified in the laboratory with imbibition tests and dynamic core flow experiments.

NPDs can be stabilized in the reservoir by altering charge density, hydrodynamic diameter, and the zeta potential of the particles. This is accomplished by surface modification, as well as with the addition of stabilizing chemistry.

This paper presents solutions to the destabilizing elements encountered in the reservoir, that until now have inhibited the downhole utilization of nanoparticle dispersions. Stability research of NPD fluids in brines empirically illustrates that by chemically modifying the particle surface and the surrounding aqueous environment, the fluids will remain properly dispersed and active in destabilizing bottomhole conditions. This will further pave the way for industry research into new applications of nanoparticle based fluid systems.
Nanomaterials in Fracturing Applications
Authors: Lafitte Valerie , Tustin Gary , Drochon Bruno , Parris Mike
Published: June 2012

Cross-linked fluids have been used in the oil industry for more than 40 years in applications such as hydraulic fracturing and water control. Today, these fluids need to be reformulated in order to respond to new challenges, such as harsher reservoir conditions and they also need to comply with tighter environmental legislation. Nanotechnology may well provide an answer to this end. By utilizing unique features such as high surface/volume ratio and specific surface functionalisation, we are able to change the nature of the cross-linking and hence better achieve the required gel properties.

This paper describes the synthesis of a series of boronic acid functionalised nanoparticles and their application to guar crosslinking. In particular, the synthesis of 15 nm boronic acid functionalized polymeric nanomaterials (also called nanolatexes), using microemulsion polymerization were investigated. Such nanodevices showed, for the first time to our knowledge, unique crosslinking properties with guar. It was found that these larger crosslinkers, as compared to standard borate molecules, can crosslink guar at much lower polymer concentrations, effectively lowering the critical overlap concentration of the polymer. We were also able to generate stronger gels over a wide range of guar concentrations. Furthermore, the optimal amount of boron required to achieve these gels was of the order 20 times lower than that with conventional borates.

This result suggested that the efficiency of the crosslinking was much higher in the case of the nanoparticles. Several rheological and stability tests were performed under field conditions and these indicate these systems have potential uses as oilfield materials. The influence of the surface chemistry of the nanoparticles was also studied along with other functionalization of other nano-materials, such as nano-silica and graphite. These results will also be presented.
Improvement of Silicate Well Treatment Method by Nanoparticle Fillers
Authors: Lakatos I.. , Lakatos-Szabó J.. , Szentes G.. , Vágó Á..
Published: June 2012

The divers silicate technologies have been used more than 120 times in Hungary, Germany, Serbia and Oman for reservoir conformance improvements including water shut-off and profile correction in oil and gas wells, restriction of gas conning in oil reservoirs, blocking of gas leakage in gas storage and restriction of CO2 migration in a collapsed well. The advanced methods based on simultaneous application of polymers, urea, humates, etc. recognizing that the pure silicate gels have disadvantageous properties under reservoir conditions. The present efforts were focused on replacement of some additives in gel-forming solutions; meanwhile the efficiency of the method remained the same or even better under various formation conditions. Based on earlier results, it was proved that addition of water-soluble polymers to silicates improved significantly the stability and flexibility of such gels. Beside the beneficial effects, however, the polymer-containing silicate solutions may also have some drawbacks to placement and in-situ dispersion of treating fluids. These difficulties can be eliminated by replacing polymers with nanomaterials. The detailed laboratory studies focused on polymer free, but SiO2 and Al2O3 nanoparticle containing silicate solutions. Results of laboratory study of gelation mechanism, rheological properties, flow behavior, and nanoparticle sizing served to draw fundamental conclusions. It has been shown that these nanomaterials can replace completely the polymers, they are compatible with even low permeability porous, and fractured media, and less pH-controlling agent is necessary to catalyze gelation.

Recently, the efficient and flexible silicate technologies arouse high interest in oil and gas production. Their environment friendly solutions are particularly appreciated. Replacing the often-questionable synthetic polymers in gel-forming solutions with nanomaterials is the final step toward to use harmless chemicals in absolute sense. Based on the laboratory tests the silicate/nonmaterial method was tailored to oil producers operating in the largest Hungarian oil field. The pilot tests will be carried out in 2013. Combining silicates and nanomaterials, new and efficient method was developed for water shutoff and profile correction in various oil and gas fields and that may open new vistas in improvement of well performance of both producers and injectors.
Use of Nanomaterials in Cementing Applications
Authors: Patil Rahul , Deshpande Abhimanyu
Published: June 2012

The two principal functions of oilwell cementing are to restrict fluid movement between zones within the formation and to bond and support the casing. Apart from these, the cement sheath also protects casing from corroding, protects the casing from shock loads when drilling deeper, and plugs lost circulation or thief zones. Once cement is placed in the wellbore, initial setting occurs wherein development of compressive strength becomes more important for further drilling operations. Early strength development is important to help ensure structural support to the casing and hydraulic and mechanical isolation of downhole intervals. Delays in strength development cause significant amounts of lost time because of the need to wait on cement (WOC). Typically, an accelerator is often used to enable early strength development in cement. It is desired that an accelerator should improve overall compressive strength without causing excessive gelation.

