bluuebunny/crossref_metadata_2025_split huggingface dataset:
Transport Study of Nanoparticles for Oilfield Application
Authors: Yu Jie , Berlin Jacob M. , Lu Wei , Zhang Lunliang , Kan Amy T. , Zhang Ping , Walsh Erin E. , Work Sara N. , Chen Wei , Tour James M. , Wong Michael S. , Tomson Mason B. 
Published: July 2010

Abstract
Recently, the revolution of nanotechnology has been noticed for its many potential applications in the oil & gas industry such as enhanced oil recovery process and subsurface mapping. Understanding the transport and retention of nanoparticles (NPs) in an oilfield environment, such as high salinity, high temperature, high pressure, and heterogeneous pore distribution is critical to their application. The objective of this study is to investigate the fundamental transport and retention properties of NPs in the challenging oilfield conditions.
In this work, dolomite core material from an oil well in Kuwait and Berea sandstone were used. Carbon NPs were used as model nanomaterials. The core sample was washed with toluene to remove residual oil, ground to 106 – 250 µm grains, and packed into columns. Carbon NP breakthrough curves were collected in synthetic seawater at room temperature. The results showed that the existence of salt ions dramatically delayed NP breakthrough time and increased NP retention. Effects of different types of salts and salt concentrations are discussed. NP transport appears to be highly dependent on the degree of interaction between the NPs, salt ions in solution, and porous medium surface, which affects retardation and retention. NP breakthrough can be significantly improved by avoiding this interaction via NP surface modification. Our preliminary results provided helpful guidelines for NP transport in oil & gas applications. The results are discussed in detail. Furthermore, the experimental results were fitted with a 1-D advective and dispersion equation combined with a first-order removal term to obtain important transport parameters for NPs that did not aggregate. More complicated models are being developed to capture the unusual breakthrough curves associated with NP aggregation.
A New Technology Combined Corrosion Inhibition and Water Shutoff in Oil Well
Authors: Qing You , Yefei Wang , Fulin Zhao , Benzhe Wang , Haiyang Yu 
Published: July 2010

Abstract
In order to solve the problem of high water cut and serious corrosion in oil well, a new technology combined the corrosion inhibition and water shutoff in oil well is proposed and developed in this paper. In this technology, corrosion inhibitor solution is first injected into the oil well, then followed by selective water shutoff agent, which mothballs the corrosion inhibitor in the high permeability zone. As the oil well is resumed to produce, the succeeding water (injected water or edge water) carries corrosion inhibitor to gradually produce along medium and low permeability zone in order to achieve the multi-purpose of inhibiting the corrosion of pipe string, decreasing the water cut and increasing oil production. The optimized corrosion inhibitor and water shutoff agent were screened out for the reservoir condition before field application. The mechanisms of the new method were studied using physical simulation experiments. This technology is carried out in one well of Shengli oilfield and gets good field effect.
Simulation Workflow Development - Capturing Formation Damage Aspects During a Field's Production Lifetime
Authors: Smith Haakon Dahle , Ducroux Sylvain , Mokdad Belkhir , Wahid Fazrie 
Published: July 2010

Abstract
The formation of near well-bore scale can have detrimental impact on well production. Pore plugging, restriction in wellbore i.d. and perforation plugging due to scale deposition can sometimes remain undetected over prolonged periods especially when very low water production is evident. To overcome this uncertainty, workers in our industry usually rely solely on scale prediction models to identify the potential of scale occurring. However, rarely is this information utilized further to explicitly quantify the impact of scale deposition on well performance and updated in the reservoir model, allowing better field management to be applied.
In general, historical work published on scale prediction analyses have concentrated on identifying the potential of scale formation based on water composition(s) and localized information such as pressure, temperature (thermodynamic), while more recent publications have attempted to capture the kinetics and fluid hydrodynamics involved.
Whilst these predictions can be very useful, it remains a challenge to then use the data output to quantify the impact of scale on overall well performance explicitly. Additionally, limiting factors and uncertainties can exacerbate the problem further. Examples are: Availability of multidisciplinary tools to capture the processes involvedUncertainty in field data including hydraulic flow unitsUncertainty over which layers bear ‘scaling water’Presence of multiple source of formation damage (e.g. fines migration)Presence of other factors that can impact well performance (e.g. liquid loading, lifting)Near-wellbore / formation scaling need not be seen physically
This paper presents an overview of a new simulation workflow development to capture the impact of scale formation by coupling the domains of chemistry and reservoir engineering. Reservoir, near wellbore and macro-scale simulation techniques were integrated to evaluate the impact of scale deposition on well performance during the production lifetime.
From the concise simulation workflow developed, we show how scale has impacted production in two synthetic wells, and more importantly, to characterize the location of the depositing scale. Initial problems relating to uncertainties in flow unit description and identification of potential layers of water source are highlighted, and the solutions to overcome these uncertainties are discussed. Based on this information, the volume of scale deposited at specific locations are enumerated and converted to wellbore and formation skins. Over time, slow deposition of scale was shown to clog up sections of specific perforation intervals along the well length and near wellbore area. By reverse engineering, the explicit impact of scale deposition on well production over time was quantified.
Application and Study of Acid Technique Using Novel Selective Emulsified Acid System
Authors: Xiong Chunming , Zhou Fujian , Liu Yuzhang , Yang Xianyou , Liu Xiongfei , Shi Yang , Tan Yanxin , Zhang Fuxiang , Ji Xiaohong , Qin Shiyong , Huang Shicai , Wang Xudong 
Published: July 2010

