bluuebunny/crossref_metadata_2025 huggingface dataset:
Evaluation of Aphid Resistance Among Sugarcane Cultivars in Louisiana
Authors: Akbar W , Showler A T , Beuzelin J M , Reagan T E , Gravois K A
Published: July 2011

Sugarcane (Saccharum L.) in Louisiana is colonized by the sugarcane aphid, Melanaphis sacchari (Zehntner), and the yellow sugarcane aphid, Sipha flava (Forbes). Five commercial sugarcane cultivars, ‘LCP 85-384′, ‘HoCP 91-555′, ‘Ho 95-988′, ‘HoCP 96-540′, and ‘L 97-128′, representing >95% of Louisiana's sugarcane-growing area, were assessed under southern Louisiana field conditions for numbers of the two aphid species. Biweekly sampling during 2007 and 2008 growing seasons indicated cultivar and time effects on aphid frequency. Aphid population peaks occurred during June and July and then crashed. M. sacchari was more abundant than S. flava on almost all cultivars and on all sampling dates during both years of the study. HoCP 91-555 was found to be the most resistant compared with the susceptible Ho 95-988 and L 97-128 cultivars. HoCP 91-555 might be useful in areas of high aphid pressure, and as a source of resistance in cultivar development programs.
Review of Mileewine Leafhoppers (Hemiptera: Cicadellidae: Mileewinae) in Madagascar, with Description of Seven New Species
Authors: Krishnankutty Sindhu M , Dietrich Christopher H
Published: July 2011

The leafhopper subfamily Mileewinae was previously known in Madagascar from a single species, Ujna flavidipes Distant, also recorded from Seychelles. Study of samples from a recently completed Arthropod biodiversity inventory in Madagascar revealed seven new, apparently endemic species distinguishable based on external and genitalia characters and all referable to the genus Ujna Distant based on the present definition of the genus: Ujna variabilis sp. nov., Ujna bimaculata sp. nov., Ujna affinis sp. nov., Ujna trishula sp. nov., Ujna acuta sp. nov., Ujna alba sp. nov., Ujna rostrata sp. nov. are described and illustrated. Ujna flavidipes Distant is redescribed and illustrated. Three informal species groups are proposed. A key to the males of Ujna from Madagascar is presented. A key to world genera of Mileewinae and a morphological comparison of Ujna with other genera also are provided. Two new placements of genera are proposed: Processina Yang, Deitz & Li is transferred from tribe Cicadellini to Mileewini (Mileewinae) placement n. and Archeguina Young is transferred from Mileewini to Cicadellini (Cicadellinae) placement n.
Taxonomic Status of Two Species of Andricus (Hymenoptera: Cynipidae) Described by Shinji (1940, 1941) as Gall Inducers on Cyclobalanopsis
Authors: Wachi Nakatada , Ide Tatsuya , Abe Yoshihisa
Published: July 2011

Andricus shirakashii Shinji, 1940 and Andricus shirokashicola [sic] Shinji, 1941 (Hymenoptera: Cynipidae) were described from leaf galls on the evergreen oak, Quercus (Cyclobalanopsis) myrsinifolia Blume [Japanese: shirakashi], but their assignment to oak gall wasps (tribe Cynipini) has long been considered enigmatic. These species are in fact inquiline gall wasps that were described as gall-inducing wasps. Because the morphological characteristics of these species are typical of the genus Ufo (tribe Synergini), we transfer A. shirakashii and A. shirokashicola to this inquiline genus. Due to the loss of the type specimens of each species, the neotypes are here designated and the two species are redescribed.
Egg-Dumping Behavior is Not Correlated with Wider Host Acceptance in the Seed Beetle Callosobruchus maculatus (Coleoptera: Chrysomelidae: Bruchinae)
Authors: Messina Frank J , Fox Charles W
Published: July 2011

If typical host plants are absent, some herbivorous insects “dump” eggs on unsuitable substrates, even though this can cause complete larval mortality and reduced maternal life span. In the seed beetle Callosobruchus maculatus (F.) (Coleoptera: Chrysomelidae: Bruchinae), the tendency to dump eggs varies genetically both within and between populations. A previous study hypothesized that egg-dumping behavior facilitates host-range expansions, and suggested that such expansions have served to maintain “dumper” genotypes in beetle populations. We tested this hypothesis in two experiments. For both African and Asian beetle populations, full-sib females from >60 families were split among three treatments: no seeds, a less-preferred novel host, and a preferred host. Within each population, we found no correlation among families between the tendency to dump eggs and the tendency to accept the novel host. We also compared egg dumping between selection lines that had adapted to a novel host and a line that had remained on the ancestral host. Females from lines that had evolved greater acceptance of the novel host did not dump more eggs if hosts were absent. Thus, neither experiment supported the host-range expansion hypothesis. Egg distributions on the preferred host in the first experiment provided weak support for a more proximate explanation: family-level variation in the tendency to dump eggs is inversely related to the tendency to avoid superparasitism of seeds. Such a relationship is also evident in comparisons between populations. Given the considerable short-term costs of egg dumping, we suggest that the host-range expansion hypothesis requires unrealistically high frequencies of host deprivation and subsequent host shifts in C. maculatus.
Song Analysis Reveals a Permanent Population of the Mediterranean LacewingChrysoperla agilis(Neuroptera: Chrysopidae) Living in Central Alaska
Authors: Henry Charles S , Brooks Stephen J , Johnson James R , Wells Marta M , Duelli Peter
Published: July 2011

