bluuebunny/crossref_metadata_2025_split huggingface dataset:
Productivity Decline in Oil Wells Related to Asphaltene Precipitation and Emulsion Blocks
Authors: Kokal Sunil , Dawood Naseem , Fontanilla Jerry , Al-Ghamdi Abdullah , Nasr-El-Din Hisham , Al-Rufaie Yousef 
Published: December 2007

Abstract
A few oil wells in a Saudi Arabian field have shown significant oil productivity decline in recent years. A few of them have ‘died’ prematurely while others have become intermittent producers. It has been noticed that the oil productivity decline is aggravated with water encroachment. The oil productivity decline has come about with relatively low water rates and without any significant drop in reservoir pressure. These wells have low productivity index (PI) resulting in relatively low flowing bottom hole pressures (FBHP).
This paper presents the results of an investigative case study to determine the causes of productivity decline in these wells. A multi-disciplinary team was set up with engineers and scientists from reservoir management, production engineering and the R&D Center for the investigative study. The team focused on multiple aspects including reservoir and production engineering, as well as a comprehensive laboratory and field investigation.
The results of this study indicate that one of the main causes of productivity decline in these wells is related to asphaltene precipitation and the subsequent formation of tight emulsions downhole. The emulsions block the pore throats and cause formation damage leading to productivity decline. Another factor that further aggravates the productivity of these wells is poor rock quality in the area. Possible causes of formation damage due to inorganic scaling, and leakage and mixing of gas from a deeper reservoir have been eliminated.
Well test analyses on some of the affected wells shows the formation damage mechanism in the affected area is further aggravated by poor reservoir rock quality. The time-lapse pressure transient analysis also indicates a deterioration of skin and productivity with time.
Based on these findings a special solvent treatment was recommended and designed as a pilot trial for one of the dead wells. The treatment included squeezing xylene and demulsifier to dissolve the asphaltenes and break the tight emulsions around the wellbore area. The treatment resulted in only a slight improvement in the productivity index and the well died after a few days. Currently a stimulation treatment with acid and demulsifier is being implemented in selected wells. The results of the field trials will be described in the paper.
Development Well Testing Enhancement Using a Multiphase Flowmeter
Authors: Mus E. A. , Toskey E. D. , Bascoul S. J. F. , Barber E. C. 
Published: December 2007

Abstract
The use of a multiphase flow meter in the well testing facilities has yielded significant enhancements for the development program of the Girassol deep offshore field. Well performance assessment is improved by the complete data coverage and better accuracy the meter provides. Operating time is reduced because the well test data is obtained during the clean-up period. Use of the meter also allows a better control of the well clean-up duration and effectiveness. Overall, the flow assurance is improved because of the improved data quality given by the flow meter.
3 D Quantification of Vugs and Fractures Networks in Limestone Cores
Authors: Martinez-Angeles R. , Hernández-Escobedo L , Perez-Rosales C. 
Published: December 2007

Abstract
This paper presents the results of X-ray scans in vuggy-fractured limestone core studies to determine porosity rock distribution and residual oil and water saturations for mexican core samples. Iodine as the injecting fluid provided a means for detecting water saturation and residual oil saturation. X-ray Computerized Tomography (CT) was applied as an approach for oil and water saturation determination. The tracer (iodine) studies indicated that the water invasion increases with time until to get conduction porosity. CT scans measure the density distribution inside of vuggy-fractured cores and block models samples during X-ray CT laboratory experiments. Firstly, an image processing method for determining, simultaneously, some of basic geometrical characteristics of homogeneous and vuggy-fractured porous media such as secondary porosity, specific surface, mean pore width, mean block thickness, mean fracture width, and absolute permeability is applied in order to characterize the core. Then, oil recovery mechanisms from vuggy-fractured reservoirs were studied because of the large reserves contained in such formations- The estimation of saturation of residual oil is fundamental to oil recovery from vuggy-fractured reservoirs under primary and enhanced recovery processes of practical interest. Saturation of residual oil depends of several petrophysical parameters such as conduction porosity, stagnation porosity, cementation exponent and fluid properties like viscosity of wetting and nonwetting phases. In this paper we present our recent work on imaging dynamic characterization in a vuggy-fractured core (calcareous) with X-ray tomographic techniques. We also perform forced displacement experiment to get two liquid phases inside the vuggy-fractured limestone core.
Laboratory development and Successful Application of a Micelle Dispersions System to EOR
Authors: Tian Yuqin , Wang Lushan , Lv Xihui , Li Jiyong , Li Gongrang , Zeng Xianxiang 
Published: December 2007