Abstract
Most of oil fields in China have stepped into the middle or later stage of waterflooding life, and oil wells begin to appear above water. In conventional acid treatment, acid fluid always flows into the pore path with high water saturation firstly, and broadens the pore path filled with water. However, it can't stimulate the pore path filled with oil as well as that filled with water. To solve this problem, especially in heterogeneous formation, this paper indicates a novel selective emulsified acid system, of which viscosity will increase when meets water and decrease when meets oil in the formation. The core flooding experiment shows that the average permeability increment of cores saturated by oil reaches to 96.1% after treated by this acid system, while the average increment of cores saturated by water is only 10.1%. The novel selective emulsified acid system behaves good retarded and protective capability to the formation. This acid system has been applied on thirteen wells in Gasikule oil field in Qinghai with remarkable results achieved. After the treatment of the new selective emulsified acid, the daily average incremental oil production of single well reachedes to 8.5t, and the water cut decreased by 3.5%. Experimental study and field applications indicate the new emulsified acid system has an excellent ability to acidify the formation selectively.
History Model For Sand Production During Depletion
Authors: Aadnoy Bernt S. , Kaarstad Eirik 
Published: July 2010

Abstract
The likelihood of sand production plays an important role in the selection and application of completion solutions like open holes, screens or perforated liners.
The paper will present a new sand production model. The model is also valid for wellbore collapse during underbalanced drilling. It is based on a full 3-dimensional analysis and takes load history into account. The model is derived for anisotropic stresses and is valid for all wellbore orientations. One interesting observation is the importance of the cohesive rock strength for stability in the depleted phases of the reservoir.
A field case investigates the sand production potential for vertical and horizontal wellbores. The second case investigates effects of in-situ stresses and rock properties in a vertical well.
Forward Modelling Techniques used to Predict Welltest Permeability
Authors: Sirju Clive , Pritchard Tim , Lovell Mike , Davies Sarah , Jefferies Christopher 
Published: July 2010

Abstract
A major drawback of well testing is the high cost and associated environmental impacts. If we can find a new methodology in defining the dynamic properties of the reservoir whilst achieving the principal objectives of a welltest, then the total operating expenditure and damage to the environment can be significantly reduced. Securities and Exchange Commission, Volume 74, January 2009, pg 2166, highlights that if a reliable technology can be used as an alternative, providing it has been field tested and has demonstrated consistency, then there is sufficient justification for it to be accepted. These proposed forward modelling techniques are towards achieving that goal of predicting welltest permeability.
One of the key dynamic properties is permeability. Permeability can be estimated from core, logs and welltests, but each of these approaches interrogates a different volume and thus the permeability estimate relates to a different scale of the reservoir. Trying to relate these scales remains a challenge to the industry. We describe new research towards establishing a novel workflow for clastic reservoirs that can be used to determine an upscaled permeability from core/log data. In developing this strategy we address questions such as, can we achieve the objectives of a welltest with a wireline dataset and can we utilize the permeability derived from logs to forward model the welltest pressure transient? In achieving this goal a flow based upscaling technique can be used to derive a tensor permeability to account for heterogeneities and used to construct a simple geological model with an effective radius of investigation similar to that of a welltest. In this case the pressure transient is interpreted using analytical techniques and used to determine an upscaled permeability. The success of these approaches is determined by comparing the results to real welltests in an existing database.
Extraction of Interference from Long-term Transient Pressure using Multi-well Deconvolution Algorithm for Well Test Analysis
Authors: Zheng Shiyi , Wang Fei 
Published: July 2010

