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74th EAGE Conference and Exhibition incorporating EUROPEC 2012
- Conference date: 04 Jun 2012 - 07 Jun 2012
- Location: Copenhagen, Denmark
- ISBN: 978-90-73834-27-9
- Published: 04 June 2012
21 - 40 of 948 results
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Integrated Reservoir Studies, Karachaganak Field, Republic of Kazakhstan (SPE 154390)
Authors A. Francesconi, C. Albertini, F. Bigoni, C. Catalani, A. Cominelli and V. TarantiniThe Karachaganak field is one of the largest accumulation of gas-condensate in the world, in production since 1985. Located in the northern Pricaspian Basin (Kazakhstan) the field is a Permo-Carboniferous isolated carbonate platform with a hydrocarbon column that resides within different environments of deposition. The distribution of reservoir properties has been largely debated because of both the depositional heterogeneity and the diagenetic overprint. These uncertainties were assessed by analyzing and integrating the vast amount of geological and production data to build a predictive history matched reservoir model. Seismic facies analysis, with support from outcrop analogues and integrated with field core and log data, reveals, within stratigraphic intervals, C"depositional regionsC" (DRs) that ranges from platform interior bedded deposits to aggrading/prograding mounds, clinoforms, slopes and basin sediments. These DRs were first seismically mapped and then petrophysically characterized using geologic and dynamic data. In a geologically meaningful manner that makes use of DRs, a sequence of better and better models was built and critical petrophysical issues (such as enhanced/matrix permeability, sealing barriers and dolomitization) were in parallel addressed. A reference model has been so defined and a history match of remarkable quality has been achieved for this complex heterogeneous reservoir. The uncertainty was investigated in a pragmatic manner using HM as benchmark. The reservoir uncertainty decreases closer and closer to the well, hence various models were built by updating DR properties up to a certain distance from the production wells. Using the distance and the magnitude of the perturbations as control parameter and the degree of history match as selection criterion, we could identify two cases. These scenarios represent possible alternative C"end membersC" consistent with the geological data, still endorsed by a high quality history match and capable to give a significant spread in the production forecast.
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Effect of Drilling Fluid (Water-based vs Oil-based) on Phase Trap Damage in Tight Sand Gas Reservoirs (SPE 154652)
Authors M. Tsar, H. Bahrami, R. Rezaee, G. Murickan, S. Mehmood, M. Ghasemi, A. Ameri and M. MehdizadehTight gas reservoirs normally have production problems due to very low matrix permeability and different damage mechanisms during drilling, completion and stimulation operations. Therefore they may not produce gas at commercial rates without production optimization and advanced completion techniques. Tight formations have small pore size with significant capillary pressure energy suction that imbibes and holds liquid in the capillary pores. Leak off of liquid into formation damages near wellbore permeability due to phase trap damage and clay swelling, and it can significantly reduce well productivity even in hydraulically fractured tight gas reservoirs. This study presents evaluation of damage mechanisms associated with water invasion and phase trapping in tight gas reservoirs. Single well reservoir simulation is performed based on typical West Australian tight gas formation data, in order to understand how water invasion into formation affects well production performance in both non-fractured and hydraulically fractured tight gas reservoirs. A field example of hydraulic fracturing in a West Australian tight gas reservoir is shown and the results are analysed in order to show importance of damage control in hydraulic fracturing stimulation of low permeability sand formations.
