bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Investigation into Near-Critical Phenomena of Rich Gas Condensate Systems
Authors: Zheng Xitan , Sheng Pingping , Li Shi , Luo Kai , Dai Zhijian 
Published: December 2007

Abstract
The petroleum exploration pushes the frontier to deeper strata with more near critical fluids. However, the documented studies on near critical behavior of complex fluids are absent, especially for unsymmetrical multi-component and real reservoir fluids. Thus the phase behavior of near critical systems has attracted considerable attention. This paper presents some experimental results of near critical phenomena of three rich gas condensate systems. The measurements are performed with mercury-free PVT equipment. The Lab. fluids consist of one six-component hydrocarbon mixture and two field samples. The results presented contain the critical points, bubble- and dew-point lines, optical phenomena and unusual phase transitions in near critical region, etc.
The percentage-liquid volumes at several temperatures are recorded in detail for all fluids, and are cross-plotted to determine the critical points in pressure-temperature diagram with no further attempts to experimentally determine the precise critical parameters due to the limitations of the PVT equipment. Instead of the opalescence previously reported for carbon dioxide, the reddish-brown color is observed in near critical regimes for three fluids, this may be attributed to the complexity of the fluids. Comparison of the near-critical phenomena obtained in this study shows a large difference between the synthetic and real systems.
Surprisingly, the unusual phase phenomena are observed for the synthetic mixture and one field sample. That is, during the constant composition expansion process the dew-point phase change occurs twice above the critical temperature, and correspondingly dew- and bubble-point phase changes occur sequentially below the critical temperature. In the later case, an interesting finding is that the fluid can not be clearly classified into gas or liquid according to the usual experimental classification of fluid types in PVT cell. In two cases, the first-appeared fluid at the bottom of PVT cell first disappears at the same lower-pressure with pressure depletion, although the temperatures are different. To our best knowledge, the unusual phenomena occurring at high temperature up to 100 Celsius degrees is reported for the first time. These observations present a new challenge on the gas-liquid concepts widely used in engineering fields, and strongly imply limitation of popular two-phase assumption of the PVT calculation in numerical simulation.
The results presented herein are of high value from the theoretical and practical viewpoints, and can find wide applications in various fields involving petroleum industry, e.g., formation fluid sampling, classification of fluid types, well testing, the optimum of the profitable development strategies of gasfield, etc..
Champion East, Low Cost Redevelopment of Shallow, Stacked and Faulted Heavy Oil Reservoirs
Authors: van Kessel Onno 
Published: December 2007

Abstract
The Champion East area offshore Brunei Darussalam consists of around 50 stacked, intensely faulted heavy oil reservoirs, spanning a depth of 200–1200 m ss. These reservoirs have been under development since 1975 and have to date produced just 8% of the oil initially in place. Over the period 1998–2003 Brunei Shell Petroleum (BSP) is embarking on a major redevelopment, with the aim of converting a further 30 million m3 of oil-in-place volume into commercial reserves—requiring at least a 50% reduction in unit development cost against the background of the prevailing, economically tough business environment.
An overview will be given of how new technology is adding value to the total redevelopment, supported by actual application results and learning points. At the same time, Shell’s process of converting notional ‘scope-for-recovery’ volumes into bottom-line reserves additions through forward planning of requirements for technology, studies, IT tools and data, will be highlighted.
The primary development of Champion East is now nearing completion, with a 30-well infill drilling campaign almost finished. This campaign uses existing facilities and ultra-shallow long-reach horizontal wells—with innovative sand exclusion and downhole ‘intelligence’—and has achieved a 60% unit cost reduction over previous drilling campaigns in the area.
The only way to unlock another 5–15% of the oil-in-place volume is to start secondary recovery through water injection, in combination with the use of Electric Submersible Pumps. Long term business value will be secured in two ways: (1) by implementing a limited pilot water injection scheme, using mostly existing wells and facilities, in 2001—again aiming for a 60% unit cost reduction over previously proposed schemes; (2) by data acquisition, studies and sponsoring of joint research programmes (in-house and 3rd party) covering 4-component OBC seismic, chemical and mechanical water shut-off techniques, geochemistry, special core analysis, development of slimhole high-GOR ESPs, produced water reinjection and geomechanics.
Field Experiment of Enhancing Heavy Oil Recovery by Cyclic Fuel Gas Injection
Authors: Zhang Fengshan , Fan Xueping , Ding Jianmin 
Published: December 2007

