bluuebunny/crossref_metadata_2025_split huggingface dataset:
Genetic Evidence Links the ASTRA Protein Chaperone Component Tti2 to the SAGA Transcription Factor Tra1
Authors: Genereaux Julie , Kvas Stephanie , Dobransky Dominik , Karagiannis Jim , Gloor Gregory B , Brandl Christopher J 
Published: April 2012

Abstract
Tra1 is a 3744-residue component of the Saccharomyces cerevisiae SAGA, NuA4, and ASTRA complexes. Tra1 contains essential C-terminal PI3K and FATC domains, but unlike other PIKK (phosphoinositide three-kinase–related kinase) family members, lacks kinase activity. To analyze functions of the FATC domain, we selected for suppressors of tra1-F3744A, an allele that results in slow growth under numerous conditions of stress. Two alleles of TTI2, tti2-F328S and tti2-I336F, acted in a partially dominant fashion to suppress the growth-related phenotypes associated with tra1-F3744A as well as its resulting defects in transcription. tti2-F328S suppressed an additional FATC domain mutation (tra1-L3733A), but not a mutation in the PI3K domain or deletions of SAGA or NuA4 components. We find eGFP-tagged Tti2 distributed throughout the cell. Tti2 is a component of the ASTRA complex, and in mammalian cells associates with molecular chaperones in complex with Tti1 and Tel2. Consistent with this finding, Tra1 levels are reduced in a strain with a temperature-sensitive allele of tel2. Further agreeing with a possible role for Tti2 in the folding or stabilization of Tra1, tra1-F3744A was mislocalized to the cytoplasm, particularly under conditions of stress. Since an intragenic mutation of tra1-R3590I also suppressed F3744A, we propose that Tti2 is required for the folding/stability of the C-terminal FATC and PI3K domains of Tra1 into their functionally active form.
Cytoplasmic and Genomic Effects on Meiotic Pairing in Brassica Hybrids and Allotetraploids from Pair Crosses of Three Cultivated Diploids
Authors: Cui Cheng , Ge Xianhong , Gautam Mayank , Kang Lei , Li Zaiyun 
Published: April 2012

Abstract
Interspecific hybridization and allopolyploidization contribute to the origin of many important crops. Synthetic Brassica is a widely used model for the study of genetic recombination and “fixed heterosis” in allopolyploids. To investigate the effects of the cytoplasm and genome combinations on meiotic recombination, we produced digenomic diploid and triploid hybrids and trigenomic triploid hybrids from the reciprocal crosses of three Brassica diploids (B. rapa, AA; B. nigra, BB; B. oleracea, CC). The chromosomes in the resultant hybrids were doubled to obtain three allotetraploids (B. juncea, AA.BB; B. napus, AA.CC; B. carinata, BB.CC). Intra- and intergenomic chromosome pairings in these hybrids were quantified using genomic in situ hybridization and BAC-FISH. The level of intra- and intergenomic pairings varied significantly, depending on the genome combinations and the cytoplasmic background and/or their interaction. The extent of intragenomic pairing was less than that of intergenomic pairing within each genome. The extent of pairing variations within the B genome was less than that within the A and C genomes, each of which had a similar extent of pairing. Synthetic allotetraploids exhibited nondiploidized meiotic behavior, and their chromosomal instabilities were correlated with the relationship of the genomes and cytoplasmic background. Our results highlight the specific roles of the cytoplasm and genome to the chromosomal behaviors of hybrids and allopolyploids.
Improving Volumetric Efficiency in an Unconsolidated Sandstone Reservoir with Sequential Injection of Polymer Gels
Authors: Saez M. , Paponi H. , Cabrera F. , Muñiz G. , Romero J. , Norman C. 
Published: April 2012