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New Flattening-based Methodology for More Accurate Geostatistical Reservoir Populating (SPE 154781)
Authors M. Poudret, C. Bennis, C. Dumont, O. Lerat and J.F. RainaudIn the domain of oil exploration, geostatistical methods aim at simulating petrophysical properties in a 3D grid model of reservoir. The main input comes from drilled wells data in the geographic space. Lithofacies and petrophysical properties as porosity and permeability are measured along these wells trajectories. These data are then assigned to every cell of the 3D grid model which intersects a well trajectory. At this step, only a small amount of cells are populated with petrophysical properties. Roughly speaking, the question is: which properties we should give to cell c, knowing the properties of n cells at a given distance from c? Obviously, the population of the whole reservoir must be computed while respecting the spatial correlation distances between petrophysical properties. Thus, the computing of these correlation distances is a key feature of the geostatistical simulations. In the classical geostatistical simulation workflow, the evaluation of the correlation distance is imprecise. Indeed, they are computed in a Cartesian simulation space which is not representative of the geometry of the reservoir. Thus, depending on the deformation degree of the lithostratigraphic units in the geographic space, significant errors may be introduced in the geostatistical simulation. This lack of accuracy has prompted us to work on and devise a new methodology in order to increase the reliability of the parameters required by the geostatistical simulators. We propose a new methodology in order to better estimate the correlation distances between wells. Our methodology is based on the isometric flattening of lithostratigraphic units. Thanks to this flattening process, we accurately reposition the initial populated cells in a flat simulation space, before computing the correlation distances. In this paper, we introduce our methodology threw study case representing different deposit modes of the sub-surface models. We finally present some preliminary results.
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Asphaltene Deposition Study and its Effects on Permeability Reduction - A Case Study (SPE 153512)
Authors S.M. Razavi, R. Kharrat and Z. ZargarAbstract Asphaltene deposition affects the porosity and permeability which in turn reduces the production and raises the processing costs. Therefore, it is necessary to determinine the amount of solid deposition causing the porosity and permeability reduction. In this paper, it has been tried to overcome this need by simulating the process in one of the South-West Iranian reservoirs in which asphaltene problem has been encountered frequently. The wells under production were facing severe asphaltene choking and coiled tubing acid wash were done every six month to remove the deposited asphaltene. Flow assurance results for the fluid are clearly indicating that oil is highly asphaltenic although it is a light oil with low asphaltene content. In the other hand, wells under production always are required to keep the rate as long as possible due to economic limits and it was critical for the management to know the effect of asphaltene deposition in the reservoir formation on the flow rate and vice versa. The best way to see the effect is reservoir simulation in which asphaltene deposition is modeled. First of all, the fluid model and asphaltene precipitation curve were prepared. Then, the reservoir static and dynamic models were generated based on the rock and fluid properties. The behavior of asphaltene during the production as precipitated, flocculated, and deposited asphaltene were modeled using commercial software. In addition, the variation of permeability due to asphaltene deposition was obtained. Asphaltene and permeability map were generated for the entire reservoir. Most of the deposition was found to form around and nearby the production wells. Minor permeability reduction was observed throughout the reservoir; however, major damage was around the wellbore. Both precipitation and deposition amounts were visible and can be reported and this ability increases the capability to decide better about the optimum production.
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Chalk Reservoir Management through Rock Physics Diagnostics - Field Examples from the Danish North Sea (SPE 154870)
Authors L. Gommesen and H.P. HansenWith improvements in 3D seismic products and an increasing number of 4D examples from North Sea chalk fields, the usages of rock physics is becoming more and more accepted as an enabler for detailed reservoir characterization and monitoring of the dynamic behavoiur of the reservoirs. In order to manage the fields optimally, it becomes increasingly relevant for the asset team to understand the effective elastic properties of the reservoir rock recorded from seismic, well logs and laboratory experiments and the related the changes that production and water injection may induce. Through a series of field examples this paper decomposes and quantifies the effect of lithology and porosity variations, fluid replacements, pressure changes in a reservoir management context using rock physics fundamentals. The examples includes both 3D and 4D seismic observations and the case examples are backed up by well log and laboratory data. The paper summarizes on how rock physics insights on North Sea chalk has increased the understanding of the chalk reservoirs and directly impacted reservoir management by integration of quantitative geophysical interpretation with solid reservoir engineering and proven geoscience processes. On basis of the examples the paper concludes that an intgrated approach to field development and reservoir management evidently includes quantitative geophysical interpretation in order to optimize hydrocarbon production from tight chalk fields.
