bluuebunny/crossref_metadata_2025_split huggingface dataset:
Case Analysis on Hydrocarbon Alternative Gas Miscible Flooding in PuBei Oil Field
Authors: Guo Ping , Wang Zhonglin , Tan Guangtian , Yang Kailei , Liu Bin , Lun Yukai , Zhang Maolin 
Published: December 2007

Abstract
PuBei oil field is the first sand oil reservoir to perform hydrocarbon miscible flooding in china. It has integrated, good connecting formation with undeveloped cracking system and permeability of 110.5*10−3 μ m2.It is a typical volatile oil reservoir .MMP is 33Mpa.Injection gas is the by-produced gas. After systematically plan design and research, field production stared. Though lad experiment showed that oil recovery by primary gas injection is higher than primary water injection, there were still some controversies. Thus, the field was developed by primary water injection at east and primary gas injection at west, keeping formation pressure at 35 Mpa. At early exploration time, there were seven injection wells and eight production wells. Now, there are nine production wells and two gas injection wells, seven water injection wells. The velocity of oil production is 44t/d, gas injection is 14.55*104m3/d, water injection is 144 m3/d. it has developed for three years till October 2001; the oil recovery is 19.05%, the synthetic water saturation is 3%. There are certain increases of GOR in some production well but no obvious gas breakout. Primary water injection well cannot change to gas injection since gas cannot be injected after water injection, so cannot perform GAW in east area. This paper introduces general geometry character, basic experimental study, exploration performance, and existing problem of the reservoir and gives some proposals, which is helpful in exploration the similar oil reservoir by miscible flooding.
Angsi Waterflood Management and Surveillance - An Integrated Team Approach
Authors: Othman Mohamad , Salleh Zaimi , Redmond John , Jakobsson Nils M. , Yunus A. Rahman , Abu A. Kamarolaili 
Published: December 2007

Abstract
The Angsi field is a new oil and gas development in its early production phase. The field is operated by PETRONAS Carigali Sendirian Berhad (PCSB), Peninsular Malaysia Operations (PMO). Waterflooding is being used to improve oil recovery. The waterflood is expected to yield close to a three fold increase of the oil recovery compared to a scenario without injection. The production from waterflood reservoirs contributes 90% of the overall Angsi oil production. It is imperative that the waterflood is managed in a prudent way to ensure its full potential is realized. An instrumental element of prudent management is a well-planned and well-executed surveillance program. The Angsi waterflood project, as many other waterflood projects, is significant in scope and multi-disciplinary in nature. It was determined that the adoption of an integrated team approach would be the optimal way to facilitate prudent management and surveillance of the Angsi waterflood project, and consequently that it would be an essential key to a successful waterflood.
The purpose of this paper is to discuss the integrated team approach adopted for the Angsi waterflood project. The paper describes how the team was built and how it has functioned during its first year. Included in the paper is a discussion on the Angsi integrated waterflood management and surveillance program. The program was developed by the team and now serves as a guideline for all Angsi waterflood related activities.
Adopting an integrated team has provided the necessary forum for open and inter-disciplinary exchange of ideas and experiences on waterflood related matters. As a result, it has aided the fostering of cooperative actions and the capturing of synergism, all to the benefit of the Angsi waterflood project.
Thus far, the integrated team approach has resulted in a timely commissioning of the water injection plant, and a high plant uptime and water injection availability.
Resolving Development Strategy by Integrating Geophysical, Geological and Pressure Transient Test Data: A Case Study of Heterogeneous Lower Eocene Sand of Upper Assam Basin, India
Authors: Lama Tshering , Phukan Jayanta , Neog Pankaj Kumar , Rath Satchidananda 
Published: December 2007

Abstract
A multi-disciplinary approach had been adopted to resolve the exploitation and development strategy for Deohal and its extension oilfield having mainly the deep Eocene clastic reservoirs which is geologically complex, over pressurized stack of thin sands [by 30-40 Kg/cm2 (assuming 0.1 Kg/cm2/m hydrostatic gradient] interbedded with shale/ carbonaceous shale. An accurate delineation of individual sand in such reservoirs is beyond the resolution of seismic as these occur at a depth of 3600 to &gt;4000 m and its thickness vary from 2 to 4 m only. The Lithostratigraphic correlation based on well log is often unreliable/ difficult due to thin and extreme heterogeneous nature of the sediments. Moreover, areal extent of reservoir as a single unit is difficult to ascertain. The petrophysical properties viz. porosity and permeability substantially deteriorate with increase in depth i.e. below 4000 m.
Initially 3D seismic data was showing a broad faulted anticline with fault 500 m to 800 m away from the crestal part. Analyses of pressure transient data showed barrier nearby and reinterpretation of 3D seismic data confirmed the presence of minor faults having limited extension.
The Paper presents how transient well test data in conjunction with static 3D seismic data, wireline log and dynamic pressure-production data have helped to workout development strategy for a geologically complex and heterogeneous Lower Eocene thin sand reservoir in one of the oilfields in Upper Assam Basin, India.
A New Method for Predicting Interwell Remaining Oil Distribution in Multilayer Sandstone Reservoirs at High Water Cut Stage
Authors: Qinglong Du , Bingyu Ji , Xiaoguang Lu , Lihua Xie , Yubo Lan , Lihong Zhu 
Published: December 2007