Abstract
In March 2008 Petro Andina Resources implemented the first polymer gel treatment in an unconsolidated sandstone reservoir in Argentina's northern Patagonia. The project was implemented in the Jagüel Casa de Piedra and El Corcobo Norte fields, located in the Neuquen basin. Oil production began in November 2004 followed by water injection project approximately one year later for pressure support. However, sand production and the generation of wormholes resulted in severe water channeling detrimenting volumetric efficiency. Tracer studies confirmed rapid transit times between injector and offset producers in patterns with an average well spacing of 280 meters.
The first conformance pilot occurred in 2008 with a non-conventional polymer injection procedure that included a series of small volume, high concentration gel slugs followed by a short shut-in period. The objective of this strategy was to allow the gelation reaction to occur before reaching the offset producing wells. Successive gel slugs were placed behind the initial gel injection in order to block a significant volume of the highest permeability wormholes. Extensive diagnostics were applied before and after the initial polymer gel treatment, including tracers, monitoring of injection pressure and analysis of fluid production data. Based on a sustained WOR reduction from 6 to 1 in the pilot project after approximately one year, nine additional conformance gel treatments were implemented as of May 2011.
The treatment designs were modified in successive projects based on lessons learned during preceding conformance campaigns. One of the major challenges was to reduce the incidence and consequences of gel breakthrough in offset producing wells.
The paper will discuss the reservoir diagnostics that led to the selection of polymer gel as a method used to mitigate severe water channeling in this unconsolidated sandstone reservoir and the evolution of the conformance strategies applied in subsequent treatments from 2009 to 2011.
Application of a Novel Amylum-Cellulose Nutrient System for Microbial Flooding in Dagang Oilfield, China
Authors: Feng Qing-xian , Cheng Hai-ying , Ma Xian-ping , Dong Han-ping , Ma Ting 
Published: April 2012

Abstract
Microorganisms inhabiting oil reservoirs can be used for microbial enhanced oil recovery (MEOR) due to their high adoptability and ability to produce oil-releasing metabolites in-situ. The compositions and function of the nutrient injected for stimulation of microbial activity is one of the keys to successful the technology. In our previous studies, we found that depletion of nutrient blend due to presence of "thief zone" with high rock permeability, led to insufficient activity of indigenous microorganisms in reservoirs. Eventually the poor additional oil production was observed. Novel multi functional amylum-cellulose nutrient was developed in this study to provide both nutrition for microorganisms as well as material for modify profile.
Reservoir physico-chemical characteristics, concentration of nutrients and microbial activity were surveyed systematically. It was shown, that nutrient activated microbial growth under aerobic and anaerobic condition, and hydrocarbon oxidizing bacteria and fermentative microorganisms played most considerable roles in microbial consortia. Microorganisms were able to oxidize oil to CH4 and CO2 with excretion hydrocarbon emulsifiers and other biosurfactants (rhamnoilpid with C6-C12 long chain fatty acid). Heterogeneous sandpacked column model with three stages nutrients flooding release delaying nutrient solution breakthrough front and enlarged effect range of microorganisms due to viscosity production, particles of cellulose and zoogloea on surface of cellulose particle while bacteria growth. Synergetic MEOR effect of the thief zone plugging and local oil displacement resulted in 15-20% increase of oil recovery in comparison with regular water flooding.
The field pilots were carried out in blocks. Special nutrient (75 tons) was injected and followed by monthly injections of 32000 cubic meters of air/water blend. The shift in microbial activities and other reservoir parameters was monitored. The injection water pressure was increased 2.2MPa and 5075 bbl of oil was increased.
Upgridding Under Multiphase Flow Conditions
Authors: Kelkar Mohan , Sharifi Mohammad 
Published: April 2012

Abstract
Due to advances in computer technology, geo-scientists are increasingly able to build reservoir models which can incorporate significant geological details. It is not unusual to find geological models which contain millions of cells. Flow simulating such models is still a challenge as running a typical simulation model takes two orders of magnitude more time than generating a geological model. Upgridding the geological model to reduce the number of grid blocks while maintaining the essential heterogeneity details to preserve the dynamic performance is the only solution to this problem.
In the literature, many solutions are proposed to upgrid the geological model. The simple static solutions involve combining layers with similar static properties so that the heterogeneous details are preserved. In our paper, we take the method one step further. It has been observed in the past that upgridding should be dependent on the flow process. That is, the way the layers are combined would be different for depletion drive compared to water flooding. The displacement of fluids is strongly dependent on the type of drive; hence, rearrangement of the fine scale layers has to be different to capture this behavior.
In our approach, we propose a method of upgridding which can be applied for either secondary or tertiary recovery processes. Our method is analytical and is based on an idea that fractional flow of a fine scale model has to be preserved on a coarse scale. We use fractional flow on a fine scale model and define our error as the difference between fractional flows of a coarse scale vs. fine scale. We combine layers which minimizes this difference. Using our procedure, we demonstrate that for favorable mobility ratio, it is better that we isolate low permeability layers; whereas, for adverse mobility ratio, we need to isolate high permeability layers. Using both synthetic and field cases, we demonstrate that our proposed method provides superior upgridding compared to other methods currently available in the literature.
New Insights into Clay Swelling: Supercritical CO2 Interaction with Montmorillonite
Authors: AlOtaibi Fawaz M. , AlKhaldi Mohammed H. , Funk Jim J. , Shen Shouwen X. 
Published: April 2012

