bluuebunny/crossref_metadata_2025_split huggingface dataset:
Bayesian Network Analysis as a Tool for Efficient EOR Screening
Authors: Zerafat M. M. , Ayatollahi Sh.. , Mehranbod N.. , Barzegari D.. 
Published: July 2011

AbstractThe 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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
Many fields in the Middle East suffer from low recovery and declines in primary production due to low oil gravity (&lt;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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.