bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improving Screening for Cystic Fibrosis–Related Diabetes at a Pediatric Cystic Fibrosis Program
Authors: Kern Andrew S. , Prestridge Adrienne L. 
Published: July 2013

OBJECTIVE:Despite guidelines recommending an annual oral glucose tolerance test (OGTT) for all patients with cystic fibrosis (CF) aged ≥10 years, screening rates for cystic fibrosis–related diabetes (CFRD) remained low at our center. The aim of this project was to implement an outpatient system to provide effective, evidence-based screening for CFRD at a pediatric CF program.METHODS:Development of a system to improve outpatient screening for CFRD included structured education, communication with families, and processes for scheduling laboratory appointments. The primary outcome measure was the proportion of eligible patients seen at the clinic who received an OGTT by the subsequent clinic appointment. The proportion of patients without CFRD in our program who received an OGTT within the previous 12 months was also tracked longitudinally.RESULTS:The outpatient screening rate for CFRD increased from 2% of eligible patients seen at the clinic during the 18 weeks before the start of our initiative to 78% during the 18 weeks after the start of our initiative (P &lt; .001). The screening rate was also increased from the corresponding date range the previous year, when only 35% of eligible patients received an OGTT (P &lt; .001). The overall percentage of patients without CFRD in our program who received an OGTT in the previous 12 months increased from 47% to 71% after implementation of our initiative (P = .003).CONCLUSIONS:A systematic, quality improvement approach effectively increased the rate of outpatient screening for CFRD at a pediatric CF program.
Scientific Research and Field Application of CO2 Immiscible Flooding in Heavy Oil Recovery
Authors: Kang Siwei , Gao Changhong , Zhang Shude 
Published: July 2013

AbstractWith the depletion of light oil, heavy oil is becoming one of the most promising resources to meet future energy consumption. It is estimated that total resources of heavy oil are 3396 billion barrels worldwide. Water flooding can only achieve less than 20% of heavy oil recovery. Thermal recovery has been proven as a feasible method to recover heavy oil. But it is not suitable for thin layers and deep reservoirs due to excessive heat loss. Polymer flooding and CO2 flooding are potential EOR techniques for the heavy oil reservoirs not suitable for thermal recovery. However, polymer degradation and high costs seriously hinder its field applications. Carbon Dioxide immiscible flooding effectively recovers heavy oil thanks to several mechanisms, such as oil swelling, viscosity reduction and blow-down recovery. This paper discusses the developments in CO2 immiscible flooding at laboratory scale as well as field scale. Laboratory tests show that CO2 can significantly improve heavy oil recover by 30%. Several field cases in USA, Turkey and Trinidad are reviewed. Field experiences show that CO2 flooding is a successful EOR method for heavy oil fields. However, some issues are encountered in field applications, including early gas breakthrough, corrosion, CO2 availability and high costs.
Recent Progress and Effects Analysis of Foam Flooding Field Tests in China
Authors: Zhu Youyi , Hou Qingfeng , Weng Rui , Jian Guoqing , Luo Yousong , Li Jianguo 
Published: July 2013

Abstract
For mature oil fields, foam flooding is an attractive chemical EOR technique and many pilot tests have been carried out in China. The performance of foam flooding pilot tests and its affect factors on oil recovery was discussed in this paper. The development trend and key technologies of foam flooding technique are pointed out.
Eighteen foam flooding pilot tests have been carried out in China from 1994 to 2010. Good performance have achieved in sixteen pilot tests. Through effects analysis of the pilot tests, three main aspects are concluded for affecting the performance of foam flooding tests. First, the characteristics of target reservoirs influence effects of foam flooding tests. The performance of foam flooding in higher oil viscous reservoirs is better than that in light oil reservoirs. The reservoir temperature and formation water salinity also influences the effects of foam flooding. Secondly, the chemical formula of foam solution and the size of slug influence the performance of foam flooding. The stability of foam formula influences the effects of foam flooding greatly. With the same amount of surfactant solution, the effect of high concentration small-sized slug is better than that in low concentration large-sized slug. Last, the injection method and gas liquid ratio can directly influence the foam performance in the reservoir, gas and liquid mixing injecting model is better than surfactant solution-alternation-gas (SAG) injection, and reasonable gas liquid ratio is important for guarantee good effects of foam flood.
At present, the trend of foam flooding in China is from nitrogen foam flooding and natural gas foam flooding to air foam flooding. The key technologies of foam flooding are the development of high stable foam formula with oil tolerance, salt and temperature resistance, good injection method and reasonable injection parameter etc.
Mechanism and Feasibility Study of Nitrogen Assisted Cyclic Steam Stimulation for Ultra-Heavy Oil Reservoir
Authors: Du Y.. , Wang Y.. , Jiang P.. , Ge J. J. , Zhang G. C. 
Published: July 2013