Nanomaterials (being smaller in size and higher in surface area) are used in several fields, including catalysis, polymers, electronics, and biomedicals. Because of a higher surface area, these materials can also be used in oilwell cementing to accelerate the cement hydration process. Moreover, they are often required in small quantities. This paper documents a case in which nanosilica was used in cement formulations to develop high early strength. Nanosilica also helps enhance final compressive strength and helps control fluid loss. Using the correct quantity of nanosilica, it is possible to design cement slurry with low rheology and good mechanical properties while controlling fluid loss.
Synthesis and Size Control of Monodispersed Al-sulphonated Polycarboxylic Acid (Al-SPCA) Nanoparticles with Improved Squeeze Performance and Their Transport in Porous Media
Authors: Yan Chao , Kan Amy T. , Wang Wei , Wang Lu , Tomson Mason B.
Published: June 2012

Sulphonated polymers are used in oilfield for scale inhibition. In this study, Al-sulphonated polycarboxylic acid (SPCA) hybrid nanoparticles were prepared by an environmentally friendly approach. Particle size of these materials was controlled at about 80 nm by applying hydrothermal synthetic method with urea as slow neutralization agent. Reaction parameters such as concentration of salt solution, reaction time, urea concentration and ionic strength were investigated to optimize nanoparticle synthesis. The mobility of Al-SPCA hybrid nanoparticles decreases dramatically in 1% (w/w) KCl solution. Using phosphino-polycarboxylic acid (PPCA) as dispersant, nanoparticles were well suspended in 1% KCl solution. Absorption of PPCA to hybrid nanoparticles increases its negative surface charge and decreases particle deposition. The retention and long term flowback performance of hybrid nanoparticles were compared with the neat chemical squeeze simulation in ground core column experiments. The results showed that the slow release of sulphonated polymer from hybrid nanoparticles in porous medium leads to an enhanced squeeze treatment efficiency and successful inhibitor treatment in the oil field.
Using Nanoscale Dispersed Particles to Assist in the Retention of Polyphosphinocarboxylic Acid (PPCA) Scale Inhibitor on Rock
Authors: Ghorbani N.. , Wilson M.. , Kapur N.. , Fleming N.. , Neville A..
Published: June 2012

Enhancing the life of scale inhibitor squeeze treatments in the oil and gas industry is a major means of increasing productivity. Having an understanding of the route by which inhibitors such as PPCA can adsorb to the rock surface is important in designing new squeeze methodologies. Nanotechnology is emerging as an enabling technology in many fields including medicine, transport and pharmaceutical. Thus far there has been research activity in novel uses of nanotechnology in the oil and gas sector but there is still enormous potential for it to be further exploited. In the squeeze process, where fluids are pushed through the rock pore space, there is potential for nanotechnology to enhance the delivery of species (i.e. placement) and/or to assist in the "binding" of active species to the rock surfaces. It is in this area the current work is focused. In this paper we investigate the adsorption of PPCA (a common scale inhibitor) onto a C-based nanoparticle (CBN). The adsorption of PPCA on the CBN is quantified as a function of time and the concentration of the CBN. Experimental data from Inductively Coupled Plasma (ICP) illustrates a substantial adsorption of PPCA on CBNs comparing to the adsorption of PPCA on the rock. Various concentration ratios of CBNs and PPCA have been tested in dynamic adsorption tests to understand the effects of absorbent and absorbate concentration. The mass of adsorbent was assumed to be key factor in adsorption of PPCA on CBNs; indicative of the number of active sites on the nanoparticle.
Well Test Analysis of Horizontal Wells and Vertical Wells with Hydraulic Fracturing Applied in Heavy Oil Fields
Authors: Kovalenko Igor V.
Published: June 2012

Today considerable amount of hard-to-recover reserves from low reservoir properties formations or high-viscosity oil are involved into development. Hydraulic fracturing or horizontal wells drilling are applied to provide economic development. On the one side the low piezoconductivity value reduces the rate of pressure redistribution in the reservoir around the well. On the other side hydraulic fracture or horizontal well move away the radial flow in the reservoir for a considerable distance from the well. The joint presence of these two conditions leads to a failure to achieve radial flow at the appropriate times resulting in a high uncertainty during well testing interpretation.

This article describes approaches of uncertainties reduction during the well testing interpretation in case of failure to achieve the late pseudoradial flow. The suggested method is based on the application of the special filtration equations in the early regimes to linear drain where as an example the horizontal well or hydraulic fracturing in the reservoir was provided.

