bluuebunny/crossref_metadata_2025_split huggingface dataset:
Logging Response Characteristic Analyses and Saturation Calculation Method for Polymer Flooded Reservoir
Authors: Liu Chuanping , Yan Weilin , Yang Qingshan , Ma Hongyu 
Published: July 2010

Abstract
After many years' development, La,Sa & Xin oil fields in Daqing Placanticline have entered into extra high water cut stage. Polymer flooding has been widely applied in the fields. Along with polymer agent injection, physical property and fluids distribution of reservoirs have changed. This challenges the qualitative and quantitative interpretation of watered out zone in high water cut stage. So the present logging interpretation method for water flooded zone is difficult to meet the needs of logging interpretation of reservoir by polymer flooding in extra high water cut stage. In this paper, based on the logging response characteristics of polymer flooded reservoir and guided by reservoir petrophysical experiment, the method of distinguishing effectively flooded layer by polymer solution from ones by water flooding through log response characteristic analysis has been established. And on the base of symmetrical anisotropic effective medium conductance theory and according to the reservoir petrophysical experiment data, the paper gives a saturation calculating model for the reservoirs by polymer flooding. The new model can recognize the fluid connectivity of pore space and rock wettability change factor resulted by polymer flooding in saturation calculation. The comparison result with sealed coring analysis data shows that the water saturation calculation precision of new model is higher with average absolute error of 6.4%, which can meet the need of production. The saturation model provides a new technical means to calculate remaining oil saturation for polymer flooded reservoir in extra high water cut stage.
The Refined-Control Vertical Fracturing Technology for Thin and Low Permeability Interbeded Reservoir
Authors: Wang Yanlou , Zhang Chuanxu , Deng Suyu , Yu Yongbo , Wang Runtao , Zhou Wei , Gao Guihong 
Published: July 2010

Abstract
This paper presents a technology that can control fracturing properly in the thin layers in peripheral Daqing oil fields. The layers are thin and numerous, and the lithology is very complex, so the conventional frac or limited entry fracturing has been serious inadaptability. For an example, only 47% of the oil layers produce in a single well, Lots of thin layers in peripheral oil field couldn't be fractured, and reservoir could not be developed fully,, so the effects t of fracturing is poor. Refined-controlled fracturing technique takes into account reservoir nature, lithologic character and the distribution of in-situ stress. In this case, the organic integration of detailed geological research and control technique has been achieved. 308 wells have been applied and tested the technology. The technology break through the limits that the fracturing layers must be more than 4m and stratified according to thickness of the barrier and crustal stress in the past. The effect of perforation parameters to the fracture's initiation direction has been determined by three-dimensional elastic-plastic finite element techniques. Based on the fracture mechanics, the model of fracture extension has been built, and simulated the perforation and its impacts, the contrast of horizontal stress on the deflection of fracture. Based on theoretical study, the perforation design of fracturing wells has been developed.
High-resolution Images and Formation Evaluation in Slim Holes from a New Logging-While-Drilling Azimuthal Laterolog Device
Authors: Allouche M. , Chow S. , Dubourg I. , Ortenzi L. , van Os R. 
Published: July 2010

Abstract
A new logging while drilling (LWD) device acquires laterolog resistivity logs and borehole images in 6-in. holes drilled with con-ductive mud. On a single drill collar, the tool combines a standard laterolog azimuthal measurement with a new, high-resolution imaging capability. The tool uses monitored button electrodes and toroidal antennas to produce focused laterolog resistivity measurements with azimuthal sensitivity, made at multiple depths of investigation. A new measurement configuration within the button electrodes gives downhole mud resistivity. The toroidal antennas provide bit resistivity and azimuthally averaged focused laterolog measurements at multiple depths of investigation.
The orientation system in the tool uses the earth's magnetic field as a reference to determine the azimuthal tool position as it rotates. Together with the multi-depth sensitivities of the measurements, this allows structural and borehole invasion profile analysis. The four laterolog images can be compressed and transmitted uphole in real-time for well placement and for wellbore-stability applications.
The high-resolution imager is an array of button electrodes on a removable sleeve. The resulting formation image combines the high resolution of wireline imager with the full borehole coverage of an LWD device. A dedicated data compression algorithm allows real-time transmission of this image with moderate resolution losses, enabling applications such as fracture detection while drilling. This paper describes the tool's main features and performances in the initial field tests.
Well Conditioning Before and After the Installation of an ICD Completion Hardware: Bloque 15, Ecuador
Authors: Vela Ivan , Almeida Roberto , Porturas Francisco , Humbert Olivier 
Published: July 2010