Abstract
Clay swelling has been recognized as one of the main mechanisms of formation damage during various well operations. Many researchers have extensively investigated the effects of many parameters such as pH, and salinity of water-based fluids on montmorillonite swelling behavior. However, studies of supercritical carbon dioxide (CO2) interactions with montmorillonite clay have been limited. These interactions can affect injectivity during enhanced oil recovery (EOR) operations. Therefore, the main objective of this study is to investigate the swelling behavior of montmorillonite in supercritical CO2 as a function clay original state: dry or hydrated.
The swelling behavior of both Ca-montmorillonite and Na-montmorillonite clays in distilled water and supercritical CO2 was investigated at temperature values of 25°C. Nearly 1 g of each clay was soaked in 10 g of distilled water at the desired temperature and atmospheric pressure for 24 hours. Then, these swollen clays were soaked in supercritical CO2 for 24 hours at the desired temperature and at nearly 2,000 psi. Absorbed water content and increase in interlayer space, after each soaking stage, were determined using nuclear magnetic resonance (NMR) and X-ray diffraction (XDR). Additionally, environmental scanning electron microscope (ESEM) analysis was used to explore the effect of liquid-like CO2 on clay structure of both dry and hydrated Ca and Na- montmorillonite clays.
Results based on this study have indicated that the swelling degree of Na-montmorillonite was higher than that of Ca- montmorillonite after being soaked in distilled water for 24 hours. After absorbing distilled water at 25°C, the (001) d- spacing of dry Ca-montmorillonite of 14.95 Å increased by 25%, while the (001) d-spacing of dry Na-montmorillonite of 11.67 Å increased by 60.4%. The (001) d-spacing of these swelled clays decreased after they were soaked in supercritical CO2. For example, the (001) d-spacing of hydrated Na-montmorillonite of 18.72 Å decreased by nearly 25% after soaking in supercritical CO2 for 24 hours at 25°C and 2,000 psi. This paper presents new interesting interaction results of shrinkage, swelling behavior and structure change of montmorillonite clay after interaction with supercritical CO2, which are important for different EOR operations.
Studies On Foam Flooding EOR Technique For Daqing Reservoirs After Polymer Flooding
Authors: Qingfeng Hou , Zhu Youyi , Luo Yousong , Weng Rui 
Published: April 2012

Abstract
Most of the high permeability reservoirs in Daqing oil field have been conducted by water flooding and polymer flooding.
The average oil recoverable recovery has reached to 53% after polymer flooding. Currently, the further development of such reservoirs has become a big challenge due to both serious heterogeneity reservoirs and highly dispersed residual oil. Foam flooding, as a candidate EOR technique integrating both properties of gas injection technique and chemical flooding, has been proposed. In this study, systematic laboratory experiments on foam flooding EOR technique for Daqing reservoirs after polymer flooding have been performed.
Several operating parameters have important influences on the recovery efficiency. ➀ Both the foamability and stability are the key factors to ensure high performance of recovery. The foam formulas were optimized with good performance of foamability and stability. ➁Injecting mode is another important factor. Three main injection modes, including co-injection of gas and solution, alternative injection of gas and solution, and direct injection of foam were compared. The direct injection of foam is the most effective mode and the alternative injection of gas and solution is the poorest. ➂The gas liquid ratio can also affect the flooding efficiencies greatly. The optimized gas liquid ratio was proposed as 3:1–4:1 for direct injection mode at the reservoirs condition. EOR effect evaluation of foam flooding after polymer flooding has been conducted upon three-layer positive rhythm sandpack cores flooding tests. Results indicate that foam flooding can contribute 12–22% OOIP recovery even if the recovery after polymer flooding is nearly 55%. The obviously increasing of injection pressure during the foam flooding indicates that nitrogen foam flooding has excellent profile control ability.
Foam flooding can block thief zones for highly heterogeneous reservoirs. It may become a promise EOR method for Daqing reservoirs after polymer flooding.
Assessment of Foam for GOR Control to Optimize Miscible Gas Injection Recovery
Authors: Cubillos Helber , Montes Jesús , Prieto Carlos , Romero Pedro 
Published: April 2012

