bluuebunny/crossref_metadata_2025_split huggingface dataset:
Wettability Alteration During Water Flooding and Carbon Dioxide Flooding of Reservoir Chalk Rocks
Authors: Fjelde Ingebret , Asen Siv Marie 
Published: July 2010

AbstractIn the presented work the wettability conditions of reservoir chalk plugs have been characterised after water flooding with formation water, after spontaneous imbibition and water flooding by sea water, and after the first cycle of water alternating carbon dioxide flooding (CO2-WAG). Core plugs from a fractured chalk reservoir in the North Sea were used in the experiments carried out at reservoir conditions. Easily accessible sulphate in the core plugs was removed before the core plugs were drained to initial water saturation by using the porous disc method. Wettability acquisition was then carried out using stock tank oil. The wettability conditions of the chalk plugs were characterised by the spontaneous imbibition of water and the water-wet area determined by the sulphate wettability test.The water-wet area of reservoir chalk plugs water flooded by formation water was found to be rather small. The spontaneous imbibition of formation water was also rather low for companion core plugs. The prepared reservoir chalk plugs therefore appeared to be close to mixed-wet or preferential oil-wet. Sea water has earlier been found to improve the spontaneous imbibition of water into reservoir chalk plugs from the same field. After spontaneous imbibition and viscous flooding with sea water, the water-wet area of the core plugs was found to be on the average slightly larger than for the core plugs water flooded by the formation water. When the same core plugs were flooded with CO2, most of the oil was produced. After the following sea water injection, the water-wet area was found to be larger than before the simulated first cycle of the CO2-WAG flooding.During long term spontaneous imbibition experiments followed by viscous water flooding by sea water, slightly alteration of the wettability conditions towards more water-wet was observed. In the first cycle of a CO2-WAG process, the reservoir chalk plugs were found to become even more water-wet. Alteration of the wettability conditions to more water-wet during CO2-WAG processes can be important for the oil recovery in fractured chalk reservoirs, and should therefore be studied further.
Innovative Drag Reduction of Flow in Rock's Micro-channels Using Nano Particles Adsorbing Method
Authors: Di Qinfeng , Shen Chen , Wang Zhanghong , Jing Buhong , Gu Chunyuan , Qian Yuehong 
Published: July 2010

Abstract
Water injection is one of the main means of improving oil recovery in oilfields where high injection pressure or low injection rate is the main problem meted. In order to exploit low permeability reservoir more efficiently, the reservoir reconstruction methods which reduce drag by amplifying pore size, such as acidification, hydraulic fracturing, are used widely. The existent problem is the possibility that the reservoir may be contaminated. Then the surface modification methods, which decrease surface tension of micro-channels, have been used in oilfield. In this paper, an innovative drag reduction method is put forwarded to decrease the drag of laminar flows of water through rock's micro-channels and then decrease the injection pressure of flooding significantly. The solution containing hydrophobic nanoparticles(HNPs) of SiO2 is injected into the micro-channels of reservoir and the HNPs are adsorbed to the wall to form a strong or super hydrophobic layer, which can lead to a slip boundary condition and decrease drag on the fluid. This mechanism has been modified with a series of experiments and simulation methods by the authors. The Scanning Electron Microscope (SEM) pictures show that a hydrophilic wall can adsorb hydrophobic nano-particles tightly and the contact angle pictures of the new surface validate that the hydrophilic wall has been turned to a strong or super hydrophobic surfaces. The core displacement experiments show that the flow resistance through nano-particles adsorbing rock's micro-channels can be reduced greatly, and about 47% of the water-phase effective permeability (WPEP) of the rock samples on average for all four core samples have been gotten, and this means that a slip effect has been made by nano-particles absorbing method. The simulation with lattice Boltzmann Method (LBM) shows that a large slip length of 0.102μm is obtained. Three oilfield tests show that the maximum injection pressure of 12.5 MPa has been dropped and this method will have good application in the development of low permeability oilfields.
Use of CO2 Containing Impurities for Miscible Enhanced Oil Recovery
Authors: Wilkinson John R. , Leahy-Dios Alana , Teletzke Gary F. , Dickson Jasper L. 
Published: July 2010