Abstract
Horizontal wells have more superior production and recovery performance rates than that of conventional wells. Worldwide, more than one-thousand completions have been placed in the ground and equipped with Inflow Control Devices (ICD's) hardware. Today, the use of ICD is an accepted technology because provides a simple solution to conventional completions which would suffer from differential inflow (heel-toe effects) and early water or gas coning usually towards the heel. Furthermore, water or gas can breakthrough anywhere along the well trajectory and not only at the heel, due to permeability variations and proximity of water traps and fluid contacts. Conventional completions do not effectively handle heterogeneity or permeability contrasts exposed along the sand face.
The success in terms of production performance of wells completed with ICD's also depend upon the appropriate selection of reservoir drilling, formation stabilizing and completion fluids. Otherwise the well may suffer from the near wellbore effects of residual drilling mud.
This paper presents the results of an ICD completion installed in a well in a high viscosity hydrocarbon reservoir within a non-consolidated sandstone reservoir in Bloque 15, Ecuador. The ICD completion architecture was successfully installed in the well. However when the completion was connected and opened to production initially the well started producing at lower liquid rates from what was expected and the pressure responses were markedly different than predicted by a series of a-priori simulations of the ICD completion. The initial production rate and pressure response of the well created doubt about the robustness of the ICD system design. After revisiting the drilling operations it was shown that the poor initial performance was due to inadequate well cleanup and the effects of shale stabilizer added to the drilling mud. Although good pay zone were completed the system experienced restricted inflow from the zones completed with the ICD system. A workover operation with a chemical treatment was conducted to remove the shale stabilizer. The ICD's facilitated this operation by establishing pressure/flow conditions that created regular and uniform distribution of the treatment fluid through the ICD nozzles. Following the treatment -the well started flowing as expected -and performed well both in terms of flux and stabilizing pressure. This resulted in lifting oil at a lower watercut (WCUT). In addition it is believed that the ICD completion delayed water breakthrough for nearly one year.
Drilling Fluid Challenge During the Ultra-deep HT/HP/HS Drilling in the Mountainous Area, Tarim Basin
Authors: Ye Yan , WenHua An , ShuQi Wang , FaQian Luo 
Published: July 2010

Abstract
The mountainous high steep structure in Tarim Basin, as a result of orogenesis, owes presses solid, structure extrusion factor and so on, caused the geology conditions, which the drilling operation must cope with, are very complex: The reservoir buried so deeply (the maximum depth presented 7600m), And there developed an very thick evaporate bed as coverage in Tertiary, which buried from 1526m to 7070m. So the formation pressure coefficient to reach to as high as 2.47, the density of drilling fluid used during operation reached as high as 2.55 sg the most, and BHT exhibited 186°C (Tests on site). Another problem is that there exhibited extensive interconnected fractures in the reservoir, which caused the serious loss circulation and overflow occurred frequently during drilling. Faced so many extreme formidable drilling conditions, This paper identifies and discusses the major HP/HT/HS drilling fluid challenges, the ultra high-density water-based drilling fluid designs, the key laboratory studies about the fluid's properties, and other considerations in HP/HT drilling.
Up to now, about 23 ultra-deep wells (&gt;6000m) and 3 ultra-deep wells (&gt;7000m) have been completed in Tarim, which are achieved by the application of a series of advanced techniques, especially the High-performance drilling fluids, which are briefly described in this paper, especially the results and observations are presented in YS-1(total depth is 7258m), DB-3 (total depth is 7090m) and KS-2(total depth is 6780m) wells. Finally the paper identified some of the drilling fluid challenges that still lie ahead during the ultra-deep drilling process.
Integrated Log Interpretation Approach for Underground Gas Storage Characterization
Authors: Cantini S. , Klopf W. , Revelant R. , Verga F. 
Published: July 2010