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History-matching with Ensemble-based Methods - Application to an Underground Gas Storage Site (SPE 154475)
Authors V. Gervais, L. Heidari, M. Le Ravalec-Dupin and T. SchaafThis paper shows the application of two ensemble-based assimilation methods to constrain an underground gas storage site operated by GDF-Suez to well pressure data. The methods considered here are the Ensemble Kalman filter (EnKF) and the Ensemble Smoother (ES). The EnKF is a sequential data asssimilation method that provides an ensemble of models constrained to dynamic data. It entails a two-step process applied any time data are collected. First, the production response is computed for each model of the ensemble at the following acquisition time. Second, models are updated using the Kalman filter to reproduce the data measured at that time. The EnKF has been widely applied in petroleum industry. More recently, the ES was used successfully on real field cases. This method is also based on the Kalman filter, but the update is performed globally over the entire history-matching period: values simulated at each assimilation time are considered simultaneously in the update step. The multiple restarts necessary with EnKF are thus avoided. We present here an application of these methodologies for constraining an underground gas storage site to well pressure data. The uncertain parameters are the porosity and horizontal permeability values populating several layers of the geological model. Both methods yield a good match of pressure data in the history-matching and prediction periods. For ES, this can require two successive applications. Considering the same initial ensemble, the ES leads to a smoother mean with less extreme values and a higher variance. The EnKF and ES methodologies turn out to be powerful tools to constrain geological models to dynamic data, and were applied successfully to a real field. The ES gives here similar results in terms of match and predictions while preserving a higher spread within the model ensemble with less extreme petrophysical values.
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On Population Diversity Measures of the Evolutionary Algorithms Used in History Matching (SPE 154488)
Authors A. Abdollahzadeh, M.A. Christie, D. Corne, B.J. Davies, A. Reynolds and G. WilliamsIn history-matching the aim is to generate multiple good-enough history-matched models in limited number of simulations which will be used to efficiently predict reservoir performance. History-matching is the process of the conditioning reservoir model on the observation data which is mathematically ill-posed, inverse problem and has no unique solution and several good solutions may occur. Numerous evolutionary algorithms are applied to history-matching which operate differently in terms of population diversity in the search space throughout the evolution. Even different flavours of an algorithm behave differently and different values of an algorithmC"s control parameters result in different value of diversity measure. These behaviours vary from explorative to exploitative. The need to measure population diversity arises from two bases. On one hand maintaining population diversity in evolutionary algorithms is essential to detect and sample good history-matched ensemble models in parameter search space. On the other hand, since objective function evaluations in history matching are expensive, algorithms with fewer total number of reservoir simulations in result of a better convergence are much more favourable. Maintaining populationC"s diversity is crucial for sampling algorithm to avoid premature convergence toward local optima and achieve a better match quality. In this paper, we introduce and use two measures of the population diversity in both genotypic and phenotypic space to monitor and compare performance of the algorithms. These measures include an entropy-based diversity from the genotypic measures and a moment of inertia based diversity from the phenotypic measures. The approach has been illustrated on a synthetic model, PUNQ-S3, as well as on a real North Sea model. We demonstrate that introduced diversity measures provide efficient criteria for tuning the control parameters of the algorithms as well as performance comparison of the different algorithms used in history matching.
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Assisted History-matching for the Characterization and Recovery Optimization of Fractured Reservoirs Using Connectivity Analysis (SPE 154392)
Authors A. Lange, A. De Lima and D.J. SchiozerAn integrated optimization workflow was developed to characterize seismic and sub-seismic fault networks from history-matching. A fractal model of fault networks is optimized via the gradual deformation of stochastic realizations of fault density maps, fault spatial and length distributions. In order to facilitate the history-matching, connectivity analysis tools were developed for characterizing wells-reservoir and well-to-well connectivity. Indeed these connectivity properties usually depend on the fault network realization and may be strongly correlated with the reservoir flow dynamics. Connectivity analyses were performed on a fractured reservoir model involving a five-spot well configuration with four injectors and one producer. The connectivity was estimated from shortest path algorithms applied on a graph representation of the reservoir model. Several reservoir simulations were performed for different fault network realizations to seek correlations between injector-producer connectivity and water breakthrough time. The impact of the fracture properties uncertainties on the wells-reservoir connectivity was estimated via the cumulated connected volume computed for each well. This connectivity measure provides a mean to characterize and classify fault network realizations. Correlations were found between the water breakthrough time and the injector-producer connectivity, thus allowing one to identify the most probable fault network realizations to match the observed water breakthrough time. Finally, for a given fault network realization, it is shown how the oil recovery can be optimized by correlating injectors rates with the injector-producer connectivity. A gain of 3e6m3 in produced oil was obtained, while retarding the water breakthrough time by 16 years, compared with a case where all injectors have the same rate. The proposed methodology and tools facilitate the history-matching of fractured reservoir, providing consistent reservoir models that can be used for production forecast and optimization.