Abstract
The laboratory performance properties of the colloidal dispersion system are described in the proposed paper. This paper deals with the improvement and application of a new technology to EOR. This technology is applicable to high salinity, high temperature and severe heterogeneity reservoir.
The essence of this technology is to decrease the water cut of production wells and attain the result of oil production and recovery enhancement by injecting an improved micelle dispersions system. According to lab test, this colloidal dispersion system is a pseudoplastic fluid with temperature tolerance, salinity tolerance, shearing resistance, stability and low cost. The lab experiment result shows oil recovery is improved by 8—10%.
The information of lab study and field application relative to this technology has been presented at the 2000 International Symposium on Petroleum Engineering. The previous technology has a defect of crosslinking to polymer's wide applicability, now this system has been improved in its properties. The new micelle dispersions system can satisfy all polymer in use and form stable weak gel system. It can keep stable when reservoir temperature is 90°C, water salinity is 80000mg/L (Ca2++Mg2+≤ 2000mg/L).
A pilot was conducted in fault—block Xin 50 of Dongxin oil field. There are 4 injection wells and 7 corresponding production wells.in the area The viscosity of aimed formation oil is 80mPa.s, the temperature is 90 °C, the salinity of reservoir is 44100mg/L, well spacing is 300m. Some production wells were effective after 2 months injection during the successive injection of this improved micelle dispersions system. Water cut of typical effective well was decreased by 34.1%. Oil production per day increased 30 ton.
Pilot test shows that this technology has better enlarge commercial application potentiality and economic value. It will be applied in others similar blocks on great scale in the future.
ESP Design Changes for High GLR and High Sand Production; Apache Stag Project
Authors: Muecke N. B. , Kappelhoff G. H. , Watson A. 
Published: December 2007

Abstract
Initial ESP designs for the Stag oil field, located on the Australian Northwest Shelf, were based on a low GOR, high viscosity, 19 API, crude oil. However, higher than forecasted gas rates and gas-oil separation in the 3300 ft long horizontal production sections resulted in flow from the reservoir in the form of slugs of gas and oil. Then, with the onset of water production, high volumes of produced sand compounded the problems. These two main issues, plus a rapidly declining reservoir pressure, have combined to present a challenging ESP production environment.
This paper reviews in detail the evolution of the completion design, focusing mainly on the ESP design, which initially ran for only 191 days, but now averages 511 days.
The intent of this paper is to provide advice to be considered when designing ESP completions for new reservoirs, to provide an example of a good completion design for handling fluids with high ratios of gas and sand, and finally, to provide information on new technology developments that have evolved from these learning experiences.
Innovative Through-Tubing Cement Packer Technique
Authors: Harris Marvin L. 
Published: December 2007

Abstract
Cement packers have been used for many years to access behind-pipe reserves above existing completions in wells with multiple completion targets. The basic function of the cement packer is to create a new annular barrier between an existing production packer and surface. They are typically used when it is not possible to set the production packer above the next zone of interest.
Most cement packer operations are performed rigless to minimize cost. However, in many of these operations, coiled tubing or hydraulic workover services are used for the placement of the cement packer. Although these costs are significantly less than the cost of a rig, they still represent a major source of the total cost to perform the cement packer operation. In certain circumstances, coiled tubing and hydraulic workover services may not be possible because of space limitations, equipment availability, or cost restrictions. Elimination of these services can significantly reduce the cost and complexity of the operation, and improve the economics for the project. This paper presents a technique that can be used to perform a cement packer using only wireline (slickline and electric line) and pumping services.
A case study of several successful cement packer recompletions using this technique is also presented at the end of the paper. The technique has been proven successful in wellbores with gas lift mandrels, in cases where the circulating holes for the cement packer are above or below the zone of interest, in producers and injectors, and in deviated wellbores.
Engineering Aspects of Geological Sequestration of Carbon Dioxide
Authors: Ennis-King J. , Paterson Lincoln 
Published: December 2007