AbstractIn the future natural gas will make a growing contribution to energy supply. Since gas production is constant during the year and its consumption almost seasonal, the importance of underground gas storage (UGS) is increasing because it acts as a buffer between production and consumption.This paper presents a workflow for reservoir and cap rock petrophysical and geomechanic characterization based on an integrated log interpretation, critically reviewing the value and reliability of information that can be gathered from the different log types. Geomechanical characterization is an essential trait in the UGS workflow, especially when the initial formation pressure is exceeded to increase the storage capacity and enhance gas deliverability or in the case of aquifer storages.The workflow consists in the following steps:Conventional reservoir petrophysical characterization. This is achieved by means of gamma ray, neutron, density and resistivity logs, and nuclear magnetic resonance logs for verification of the nature and quantity of the pore fluids. Cap rock petrophysical characterization. An innovative approach with nuclear magnetic resonance log is described. Reservoir and caprock geomechanical properties characterization. Information is provided by advanced sonic tools, allowing estimation of the stress profile magnitude, calibrated with micro-hydraulic fracturing tests (stress tests). The direction of the stresses is determined through image logs. Well integrity assessment. Sonic and ultrasonic cement evaluation tools are recommended. Reservoir monitoring. A pulsed neutron tool can be used in order to identify the position of the gas-water contact during gas injection and withdrawal cycles.Case studies are provided in order to complement the theoretical workflow description.
Optimal Parameter Updating in Assisted History Matching of the Nelson Field using Streamlines as a Guide
Authors: Kazemi Alireza , Stephen Karl D 
Published: July 2010

Abstract
It is becoming more and more common to use assisted history matching methods to find different combinations of reservoir simulation models that agree with production data. Models with a large number of cells contain millions of unknown parameters and selecting the correct values can be difficult. In practice not all are important but finding which parts of the reservoir require updating can be difficult. In this work we investigate methods of history matching by focusing on sub-volumes of the parameter space and we use streamlines to help us choose where the model requires change. We identify localities in the reservoir that affect particular wells and we update reservoir properties (net:gross and permeability) within. We control changes using the pilot point method combined with a Neighbourhood Algorithm.
We apply these approaches to the Nelson field where uncertainty of the shale distribution controls predictions. The field is divided into localities based on the performance of the worst well predictions. We history match to improve production rates.
The localities that require change are sufficiently separate that we can modify them one at a time. We also compare our result with a more ad hoc approach where the whole area around the well is modified. We find that, for the wells of interest, the streamline guided approach gives a 70% improvement in the history match from our starting model and around 40% reduction of misfit in prediction. This improvement is twice that of the total area approach.
Reservoir simulation and history matching are crucial for reservoir management especially when developing field management plans. By application of a good updating workflow in the right area of the model through an automatic history matching process we have gained a greater insight into reservoir behaviour and have been able to better predict flow from simulation models.
A New Method to Improve Convergence Rates with Seismic History Matching
Authors: Arwini Saleh , Stephen Karl D. 
Published: July 2010

Abstract
The aim of history matching is to minimise the difference between calculated and observed data. An assisted history matching method has been developed where predictions are quantitatively compared to observed seismic and production data and then the model is updated in an objective manner. To improve convergence to suitable solutions, we use a proxy model to understand how parameters control the misfit and then use a global stochastic method with these sensitivities to optimise the search of the parameter space. This maximises the breadth of search offered from stochastic approaches with rapid convergence associated with gradient type methods. We apply the approach to the Schiehallion field from the west of Shetland. The field has two preproduction and several monitor surveys. We have studied this field previously and use it as a laboratory to apply our new technique. A quadratic regression equation is derived from a representative sample of models and used to generate gradients of the misfit with respect to the parameters. These are used to direct the choice of new models during a random search increasing the chance of finding new models. The new method speeds up the rate of convergence towards better models by a factor of three generally. Suitable models that match observations can be found after running a few hundred models instead of many hundreds. We also tested for the effects of noise in the seismic and production data which can be minimised. The regression equation itself is of limited use to replace the full misfit calculation but provides excellent sensitivity information. With improved convergence we have the ability run fewer models or search the parameter space more widely. This leads to an improved set of final reservoir models. These in turn can be used more effectively in reservoir management decisions.
An Integrated Approach on Carbonate Reservoir Evaluation by Combining Borehole Image and NMR Logs -A Case Study in Ordovician Carbonate, East China
Authors: HuiJun Hou , HuaYun Yun , Yun Xie 
Published: July 2010