Chrysoperla agilis Henry et al. (Neuroptera: Chrysopidae) is a widespread, nomadic lacewing in the carnea group of cryptic species. C. agilis has previously been found only in the warm parts of Europe, western Asia, and a few oceanic islands. Like others of the carnea group, C. agilis is identifiable only by its unique courtship song. Recently, a population with by the C. agilis song was discovered in central Alaska; based on its persistence over several years and its distribution over a wide area near Fairbanks, it seems to be permanent rather than transitory. To assess the relationship of this Western Hemisphere population to C. agilis in the Eastern Hemisphere, we 1) analyzed its courtship song, comparing it to the Eurasian song; 2) compared larval and adult morphology of Alaskan and Eurasian specimens; 3) inferred phylogenetic relationships of Alaskan and Eurasian specimens, by using sequences from the cox2 gene; and 4) crossed Alaskan with European individuals, raising their progeny and analyzing their “hybrid” songs. Alaskan C. agilis generally fell within the range of variation of Eurasian individuals for all acoustic and morphological traits, and their hybrid progeny were also acoustically indistinguishable. Phylogenetically, and despite current geographical isolation, Alaskan individuals clustered with Eurasian C. agilis rather than with Western Hemisphere taxa of the carnea group. We conclude that the Alaskan population is a bona fide member of C. agilis. Examination of the geographical pattern of song variation suggests that dispersal to Alaska took place quite recently in a west to east direction, via eastern Asia and the Bering Strait.
On the intrusion of polyethylene glycol during osmotic tests
Authors: TRIPATHY S. , TADZA M. Y. M. , THOMAS H. R.
Published: July 2011

In the laboratory, semi-permeable membranes and polyethylene glycol (PEG) solutions are used for applying suction in soils using the osmotic technique. In this study, the pore structures of cellulose semi-permeable membranes with molecular weight cut-off values of 3500 and 14 000 were examined via an atomic force microscope (AFM). Fourier transform infrared (FTIR) spectroscopy was used to identify any degradation of PEG molecules with elapsed time. Freshly prepared PEG solutions and solutions aged for 15 days were considered for this purpose. Osmotic tests were carried out on initially saturated MX80 bentonite specimens at two suction levels (0·44 and 7·04 MPa). Comparison of the AFM images of the semi-permeable membranes before and after the osmotic tests clearly revealed that the pore size of the semi-permeable membranes increased significantly, particularly at the higher applied suction that enabled passing of PEG molecules into the clay specimens. FTIR spectrums of PEG 20 000 and PEG 6000 did not provide any evidence of degradation of the PEG molecules with elapsed time.
A Study on Alkali Consumption Regularity in Minerals of Reservoirs During Alkali(NaoH)/Surfactant/Polymer Flooding in Daqing Oilfield
Authors: Wei Jianguang , Tao Jianwen , Xin Shuzhen , Zhang Qingjie , Zhang Xin , Wang Zhiming
Published: July 2011

In the process of oil displacement of ASP (Alkali/Surfactant/Polymer) flooding, when Alkali interacts with the fluid and minerals of the reservoir, the alkali is subject to be consumed. The consumption regularity is the key factor affecting ASP ingredient, injection plan, scaling regularity for production wells and oil displacement effectiveness. Therefore to study the alkali consumption is of great significance in guiding ASP ingredient, injection project design, and the analysis for oil displacement mechanism. In this paper, aiming at the main components of minerals in the reservoir in Daqing Oilfield, the laboratory study on static alkali consumption for five kinds of minerals (kaolinite, grundite, chlorite, feldspar and quartz) in ASP system and single component NaOH solution are done respectively. The alkali consumption regularities for five kinds of minerals in ASP and single component NaOH solution are concluded.

The research indicates that the amount of alkali consumption for kaolinite, grundite, chlorite, feldspar and quartz is changing from larger to less accordingly, but is mainly caused by clay minerals; the average alkali consumption is 18.3% higher than that by matrix minerals. In single component NaOH solution, the alkali consumption styles of clay minerals and the matrix minerals take the chemical reaction as the lead, and the physical adsorption as the second. In ASP system solution, the alkali consumption style of clay minerals, takes the physical adsorption as the lead, and of matrix minerals takes the chemical reaction as the lead. In ASP solution, compared with single component solution, polymer and surfactant have the functions of restraint to alkali consumption in minerals of the reservoir, and the amount of alkali consumption decreases evidently.
The Performance of Polymer Solution Added with Viscosity Stabilizer and The Evaluation of Its Oil Displacement Efficiency in Daqing Oilfield
Authors: Xin Shuzhen , Zhang Qingjie , Wei Jianguang , Chen Ying , Wang Rongjiu , Wang Jingbo , Wang Zhiming
Published: July 2011