Abstract
Of the oil produced by Jinzhou Oil Company, Liaohe Petroleum Corporation, 72.7 percent is heavy oil, mainly recovered by cyclic steam injection method. As for the major pay zone, Block Jin-45 and Block Jin-7, the average number of huff-and-puff cycles is as high as 8.9, and average fluid pressure is dropped to 4 MPa at the depth of 1000 meters. Non-uniform production worsens the situation: Oil/steam factor is dropped to 0.49; Natural reduction rate is as high as 46%; and the profit is decreasing year by year. To maintain a sustainable and steady increase in oil production under the current situation, experiments of combined fuel gas and steam cyclic injection were first carried out on heavy oil wells, taking into account the current situation of our oilfield and the development history of similar oil fields in and outside China. After nearly one year’s field experiment, identifiable results have been discovered, such as less air pollution resulted from the emitted gas, better protection of the casing, fewer heat-insulation pipes, more modification of steam injection profile, higher production rate, shorter water drainage period, and greater reduction of operation cost. By the end of year 1999, 599448 cubic meters of fuel gas has been injected into six wells in Block Jin-7 and Block Jin-45; 3350 cubic meters of steam was saved and 1964 tons of incremental oil was obtained. The social and economical efficiency was obvious.
The Potential of Carbon Dioxide Gas Injection Application in Improving Oil Recovery
Authors: Abdassah D. , Siregar S. , Kristanto D. 
Published: December 2007

Abstract
Carbon dioxide (CO2) gas could increase oil recovery by means of swelling, evaporating and lowering oil viscosity. In the displacement front, injected gas may become enriched by the oil components and gas may dissolve into the reservoir oil. By assuming that local thermodynamic equilibrium is occurring at the oil-gas interface, the phase behavior can be calculated by the equation of state.
The displacement process can be modeled by a set of differential equations, called the mass balance equations, which can be written for each component in the reservoir oil and the CO2 gas injected. The linear velocity component in the mass balance equation is expressed by Darcy’s law for oil and gas phase flow, which comprise oil and gas permeability, oil and gas viscosity and pressure gradient terms. A set of the flow equation then solved numerically by the use of a one dimensional compositional simulator. The simulator has been validated by analytical methods, which is based on the method of characteristics.
In this study, we want to see the potential of CO2 injection application in improving oil recovery by simulating a slim tube experiments. CO2 gas is available in large quantity in the Natuna Sea and some place in Kalimantan, Indonesia. The benefit of the study is that we could predict the recovery efficiency of CO2 gas injection in the field by combining the results here with the macroscopic areal sweep and invasion efficiencies obtained from other models or simulations. And, the potential application of the study is that we could have a good estimate of the recovery improvement under CO2 gas injection, which will be the basic input parameters for the economic feasibility study and also a decision can then be made whether to implement or abandon the prospective project.
Research on Packing Materials for Sand Control in Steam Injection Wells
Authors: Chen Duanzong , Jin Qianhuan , Xu Riyi 
Published: December 2007

Abstract
Recovery of highly viscous oil requires thermal recovery method with steam injection into the formation. Severe sanding problem is one of the major contradictions in oil production for this type of reservoirs because of unconsolidated formations.
Traditional sand-control technology used in steaming wells is gravel pack with wire-wrapped screen. Many foreign scholars think that the packed gravel (quartz sand) will be greatly dissolved by high-temperature steam injected, so that gravel cannot be applied to sand control in steaming wells. Thereby, many efforts have been done to search for some new packing materials with lower dissolubility and high-temperature resistance in wet, saturated steam to replace the traditional gravel. However, these new materials are not commercially used because of expensive cost.
This paper describes the systematic lab research on quartz sand behavior in detail. Lab tests and field application have proved that gravel (quartz sand) is still an effective packing material for sand control in steam injection wells. It is not necessary to worry about the dissolving corrosion of gravel leading to sand-control failures, and not necessary either to employ some special materials for packing with much higher cost.
This research fruit has been successfully used in various fields in China with attractive sand-control and production results.
Field practice shows that many gravel-packed wells have been produced successfully under the condition of high-temperature steam injection (320°C–350°C) for more than 6 cycles of huff-and-puff.
An Accurate Characterization of Sand Strength in Weak and Unconsolidated Formations Aids Offshore Production Test Designs - A Bohai Bay Case Study
Authors: Ong Seehong , May Andy , George Ian , Walker Tim , Zheng Ziqiong 
Published: December 2007

Abstract
This paper presents a case study where the creative use of wireline-derived sand strength in the offshore production test process improved operational efficiency. Sand strength was computed using wireline data only and subsequent testing of two wells verified the accuracy of the calculations.
Well logs provided the basis for evaluation of formation petrophysical and mechanical properties. These log-based properties enabled a foot-by-foot profile of the critical drawdown pressure to be generated. Analysis of critical drawdown pressures in the Bohai Wells A and B, located in the northeastern People’s Republic of China, provided a cost-effective method to predict potential sand production problems. This information proved invaluable in reducing the risk and costs associated with the testing of viscous oils in the shallow, moderately unconsolidated sandstones of Bohai Bay.
Improving the Static Model of a Complex Reservoir through the Inversion of Seismic Data
Authors: Marzuki Zakaria B. , Sams Mark S. , Atkins Dave 
Published: December 2007