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Assisted History Matching Using Three Derivative-free Optimization Algorithms (SPE 154112)
More LessDescription: Gradient-based optimization algorithms can be very efficient in history matching problems. Since many commercial reservoir simulators do not have an adjoint formulation built in, exploring capability and applicability of derivative-free optimization (DFO) algorithms is crucial. DFO algorithms treat the simulator as a black box and generate new searching points using objective function values only. DFO algorithms usually require more function evaluations, but this obstacle can be overcome by exploiting parallel computing. Application: This paper tests three DFO algorithms, Very Fast Simulated Annealing (VFSA), Simultaneous Perturbation and Multivariate Interpolation (SPMI) and Quadratic Interpolation Model-based (QIM). Both SPMI and QIM are model-based methods. The objective function is approximated by a quadratic model interpolating perturbation points evaluated in previous iterations, and new search points are obtained by minimizing the quadratic model within a trust region. VFSA is a stochastic search method. These algorithms were tested data with two synthetic cases (IC fault model and Brugge model) and one deepwater field case. Principal Component Analysis is applied to the Brugge case to parameterize the reservoir model vector to less than 40 parameters. Conclusions: We obtained good matches with all three derivative-free methods. In terms of number of iterations used for converging and the final converged value of the objective function, SPMI outperforms the others. Since SPMI generates a large number of perturbation and search points simultaneously in one iteration, it requires more computer resources. QIM does not generate as many interpolation points as SPMI, and it converges more slowly. VFSA is a sequential method and usually requires hundreds of iterations to converge. With enough computer resources available, applying the SPMI method is the best choice. When the number of computer cluster nodes is limited, QIM is the best choice. We recommend applying VFSA when using a single computer.
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A Comprehensive Workflow for Assisted History Matching Applied to a Complex Mature Reservoir (SPE 154383)
Authors J.F.M. Van Doren, G. Van Essen, O. Wilson and E.B. ZijlstraCurrently a multitude of techniques exist for (computer-) assisted history matching (AHM) of simulation models, each with their merits and limitations. In this paper, it is demonstrated how different AHM techniques can be combined to quickly reveal diagnostics of a subsurface model and to obtain a better model in less time, optimally using the strengths of each method. A completed field application of AHM will be presented, in which several AHM techniques are sequentially used to arrive at a history match on pressures and fluid rates and, equally important, an improved understanding of both the static and dynamic model. The water flooded field, located in the Middle East, has decades of historical production data from about 30 wells and is notoriously difficult to match. The first technique that has been applied involves Design of Experiments to generate proxies followed by Monte Carlo Markov Chain to find the ensemble of global parameters that give an improved match. Subsequently, adjoint-based history matching has been used to find the areas in the model that were under-modelled and needed additional attention of the subsurface team members. Based on the results in this step of the workflow the static model has been improved such that it is consistent with the information in the production measurements. For this field, the AHM workflow has achieved a considerable reduction of history matching time and improved quality of both the match and the model. For general simulation studies this workflow is estimated to result in a time saving of 40% with respect to manual history matching. In addition, it results in a better understanding of the static and dynamic subsurface uncertainties.