Abstract
When conducting enhanced oil recovery (EOR) projects, utilizing CO2 as a solvent, there are three primary options for sourcing the CO2 injectant. These are naturally occurring deposits, anthropogenic flue gas capture, or recycled CO2 from an earlier stage of an EOR project. All of these sources may contain impurities that will change the properties of the injectant, potentially impacting all stages of the system. For instance, captured flue gas may contain quantities of N2, while produced or recycled sources may contain CH4 and/natural gas liquids (NGL). Either or both may contain SO2 or H2S. Each of these impurities has a different effect on the thermodynamic and fluid flow characteristics of CO2; exhibiting either beneficial or detrimental impact on miscibility, density and viscosity of the injectant and its interaction with in situ hydrocarbons. Impurities can also modify compression capacity, corrosion control and pipeline specifications. This paper describes the impact of CO2 impurities on all stages of an EOR project, from CO2 capture to flood efficiency prediction.
Miscibility, density, and viscosity, along with rock properties, are the primary determinants of flood efficiency in a given rock and fluid setting. A screening tool has been developed to estimate EOR performance for different crude oils. Screening is done for miscibility, density, and viscosity and other parameters important to the efficiency of an EOR process. A key component of the screening tool is a solubility-parameter-based approach to screening CO2 injectants containing impurities for miscibility against a range of crude oils. This technology, combined with worldwide operating experience, has been used to evaluate EOR potential in reservoirs across a full range of pressure, temperature, and fluid compositions. By accurately evaluating the impact of impurities in the injectant, it is also possible to estimate an economic optimum solution for securing and utilizing an injectant supply without incurring the additional costs of treating the stream to remove and dispose of all impurities.
By way of a field example, the paper discusses the impact of miscibility, density and viscosity on the efficiency of the CO2 miscible EOR process. It also presents investigations aimed at extending current light oil recovery projects into reservoirs with either residual oil zones (ROZ), viscous oils or biodegraded crudes.
Scale Management Strategy and its Results in a Giant Deepwater Oilfield in Campos Basin
Authors: Gomes R. M. , Deucher R. H. , Aniceto P. H. , Silva F. A. , Prais F. , Skinner R. 
Published: July 2010

Abstract
Scale occurrence in a giant oilfield located in deepwaters off the Brazilian coast required the implementation of strategies to remediate and prevent scale formation, which was a cause of significant production loss in the field. To prevent scale formation, inhibitor squeeze treatments have been utilized since 2006, when two squeeze treatments indicated an inhibitor lifetime lower than the predicted from laboratory tests. The inhibitor used is derived from the phosphonic acid, making it possible to analyze the inhibitor concentration in the produced water, and consequently, determine its lifetime. Despite the lower lifetime, the wells did not show any production loss, even when inhibitor concentrations were lower than the minimum inhibitor concentration (MIC), determined in laboratory tests. Throughout 2007, due to operational and contractual concerns, it was not possible to perform the squeeze treatments. Consequently, by the end of that year, production losses were verified. In 2008, the inhibition campaign was restarted, and based on the results of 2006 operations, the squeeze treatment volumes were recalculated, in order to obtain a higher inhibitor lifetime. As a result, it was possible to extend the treatment lifetime and maintain the production of the wells stabilized. Historic cases of three wells will be shown, emphasizing the extensive production loss verified when the treatment was not performed, the impact observed in the production when the treatment was delayed and the success obtained when the treatment schedule was accomplished. Beyond the scale occurrence in the production wells, there are also severe scale problems in the production facilities, which will be discussed in this paper. This work describes and details the scale monitoring, prevention and remediation strategies employed in this field, exposing the results obtained, as well as the learned lessons and opportunities to improve the scale management strategy.
Numerical Simulation Studies of Gas Production from Natural Hydrate Accumulations Using Depressurize Technology
Authors: Dou Bin , Jiang Guosheng , Qin Mingju , Wu Xiang , Gao Hui 
Published: July 2010