Abstract
It is common practice to build static models of reservoirs based on simple algebraic combinations of well log data within a structural framework. This can potentially lead to large errors in estimating volumetrics due to oversimplification of the reservoir geometry, underestimation of the reservoir heterogeneity and the miscorrelation of flow units between the wells. In addition a biased estimate of uncertainty is produced that can distort the quantitative assessment of the risks involved in field development.
Seismic data can be used at various levels of sophistication to guide the interpolation of log data between the wells to provide more realistic static models. The most effective way to include the seismic data is through the construction of impedance models derived from seismic inversion and geological modelling. This ensures that the well log and seismic data are tightly integrated within a geological model. Geostatistical techniques can be applied to generate models of reservoir properties such as porosity that honour not only the detail provided by the well data but also the complexity and heterogeneity of the reservoir between the wells as defined in the impedance model. These techniques also produce an estimate of the uncertainty associated with this interpolation.
A number of static models that include the seismic data and those based on log data alone have been compared for an oil field from the Malay basin. Significant differences in volumetric estimates were found. These differences were caused by the variations in sand quality across the field that were misrepresented when the seismic data were not used.
The Use of Four-Component Seismic for Improved Reservoir Imaging and Reservoir Characterization
Authors: Fromyr Eivind , Randazzo Santi , Lynn Walt 
Published: December 2007

Abstract
In recent years, the development of marine four-component (4-C) acquisition and processing technology has made it possible to apply the technique in most geographical areas and in a wide range of water depths. Due to higher cost compared to conventional streamer surveys, a key to future success of 4-C technology is to identify proper geophysical uses and demonstrate that results can be interpreted and used in ways that make the technology cost efficient. In this paper, we will discuss the 4-C data results associated with three different case histories, each showing a different application of the technology. The applications cover both reservoir imaging and reservoir characterization.
Recovery Area and Reserves Increment by Tapping the Potential of Regions Beyond the Oil-Water Transition Zone
Authors: Yulin Ren , Ying Lin , Chengdou Ma , Qingxia Wang 
Published: December 2007

Abstract
Through analysis on transitional zone and extending pilot area in Daqing oil field, oil and water distribution regularity, formation development status of transitional zone and extending area are studied in this paper, clarifying the extending potential of the pilot area. The problem of crude oil out flow during development in transitional zone is comprehensively studied, rational water injection pressure limit in transitional zone is provided by combining numerical simulation, the extending development principle of transitional zone is concluded, all these would provide theoretical basis and practical experience for guiding the extending and potential tapping of transitional zone.
Non-Equilibrium Adsorption and Precipitation of Scale Inhibitors: Corefloods and Mathematical Modelling
Authors: Zhang H. , Mackay E. J. , Chen P. , Sorbie K. S. 
Published: December 2007

Abstract
Adsorption/desorption and precipitation/dissolution are thought to be the two major mechanisms operating in the retention and release of scale inhibitor in squeeze treatments in an oil reservoir. The general nature and extent of the scale inhibitor adsorption process is determined principally by the equilibrium isotherm, although the shape of the inhibitor return curve may be significantly modified by kinetic effects for a specific squeeze practice. For a precipitation squeeze process, the solubility of the inhibitor-calcium complex and the rate of dissolution are currently thought to be two main factors that govern the return curves in our computer modelling studies. Experimental coreflood techniques can be used to provide inhibitor breakthrough profiles and these effluent concentration data can then be used to derive isotherms for the adsorption systems or to test the validity of the above precipitation mechanisms.
This paper presents results from a series of flow rate varying adsorption and precipitation laboratory corefloods for a penta-phosphonate (DETPMP) and a poly-carboxylate (PPCA). This experimental data is the most complete and accurate ever produced and is of a quality that allows us to test the details of the above mechanisms. A general analysis and discussion of the adsorption isotherm derivation is provided and modelling results for the non-equilibrium adsorption corefloods are reported. The significance of these results for field applications is discussed.
Productivity of Selectively Perforated Vertical Wells
Authors: Yildiz Turhan 
Published: December 2007

Abstract
This study presents analytical models to predict the productivity of selectively perforated vertical wells. The models consider arbitrary phasing angle, non-uniform perforation size and length, and formation damage around perforations. The accuracy of the models were verified against the results from electrolytic models and the semi-analytical correlation proposed by Karakas and Tariq.
A Modified Genetic Algorithm for Reservoir Characterisation
Authors: Romero C. E. , Carter J. N. , Gringarten A. C. , Zimmerman R. W. 
Published: December 2007

