bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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.
History Matched Full Field Geomechanics Model of the Valhall Field Including Water Weakening and Re-Pressurisation
Authors: Tron Golder Kristiansen , Bertold Plischke
Published: July 2010

Valhall is a large chalk field in the Norwegian sector of the North Sea. The reservoirs consist of highly overpressured (0.84 psi/ft) chalk. The high overpressure and early oil migration has resulted in very well preserved porosity, exceeding 50% in parts of the field. This highly porous chalk is extremely weak, which results in liquefaction of the chalk at certain conditions during production. The weak nature of the chalk does also result in significant reservoir compaction, exceeding 10 meters in some locations in the reservoir. The compaction is providing an excellent source of reservoir energy, accounting for 50-60% in certain areas of the field. The compaction is transferred to the seafloor in the form of subsidence and is currently exceeding 6 meters below the central platform complex.

The seafloor subsidence has resulted in a diminishing air gap for the platforms at Valhall, resulting in demobilisation of personnel during very rough winter storms. Water injection started in the field in 2004 with a gradual step up in rate. An offset chalk field in the area have experienced an increasing subsidence rate due to water weakening of the chalk. The micro-scale physical and chemical processes involved in water weakening of chalk have not been quantitatively determined, but a strategy to handle this had to be developed. This paper documents the development of a prediction model for the subsidence at Valhall between 2002 and 2008. The paper covers the development of a suitable and effective constitutive model to account for strain rate dependent reservoir compaction during depletion, re-pressurisation and waterflooding. The constitutive deformation model is driven by pore pressure and watersaturation calculated in a reservoir flow model and imported into the geomechanics model.

It will be described how the constitutive model for the reservoir was populated. The overburden, underburden and sideburden were also modelled and required properties. The initialisation requires an initial stress state and it will be presented how this was defined. We also included faults in the model and check for re-activation and amount of slip on them. The Valhall model can also be constrained by a relative large amount of field and surveillance data. It will be presented how this data was used in the history matching process. The data used for the history matching process includes vertical and horizontal platform movements from GPS, time lapse seafloor bathymetry maps, radioactive markers in the reservoir and overburden as well as 4D seismic. It will be presented how the model matched the observed data from the field, showing a gradual decrease in subsidence rate from around 25 cm/year with the risk to increase due to water weakening, to the current reduced rate at 11 cm/year. This response is different to the one reported from the offset field. We will also present other high impact business applications of the model prediction, besides seafloor subsidence forecasting.
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

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

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

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 (>6000m) and 3 ultra-deep wells (>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

In 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

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

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

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

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

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.