Abstract
In China, cyclic steam stimulation is the most widely applicable method for the development of common and ultra-heavy oil, and about 80% of thermal production is by CSS. Henan oilfield is one of the main producing areas of heavy oil in China and oil viscosity mainly ranges from 10000 to 30000mPa.s, belonging to ultra-heavy oil. After 6~8 cycles&#39; huff and puff, the heating radius reaches to its economic limit and both oil and water recovery is low due to the unfavorable reservoir pressure. Though nitrogen can enhanced common heavy oil recovery after CSS, there are few reports about nitrogen assisted CSS for ultra-heavy oil. For these problems, this paper studies the feasibility and mechanism of nitrogen assisted CSS via laboratory experiments and simulation. Simulation results showed that it was feasible to inject nitrogen before CSS. Though nitrogen has little effect on the reduction of oil viscosity, the main mechanism of enhanced oil recovery was its good ability of heat insulation effect, so the heat loss of injected steam could be reduced and the heating radius was increased. Besides, compressibility coefficient of nitrogen was very large, so it could supply energy during exploitation process and avoid the rapid reservoir pressure drop. Pilot tests were conducted to several wells in Jinglou ultra-heavy oil reservoirs in Henan oilfield. Most wells achieved good effect. With the ratio of nitrogen to steam (volume ratio at standard conditions) increasing, the oil recovery got better. When the ratio was larger than 30, it had no better effect on enhanced oil recovery. These results are of significance for the development of ultra-heavy oil reservoirs.
Study of Thermal Well Test Analysis for Vertical and Horizontal Steam Injection Wells with Application to Athabasca Heavy Oil
Authors: Ghahfarokhi Ashkan Jahanban , Kleppe Jon 
Published: July 2013

Abstract
Determination of swept volume is important for evaluation of a thermal project. Thermal well testing offers a simple method to estimate the steam zone properties using pressure falloff tests. A composite reservoir model is assumed with two regions of highly contrasting fluid mobilities and the flood front as an impermeable boundary. The swept zone therefore acts as a closed reservoir and pressure response is characterized by pseudo steady state behavior.
Most of the previous studies have considered vertical wells because of the simpler method of well test analysis compared to horizontal wells. However, a steam assisted gravity drainage (SAGD) process using horizontal well pairs is a promising technique in heavy oil recovery.
The applicability of thermal well test analysis in estimating the swept zone properties for vertical and horizontal wells was thoroughly investigated in this study. A thermal simulator was used to simulate pressure falloff tests. The generated pressure data were then analyzed to calculate swept volume and reservoir parameters. Properties of an Athabasca heavy oil sample, measured in the lab, were used as input for numerical simulation purposes.
Results of this work show good agreement between the calculated and simulated values of swept volume, swept zone permeability and skin factor for both vertical and horizontal wells. Estimations depend on the vertical position of the pressure gauge. Effects of gravity, swept region shape, dip, steam quality, steam injection rate, injection time, permeability anisotropy and gridblock density on the results were also investigated. Higher injection rates and longer injection times lead to poorer estimates of the swept volume because of a more irregular shape of the swept region and the possibility of earlier breakthrough. Vertical and lateral distances between the horizontal injector and producer affect the estimation of swept volume. Isotropy and grid refinement do not necessarily improve the estimations.
Enhance Heavy Oil Recovery by In-Situ Carbon Dioxide Generation and Application in China Offshore Oilfield
Authors: Jia Xiaofei , Ma Kuiqian , Liu Yingxian , Liu Bin , Zhang Jing , Li Yanlai 
Published: July 2013