Abstract
The objective of this study is the analysis of gas production scenarios from gas-hydrate-bearing zone. The zone is characterized by a 15-m-thick hydrate accumulation, the base of which marks the bottom of the hydrate stability zone. The temperature at the bottom of the hydrate layer is 13.5°C, the gas hydrate equilibrium temperature at the formation pressure of 10.7 MPa. The gas hydrate interval has a hydrate saturation SH=0.7, the rest being gas. The analysis of the production scenarios in this paper were conducted using the TOUGH+HYDRATE general-purpose simulator for multi-component, multiphase fluid and heat flow and transport in the subsurface with the EOSHYDR HYDRATE module. Using numerical simulation, we estimate the rates of gas production and gas release from hydrate dissociation, the corresponding cumulative volumes of released and produced gas in single hydrate exploitation well that production gas using depressurize technology. The results of this study indicate that, the decomposition speed of gas hydrate is from high to small, and the process is cycle. The general trend of gas volume production from hydrate is increasing. So as to keep the gas volume stable of gas production from gas hydrate, a certain degree of heat should be added to the gas hydrate production well cyclically in accordance with design parameters. The results of study provide a theory and technical foundation for natural gas hydrate mining able and economic evaluation.
Reservoir Characterisation of the Mio-Pliocene Reservoirs of PM301 in the North Malay Basin
Authors: Carney S. , Abd Aziz I. , Martins W. , Low A. , Kennedy J. 
Published: July 2010

Abstract
Block PM301 is located in the north Malay Basin adjacent to the Malaysia Thailand Joint Development Area (MTJDA) gas hub. Seven gas fields have been discovered in the block to date. In order to move the project through the production value chain, an integrated subsurface study was carried out to gain a deeper understanding of the fields’ potential and an insight into how to optimally develop these complex reservoirs.
The PM301 fields will be challenging to develop as they are relatively small (typically 200Bcf each, GIIP) and geologically complex, associated with deposition in a fluvial to shallow marine setting. There are also petrophysical issues, including fine scale reservoir heterogeneity, complex mineralogy and low-resistivity low-contrast pay. Seismic interpretation is challenging due to shallow gas, the presence of coal and resolution of thin reservoir intervals.
A detailed, integrated data gathering and interpretation effort involved the development of a depositional model, a stratigraphic layering scheme, definition of key depositional and lithofacies and a reservoir characterisation study. Reservoirs have been characterised in terms of rock types and pore types based on petrographic and core analysis data which have been combined with detailed log evaluations to determine potential flow units, baffles and barriers. Detailed analysis of rock property data tied to seismic is one of the most important aspects of the project.
Key lessons learnt include the importance of acquiring good subsurface rock data and the need for meticulous seismic interpretation in order to filter out acquisition artifacts and optimise the data. Also, the application of Lorenz plots and Winland R35 analysis, calibrated to test data provided key rock quality and heterogeneity information. This study and the techniques applied have application in other complex fields.
A Multi-Segment Multiphase Wellbore Model Associated with Dynamic Gridding
Authors: Dong Chao C. , Bahonar Mehdi , Chen Zhangxin , Azaiez Jalel 
Published: July 2010