Abstract
Miscible gas flood in a CEPSA-operated oil field has matured and, over the years, oil has been produced at an increasing gasoil ratio (GOR). Even though the gas displacement mechanism is miscible, or close to miscible, the poor mobility ratio between injected gas and displaced oil has led to inefficient sweep of the reservoir.
The use of foam for gas mobility control is a proven IOR technology that can greatly improve gas injection conformance and hence improve volumetric sweep efficiency in secondary or tertiary recovery processes. This paper presents the results of comprehensive laboratory studies undertaken to define a foam system that will reduce gas mobility and preclude any risk of affecting formation injectivity.
We evaluated four surfactants to establish the Foaminess, Mobility Reduction Factor (MRF) and impact of hardness, oil presence and surfactant concentration on foam strength: AOS C12-14 and AOS C14-16, LAS and Fluorobetaine. We found AOS C12-14 and AOS C14-16 to be the best foamers under screening conditions (60 bar, 90 °C): both significantly reduced mobility. AOS was not brine-sensitive but in the presence of oil, the foam performance was reduced. Optimum concentration regarding cost and effectiveness was found to be 5000 ppm. We demonstrated that strong foam can be formed under reservoir conditions (200 bar, 96 °C), using the Surfactant-Alternating-Gas injection technique.
We have submitted a request for approval of a field pilot test which will be the first application of foam as an IOR technology in this field. If success is demonstrated in the field, the proposed approach should be helpful for field operators facing similar production optimization challenges or, for example, Foam-Assisted Water Alternating Gas (FAWAG) projects.
Visualization of Oil Recovery by CO2-Foam Injection; Effect of Oil Viscosity and Gas Type
Authors: Emadi Alireza , Sohrabi Mehran , Jamiolahmady Mahmoud , Ireland Shaun 
Published: April 2012

Abstract
CO2 injection is a well-established enhanced oil recovery technique which has been successfully applied in conventional oil reservoirs where it can vaporize light hydrocarbon components and displace the oil miscibly. In heavy oil reservoir, CO2 does not develop miscibility but it can significantly promote recovery by dissolving in the oil and reducing its viscosity. Heavy oil viscosity reduction upon mixing with CO2 can be substantial and reductions up to two orders of magnitude can be achieved. However, displacement of viscous and heavy oil by CO2 is generally perceived as being inefficient and hence, very limited number of heavy oil fields have been considered for CO2 injection. There are two main reasons for this; (1) the large viscosity contrast between heavy oil and CO2 which results in viscous fingering and; (2) the slow rate of CO2 diffusion in heavy oil.
The use of CO2 foam represents an opportunity to reduce mobility of CO2 and improve sweep efficiency and at the same time facilitate CO2 dissolution by increasing the contact area between the oil and CO2. The application of foam injection for enhanced heavy oil recovery has not been widely reported in the literature and hence the potential of foam for improving heavy oil recovery is by and large untested.
In our previous works, we reported a series of micro-scale visualization experiments to investigate potentials of sub- critical CO2 and CO2-foam injection for recovery of a medium-heavy crude oil. The results showed that if strong CO2-foam forms in porous medium, it can drastically increase the rate of oil recovery and reduce the residual oil saturation. This paper presents the results of a new series of visualization experiments to investigate the performance of sub-critical CO2-foam for recovery improvement in an extra-heavy crude oil. In the first part of this paper, the effect of oil viscosity on oil recovery and displacement mechanisms has been investigated. The results show that while foam can significantly accelerate and improve oil recovery by CO2 injection, the increase in oil viscosity slows down the process of oil recovery by CO2-foam and may result in weakening of some of the pore scale displacement mechanisms.
In the second part of the paper, the results of an experiment conducted using the same extra-heavy crude oil and surfactant with N2-foam (instead of CO2) is presented. The results show that despite forming strong foam in the porous medium, the oil displacement process is much less efficient during N2-foam injection compared to CO2-foam. The results clearly demonstrate the potential of CO2-foam for enhancing heavy oil recovery for very viscous crudes as a technically viable non-thermal oil recovery method. The results of these experiments significantly improve our understanding of the processes involved in heavy oil recovery by CO2-foam and the pore scale differences with the example of N2-foam injection.
Investigating Low-Salinity Waterflooding Recovery Mechanisms in Sandstone Reservoirs
Authors: Aladasani Ahmad , Bai Baojun , Wu Yu-Shu 
Published: April 2012