Abstract
This paper is a case study in an Ordovician carbonate, east China. Most carbonates are buried hill of Ordovician age and the reservoirs are dolomitized. Fractures are very important here as the porosity is often very low (about 2-5%). But the puzzle is the higher fractured zones not always are the higher production zones. So the two important things that one should be concerned with are (i) how to find the fractured zones, and (ii) the factors influenced the production rates.
An integrated approach using a combination of borehole image and NMR logs is applied in this study. Borehole images are used to extract fractures, vugs, rock textures and pore textures. Structure profile across the wellbore is created from the image dips as well, as an aid of the fracture analysis. NMR Bin data and T2 distribution spectrum are displayed to reflect pore textures, and a relative permeability also calculated from NMR logs. Furthermore, the morphic rock types are classified in details base on borehole images and lithology identified with other openhole logs. Nine morphic rock types are identified. All the summary data are displayed in one integrated plot for thorough analysis. The reservoir properties are found well related to morphic rock types and pay zones are observed located near the fault zone. Faults in one hand enhance the reservoir by dissolution on fracture and vugs near the fault zone, while in the other hand, it impair permeability of the fractures with clays in the fault zone. Those clay filled conductive fractures can be seen in borehole image, but no any permeable indictors in NMR data. The vuggy fractured dolomite is deemed as pay zone. The results are validated by the later well production. The combination of borehole image and NMR logs provide a valuable solution for clear understanding of this reservoir.
A Numerical Study of Transport and Storage Effects for Tight Gas and Shale Gas Reservoir Systems
Authors: Freeman C. M. , Moridis G. , Ilk D. , Blasingame T. A. 
Published: July 2010

Abstract
Various analytical, semi-analytical, and empirical models have been proposed to characterize rate/pressure behavior as a function of time in tight/shale gas systems featuring wells of various completion designs. Despite a few analytical models as well as a small number of published numerical studies there is currently little consensus regarding the importance of the various transport and storage mechanisms on performance over time and whether or not reservoir properties/volume can be estimated from well performance data.
We constructed a fit-for-purpose numerical simulator which accounts for a variety of production features pertinent to these systems, specifically: hydraulically fractured horizontal wells possessing induced fractures with Forchheimer flow, stress dependent properties, multicomponent diffusive and Knudsen flow and desorption, and the presence of water, which introduces issues of relative permeability and wettability, as well as gas solution and phase change. These features cover several of the production and storage mechanisms which are currently believed to be relevant in tight/shale gas systems.
We employ the numerical simulator to examine various tight/shale gas systems and to study the effects of reservoir and completion parameters on performance.
We employ rate and auxiliary functions to illustrate the impact of water, desorption, thermal, and non-Darcy flow effects on performance. The relationship between these factors and the change in produced gas composition with time is explored.
We explore variations of possible shale gas system models. Based on non-Darcy flow in the microscale and inertial regimes (with/without desorption), we show that due to the extremely low permeability of shale and various intrinsic permeability reducing effects, the flow behavior is dominated by the fracture system configuration and extent.
This work expands our understanding of transport and storage mechanisms in tight gas and shale gas systems and their impact on performance, where such an understanding may ultimately be used to estimate reservoir properties and reserves in these types of reservoirs.
New Correlations of Acid Fracture Conductivity at Low Closure Stress Based on the Spatial Distributions of Formation Properties
Authors: Mou Jianye , Zhu D. , Hill A. D. 
Published: July 2010

Abstract
In acid fracturing, because of irregular fracture surfaces caused by heterogeneities such as variations in local mineralogy and variations in leakoff behavior, we use a correlation to calculate fracture conductivity. An acid fracture conductivity correlation consists of two parts: conductivity at zero closure stress and the rate of conductivity change with closure stress. Existing correlations do not consider the effect of variations in formation properties and were developed based on laboratory experiments, which used core samples having dimensions of a few inches. Acid fracture simulators, on the other hand, have grid sizes of several to tens of feet. Therefore, correlations should be scaled up properly when used in a fracture simulator. This paper presents new correlations to obtain the conductivity at zero closure stress which can then be incorporated in acid fracture conductivity models that consider the effect of closure stress.
In this study, an extensive numerical study was done using an intermediate-scale acid fracture model with total dimensions comparable to a grid block size in an acid fracturing simulator, and grid sizes comparable to core sample sizes used in laboratory acid fracture conductivity tests. In this model, the distributions of permeability and mineralogy along the fracture faces are geostatistically generated. The model outputs fracture surface etching profiles as a function of acid contact time, from which we can get fracture width distributions when the fracture surfaces have come in contact at low closure stress. We then calculate the fracture conductivity by solving for the flow rate through this irregular domain for a fixed Δp across the domain. By analyzing the relationship between the fracture conductivity created and statistical properties of the permeability and mineralogy distributions, we developed new acid fracture conductivity correlations for low closure stress. These correlations can be used directly to better predict the primary coefficient in the widely used Nierode-Kruk correlation of acid fracture conductivity. This work allows the Nierode-Kruk correlation to be scaled up to the dimensions appropriate for use in an acid fracturing simulator.