AbstractInjection into geological formations is a technical option for decreasing carbon dioxide emissions to the atmosphere. Several key factors influence the performance and long-term integrity of injection into deep saline formations. Accurate representations of the physical properties of carbon dioxide have compiled and use to determine the theoretical storage density at typical sub-surface conditions, and the amount of energy that would be expended in injecting the carbon dioxide (whether pure or mixed with other gases), leading to an estimate of the net reduction of emissions. Detailed computer simulations indicate that the distribution of the injected carbon dioxide is initially dominated by gravity segregation, relative permeability effects and the permeability anisotropy of the saline formation. Post-injection, important effects occur which are not taken into account in conventional petroleum reservoir simulation. Convective mixing is predicted to occur, which greatly accelerates the dissolution of carbon dioxide in the saline formation water. This unusual phenomenon arises from the increase in the density of brine when saturated with carbon dioxide. Complete dissolution of the injected carbon dioxide is predicted to occur over hundreds to thousands of years, depending significantly on the vertical permeability of the formation and the geometry of the top seal. Reactions between the carbonated water and the formation also increase the rate of dissolution. If the chosen site is not a structural trap but a gently dipping regionally extensive formation, then the carbon dioxide can migrate up to tens of kilometres from the injection site, depending on the angle of dip and the horizontal permeability. However, convection and dissolution can still keep the carbon dioxide confined. This theoretical analysis has been developed as part of the Australian Petroleum CRC's GEODISC program, and is being used to assess the suitability of proposed sites for carbon dioxide sequestration.
Influence of the Horizontal Well Length upon Production Rate and Water-Cut Performance in Regular Field Development Systems with Horizontal Wells
Authors: Mukminov I. R. 
Published: December 2007

Abstract
To date, the problems of current productivity and water-cut performance calculations for horizontal wells in different regular field development systems have been poorly studied, and the main method of investigation has been the numerical one. In sheet deposits of Western Siberia, Russia, which have nearly equal mobility ratios of oil and injected water, a nearly frontal drive is observed. This aspect is discussed in the present paper.
The report presents a precise analytical solution of steady-state fluid filtration problem in six regular development systems where horizontal wells are applied. The solution allows the derivation of analytical expressions for the rate, pressure field and filtration velocities, water-free operation time, flooding factor during water-free and water periods of operation, water-cut performance for horizontal wells, and flood front.
Graphic illustrations allow a visual evaluation of the operation character for different sections of the horizontal well, location of unusable zones in a number of well patterns with horizontal wells applied.
The paper shows the influence of the horizontal well length, distance between wells in rows and between well rows upon rate, velocity field of filtration, water-cut time, flooding factor, water-cut dynamics for horizontal wells, and the form of the flood front.
A quantitative range of effective and ineffective applications of horizontal wells is given for each system, depending upon the length of the horizontal section, injection well type (vertical or horizontal), distance between wells in rows and distance between well rows.
The author believes that the paper is very important for a better understanding of flooding processes in field development systems where horizontal wells are applied, and it gives an idea of the way various parameters that characterize the geometrical location of horizontal well systems, influence the deposit operation parameters. The author uses the results to construct a rational 3D hydrodynamic model of Western Siberian reservoirs with reference to a detailed description and the number of cells.
Advanced Production Logging Technology for More Accurate Flow Profiling-Case Studies from the Gulf of Suez
Authors: Elshahawi Hani , Mostafa Hanaey 
Published: December 2007

Abstract
The already complex job of diagnosing production problems and flow profiling in a multiphase environment is further complicated by the complex flow regimes encountered in horizontal, highly deviated, and slim wells. Accurate holdup measurements are needed to clearly identify the first point of hydrocarbon or water entry, and independent oil, water and gas flow rates versus depth are needed to obtain overall downhole flow rates and to identify production from each perforated interval. Qualitative fluid identification is also needed to help determine the type of fluids contributed by each zone. Finally, imaging of the well bore is needed to detect cross flow, circulating flow, and phase segregation.
The latest generation of production logging tools has traditional measurements such as pressure, temperature, density and spinner redesigned to deliver superior accuracy and resolution. New sensors such as local electrical probes for holdup have been collocated with the spinner and an integrated X-Y caliper to provide accurate answers in complex flow regimes. Introduction of this advanced production logging technology in the fields of the Gulf of Suez has represented a virtual breakthrough in the use of production logging in that company. This has enabled the diagnosis and treatment of problems previously undetectable and hence unsolvable due to excessive well deviation, high water cut, or mixing of water injected and formation waters. Correct diagnosis has resulted in proper work over planning and application and, in turn, to improved reservoir management practices.
This paper describes this new technology and presents case histories in which operators in the Gulf of Suez have successfully employed revolutionary production logging improvements to provide timely cost-effective diagnosis for some of the most challenging well production problems.
High Membrane Efficiency Water-Based Drilling Fluids: Alternatives to Invert Emulsion Fluids for Drilling Troublesome Shale Formations
Authors: Tan Chee P. , Drummond Calum J. , Mody Fersheed K. , Tare Uday A. 
Published: December 2007