Abstract
Since the remaining oil distribution is characterized by scatter and complex in multilayer sandstone reservoirs at high water cut stage, a new method is put forward in this paper to predict interwell remaining oil distribution by using cores, logging data, geologic model and production testing data. Firstly, the interwell sandbody prediction model are set up to predicte interwell sandbody thickness and sedimentary microfacies by using geostatistics and stochastic modelling methods. Secondly, the remaining oil prediction models of various reservoirs are set up by combining the expert system and neural network based on the comprehensive analysis of the relationship between watered-out degree and influential factors in various layers of inspection wells and separated layer testing wells. These factors include sedimentary microfacies, sandstone thickness, structural pattern, communicating states of sandbody with surrounding water injection wells, and injection distances, intensity of water injection, injection-production relationship.The above-mentioned models are used to predict the interwell remaining oil distribution of each layer. This method has been successfully applied in predicting the remaining oil distribution before drilling the tertiary infilling wells in Xing 1-3 area of Daqing oilfield. About 100 layers are studied in this pilot area and maps of remaining oil distribution in each layer are worked out. In addition, the distribution map of remaining oil sandstone thickness in this pilot area is also drawn up and the potential area of remaining oil is pointed out. This method has been used in 28 infilling adjustment areas in Daqing oilfield and good results have been received. By checking 208 layers of 3 newly drilled inspection wells in these development blocks, coincidence rate of single layer predicting remaining oil is at the range of 81%~84%.This paper explores an effective way to study interwell remaining oil distribution in multi-layer sandstone reservoirs.
Practical E&P Waste Minimization Opportunities: Moving Up the 5R Hierarchy
Authors: Hoffmann Robert E. , Koesoemo Budi R. 
Published: December 2007

Abstract
As a production-sharing contractor to BP-Migas, PT Caltex Pacific Indonesia (CPI) is Indonesia's largest oil producer. CPI employs approximately 6,500 people and contracts an additional 25,000 people in its operating area throughout Riau Province on the island of Sumatra. The distances between CPI's producing fields, limited waste management infrastructure, and the evolving nature of Indonesia's waste management regulations complicate waste management efforts. CPI's activities generate both domestic waste as well as conventional E&P waste.
E&P waste management initiatives often focus exclusively on treatment and disposal. The 5R strategies of source reduction, re-use, recycle, recover and replace offer greater potential environmental and financial benefits for many common E&P wastes.
As part of CPI's integrated waste management initiative, practical 5R strategies have been identified for several waste streams: seismic shot, excess cement, empty drums and containers, construction and demolition material, oil-based drilling mud, batteries, consumable IT products, used tires, paper, cardboard, and used oil.
Development of these strategies is underway. Eventual implementation will minimize waste management costs and benefit the environment.
Storable Slurries and Their Use in Oil and Gas Well Cementing
Authors: D'Almeida Arnaldo Rodrigues , de Miranda Cristiane Richard , Campos Gilson 
Published: December 2007

Abstract
This paper presents the concept of the Storable Slag Slurry, a zonal isolation system which can be prepared in advance, stored and transported to the rigsite at anytime, without setting time concerns.
The compositions contain blast furnace slag to be used in water-based fluids as the hydraulic material, in the absence of set inhibitors. The slurry can be stored in liquid state from 3 days up to several months, at room temperature, depending on its composition.
There are two basic methods of preparing the Storable Slag Slurry. In both it is possible to avoid using the single batch (a so-called batch-mixer) saving money and to maintain good homogeneity of the slurry, and consequently, the uniform physical properties (density, compressive strength, etc.) in all its volume.
Numerical Simulation and Screening of Oil Reservoirs for Gravity Assisted Tertiary Gas-Injection Processes
Authors: Ren W. , Cunha L. B. , Bentsen R. 
Published: December 2007