Aiming at the low viscosity of polymer solution, which is compounded with fresh water but diluted with produced water, and at the problems concerning oil displacement efficiency, an onsite test on polymer solution with viscosity stabilizer (PSVS) is carried out. As a result, it has great and guiding significance to the application and popularization of viscosity stabilizer by studying the performance of polymer solution with viscosity stabilizer and its influence on oil displacement efficiency. In this paper, aiming at two different kinds of polymer solutions among which one is compounded with fresh water but diluted with fresh produced water and the other with aerated produced water, two laboratory evaluative tests concerning viscosity stabilization, anti-shear stability, fluidity, and absorbability of polymer solution as well as its oil displacement efficiency are done. The results of onsite application of PSVS are traced and analyzed.

The viscosity stabilization of the polymer solution adding with viscosity stabilizer becomes much better than that of the normal polymer solution. The resistance and the residual resistance factors, the static oil sand adsorption rate and the dynamic core adsorption rate of the solution are all increased markedly. The working viscosity and oil displacement efficiency are improved markedly as well. In comparison with the polymer solution diluted with fresh produced water, the polymer solution diluted with aerated produced water is much better in terms of viscosity stabilization. Comparing with the normal polymer solution with viscosity stabilizer before sheared, the polymer solution which is sheared before adding with viscosity stabilizer performs obviously better in terms of viscosity stability. In contrast to the adjacent block injected with normal polymer solution, the block under onsite flooding test with injection of PSVS features that the average injection pressure increases slightly but keeps steady, the recovery speed of the average monthly water cut of production wells slows down, the thickness of the absorptive layers increases, and the periodic recovery rate improves as well.
Laboratory Tests with CO2, N2 and Lean Natural Gas in a Naturally Fractured Gas-Condesate Reservoir under HP/HT Conditions
Authors: Gachuz-Muro Heron , Gonzalez-Valtierra Bianca , Luna-Rojero Erick , Aguilar-Lopez Berenice , Pineda-Muñoz Armando
Published: July 2011

The study of gas-condensate reservoirs has been a fruitful field of research in the last years because of their peculiar behaviour. Gas cycling is the recovery process of choice for gas-condensate reservoirs but this process can often not be implemented because of economic reasons. Nitrogen is a potential alternative injection gas. Nevertheless, this has also disadvantages. The application of these processes is more complex in the offshore sites.

This paper describes laboratory studies performed to evaluate the effectiveness of some gases (CO2, N2, lean natural gas) in displacing condensate from naturally fractured gas-condensate reservoirs (offshore field). Numerous hurdles had to be overcome. The experiments represented the behavior of a reservoir under HP/HT conditions, 334 °F and 8455 psia. The results of CO2 and natural depletion showed little difference in their ability to recover condensate. The natural gas raised the recovery of the light fraction, but, by contrary, the addition of N2 made evident to be less effective than the rest.

The residual saturations and condensate recovery were measured and the results are presented. The detailed analyses revealed that natural gas seems to have been more effective in recovering condensate. Under these conditions, condensate recovery will significantly increase if the lean natural gas is injected. The answers are in agreement with the simulation model.

The conclusions are relevant to the overall management of gas-condensate reservoir. These experiments will serve as a guideline to develop the long term corporate strategy to improve additional recoveries in Mexico.
Assessment of Development Methods for a Heavy-Oil Sandstone Reservoir in Middle East: Part II: Numerical Evaluation of Thermal Recovery Methods in a Hetrogenos System
Authors: Alajmi Hifaa , King Peter R.
Published: July 2011

A combination of growing energy demand, declining performance of conventional oil fields and attractive oil prices have renewed interests in both the heavy oil resources and the methods of exploiting them. However, their low mobility precludes relying on natural drive mechanisms for their extraction. Given that there are a very large number of EOR methods and to accelerate decision-making, a relatively simple screening procedure has been developed and implemented. Several simulation runs were conducted, investigating the effects of petrophysical properties and operating variables on performances of thermal and non-thermal flood processes. Then, a detailed economic analysis was performed to assess the economic feasibility of each recovery process/scenario. This work has contributed significantly toward our understanding of the mechanisms of thermal injection in high permeability heavy oil reservoir. This is critical in the decision on the applicability of thermal recovery methods and its field application success.
Microbial Enhanced Oil Recovery in Carbonate Reservoir: An Experimental Study
Authors: Gao Chang Hong
Published: July 2011

Many successful field cases of microbial enhanced oil recovery (MEOR) method have been reported for sandstone reservoirs. The objective of this study is to investigate the potential of MEOR method in UAE carbonate reservoirs. Two Bacillus strains were incubated at temperatures from 35 to 55°C, and their effects on crude oil properties and recovery were tested. It was discovered that neither strain could effectively reduce crude oil viscosity. Bacteria solutions were subsequently injected into a glass Hele-Shaw model to simulate microbial flooding in a fracture. It was observed that both strains grown under 45°C achieved maximum enhanced recovery of over 13%. Core flooding tests were conducted at elevated temperature of 70°C with limestone core. The two strains achieved enhanced oil recovery of more than 4.5%, respectively. The observation on core flooding test indicated selective plugging as the dominant recovery mechanism. Even though the recovery test results were positive, an analysis shows that MEOR method is not cost-effective. Therefore, MEOR technology may have limited potential in UAE carbonate reservoirs.
Bayesian Network Analysis as a Tool for Efficient EOR Screening
Authors: Zerafat M. M. , Ayatollahi Sh.. , Mehranbod N.. , Barzegari D..
Published: July 2011