AbstractNumerous core-flooding experiments have shown that Low-Salinity Water Flooding (LSWF) could improve oil recovery in sandstone reservoirs. However, LSWF recovery mechanisms remain highly contentious primarily because of the absence of crucial boundary conditions. The objective of this paper is to conduct a parametric study using statistical analysis and simulation to measure the sensitivities of LSWF recovery mechanisms in sandstone reservoirs. The summary of 411 coreflooding experiments discussed in this paper highlights the extent and consistency in reporting boundary conditions, which has two implications for statistical analysis: (1) Even though statistical correlations of the residual oil saturation to chlorite (0.7891) and kaolinite (0.4399) contents, as well as the wettability index (0.3890), are comparably strong, the majority of dataset entries are missing, and a prediction model cannot be generated; (2) If a prediction model is generated without clay content values and a wettability index, even though LSWF emphasizes wettability modification by virtue of oil aging time and the strong influence of brine cation and divalent ion concentrations on Sor, the prediction model's regression curve and confidence level are poor. Reservoir simulations conducted to examine LSWF recovery sensitivities conclude that LSWF recovery mechanisms are governed based on the initial and final wetting states. In strong water-wet conditions, the increase in oil relative permeability is the underlying recovery mechanism. In weak water-wet conditions, the incremental recovery of LSWF is driven by low capillary pressures. In weak oil-wet conditions, the primary LSWF recovery mechanism is the increase in oil relative permeability, and the secondary mechanism is the change of the non-wetting phase to oil. In strong oil-wet conditions, the underlining LSWF recovery mechanism is the increase in oil relative permeability. In all cases, an appreciable decrease in interfacial tension (IFT) is realized at the breakthrough recovery however that is rapidly overshadowed by the increase in oil relative permeability and decrease in contact angle.
Gel Dehydration by Spontaneous Imbibition of Brine from Aged Polymer Gel
Authors: Brattekås B. , Haugen Å. , Graue A. , Seright R. S. 
Published: April 2012

Abstract
This work investigates dehydration of polymer gel by capillary imbibition of water bound in gel into a strongly water-wet matrix. Polymer gel is a cross linked polymer solution of high water content, where water can leave the gel and propagate through porous media, whereas the large 3D polymer gel structures cannot. In fractured reservoirs, polymer gel can be used for conformance control by reducing fracture conductivity. Dehydration of polymer gel by spontaneous imbibition contributes to shrinkage of the gel, which may open parts of the initially gel filled fracture to flow and significantly reduce the pressure resistance of the gel treatment. Spontaneous imbibition of water bound in aged Cr(III)-Acetate-HPAM gel was observed and quantified. Oil saturated chalk core plugs were submerged in gel and the rate of spontaneous imbibition was measured. Two boundary conditions were tested; 1) all faces open (AFO) and 2) two ends open-oil-water (TEO-OW), where one end was in contact with the imbibing fluid (gel or brine) and the other was in contact with oil. The rate of spontaneous imbibition was significantly slower in gel compared to brine, and was highly sensitive to the ratio between matrix volume and surface open to flow, decreasing with increasing ratios. The presence of a dehydrated gel layer on the core surface lowered the rate of imbibition; continuous loss of water to the core increased the gel layer concentration and thus the barrier to flow between the core and fresh gel. Severe gel dehydration and shrinkage up to 99 % was observed in the experiments, suggesting that gel treatments may lose efficiency over time in field applications where spontaneous imbibition is a contributing recovery mechanism. The implications of gel dehydration by spontaneous imbibition, and its relevance in field applications, are discussed for both gel and gelant field treatments.