Abstract
As more and more wells have been put in operation, an accurate modeling of wellbore flow plays a significant role in reservoir simulation. One requirement of a wellbore model is its ability to trace various flow boundaries in the tubing, such as due to phase or flow regime changing. A black oil multi-phase multi-segment dynamical wellbore flow model has been coupled into Stanford's General Purpose Research Simulator (GPRS), which has the capability to simulate the isothermal black oil reservoir model to obtain detailed information on such important quantities as flow pattern and mixture velocity in any specific location of wellbore. A significant problem in this case is how to calculate fluid and velocity properties with a fine grid (segment) on the boundaries of different flow regimes in the wellbore. Local dynamical segment refinement in the well can accurately and effectively handle this problem. This wellbore model includes mass conservation equations for each component and a general pressure drop relationship. The multiphase wellbore flow is represented using a drift-flux model, which includes slip between three fluid phases. The model determines the pressure, mixture flow velocity and phase holdups as functions of time and the axial position along the well or alleviation depth. In addition, this model is capable of generating automatically adaptive segment meshes. We apply the black oil model to simulation of several cases on dynamical local mesh refinement isothermally, and compare the results with fixed coarse and fine meshes. The experiments show that using local segment refinement can yield accurate results with acceptable computational time.
Borehole Stability Challenges in Gas Drilling: Case Studies in West Sichuan Basin
Authors: Li Gao , Meng Yingfen , Liu Houbin , Zhou Yuliang , Zhu Yixin 
Published: July 2010

Abstract
Tight sand gas reservoirs in west Sichuan basin are deeply buried, about 3 to 5 kilometers. They are easily damaged during conventional drilling, and the drillability of the mid-depth sand shale layers is poor. Air drilling and nitrogen drilling are selected to improve ROP and protect formation. However, the borehole stability is a big problem through several pilot gas drillings. In this paper, combined lab investigations with pilot drilling information analysis, it is found that the complex geologic conditions and drilling operations lead to at least four kinds of borehole instability. First, the lithology varies frequently in longitudinal section and the weak argillutite alternate layers rate more than 50% thickness of the whole profile, which leads to mechanic instability problem. Next, drilling open of abnormal high pressure gas layers leads to second wellbore stress distribution, which results in sandstone avalanche and adjacent argillutite layer collapse. Third, wellbore enlargement is common due to breakage of deep friable hard shale layers. At last, aqueous phase invasion due to drilling operation or formation water production from lower layers leads to swelling and weakening of argillutite formation, which results in borehole collapse and sticking. According to such mechanisms, gas drilling borehole stability prediction methods were presented and proved to be helpful to successful gas drillings in this area.
Case Study: The Sand Management and Control Techniques for Complex Fault-Block Reservoir in Gangxi Oilfield
Authors: Jianwen Yan , Yurong Zhang , Yuzhang Liu , Chunming Xiong , Jiandong Liu , Hanbing Xu , Qiqing Han 
Published: July 2010

Abstract
Gangxi Oilfield is a typical complex fault-block oil reservoir which belongs to unconsolidated sandstone reservoirs with high porosity and high permeability. Sand producing, sand jamming and sand bearing are serious problems for most producers in this field during oil production. With the increase in water cut, the sand producing problem is getting worse which seriously impacts normal production of oilfields. According to the statistics for Gangxi Oilfield in the last two years, there were 283 wells with serious sand producing problem, among which 274 had to stop production because of sand producing and sand bearing. The average sand production of single well was 6.96 m3 under inspection operation from the statistics of 73 wells. Based on the locations of producing zones, frac-pack was chosen as the main sand prevention technique for the wells through Minhua formation, circulating packing for the wells through Guantao formation, chemical sand control for horizontal wells and sidetrack drilling wells, and packing layer by layer for the multilayer-section production and long-hole section. By selecting the sand control techniques and optimizing the parameters for Gangxi Field, a scientific basis was laid down for the sand management, and it was applied succefully in the field.
Use of Multi-Sample Characterization Method for EOS Tuning to Model Full Field Crude Oil Properties
Authors: Khajooie S. , Shahrabadi A. , Hamid K. 
Published: July 2010