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An Improved Inversion Workflow Jointly Assimilating 4D Seismic and Production Data (SPE 154157)
More LessDescription: Quantitative integration of 4D seismic data with production data into reservoir models is a challenging task. This paper tackles two key issues of the complex joint inversion workflow to improve its efficiency and accuracy. We applied two derivative free optimization (DFO) methods, namely particle swarm optimization (PSO) and Simultaneous Perturbation and Multivariate Interpolation (SPMI), and compared their performances. We tested different strategies of effectively mining information in both 4D seismic and production data. We proposed a method of choosing the different weights in data domain by utilizing sensitivity of inversion parameters to different types of data. We also tested the strategy of combining the inversion results from separate inversion runs using 4D seismic data or production data only. Application: We tested the workflow in a 3D synthetic model. Uncertain parameters for this model include relationship between porosity and permeability, and the ratios of kv to kh for different reservoir zones. The performance of PSO and SPMI are compared in terms of the evolution of objective function and estimation of uncertain parameters. We also provide recommendations about when to use which method. Different strategies of optimal use of 4D seismic and production data are also applied and compared using this model. The learning is also applied to a deepwater turbidite field. Results, Observations, Conclusions: Both PSO and SPMI are effective DFO methods and deliver good results for 4D seismic history matching problems. The complementary features of these two methods can ensure both applicability and efficiency of this joint inversion workflow. Choosing proper weights in either data or model domain can improve the accuracy of this workflow. Significance of Subject Matter: By solving the two key issues of jointly assimilating 4D seismic and production data, we deliver reliable workflow for reservoir model characterization and management.
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Refined Adaptive Gaussian Mixture Filter - Application on a Real Field Case (SPE 154479)
Authors R. Valestrand, G. Nævdal, A. Shafieirad, A.S. Stordal and E. DoveraOver the last decade the ensemble Kalman filter (EnKF) has attracted attention as a promising method for solving the reservoir history matching problem: Updating model parameters so that the model output matches the measured production data. The method possesses unique qualities such as; it provides real time update and uncertainty quantification of the estimate, it can estimate any physical property at hand, and it is easy to implement. The method does, however, have its limitations; in particular it is derived based on an assumption of a Gaussian distribution of variables and measurement errors. A recent method proposed to improve upon the original EnKF method is the Adaptive Gaussian mixture filter (AGM). The AGM loosens up the requirements of a linear and Gaussian model by making a smaller linear update than the EnKF and by including importance weights associated with each ensemble member at computational costs as low as EnKF. In this paper we present a refined AGM algorithm where the importance weights are included in the calculation of the apriori and the aposteriori covariance matrix and we also present results where this algorithm is combined with distance based localization. Moreover, in this paper the AGM algorithm is for the first time applied to a real field study. To validate the performance of AGM the result is compared with the EnKF, with and without distance based localization. Several statistical measures are used to validate the performance of the filters, and we are able to distinguish the performance of the different filters. In particular all the methods provide good history match, but we see that the AGM stands out by better honoring the original geostatistics.
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Removal Efficiency of Water-based Drill-in Fluid Filter Cake Using Polylactic Acid (SPE 154192)
Authors S. Elkatatny and H.A. Nasr-El-DinWater-based drilling fluids consist of xanthan gum, starch, sized calcium carbonate and salt particles to increase mud density was used to drill horizontal wells. Available chemical methods of removing filter cake like mineral acids, esters, oxidizers, and chelating agents are limited at certain conditions. A drilling fluid was designed based on calcium carbonate particles and an ester of lactic acid. The objective of the latter is to remove calcium carbonate once the drilling operation is complete and there is a need to remove the filter cake. Extensive lab work was done to; 1) determine thermal stability of the drilling fluid (70-72 pcf) for 24 hrs, 2) characterize the filter cake using a computer tomography, 3) assess potential formation damage for different rock types (limestone and sandstone) using a modified HPHT filter press, and 4) determine the removal efficiency of the filter cake and the return permeability. The results obtained showed that the drilling fluid has stable rheological properties up to 300oF over 24 hrs. CT scan showed that the filter cake contained two layers, one layer closed to the rock surface, which contained a mixture of calcium carbonate and acid-precursor and one layer closed to the drilling fluid that contained a mixture of XC-polymer and starch. The polymer layer was removed by using 10% solution of alpha amylase. The rest of the filter cake was removed by lactic acid that was produced from the hydrolysis of the ester. The removal efficiency of the filter cake was nearly 80% and the return permeability was about 100%. The decrease in CT number of the core after the removal process indicated that the filter cake was completely removed. This paper will discuss the development of this new drilling fluid and will give recommendations for field applications.