The main tool for screening of EOR techniques is generally based on the criteria presented in a variety of tables and graphs given in the literature. These data are derived from the basic theory of multiphase fluid flow through porous media, reservoir simulation, laboratory experiments and existing field-scale experiences. The purpose of this study is to develop a procedure capable of combining the data extracted from different sources ranging from worldwide field experiences to the existing tables into a unified expert system. This expert system is based on Bayesian network analysis in order to sort the proper EOR techniques for further assessment by economical and environmental criteria.

A data bank has been gathered from worldwide EOR/IOR techniques and analyzed using data mining procedure which is then combined with extracted data from previously published screening tables. Bayesian network quantitative learning technique was applied to different data combinations from the data bank to train the network which is to serve as the expert system.

The produced expert system is also applied to the gathered data pertaining to 10 Iranian southwest reservoirs. The results show that, CO2 flooding can be the most promising among various EOR techniques, which is in agreement with a previous work. According to this study, considering reservoir characteristics, and excluding the economic limitations, CO2 flooding is considered as the most efficient EOR method for Iranian carbonate reservoirs under study.

The results show that Bayesian Belief network analysis can be successful in the prediction of proper EOR technique by providing sufficient Data to train the network.
Field Applications of an Evaluation Model for Enhancing Recovery Efficiency to Polymer-flooding
Authors: Dandan Hu , Yuanqian Chen , Yuanbing Wu , qingfei Zhao , Mingsheng Feng , Hui Liu
Published: July 2011

Polymer flooding development tests stared from 1990’s were carried out on Daqing and Shengli oilfields in China, with water-flooding as its most important development measures formerly, which enlarged size scale of tests continuously. Stable production and enhancing recovery efficiency in these oilfields were implemented by polymer flooding technology. Successful field applications showed the yearly production rate reached to nearly 90 million bbl in Daqing oilfield. Feasible and effective report has not been provided yet on the problem that the range of recoverable reserves and recovery efficiency can be reached after polymer flooding. Considering most oilfields accomplished polymer flooding in quick succession and some oilfields were just developed by polymer flooding, practical resolution should be recommended such as the corresponding evaluation model for enhancing recovery efficiency range of polymer flooding. The resolution can also provide an evaluation basis of enhancing recovery efficiency for alkaline-surfactant-polymer flooding in future. This paper proposed an evaluation model for enhancing recovery reserves and recovery efficiency of polymer-flooding based on production decline model of reservoir engineering. Applications of these concepts are illustrated with field examples. Results indicated that recovery efficiency by polymer-flooding after the water-flooding development may be increased between 7% and 12% in Chinese oilfields. The evaluation model has been used effectively to predict EOR effect in Chinese oilfields.
A Novel PPG Enhanced Surfactant-Polymer System for EOR
Authors: Cui Xiao-hong , Li Zhen-quan , Cao Xu-Iong , Song Xin-wang , Zhang Xinying
Published: July 2011

Based on the analysis results with rheometer, spining drop interfacial tensionmeter, laser particle analyzer, microscopic oil displacement and oil displacement, a novel Preformed Particle Gel (PPG) for chemical EOR was screened out. Its application properties were evaluated. A new chemical flooding system, Heterogeneous Combination Flooding System (HCFS), was designed according to the interaction laws of PPG, polymer and surfactant. Core flooding tests were conducted under two types of reservoir conditions of Shengli Oilfeild, 1) high temperature and high salinity (HT/HS) conditions, and 2) after polymer flooding reservoir condition, to figure out the enhanced oil recovery effects of HCFS. It showed that PPG can not only migrate and penetrate in porous medium, but also generate more significant volumetric sweep efficiency by the cycle of piling up-plug-pressure rising-extending and deforming to pass through porous throats than the conventional polymer flooding to modify the existing dominant migration path. Because of the enhanced sweep efficiency introduced by the mixed PPG-polymer system with higher viscosity and viscoelasticity as well as the displacement efficiency by surfactant system, HCFS can improve the oil recovery by 22.5% for HT/HS reservoirs and by 19.1% for after the polymer flooding reservoirs in dual sandpacked tube flooding experiments with the interlayer heterogeneity of 1000:5000 × 10−3μm2.
Experimental and Numerical Simulation Studies of Different Modes of CO2 Injection in Fractured Carbonate Cores
Authors: Aleidan A. A. , Mamora D. D. , Schechter D. S.
Published: July 2011

We have performed a miscible CO2 flood study using fractured and unfractured carbonate cores and 31° API west Texas oil to evaluate oil recovery under three main injection modes: SWAG, WAG, and CGI. For each injection mode, three cases were considered: unfractured, one horizontal fracture and two fractures (one horizontal and one vertical). Increasing the number of fractures will investigate different shape factors such as the elongated slab and sugar cube models. Then, a commercial simulator was used to match the experimental results and model the fractures.