Abstract
Interference effect between wells is very common in mature reservoirs. This is particularly true for transient pressure data from permanent down-hole gauges (PDG). As soon as the recorded pressure interfered by the pressure disturbance from other wells nearby, the PDG pressure becomes the product of two components, i.e. self response due to the well production and interference from neighbouring wells. This combined pressure data recorded by the PDG has a nonlinear nature, which can not be analysed by traditional well testing principles such as superposition or deconvolution.
There are two approaches handling this type of data. One is numerical well testing designed for solving well testing problems in a nonlinear reservoir system. Another is to pre-process the data by decomposing the total pressure response into linear reservoir response and the component that causes the nonlinearity of the response, i.e. interference effect. Thereafter, the extracted interference data can be analysed as interference test, and the remaining data can be analysed by traditional well testing methods.
This paper presents a newly developed multi-well deconvolution algorithm specially designed for analysing long term transient pressure with interference. The procedures include firstly, the diagnostic of the reservoir system response for the nonlinearity. As soon as the reason causing this nonlinearity is found, in this presented case, is due to interference, the following step is to extract the interference from the total pressure response. Then, the analysis of the decomposed data can be made using the available traditional well testing methods. Numerical well testing synthetic studies were performed to demonstrate these procedures.
The study results proved that the new method appeared to work well in homogeneous reservoirs with wells flowing at single phase, single and multiple rates. The potential in further developing this technique for practical application is obvious and looks very promising.
Brightwater® Trial in Salema Field (Campos Basin, Brazil)
Authors: Roussennac Bruno , Toschi Celso 
Published: July 2010

Abstract
The Salema field, a waterflood development off the coast of Brazil (Campos Basin) has been suffering from early water breakthrough and poor sweep on the south part of the field.
In an attempt to increase the sweep efficiency, a novel in-depth waterflood conformance control technology commercialized by Tiorco (Nalco company) as Brightwater®6 has been selected.
This paper describes the feasibility, maturation, execution, monitoring and results of the first trial in Brazil (July 2009), which is also the first for Shell worldwide. We will discuss reservoir simulation and lab work (core tests, sand-pack tests…) that lead to the decision of performing the field trial. The offshore set-up and pumping job will be described briefly. Finally surveillance techniques and results to date will be presented.
Study on External Detection Techniques for Pipeline Corrosion in High Sour Gas Fields
Authors: Li Changjun , Jia Wenlong , Liao Kexi , Wu Xia , Liu Enbin 
Published: July 2010

Abstract
With the development of high sour gas fields, the failure of gas gathering pipelines in high sour gas field caused by corrosion is becoming more serious. So it is important to select effective detection methods to detect the corrosion defects to insure the safety operation of the pipelines. In view of the characteristics that uniform corrosion, pitting, hydrogen induced cracking and stress corrosion cracking occur easily in high sour gas fields, adaptability of the three external detection techniques which include transient electromagnetic method, metal magnetic memory testing and ultrasonic guided wave technology are studied by theoretical and application analysis. Advantages, disadvantages and applicable scopes of these techniques are analyzed and compared. The achievements of the study provide basis for selecting reasonable methods to detect corrosion defects of pipelines in high sour gas fields.
Estimation of Casing-Cement-Formation Interaction using a new Analytical Model
Authors: Teodoriu Catalin , Ugwu Ignatius , Schubert Jerome 
Published: July 2010

Abstract
The objective of this paper is to develop a better understanding of the performance of the casing - cement bond under HPHT well conditions, leading to a model to predict well life. An analytical model of wellbore stresses based on wellbore parameters was developed. The new model considers the casing as a thin wall cylinder, while cement and formation are modeled using a thick wall cylinder theory. Also the equivalent stress is calculated using different failure criteria that allow the user to simulate all possible load conditions on the casing-cement-formation system. The results were confirmed by finite element simulations. The new model that was implemented in an easy to use calculation sheet will give production engineers a simple tool to estimate the well integrity under various downhole conditions.
Investigations on Casing-Cement Interaction with Application to Gas and CO2 Storage Wells
Authors: Teodoriu Catalin , Reinicke Kurt M. , Fichter Carsten , Wehling Pascal , Clausthal TU 
Published: July 2010

Abstract
This paper describes the construction and theoretical background of a new testing facility to investigate long-term sealability of cement recipes with application to storage gas wells. The first part deals with a theoretical downscaling of well conditions in order to determine the test parameters. Storage gas wells may have production casing strings with sizes up to 9 5/8" and therefore some downscaling criteria are necessary. The test facility representing an artificial annulus allows the simulation of the load changes and their effect on the cement. The adjustment of the test loads in the test facility is supported by an FEM-Analysis. This allows generating stresses in the test facility equal to those at the cement casing interface in the wellbore. The testing procedure is independent of the cement recipe and designed to expose the cement to common loads, as it has been found in gas or CO2 wells.
Based on the visual observation, the measured axial and radial strains, axial displacement and test gas pressure drop it was possible to identify the development of a micro annulus and radial cracks in the cement sheath. The tests also showed that there is a region of minimum leakage in the failed cement sheath depending on the internal casing pressure.
Is It Possible to Inject Larger Sizes and Higher Solids Concentrations of Drill Cuttings?
Authors: Ji Lujun , Guo Quanxin , Wang Cong 
Published: July 2010