Abstract
Miscible/Immiscible carbon dioxide injection is considered as one of the most effective technology to improve oil recovery from complicated formations. Main factor restraining wide application of this technology is its dependence on natural CO2 sources, transportation of CO2, breakthrough of CO2 to production wells, corrosion of well and field equipment, safety and environmental problems etc. However, in-situ carbon dioxide generation technology is eliminating CO2 negative impact and strong control of the process.
The EOR mechanism of proposal technology is described as follows: acid and exothermic chemical reaction function relieve deep reservoir damage, micronucleus systems formed possess abnormal reological properties allowing to improve water flooding efficiency, CO2 as a super-critical fluid decreases oil viscosity and gas form CO2 reaches such place in the formation where not many solvents can enter to, foamed gas-liquid system creates additional resistance for water injected after gas-liquid system, surfactant formed decreases interfacial tension in oil-water contact, and CO2 solved in oil increases oil volume what affects on displacement of residual oil.
Lab research shows that proposed technology can decrease injection pressure of damaged core by 11.7MPa, gas generation amount and oil volume increasing rate increases with temperature and system concentration increasing, oil volume increasing rate and oil viscosity reducing rate increasing with oil viscosity increasing. Under the conditions of 60 degrees Celsius, 10MPa, 2010mPa.s, it can increase oil volume by 25%, reduce oil viscosity by 52.7%, improve recovery efficiency by 7.6%~14.2%.
Field pilot tests were conducted in seven injection wells in China Bohai offshore oilfield in 2009~2010. All the wells present significant effect of decreasing injection pressure and increasing injection rate, average decreasing pressure by 3.2MPa, average increasing injection rate of single well by 22118m3, cumulative increasing injection rate by 154827m3, cumulative increasing oil of around production wells by 29000m3. Field pilot tests shows that proposed technology can be applied in a wide range of geological conditions, and be the key to recovering huge amount of oil from highly watered, depleted, heterogeneous and other type of so called hard-to-recover oil reserves.
Eco-Friendly Surfactant for EOR in High Temperature, High Salinity Carbonate Reservoir
Authors: Ghosh Bisweswar , Obasi Daniel 
Published: July 2013

Abstract
Factors confronting the application of surfactant flood in high temperature, high salinity carbonate reservoirs include: high concentration of divalent ions in the formation brine, the stability of the surfactant in high thermal environment, surfactant adsorption on carbonate rock fabrics and the effect of high salinity and brine mineral composition on the multiphase system, typically encountered in carbonate reservoirs. For preliminary screening purposes, thermal stability, salinity tolerance and emulsification characteristics are given importance, while the capacity to alter the wettability of the reservoir rock towards a water-wet system is desired.
Several surfactants were screened based on their abilities to address issues of high thermal environment, high salinity effects and capacity to create a water-wet environment. A series of akyl-polyglucoside (APG) surfactants were studied which are established as eco-friendly, renewable, nontoxic and bio-degradable surfactant and one of them found to be suitable for the target carbonate reservoir. An unique approach adopted during the screening process for thermal stability was the analysis of the UV-visible light absorption profile of the surfactants after subjecting them to reservoir condition for specific periods. The APG showed salinity tolerance up to 263,000 ppm at 220 oF. During phase study divalent ions are seen to have considerable impact on the nature of microemulsion (middle phase). Incremental recovery between 19-15% was observed for surfactant flood after secondary waterflood and spontaneous imbibition of aqueous phase was enhanced in the presence of surfactant solution. The recovery was correlated with microemulsion phase behavior and wettability alteration.
Modelling of Possible Impact of Reservoir Brine Salinity During CO2 Injection
Authors: Zhang Yi , Sarma Hemanta 
Published: July 2013