The experimental results may be summarized as follows. First, for the unfractured case, the oil recoveries for SWAG, WAG, and CGI are 98, 92, and 75 % of OOIP, respectively. Second, for the elongated slab case (one horizontal fracture), the oil recoveries for SWAG, WAG and CGI decreased to 72, 70, and 27 %, respectively. Third, for sugar cube model (two fractures), the oil recoveries for SWAG, WAG and CGI are 79, 79, and 55 %, respectively. The simulation shows that the improvement in recoveries during SWAG and WAG over CGI is a result of a better conformance provided by the injected water which hindered CO2 mobility and decreased its cycling through the fracture. Also, the sugar cube model has shown better results than the elongated slab because of the presence of a vertical fracture in the middle which helped CO2 to diffuse more in the matrix and contact oil. The results suggest that injecting CGI in fractured cases is not recommended and injecting water (wetting phase) along with CO2 is essential. Finally, among all injection modes, SWAG has resulted in the most uniform displacement profile with the lowest residual oil saturation after the flood. This injection mode combines the benefits of water to transfer into the matrix with CO2 excellent displacement.
Simulation of Optimal Peak Oil Production Rate in a Fractured Reservoir during Miscible CO2 Flooding
Authors: Joshi Abhishek , Kumar G Suresh
Published: July 2011

Increasing oil prices and depleting domestic resources have generated interest in Enhanced Oil Recovery (EOR) methods. Many EOR methods are currently being used, and CO2 flooding is of great interest, particularly in fractured reservoirs as it not only increases the ultimate recovery but also reduces greenhouse emissions allowing companies to earn carbon credits. In general, primary recovery based on the natural energy of reservoir can produce only 33% of original oil in place (OOIP), while secondary recovery methods based on gas and water flooding can enhance it to 66% in non-fractured reservoirs. However, in fractured reservoirs, gas/water bypass the resident fluid residing within the low-permeability rock-matrix due to the marked difference in porosity and permeability between fracture and its associated rock matrix, and eventually, provides poor sweep efficiency. Thus, fractured reservoirs have always been considered as poor candidates for EOR as these high permeability fractures provide a preferential pathway for injected fluids to channel through directly from injection to production wells without significant fracture-matrix interaction. In the present study, Computer Modeling Group (CMG - GEM) and WINPRO reservoir simulators are used to perform CO2 injection experiments numerically using the concept of "dual-porosity" with different CO2 injection rates and eventually to determine the optimal peak oil production rate during CO2 fluid injection within a fractured reservoir process in a single fracture. Through simulation, sensitivity analysis is conducted to determine the effect of parameters like fracture permeability, matrix porosity, matrix permeability, fracture spacing and fluid velocity on oil recovery factor. Results suggest that oil recovery in case of fractured reservoir is significantly greater than that in a non fractured reservoir or porous reservoir.
EOR: Challenges of Translating Fine Scale Displacement into Full Field Models
Authors: Moreno Jaime , Flew Steve
Published: July 2011

Increasing demand of oil and gas worldwide is promoting a new, fast growth in the oil industry where the presence of experienced engineers is limited. Exploration for hydrocarbons is reaching limiting frontiers and the near future and long term challenge will be to maximize recovery from the existing fields. Enhanced oil recovery offers an alternative to improve recovery by means of introducing an external agent which enhances oil sweeping at a pore level scale.

While the EOR concept is not new; field implementation has been scarce. As a consequence the physics governing the displacement processes have not been completely understood, posing a challenge for the design and modeling of the process. This is enhanced when dealing with numerical models, which, typically are designed for primary and/or secondary depletion processes, with grid orientations and dimensions suitable for these field conditions. Very often though, these same models are used to design and evaluate the potential for field EOR. This paper addresses the main challenges of modeling the fine scale displacement mechanism with a full field model, highlighting the typical errors in recovery efficiency that can occur and suggesting scales at which screening models can be built.

Displacement processes in the reservoir are dominated by the combination of the viscous and capillary forces, the efficiency and ultimately the amount of displaced oil is controlled by the balance of these forces. During a core scale displacement process, viscous forces are dominant and most of the oil is contacted by the injected agent. This displacing mechanism is different from the one experienced at reservoir conditions where gravity forces play an important role, influencing the amount of oil which is contacted by the EOR agent, where under and overrunning may occur. Modeling of these displacements requires a greater resolution than the one used in for the full field model. The impact of model size and force balance during an EOR displacement process is presented is this paper.
Impact of Fluvial Geological Characteristics on EOR Screening of a Large Heavy Oil Field
Authors: Soleimani A.. , Penney R.. , Hegazy O.. , Ngah Ab Wahab , Sulliman Abdalla Elhaj , Tewari R..
Published: July 2011

Many fields in the Middle East suffer from low recovery and declines in primary production due to low oil gravity (<20 API) and viscosities above 100 cP. The studied field contains well in excess of 1 billion barrels in place with overall recovery expected to be less than 10% without EOR. 75% of the STOIIP comprises 20 API oil with 120–160 CP viscosity while the remainder comprises 17 API with 800 cP viscosity. Complicating matters, the three main sandstone reservoirs vary from braided fluvial streams in Upper formation (A), to thick sheet sands in the middle formation (B) and thinner sands separated vertically by thin shales in the Lower formation C.