Abstract
In compositional simulation of oil and gas reservoirs, equation-of-state (EOS) methods are seeing increasing usage for phase equilibrium calculations. EOS compositional reservoir simulation is an accurate and powerful means to model complicated phase and flow behavior when the displacement process depends on pressure and fluid composition. Many field development projects have strong composition dependence, such as miscible gas injection for oil reservoirs or liquid recovery under lean gas injection for condensate reservoirs or water-alternating-gas injection.
This paper presents characterization of some crude oil samples from an Iranian reservoir using the Peng-Robinson Equation of State (PR-EOS) to arrive at one EOS model that accurately describes the PVT behavior of crude oil produced from the different wells in the reservoir. The multi-sample characterization method is used to arrive at one consistent model for crude oil for the whole reservoir.
However, uncertainties still exist that are associated with the use of an EOS to model petroleum reservoir fluids because of the complicated nature of such fluids and limitations of the most commonly used EOS's. Tuning the adjustable EOS parameters to match experimental fluid PVT data is a common practice. The tuning procedure for the EOS is done systematically by matching the volumetric and phase behavior results with laboratory results. Also, a consistent C7+ pseudo component split using the Whitson splitting method is used for all samples to arrive at a consistent model for crude oil for the whole reservoir.
Results showed a good agreement between model predictions and laboratory data. Also the results demonstrate that multi-sample method has high ability to provide one EOS model for the crude oil using PVT test results from different wells. The EOS model developed for this particular field may be used in reservoir simulation studies to optimize hydrocarbon recovery.
A New Method to Evaluate the Gas Migration for Cement Slurries
Authors: Haijin Zhu , Jiansheng Qu , Aiping Liu , Jianlong Zou , Jiaxing Xu 
Published: July 2010

Abstract
The oil industry wrestled with the problem of gas migration after cementing for many years. As yet an extensive research has been carried out on the problem of gas migration. A lot of corresponding slurries were developed, and most of them have been used successfully in some districts but not total alleviation of the problem. The main reason is the lack of a method to evaluate the gas migration of cement slurries when considering actual well parameters.
In this paper, based on previous art of the method to scale-down well parameters to laboratory for more realistic testing of cement recipes, by establishing the method of measuring cement slurries’ static gel strength to gain the development of the annular column hydrostatic pressure, a new method to evaluate the gas migration for cement slurries was developed. This method depends on the decline of upper annular column hydrostatic pressure, and can be used to evaluate the ability of the cement slurry in controlling gas migration. Several cement slurries were investigated by this method. The laboratory tests were presented with good repeatability, and could be used to test the ability of cement slurries in controlling gas migration.
In field applications, this method has been used in designing cement recipes when cementing gas wells in Chuanyu Area of China. The ability of cement slurries in controlling gas migration has been tested. The field results were consistent with the laboratory tests, and demonstrated the method could be used to guide cement slurries design effectively.
The Study of The Circulation of Drilling Foam
Authors: Wan LiPing , Meng YingFeng , Li YongJie , Wang Jian , Shu XiaoBo , Zeng QingMing 
Published: July 2010

Abstract
The circulating utilization of foam fluid is available, which was based on some of the lower carbon alcohols presenting the characteristics of both strong defoaming and weak restricting foam ability, and through optimum selection of formula by indoor experiments. The recirculable feature of four kinds of alcohols on unstable foam (0.6%K12), stable foam (0.6%K12+0.2%XC+0.2%HV-CMC) and stiff foam (0.6%K12+0.2%XC+0.2%HV-CMC+5.0%bentonite) was comparatively investigated. The circulating foam ability of the mixed system of alcohol D and tributyl phosphate (TBP)was studied on the self-made foam fluid circulation experimental device. The results show that alcohol D is the most suitable defoamer in four kinds of alcohols. The mixed system of alcohol D and TBP can recycle stable foam at least 8 times. With increasing cycle number, both foam volume and half life decrease, in which foam volume falls gradually and half life declines more dramatically. After 8 runs, the volume of foam falls from 470ml to 420ml and half life declines from 28.7min to 15.8min, but both of them can fill the actual requirements of on-site drilling.
This paper is the first in a series of studies designed to bring forward foam circulating utilization in underbalanced drilling by adding alcohol as defoamer. The goal is to understand the mechanism of foammg-defoaming-refoaming of alcohol better, and extend air foam drilling techniques in suit region.