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Wellbore Section Contribution in Fractured Horizontal Openhole Wells (SPE 153326)
More LessMore and more horizontal wells are completed as openhole and fractured with multistage fractures. The question is what is the contribution of the openhole section to total production in a fractured horizontal openhole well? Based on actual production data of a horizontal well before and after multistage fracturing, combining the data from a cemented casing horizontal well nearby, the paper analyzes popular horizontal and fractured horizontal well correlations first, and then presents a new inflow performance model accounting both the horizontal openhole section and the fractures of horizontal wells. Data from 13 fractured horizontal openhole wells were used to check the presented model. The paper can be used to study the inflow performance of a horizontal gas well, and to check how much the horizontal openhole section contributes in a fractured well. The presented analyses can also be used to determine fracture numbers and weather to use openhole or cemented casing completion. For a fractured horizontal openhole well, both wellbore and fractures contribute to the total production of the well. Openhole length, fracture number and the ratio of horizontal to vertical permeability are the major control factors. The producing part from the wellbore section is less than that from widely used horizontal models (like JoshiC"s). The more the fractures are, the less the openhole section contribution is. The model can be used for horizontal wells with or without fractures. The presented new model gives better results for authors 13 wells. Previous fractured horizontal well models overestimate the production from the wellbore, and underestimate the production from the fractures. The paper presents the change of fluid flow direction due to hydraulic fractures into the wellbore.
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Real Time Advanced Surface Flow Analysis for Detection of Open Fractures (SPE 154927)
Authors T. Al-Adwani, J.M. Dashti, J. Estarabadi, G. Ferroni, B. Khan, A. Martocchia and K. SinghDescription A Coriolis-type mud flowmeter was run on an exploratory well to obtain Real-Time identification of open formation fractures in an otherwise tight carbonate reservoir. The well was drilled with oil base mud which does not enable accurate flow measurement with other sensor types. This was the first time that accurate fracture detection via advanced flowmeters was performed in oil base mud. Application Tight, fractured carbonate reservoirs are the prime targets for hydrocarbon exploration in Kuwait. Sustained economic production from carbonate reservoirs depends entirely on the connectivity of open fracture networks. Hence, proper evaluation of fractures is key to exploration of these reservoirs. Cores and image logs are used for fracture characterization, but they do not provide Real-Time response. The patterns in the variations of mud flow, instead, enable to identify open fractures. Results, Observations, Conclusions The system has proven to be the only source of Real-Time information on the presence of open fractures while drilling. It has also been utilized as an early kick detection tool. The paper presents a series of events in which these results are substantiated. These results have enabled to confirm and further develop interpretation models for flow behaviour in relation to fluid exchange between the borehole and the formation. Furthermore, in order to maximize the quality of the flow data, a correct sensor installation design and execution has proved critical. Significance of Subject Matter No open hole logging was possible in the zone of interest in the pilot well due to high pressure and associated drilling complications. In this situation, information from mud flow anomalies was the only source for identification of open fractures. This information was utilized to identify the well test interval.
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Evaluation of Multistage Fracturing by Hydrajet, Swellable Packer and Comprehensive Packer Techniques in Horizontal Openhole Wells (SPE 153328)
More LessHorizontal openhole wells are commonly fractured by one of the three hydraulic fracturing techniques of hydrajet, swellable parker and compressive packer techniques. The paper reviews the application of 23 wells fractured by hydrajet (12 wells), swellable parker (4 wells) and compressive packer (7 wells) in tight gas sands in China. None method is overwhelming in the view of increasing production rate from the paper. The paper presented that different treatment pressures among stages may not a signal of perfect isolation. Created traverse fracture by hydraulic stimulation may not be at the middle of two packers or at the place of opened sleeve port for swellable packer and mechanical packer stimulation. Hydrajetting is a good choice to stimulate a specific place along the entire wellbore. Unlike in vertical wells, hydrajetting may not reduce the breakdown pressure in horizontal well treatment. The presented comprehensive comparison and discussion of the three fracturing methods will help operators understand the three methods better and accomplish production goals.