In this study EOR techniques have been assessed for these three formations in order to recommend suitable development options for the field. Simulation schemes were developed for the following seven recovery mechanisms, including, water flood, chemical EOR – polymer and ASP, thermal EOR – CSS, steam flood, SAGD and in-situ combustion. Due to geological and fluid variation in these three formations, EOR mechanism behaves differently in terms of recovery for each reservoir.

The three most promising techniques, ASP, steam flood/CSS and insitu combustion were then developed to optimise pattern spacing and injection rates for each technique and for all three formations in this field.

Heterogeneity and geological factors have different impacts on the various EOR mechanisms, including convective methods like ASP and polymer flooding and convective-conductive methods like Thermal EOR. Overall, thermal EOR has been found to be more effective and economically feasible for this field, in particular for the heterogeneous formation with high viscosity oil. Different EOR techniques could be considered for each formation due to the variation in heterogeneity, with recovery also changing from one formation to another due to fluid viscosity.

Different thermal schemes, for example varying the number of steam injection cycles before continuous steam injection, have been suggested for each formation in respect to its heterogeneity and oil properties. It is also noted that a SAGD EOR process can be more effective in certain formations in this field.
Detailed Modeling of the Alkali Surfactant Polymer (ASP) Process by Coupling a Multi-purpose Reservoir Simulator to the Chemistry Package PHREEQC
Authors: Farajzadeh R.. , Matsuura T.. , van Batenburg D.. , Dijk H..
Published: July 2011

Accurate modeling of an Alkali-Surfactant-Polymer (ASP) flood requires detailed representation of the geochemistry and, if natural acids are present, the saponification process. Geochemistry and saponification affect the propagation of the injected chemicals and the amount of generated natural soaps. These in turn determine the chemical phase behavior and hence the effectiveness of the ASP process.

In this paper it is shown that by coupling the Shell in-house simulator MoReS with PHREEQC a robust and flexible tool has been developed to model ASP floods. PHREEQC is used as the chemical reaction engine, which determines the equilibrium state of the chemical processes modeled. MoReS models the impact of the chemicals on the flow properties, solves the flow equations and transports the chemicals.

The validity of the approach is confirmed by benchmarking the results with the ASP module of the UTCHEM simulator (UT Austin). Moreover, ASP core floods have been matched with the new tool. The functionality of the model has been also tested on a 2D sector model. The advantages of using PHREEQC as the chemical engine include its rich database of chemical species and its flexibility to change the chemical processes to be modeled. Therefore, the coupling procedure presented in this paper can also be extended to other chemical-EOR methods.
CO2 Gas + WAG + Water Injection in the Same Oil Reservoir - Case Study
Authors: Uj Istvan , Fekete Tibor
Published: July 2011

The "PF-A-I" - an undersaturated oil reservoir located in Hungary- is more than 50 years old. It was discovered in the late 1950’ years and put in production in 1960. The reservoir produced by depletion, then by CO2 injection, by WAG injection, afterwards by water injection and finally by "depletion" again.

The case study shows all production stages in detail – the most important data, what were the results of different type of injections, how saturations, pressure, recovery factor changed followed by the comparison of planned injection and production rates with facts by diagrams and maps.

It shows why the CO2 injection was more important than the experts thought and which type of injection was the most effective and gave the most extra oil.
A Systematic Approach to Evaluate Asphaltene Precipitation during CO2 Injection
Authors: Adyani Wan Nurul , Daud Wan Ata , Darman Nasir , Memon Afzal , Khan Ifadat Ali , Jamaluddin Abul
Published: July 2011

With declining oil production, the E&P companies are in search of applying innovative methodologies to improve recovery factors from existing fields. Gas injection is one of the most commonly used enhanced-oil recovery techniques in the oil and gas industry. Here, gas such as carbon dioxide, natural gas, or nitrogen is injected into the reservoir. Gas injection relies on the phase behavior of gas and crude oil mixtures that are strongly dependent on reservoir temperature, pressure and crude oil composition. In addition, water is also injected in alternating manner to alter the wettability of the porous medium, and hence improving the sweep efficiency.

Carbon dioxide in combination with alternating water is usually injected in light to medium oil reservoirs in order to increase the ultimate oil recovery. Available data on carbon dioxide injection indicates that an additional recovery of 7% to 15% can be achieved (put reference here). Also, it has been illustrated in the literature that carbon dioxide may cause asphaltenes to precipitate in contact with oil in the laboratory pressure-volume-temperature equipment or in the reservoirs. The asphaltene precipitation mechanism in the porous medium can have serious consequences of blocking pore throats depending on the size of the asphaltene aggregates, and hence, the permeability.