Abstract
Subsurface drilling waste injection (WI) technology has been applied worldwide both onshore and offshore to minimize or eliminate surface disposal of drill cuttings and other drilling wastes, as well as minimize processing delays affecting drilling operations. Most current waste injection operations are conventionally limited to a maximum 300-micron size of cutting particles and solids concentration of 20% by volume. With these rules, the time required to grind drill cuttings into 300 micron or less and mix them into 20% slurry before injection limits the processing capacity of a WI system and sometimes restricts drilling operations. If operators were able to inject slurries with larger sizes and/or higher solids concentrations of drill cuttings, it would significantly reduce the grinding and mixing times, reduce the volume of slurry to be injected, and increase the processing capacity of the same WI equipment.
This paper presents subsurface injection simulation results of injecting larger sizes and higher solids concentrations of waste slurries based on typical waste slurry properties and formation conditions using a true 3D boundary-element hydraulic fracturing simulator. These simulations identify the potential subsurface issues and risks, e.g., screen-out, fracture plugging from injection of such slurries with larger sizes and/or higher concentrations of drill cuttings. Based on these simulation results, this paper also outlines a systematic engineering design procedure for a project-specific WI study.
EnKF-MCMC
Authors: Emerick Alexandre A. , Reynolds Albert C. 
Published: July 2010

Abstract
The ensemble Kalman filter (EnKF) has recently become a popular history-matching tool largely because of its computational efficiency and ease of implementation. While EnKF has improved a previous history match obtained manually in several field cases, and often appears to give reasonable results for realistic synthetic history matching problems, one cannot theoretically establish that EnKF samples correctly the posterior probability distribution for the reservoir model parameters or correctly assesses the uncertainty in the production forecast unless strong assumptions of Gaussianity and linearity apply. In multiphase flow problems, the relationship between data and reservoir model parameters and the primary simulation variables is highly nonlinear, so the theoretical justification for obtaining a correct assessment of the uncertainty in model parameters and future performance predictions does not hold. On the other hand, it is well known that the Markov chain Monte Carlo (MCMC) method sample correctly in the limit. However its direct application to reservoir problems can be prohibitively expensive computationally. Here we use a variant of EnKF, the ensemble square root filter (EnSRF), to provide an initial sample of the posterior pdf and to propose transitions for the MCMC method. We present a synthetic reservoir case and show that the combined application of EnSRF and MCMC provides improved history-matching results and a better characterization of uncertainty in the predicted reservoir performance.
Ensemble Based 4D Seismic History Matching: Integration of Different Levels and Types of Seismic Data
Authors: Fahimuddin A. , Aanonsen S. I. , Skjervheim J.- A. 
Published: July 2010

Abstract
One of the challenging issues of using 4D seismic data into reservoir history matching is to compare the measured data to the model data in a consistent way. It is important to decide which kind of seismic data can be best used and at which level of history matching process they can be integrated. In this work, we have performed 4D seismic history matching of a sector model based on a North sea reservoir in the ensemble Kalman filter (EnKF) framework and have investigated the effects of different types of time-difference seismic data to update reservoir models. The reservoir-seismic model system consists of a commercial reservoir simulator coupled to an implemented rock physics model and a forward seismic modeling tool based on 1D convolution with weak contrast reflectivity approximation. The objective of this work is to investigate the sensitivity of different combinations of production and seismic data on EnKF model updating. The uncertain static reservoir parameters considered are porosity and permeability; dynamic variables such as pressure and water saturation are conditioned to both production and seismic data. In particular, we are interested to quantify the performance of the wells; also to match seismic data and to estimate the reservoir parameters. In most of the cases of reservoir characterization, time-difference impedance data performed better than time-difference amplitude data and considerably reduced posterior ensemble spread. The matching of seismic data generally improved with the inclusion of time-difference seismic data. In estimating posterior porosity and permeability, seismic difference data provided better estimate than using only production data, especially in aquifer region and also in areas that might be considered for in-fill wells. Thus, in our realistic synthetic case based on a full field reservoir model, we experienced that the integration of seismic data in the elastic domain provided better performance than using amplitude data. In addition, we investigated the effects of vertical resolution of seismic data on EnKF model updating, and showed that the choice of wavelet discretization points can have significant influence on the quality of history matching.