The presented solutions were successfully applied in both the heavy oil fields and in the other types of fields where the late filtration radial regime was not achieved during the well testing.
Preventing Adhesion of Scale on Rock by Nanoscale Modification of the Surface
Authors: Kazemi N.. , Wilson M.. , Kapur N.. , Fleming N.. , Neville A..
Published: June 2012

Organosilane has been explored previously as a kaolinite fixing agent, and surface modifier to enhance adsorption of scale inhibitors. Here, self-assembled organosilane films are investigated for their potential to prevent scale deposition directly, that is without the presence of scale inhibitors. Film formation on quartz crystals is analysed using a quartz crystal microbalance, which suggests that different film structures can be created using the same organosilane molecule. Brine tests using singlecrystal quartz coupons coated with organosilane indicate that calcium carbonate scale deposition can be reduced by 66%.
Recent Progress of High-Pressure Air Injection (HPAI) Process in Light Oil Reservoir: Laboratory Investigation and Field Application
Authors: Jia Hu , Yuan Cheng-Dong , Zhang Yu-Chuan , Peng Huan , Zhong Dong , Zhao Jin-Zhou
Published: June 2012

High-Pressure Air Injection (HPAI) in light oil reservoirs has been proven to be a valuable IOR (Improved Oil Recovery) process and caused more attention worldwide. In this paper, we give an overview of the recent progress of HPAI technique, based on a review of some representative HPAI projects including completed and ongoing projects. Some most important aspects for HPAI field application are discussed in depth, including reservoir screening criterion, recognition of recovery mechanism, laboratory study, numerical simulation, gas breakthrough control, tubing corrosion consideration and safety monitoring. With the successful HPAI application in Zhong Yuan Oil Field in China, it is estimated that foam or polymer gel assisted air injection should continue to grow in the next decade as a derived technology of HPAI for application in high-temperature high-heterogeneity reservoirs. The purpose of this paper is to investigate the ranges of some key parameters, new understanding based on laboratory test and successful field application, thus to provide lessons learnt and best practices for the guideline to achieve high-performance HPAI project.
Enhanced CO2 Storage In Deep Saline Aquifers By Nanoparticles: Numerical Simulation Results
Authors: Singh Harpreet , Hosseini Seyyed A. , Javadpour Farzam
Published: June 2012

Javadpour and Nicot (2011) presented a novel idea of adding nanoparticles (NPs) to injected CO2 (aka. nano-CO2) to expedite convective mixing and decrease the potential of buoyancy flow of CO2. In this paper we implement that idea through the use of compositional numerical simulations.

Numerical simulation scheme is divided into two scenarios. The first scenario represents a saline aquifer of 20 m thickness, and extending 100 m laterally from the wellbore. This scenario is modeled to show the effect of nano-CO2 injection on field scale for 200 years. The second scenario represents a small part of the field scale model with dimension of 7.5 cm × 7.5 cm. These small scale models show density contrast effect on convective fingers at the brine/nano-CO2 interface.

Comparison of results between injection of nano-CO2 and normal CO2 clearly show that nano-CO2 exhibits the capability of improved mixing and reduced buoyancy driven flow in both scenarios. In scenario 1, nano-CO2 plume is able to dissolve deeper and move less laterally forward than the normal CO2 plume. In scenario 2, the CO2 dissolves and forms fingers due to gravity driven flow in a heterogeneous medium. The difference in length of convective fingers between nano-CO2 and CO2 increases with time.

Adding nanoparticles with the injected CO2 presents a great potential in quick mixing with the in-situ brine which will reduce the chances of leakage through the sealing. Injection of nano-CO2 can obviate the use of some of the monitoring techniques post injection. Waste materials such as depleted Uranium can be used as nanoparticles which favor economic feasibility of the proposed idea.
Quantitative Identification of Steam Breakthrough Channel after Steam Flooding in Heavy Oil Reservoirs
Authors: Zheng Qiang , Liu Huiqing , Li Fang , Zhang Jie , Wang Changjiu
Published: June 2012

In the development process of oilfields, dynamic data, which is easy to obtain, reflects the connectivity between injection wells and production wells commendably. A set of method has been established in this paper for studying on steam breakthrough channels quantitatively by using dynamic data. Firstly, steam breakthrough wells were identified through curves of watercut and temperature. Then, breakthrough relations were identified with the correlation coefficient method. Lastly, an analytic model, in which pressure and temperature were considered, was established to calculate the breakthrough channel volume. A production well named L31815 in LZ27 block in Henan oilfield in China was systematically analyzed by using the method established. The whole block was further analyzed, and the distribution map of steam breakthrough channels and the breakthrough channel volume were obtained. The results show that the steam breakthrough level around L31513 is serious, while the steam breakthrough level around L31917 is mild. Therefore, steam breakthrough does not only occur limitedly inside a well group, but also sometimes occurs between wells in different well groups. It is proved that the results are credible. The calculation of the breakthrough channel volume provides a theoretical basis for bringing the measures like plugging into operation.