Abstract
A major collaborative project was undertaken to develop novel environmentally acceptable water-based drilling fluids with high membrane efficiency to help meet the future requirements of the petroleum industry. This paper describes the rationale of the project, the fundamental understanding of osmotic membrane generation in shale that lead to the development of the drilling fluids, and the practical guidelines for maintaining shale stability with the drilling fluids. Specialised test equipment, including membrane efficiency screening equipment, and test procedures were developed for simulation of key drilling fluid-shale interaction mechanisms. More than 300 membrane efficiency screening tests were performed on Pierre II shale samples to screen a wide range of novel compounds for their membrane generation capacity in the shale. Typical examples of the tests conducted with three novel compounds that generated moderately and highly efficient membranes are presented and discussed. The results demonstrate that some of the compounds are capable of generating membrane efficiencies of between 55% and 85%. The new generation of water-based drilling fluids that have been developed performs essentially like oil-based muds in terms of shale stabilisation. Practical mud design guidelines that have been developed can be used to optimise the drilling fluid design, in terms of mud weight, salt type and salt concentration, to manage efficiently time-dependent wellbore instability in troublesome shale formations.
Producing More Than 75% of Daqing Oil Field's Production by IOR, What Experiences Have Been Learnt?
Authors: Wang Demin , Sun Yingjie , Wang Yan , Tang Xuping 
Published: December 2007

Abstract
The annual production of Daqing Oil Field reached 50 million tons (1 million bbl/d) in 1976 and has maintained stable up to the present for 26 years. In year 2001, the annual production produced by wells drilled before 1975 is only 12 million tons, the remaining 38 million tons, which amounts to about 76% of Daqing's total production mainly comes from IOR. The large scale implementation of IOR not only increased the production, but also more than doubled the recoverable reserves of Daqing from 1 billion tons to 2.2 billion tons.
A large amount of actual field data and production history curves are used to show the results on the entire field of different IOR methods on multi-zone stacked reservoirs and single zone thick reservoirs, including the increase in production and recovery, decrease in water-cut and influence on production costs of the entire field.
The total results of IOR implemented on large areas of the oil field (each having more than 1 thousand wells) and on the entire field (more than 50 thousand wells) over a long period of time of more than 30 years is shown. The change in production rate, recovery, water-cut and production costs are also shown. How IOR can maintain the production stable and increase the reserves at low production costs is explained.
Producing by Polymer Flooding more than 300 Million Barrels of Oil,What Experiences Have Been Learnt?
Authors: Wang Demin , Cheng Jiecheng , Wu Junzheng , Wang Yan 
Published: December 2007

Abstract
In 1996, Daqing Oil Field started industrial scale polymer flooding. The production by polymer flooding since then has rapidly increased. The annual production by polymer flooding in year 2001 was more than 70 million barrels (bbl), cumulative production more than 300 million bbl and more than 3 thousand wells are on polymer flooding. Much experience has been learnt on large scale polymer flooding in these 6 years, including: actual recovery in the field; major factors that influence the recovery and methods to increase the recovery; measures to obtain a uniform polymer flood front; and how to lower the costs of producing crude oil by polymer flooding.
Improvement of Permeability Prediction for Carbonate Reservoirs Using Well Log Data
Authors: Babadagli T. , Al-Salmi S. 
Published: December 2007

Abstract
The prediction of permeability in heterogeneous carbonates from well log data represents a difficult and complex problem. Generally, a simple correlation between permeability and porosity cannot be developed and other well log parameters need to be imbedded into the correlation. The first part of this paper covers an extensive review of the existing correlations in literature. The use of porosity and other petrophysical properties of rock in permeability prediction is discussed for carbonaceous rocks. This discussion also covers the usefulness of a wide variety of correlations developed using pore (Kozeny-Carman, percolation, and fractal models) to field scale models (well logs).
In the second part of the paper, a case study was presented. The data are obtained from a complex carbonate field in Oman. Conventional and non-conventional (mainly Nuclear Magnetic Resonance, NMR) well log data are evaluated to seek the parameters reflecting a good correlation with permeability. After testing each independent variable against core permeability, the variables yielding the highest correlation coefficient are included in multiple regression analysis. Data collected from seven wells are used to obtain the permeability correlations for the whole field and four geological units separately. The test of the correlations is achieved through the comparison of the estimated permeability values to core permeability. Finally, the correlations are compared with the core permeability of the eighth well (data from this well are not included in the development of the correlation) for validation. The correlations are obtained for the four geological units. Two of these units responded well to conventional well log data. Other two units yielded reasonable correlations only with NMR log data.