Abstract
Corefloods and field investigations confirm that a large amount of incremental tertiary oil can be recovered from dipping water drive reservoirs using gravity assisted tertiary gas injection processes. These processes include the Double Displacement Process (DDP) and the Second Contact Water Displacement Process (SCWD). The DDP consists of injecting gas into waterflooded oil zones. The SCWD process consists of submitting these gas-flooded zones to a new water displacement process.
Reservoir simulations performed with an adaptive-implicit simulator were applied to investigate the macroscopic mechanisms of the two processes. The effects of several important parameters on the performance of the DDP were studied to optimize the oil production of the process and to develop a set of screening criteria for selecting candidate reservoirs for the process. Moreover, the SCWD process was simulated to investigate its feasibility. Furthermore, the two processes were simulated physically in a micromodel – transparent cell.
The results have shown that both processes are efficient methods for recovering the residual oil to water. A good representation of the laboratory results was obtained through the simulations. It was confirmed that oil film flow plays a very important role in achieving high recovery efficiencies in the DDP. In the SCWD process, trapped gas reduces the possibility of the residual oil being trapped in the center of pores in the secondary water invasion. Consequently, residual oil can be recovered quickly by a second water flood. Therefore, the SCWD process is suitable for application in situations where the source of gas is not sufficient, and where the formation has a high irreducible gas saturation.
A Case Study in the Design and Execution of Subsea Production Development Wells in the Captain Field
Authors: Rae G. , Hampson J. , Rennie M. , Morrison A. , Ramsay D. 
Published: December 2007

Abstract
This technical paper outlines the challenges presented and solutions chosen to allow execution of the well construction design for the Captain Area ‘B’ subsea development. It is intended to give an overview of how a blend of proven and emerging technologies can be applied to develop such fields in innovative ways in order to meet performance metrics.
Upscaling of Relative Permeability Curves for Reservoir Simulation: An Extension to Areal Simulations Based on Realistic Average Water Saturations
Authors: Crotti M. A. , Cobeñas R. H. 
Published: December 2007

Abstract
Special core analysis laboratories generally obtain relative permeability curves through frontal advance theory developments. The outer face of the sample, where production rates are measured, is usually selected to perform calculations. As a result, relative permeability curves are reported as function of point fluids saturations and not as function of average saturations. In spite of this procedure, numerical simulators perform their calculations using the average water saturation within every cell. Although point and average saturations are expected to be the same at infinitely small grid sizes, this is not the case with real application grids.
As previously shown by the authors1, relative permeability curves as a function of average water saturation could be used to overcome numerical dispersion and drastically reduce the number of grid cells needed for linear numerical simulation situations.
In this paper a series of experimental tests were performed to extend the methodology to 2D (areal) displacement. On this geometry, an additional issue should be taken into account that does not impact the linear cases. A geometry effect appears as a consequence of flow leaving the grid cells in a direction perpendicular from where it enters. As in the previously studied linear situation, water-cut as a function of produced oil was analyzed. The history was matched using a numerical simulator and relative permeability curves defined as a function of point saturations and average water saturation for different grid sizes. Representative relative permeability curves were previously determined through routine laboratory explicit computation based on linear unsteady state displacement. It is shown that only curves taking into account average saturation values and geometry considerations give reliable data, and a general methodology to obtain the proper relative permeability curve for every cell is examined.
A New Tool to Uphold Spatial Reservoir Heterogeneity for Upscaled Models
Authors: Idrobo E. A. , Jimenez E. A. , Ospino A. A. , Arroyo E. A. 
Published: December 2007

AbstractThe weakest characteristic of most scaled reservoir models is the incompetence of describing accurately the reservoir heterogeneity. This limitation has a strong impact in the adequate match of existing historical data, usually resulting in unrealistic predictions. The scaled reservoir model validation is a fundamental step toward developing a successful reservoir simulation model. The results achieved from an imprecise simulation model can be more harmful for reservoir management decisions than not having a simulation model at all.In this paper we present a quick and efficient application designed to meet specific needs to preserve, in scaled models, the reservoir heterogeneities represented in high-resolution geostatistical realizations. The developed tool works in a systematized architecture where multi-attributes as geological, petrophysical and reservoir objects are stored in a dynamic hierarchical platform. The validation procedure, which works as a 3D visual interactive platform, includes optimization methods and transmissibility definitions using vertical windows.We have applied the proposed tool to Dina Cretaceos and Palogrande Fields, Valle Superior del Magdalena Basin in Colombia, South America. The Dina Cretaceos Field is estimated to contain over 180 million barrels of oil in place of which 26% has been produced. The Palogrande Field is estimated to contain over 230 million barrels of oil in place with a recovery of 20.5 %. Departing from high-resolution geostatistical reservoir images, scaled models for simulation purposes were built up and validated with our tool. The flow capacity tuning procedure, a strong stratigraphic constraining, and a detailed control of sand to sand connections reduced the risk of oversimplifying the scaling up process. Therefore, a much better reservoir heterogeneity representation was achieved and a suitable history matching were possible without manipulating, deforming, or even losing the physical sense of the model.
Exact Solution of Two Layer Reservoir with Crossflow under Constant Pressure Condition
Authors: Sun HeDong , Liu Lei , Zhou Fangde , Gao Chengtai 
Published: December 2007