AbstractAlthough more emphasis is placed on the interaction between CO2 and oil during a CO2 injection process, the interaction of CO2 with the reservoir brine, too, could be significant in terms of its impact. This study presents a modeling approach to evaluate the possible effects of brine salinity on CO2 injection in the context of both CO2 injection and low-salinity waterflood.In the first phase of the study, the relevant correlations widely reported in the literature were applied for investigation of brine salinity effects on CO2-brine system properties for carbonate reservoir conditions at 248°F (120°C) and 3000psi (20.68MPa). The properties investigated include CO2 solubility in brine, IFT between CO2 and CO2-saturated brine, and density and viscosity of CO2-saturated brine. Some relevant experimental data were also incorporated in the validation of these correlations. In the second phase, a simple pore-scale model was developed to evaluate the brine salinity effect on water-isolated oil recovery by CO2 diffusion through water barrier. Furthermore, compositional reservoir simulation using a hypothetical geological model and a real PVT model was conducted to study the brine salinity impact on oil recovery of carbonated-water injection (CWI). The following findings were noted:Under our reservoir conditions, lowering the brine salinity could significantly enhance CO2 dissolution in brine, consequently leading to great variation of the system properties, which may make a big difference on CO2 injection performance. The CO2 diffusion-controlled modeling showed that reduction of the salinity in the water, which acted as a barrier blocking the direct contact between CO2 and oil. This could greatly promote the rate and amount of CO2 mass transfer through water barrier to the bypassed oil. Oil recovery results from simulation studies illustrated that increasing the CO2 solubility by reducing injected brine salinity during carbonated water injection could remarkably ameliorate its performance.
Investigation on Principles of Enhanced Offshore Heavy Oil Recovery by Coinjection of Steam with Flue Gas
Authors: Zhong L.. , Dong Z.. , Hou J.. , Li Y.. , Sun Y.. , Zhao L.. , Lu W.. , Qin F.. 
Published: July 2013

Abstract
In consideration of the difficulty to setup conventional steam generator on offshore production platform, a compact steam and flue gas generator is developed to thermally stimulate offshore heavy oil reservoir, which consists of water treatment and injection unit, fuel injection unit, air injection unit, and metering and controlling unit. The temperature of steam and flue gas generated is usually 200-350°C with 13.1-28.3wt% flue gas, the injection pressure could be up to 20MPa, and steam injection rate is 80-270 m3/day. In past two years, cyclic steam-flue gas co-injection are applied to 8 offshore horizontal heavy oil wells completed thermally or non-thermally with screen pipe, and up to 3 times of oil production rate in average is observed compared to that of cold production, the peak oil production is more than 100 m3/day.
In order to optimize the steam and flue gas co-injection strategy, laboratory experiments such as rheological characteristic measurement and PVT visualization of mixture of heavy oil and flue gas, 1D micro model displacement and 3D macro sandpack model stimulation, and numerical simulation are carried out to investigate the EOR principles. It shows significant synergistic EOR effect in steam and flue gas co-injection because of the foamy oil flow, improvement in heating and sweeping efficiency and gravity assisted drainage, besides of the combined reduction in oil viscosity by heating and gas solution. Flue gas plays an important role in co-stimulation of heavy oil with lower viscosity (500-2000mPa•s under reservoir condition) for the foamy oil flow and enlargement of heating and sweeping efficiency, at the same time, steam heating becomes more important for heavy oil with larger viscosity. At last, based on above researching results an empirical formula is developed to optimize ratio of flue gas to steam according to special reservoir conditions.
Fluid Saturation Monitoring by Cased Hole Logging for CO2 Huff-n-Puff Test in a Vietnam Offshore Field
Authors: Konishi Yusaku , Takagi Sunao , Farag Sherif , Ha Vo Viet , Hatakeyama Atsushi , Trung Phan Ngoc , Son Le Ngoc 
Published: July 2013