This paper presents a systematic approach and a workflow process to evaluate carbon dioxide miscibility evaluation criteria along with the propensity of asphaltene precipitation in the reservoir for a field located in South China Sea. In this study, measurements were conducted to define the minimum miscibility pressure and also, asphaltene precipitation locus during carbon dioxide injection process. Consequently, these data were used to develop thermodynamic models.
Identification of Thief Zones by Dimensionless Pressure Index in Waterfloods
Authors: Feng Qihong , Wang Sen , Wang Shoulei , Wang Yanzhong , Chen Depo
Published: July 2011

Pressure Index (PI) is a significant parameter, which is commonly used for profile control project design and injection well performance analysis in China, due to its simple and economical application. However, PI can only reflect the current fluid flow capacity and present heterogeneity of the formation. It’s well known that the formation structure will change distinctly after long-term waterflooding for the pressure variation and its in-situ heterogeneity, during which thief zones or high-conductive channels may come into being. Therefore, PI can not take into account the dynamic change of the formation structure, and thief zones can not be identified by PI. As a result, efficiency of profile control decision might be not as good as expected.

The objective here is to develop a new parameter which can identify thief zones easily and to verify its validity from both the synthetic model and the pilot test. Dimensionless Pressure Index (DPI) is established on the basis of PI, which not only takes the transformation of fluid flow capacity into consideration, but also keeps its initial advantages—simple and low-cost. Synthetic models are used to validate the methodology. And the pilot test shows that identification of thief zones by DPI is in good accordance with other approaches. Moreover, DPI can also be applied to determine the severity of the thief zone for a certain oilfield. Another advantage of DPI is that the combination of PI and DPI will make the profile control project design more effective and improve waterflooding surveillance. This approach has been applied successfully in several China oilfields.
The Application of Microbial Enhanced Oil Recovery in Daqing Oilfields
Authors: Zhaowei Hou , Xumou Dou , Rui Jin , Rui Wang , Yanling Wang , Wei Li
Published: July 2011

To seek an effective oil recovery approach, Brevibacillus brevis and Bacillus cereus were screened and applied in a Microbial Enhanced Oil Recovery (MEOR) process to recover oil from Daqing low permeability oilfield where have many disadvantageous conditions. Microbial huff and puff trials have been conducted in 93 wells with accumulative incremental oil amounting to 100878 barrels and average of 1081.9 barrels for one individual well. The effective ratio was 74.2%. Microbial flooding field test with 2 injectors and 10 producers was carried out.7 out of 10 wells showed effective results, with 105995 barrels of accumulative incremental oil. In October 2009, expanding field test with 9 injectors and 24 producers was carried out in this block. Now 15 wells have shown good effect with oil production increased by 41.6%. The analysis showed that wells with good injection-production relationship, differences of layers and well deliverability are main effects to the results of microbial huff and puff. The microbial flooding results showed that wells along the main channel sand and developed fracture zones had a better response.
Reliable Characterization and Modeling of the Capillary Transition Zone and Flow dynamics in the Oil Rim Reservoirs
Authors: Masoudi Rahim , Karkooti Hooman , Othman Mohamad B. , Darman Nasir H.
Published: July 2011

The oil rim reservoirs are referred to the reservoirs with limited oil column underlain with aquifer and overlain by a gas cap. In such reservoirs, the whole oil column can be in the capillary transition zone with a complex flow dynamics. In some cases, oil might have been displaced by imbibition process over geological time during the fluid migration history following the initial primary drainage. Understanding the capillary transition zone, displaced oil zone, saturation modeling, mobile oil distribution and flow dynamics can influence the resource estimation, field development planning and ultimate recovery.

In this paper, we present an extensive review on the concept of the transition zone characterization and the current limitations and challenges in modeling static and dynamic properties in oil rim reservoirs. Various actual field data and examples are presented to better understand the flow characteristics in capillary transition zone. To perform the study, we utilize sector modeling from real oil rim fields with displaced oil zone, the actual drainage and imbibition SCAL measurements, and the historical field performance data. Modeling approaches based on sole drainage and sole imbibition for initialization, imbibition and hysteresis impact on the flow dynamics and residual oil saturation (Sor) dependent to the initial oil saturation (Soi) have been investigated.