Abstract
The max effective hole-diameter mathematical model describing flow of slightly compressible fluid through two-layer reservoir with crossflow is solved rigorously. The model considers all layers open to a single well that flows at a constant wellbore pressure. The effect of formation damage is included in the model. The exact solutions are expressed in terms of ordinary Bessel functions by using the method of Laplace transform. The numerical computation of these solutions is made by Stehfest numerical inversion method. The new model is numerically stable when the skin is positive and negative. The effect of the reservoir parameters such as permeability, vertical permeability, skin, outer boundary conditions and storativity on the layer production rate and total rate were investigated. These results can be used to analyse unsteady flow test of production under the constant pressure condition.
In-Situ Stress State Eastern Cordillera (Colombia)
Authors: Torres M. E. , Gonzalez A. J. , Last N. C. 
Published: December 2007

Abstract
Knowledge of the regional state of in situ stress direction and magnitude is required to delineate stress provinces, to analyze intra plate earthquakes, to optimize petroleum recovery and for the development of civil projects in rock masses. This paper on rock mechanics and reservoir geomechanics studies the stress state including the pore pressure that operates in the rock mass and the mechanical behavior of the rock, to create an integrated model to study the in situ state of stress in the Eastern Cordillera, Colombia. Several measurement techniques were used, which include strain-relief overcoring, hydraulic fracturing techniques, shear fractures in the walls of the boreholes knows as breakouts, leak off test and induced drilling tensile fracture in the walls of the boreholes. Rock mechanics properties are required for the application of these methods and laboratory tests were carried out to find elastic constants. The orientation of the maximum horizontal principal stress σHmax is parallel to that of tensile failures (tensile wall fractures) and perpendicular to that of compressive failures (breakouts). The magnitude of the minimum principal horizontal stress σhmin is determined from leak off tests (LOT) and hydraulic fracturing, while the magnitude of the vertical stress σV is simply calculated based on the density data collected in several representative wells in the Cusiana field. From recent tectonics results are clear that the region in the Eastern Cordillera is characterized by an active strike-slip / thrust faulting regimen. The actual regional state of stress found means that the minimum principal stress σhmin (0.65 psi/ft to 0.77 psi/ft) oriented in a NE-SW direction, is less than the vertical stress (1.07 psi/ft), and the maximum principal stress σHmax (1.2 psi/ft to 1.7 psi/ft) in NW-SE compressional direction is significantly greater than the vertical stress, which therefore is the intermediate principal stress.
Bioremediation of Oil-Based Drill Cuttings under Tropical Conditions
Authors: Chaîneau Claude-Henri , Vidalie Jean-François , Hamzah Udi Syahnudi , Suripno Suripno , Asmaradewi Gayatri , Najib Muhammad 
Published: December 2007

AbstractOnshore drilling operations may generate oil-based waste like the drillcuttings. These wastes are composed of mineral matter mixed with the drillingfluid. They are usually disposed of in a variety of methods including thermaland physico-chemical treatments. Over the last ten years, bioremediation hasbeen considered as a possible alternative to "classical" treatments since ithas been well established that hydrocarbons are prone to be biodegraded bymicroorganisms. This paper presents the results of a large-scale industrialbiotreatment of drill cuttings in Indonesia. A 12-mo field experiment was setup following a petroleum drilling operation. Resulting cuttings were treated inwindrows on a dedicated area. Periodical mixing, fertilisation andmicroorganisms seeding allowed the biodegradation of hydrocarbons.Concentration and chemical composition of hydrocarbons, nutrientsconcentrations, microbial counts were periodically determined. Gaschromatographic analyses demonstrated the metabolism of alkanes. Microbialcounts increased during the biotreatment. After treatment, the cuttings werespread on a dedicated area to allow a cover by vegetation. This publicationaims at demonstrating that oily waste can be depolluted by bioremediation.