Abstract
This paper describes the implementation of a Genetic Algorithm (GA) to carry out hydrocarbon reservoir characterisation by conditioning the reservoir simulation model to production data (history matching) on a predefined geological and structural model. The proposed technique combines the advantages of the pilot point method for the description of petrophysical properties, with the advantages of GAs for global optimisation.
The modified GA uses a complex genome, which is divided into seven separate chromosomes for different types of reservoir parameters. Chromosomes containing the pilot point information are three-dimensional real number structures which include information for the wells, while the chromosomes for all other parameters are one-dimensional arrays. Specially designed crossover and mutation operators have been created to work with the non-standard genome structure. Results from tests on several GA design issues are presented, including crossover and mutation operators, encoding, selection, and other population strategies such as elitism. In addition, a comparison is made with a standard Simulated Annealing algorithm.
Quantification of Uncertainties on Volumes in Place Using Geostatistical Approaches
Authors: Doligez Brigitte , Chen Liang 
Published: December 2007

Abstract
At the exploration and development phase of an oilfield, there is limited amount of hard data for reservoir characterization. For that reason significant uncertainty exists in the life of the oilfield. Especially uncertainties on volumes in place (VIP) are important, contributing to decisions being made with respect to facilitate design and commercial evaluation. Therefore the issue of uncertainty management and quantification has been recognized as crucial by petroleum industry.
The calculation of VIP involves several parameters and a number of nonparametric factors. VIP uncertainties come from many sources, however major uncertainties exist on geological parameters. Geological complexity can make reserve estimation uncertain. Geostatistical approaches can help in understanding the magnitude of this uncertainty.
A framework for quantifying VIP uncertainties is presented in this study. Our method is to divide the potential uncertainties into structural, sedimentary facies, petrophysical properties, and to use multiple stochastic reservoir models in a systematic way to evaluate the impact of each of those on VIP forecasts. Moreover, we perform tests of sensitivity using different geostatistical methods, different initial constraints, different initial data to hierarchies the influence of the uncertainties on the data depending on the chosen simulation method. Also an overall quantification of uncertainties is illustrated clearly from a nonmarine reservoir.
Gas Loss Determination from a Well Blowout - A Simulation Approach
Authors: Horton Lary D. , Kobelan Mark T. , Singh Surendra P. 
Published: December 2007

Abstract
A simulation approach was used to determine the gas loss from a storage field after a well got out of control during a replugging attempt. Because the event occurred in a storage field which has over 250 active wells, a smaller portion of the reservoir surrounding the problem portion of the reservoir surrounding the problem well was selected for reservoir simulation. The movement of gas into the smaller portion of the reservoir from the rest of the reservoir was simulated by using pseudo injection wells in the model.
The pseudo wells were placed at the grid boundary where gas migration was expected to occur. Wells surrounding the incident well were shut-in for pressure observation throughout the event and were included as observation wells in the model. By assuming different injection rates in the pseudo wells with various assumed loss rates from the incident well, a good history match was obtained. From these studies, an accurate estimate was made of the natural gas lost during the 16 day incident.

Introduction
The Taggart Storage Field (originally called the Six Lakes Field) was discovered on May 11, 1934 at a wellhead discovery pressure of 513 psig. The field was developed on 40 acre spacing. By March 1, 1936 there were 75 gas wells and ultimately there were 224 producing gas wells. The largest gas well had an initial gas flow potential of 112,000 MCF per day.
The reservoir is the "Stray Sandstone" unit in the Michigan Formation of late Mississippian Age. The reservoir is a structural trap (Fig. 1) in a porous and permeable sandstone that can be correlated for many miles across Michigan. Porosity of the sandstone ranges from 15–23% and Porosity of the sandstone ranges from 15–23% and permeabilities are as high as 1000 millidarcies. permeabilities are as high as 1000 millidarcies. The reservoir is approximately 1300 feet deep and has a maximum gross thickness of 50 feet (Fig. 2).
By March 12, 1953, the Taggart Field had produced 51.3 BCF and was essentially depleted. produced 51.3 BCF and was essentially depleted. All but 64 of the original 224 gas wells had been plugged and abandoned, due to water encroachment. plugged and abandoned, due to water encroachment. Michigan Consolidated Gas Company had completed acquisition of mineral interests and storage rights at that date. The company then started to develop the field for underground gas storage. It was necessary to reopen all of the plugged and abandoned gas wells and to convert them to facility wells with new casing or replug them to prevent leakage. prevent leakage. Many of the old wells had both the surface and production casing shot off or ripped when they were abandoned. This made it difficult to locate them. As of 1974 there remained thirty five wells to be replugged. Twelve of these wells had been relocated with a Casing Finder Tool. One of these 12 wells, the S. L. #375, was plugged in 1949.