The study show that the sole drainage based approaches could underestimate the potential of the transition zone, which can make the project less commercially attractive. This method can lead to significant errors in residual oil saturation and inevitably unrealistic history match assumptions. The resulted model could be very mis-leading in the production forecasting. It is shown that proper description of representative relative permeability and capillary pressure data and residual/initial oil saturation dependency will lead to a more realistic history matched model. This could play a major role in the field performance predictions including the value of the tertiary oil recovery, in particular, for heterogeneous reservoirs.
Emulsion Characteristics and Novel Demulsifiers for Treating Chemical Induced Emulsions
Authors: Nguyen Duy , Sadeghi Nicholas , Houston Christopher
Published: July 2011

In this paper, the stability of oil-in-water emulsions produced from chemical enhanced oil recovery processes was investigated over a wide range of parameters. These parameters are surfactant concentration, polymer concentration, mixing speed, asphaltene concentration, salinity concentration, water cut, temperature, and alkaline concentration. Emulsion stability decreased with an increase in temperature, salinity content, or water cut. Increasing surfactant concentration, polymer concentration, or shear rate enhanced emulsion stability. One of the main contributions for the tight emulsion from alkaline surfactant polymer (ASP) flood was the addition of alkaline. The surfactant, alkaline, and polymer decreased the size of oil droplets, increased the surface charge of oil droplets, and increased the film elasticity, thereby making oil-water separation difficult. Selected cationic surfactants (patents pending) proved much more effective than conventional nonionic resins and polymeric cationic flocculants in separating oil-in-water emulsions. We also studied the effect of alkyl chain length (C8 – C18) of benzyl and methyl quats on demulsifying efficiency and compared the performances of monoalkyl quat with dialkyl quat. As the surfactant concentration in the brine decreased, the concentration of the cationic demulsifier required to separate the emulsion decreased and the optimum chain length of the cationic demulsifier also changed. Particle video microscope and focused beam reflectance measurement probes showed significant increase of the size of oil droplets and reduction in the number of oil droplets in the presence of a cationic surfactant. This is in agreement of a decrease of the anionic charge on the surface of the oil droplets and a reduction of the film elasticity in the cationic system. Application of this novel demulsifier resulted in a much more effective oil/water separations process with the production of dry oil and clean water at a pilot ASP flood that was experiencing very stable emulsions.
Prediction and Experimental Measurements of Water-in-Oil Emulsion Viscosities during Alkaline Surfactant Injections
Authors: Kalra Amrit , Raney Kirk , Dindoruk Birol , Venkatraman Ashwin
Published: July 2011

Oil production is generally a complicated multi-phase flow inside pipelines, with possible W/O emulsions present with other usual phases such as free water and free oil. The water-in-oil (W/O) emulsions formed can present significant hurdles in production facilities for pumping fluids and during pipeline transport. It is well known that high shear rates provided by pumps, chokes or valves result in stable emulsion behavior for a field in primary production. Several field tests are underway to test the potential of surfactant flooding as a tertiary recovery mechanism. The effect of addition of surfactants on the emulsion rheology of production fluids, as in Alkaline Surfactant Polymer (ASP) flooding, is not very well understood. This understanding of W/O emulsion rheology in ASP injected oil recovery is essential for design of pumps and pipelines as well as for handling flow assurance issues.

In this paper, we report results from experiments as well as modeling of W/O emulsion rheology that can form during ASP injections. We focus here only on the Alkaline Surfactant (AS) part of these injections in order to clearly understand the impact of surfactants and removing the uncertainities that come with large rheology changes with polymer addition. The effect of surfactants on the rheology of W/O emulsions was studied by making two different types of emulsions: 1) native brine W/O emulsions without surfactants to provide a baseline 2) W/O emulsions with surfactants used in AS injections. This way, the impact of AS injections on emulsion rheology can easily be quantified. A new correlation is developed, based on in-house historical experimental data, to describe rheology of emulsions without surfactants. This correlation should assist in managing the uncertainties that come from extrapolating emulsion rheology measured in the laboratory to actual field conditions. Further, in order to understand the effect of AS injections, new experimental measurements were made by adding surfactants to brine solutions. The addition of surfactants resulted in different rheology as compared to emulsions formed by brine solutions. These differences have been attributed to the water-oil interfacial tension (IFT), and IFT was added to modify the original correlation. To our knowledge, this is the first study that explicitly relates emulsion rheology with interfacial tension.
Adjoint-based Optimization of Polymer Flooding
Authors: Van Doren Jorn , Douma Sippe , Wassing Bart , Kraaijevanger Hans , de Zwart Bert-Rik
Published: July 2011

In this work we consider model-based optimization of polymer flooding. The reservoir performance is optimized by finding for each injection well optimal values for control variables such as injection and production rates, polymer concentrations, and times when to switch from polymer to water injection (i.e. polymer grading). The same technique can also be applied to optimize other EOR processes such as for example designer water flooding, alkali-surfactant polymer (ASP) flooding and foam flooding. The optimization method that has been used relies on the adjoint implementation in our in-house reservoir simulator to efficiently calculate the gradients. The adjoint method enables the computation of gradients with respect to injection and production rates, injection compositions of each well and switching times of each well at the additional cost of approximately the computation time of a single reservoir simulation. The optimization method uses the adjoint-based gradients to estimate the values of all polymer injection control variables that maximize reservoir performance.

The optimization method is demonstrated on a full-field reservoir simulation model. The physics that is modeled includes polymer mixing, hydrodynamic acceleration of the polymer molecules and adsorption of the polymer to the rock. The example shows that the Net Present Value increases significantly as a result of the optimization, mainly due to increased oil production and decreased polymer injection. The obtained optimal control is physically interpreted, so that the learning points from the model-based optimization can be applied to the field and can be used to enhance the polymer flood.