Abstract
The application of the Carbon Dioxide Enhanced Oil Recovery (CO2-EOR) to an offshore oilfield in Vietnam has been investigated through an international joint study between Japan and Vietnam since 2007. In order to reduce and mitigate uncertainties and risks for future field scale application, a CO2-EOR pilot test was conducted in the Rang Dong field, offshore Vietnam in 2011.
The pilot test was conducted as a single-well "Huff-n-Puff" operation which was designed to minimize the test duration, required CO2 volume to observe the meaningful CO2-EOR effects and to reduce the risk of corrosion to the existing facility. Over 100 tons of CO2 were successfully injected into the Lower Miocene sandstone reservoir and the well was flowed back after two days of soaking time. Various parameters were monitored including production rate, bottom-hole pressure and production fluid properties. To investigate the CO2-EOR effects and for the purpose of monitoring the reservoir fluid saturation change, cased hole pulsed neutron saturation logging was carried out during every stage of the test. These logging operations and their timing were carefully designed to avoid any possibility of fluid contamination and to minimize operation time.
Through the analysis of the acquired logs, vertical contrast of preferential CO2 injection, zonal oil saturation change, oil saturation change with time within single run, etc., were clearly identified. These observations played important roles in evaluating the CO2-EOR effect in detail by comparing them with the reservoir simulation prediction.
In this paper the detailed design for the reservoir fluid saturation monitoring, observed results and three-phase fluid saturation changes with time are discussed.
Secondary Polymer Flooding in Extra-Heavy Oil: Gaining Information on Polymer-Oil Relative Permeabilities
Authors: Fabbri C.. , Romero C.. , Aubertin F.. , Nguyen M.. , Hourcq S.. , Hamon G.. 
Published: July 2013

Abstract
In this work we present the results obtained from a coreflood experiment with polymer injection in secondary mode for extra heavy oil at 5500 cP viscosity. The work was carried out on a 30 cm length reconstituted core composed from cleaned reservoir sand. The core was packed using an in-house developed method, and then saturated with live oil partially degassed in PVT cell from initial reservoir conditions down to expected pressure at start of a field test (Pres). Saturation profiles were accurately measured by means of X-Ray scans on the core, enabling the visualization of flow instability development (viscous fingering). Effluents were collected in carbon cells under reservoir conditions with X-Ray production level measurements. The effluents were then flashed to atmospheric conditions, collected in test tubes and re-measured by X-Ray and UV measurements.
The polymer flood carried out in secondary mode showed excellent results with a recovery of around 60% after 1.8 PV of polymer injected at 1 cc/h, even though viscosity ratio was highly unfavourable. The estimated apparent viscosity of the polymer was 60 cP at 7 s−1, corresponding to the frontal advancement rate achieved during the coreflood. This recovery is in the same order as that obtained in tertiary mode after water flood in outcrop cores (Wassmuth et al. 2009, Wassmuth et al. 2007).
Kinetics of the Low Salinity Waterflooding Effect Studied in a Model System
Authors: Mahani H.. , Berg S.. , Ilic D.. , Bartels W. -B. , Joekar-Niasar V.. 
Published: July 2013

AbstractLow salinity waterflooding (LSF) provides an opportunity for improved oil recovery. However the complexity of the process makes both the fundamental understanding of the underlying mechanism(s) and the interpretation of laboratory experiments difficult. Therefore we use a model system for sandstone which consists of clay minerals deposited on a glass substrate and covered with crude oil droplets in order to study the kinetics of oil detachment when exposed to low salinity brine. The system is equilibrated first under high saline brine and then exposed to brines of varying (lower) salinity while the shape of the oil droplets is continuously monitored at high resolution allowing for a detailed analysis of the contact angle and the contact area as a function of time.We observe that the contact angle and contact area of oil with the substrate reach a stable equilibrium at high saline brine and show a clear response to the low salinity brine towards less oil wetting conditions and ultimately detachment from the clay (Na-montmorillonite) substrate. This behavior is characterized by the motion of the 3-phase (oil-water-solid) contact line which is initially pinned by clay particles at high salinity conditions and that pinning decreases upon exposure to low salinity brine leading to a decrease in contact area and contact angle which indicates wettability alteration towards a more water-wet state. When the contact angle reaches a critical value around 40-50°, oil drops start to detach from the clay. During detachment most of the oil is released but in some cases a small amount of oil residue is left behind on the clay substrate.Our results for different salinity levels indicate that the kinetics of this wettability change correlates with a simple buoyancy over adhesion force balance and has a time constant of hours to days; i.e., it takes longer than commonly assumed.The unexpectedly long time constant, i.e. longer than expected by diffusion alone, is compatible with an electrokinetic model. It is an important finding which provides new insights into the pore-scale mechanism of LSF and also has implications for the execution of low salinity coreflooding experiments, i.e. provides how long it takes to reach equilibrium and at which time scale a response to LSF can be expected.