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A Novel Optimisation Algorithm for Inflow Control Valve Management (SPE 154472)
Authors I. Grebenkin and D.R. DaviesIntelligent Wells are equipped with downhole sensors to monitor the downhole flow and Inflow Control Valves (ICVs) to control the zonal flow rate. These ICVs are operated to increase the hydrocarbon recovery and prevent unwanted fluid production. This objective is simply stated, but optimisation of ICV operation is a complex, non-linear problem. Several commercial software providers have made optimisation algorithms available to the industry. Nevertheless, experience shows that challenges still arise with these algorithms when they are applied to real-field cases. Not only does the calculation time increase dramatically (up to 50 times when compared with non optimal run), but also stability and convergence problem give additional increases in running time as well as providing unrealistic results at random intervals. These problems are particularly acute if the software is applied to production uncertainty analysis where the running of multiple realisations is required. This paper will present a novel method for implementing an ICV control strategy. We chose the direct search algorithm to form the basis for our method since it is not affected by convergence problems. Our control strategy will use the current, zonal inflow rate and water cut data to identify the optimal ICV choke positions. The availability of this data reduces the number of possible choke positions that have to be evaluated at each time step by the simulator. Run times only 2-5 times greater than the base case can then be achieved while, equally importantly, the optimal value identified is similar to the value from other, widely accepted methods. We will show how this method can be used for reactive control of oil production from intelligent wells completed with discrete ICVs and, since this control algorithm is always convergent, fast and sufficiently stable will indicate how it may be used for production uncertainty analysis.
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A Modified Version of the Aziz et al - Multiphase Flow Correlation Improves Pressure Drop Calculations in High-rate Oil Wells (SPE 154125)
Authors H. Al-Attar, M. Amin and M. MohamedThe prediction of multiphase pressure drop during the simultaneous flow of oil, gas and water in vertical tubing strings is crucial in the development and optimum exploitation of an oil field. In this paper a method is proposed to improve pressure drop calculations of the Aziz et al. multiphase vertical-flow correlation which has been theoretically justified. The present method suggests combining several flow pattern maps with the Aziz et al. correlation in an attempt to achieve the improvement sought. Two field data sets gathered from 38 production tests conducted in the Middle East and North Africa are used to examine the performance of the various combinations. The results of this work indicate that the performance of Aziz et al. multiphase correlation can be best improved by replacing its original flow-pattern map with the traditional Duns-Ros flow-regime map and for both data sets used. A significant improvement has been observed giving an overall absolute average percent deviation of 2.17% compared with 9.54% for the original correlation. Surprisingly, the Taitel et al. and Barnea et al. flow pattern map does not seem to give accuracies comparable to those of the Duns-Ros correlation. Also it has been found that an improvement in the performance of the Taitel et al. and Barnea et al. flow pattern map would be possible by assigning a value of 0.33 to its void fraction parameter instead of the original value of 0.25. This work represents an addition to the technology of multiphase behavior in vertical pipes and its results will help in a more accurate design of oil well tubing strings in high-rate producing wells.
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Vertical Lift Models Substantiated by Statfjord Field Data (SPE 154803)
Authors O. Fevang, M.G. Fossmark, K.N. Kulkarni, H.T. Lauritsen and S.M. SkjaevelandThe Statfjord field entered into the blowdown phase after 30 years of production. Production of injection gas and gas liberated from residual oil is the main production target in this phase. In some areas, the gas cap has been produced and the wells are producing mainly water until the solution gas is mobilized. These wells have gone through large changes in GLR and WCT. Production tests from wells located in such areas have been used when analysing the ability of multiphase-flow correlations to model vertical lift performance (VLP). Accurate modelling of the VLP is critical to predict a realistic production rate during the blowdown phase. Measured wellhead (THP) and downhole pressures from 203 production tests, from six wells, were used to analyse the accuracy of VLP correlations at widely varying flow conditions (GLR, WCT, and THP). Altogether 17 partly well-known, multiphase pressure drop correlations incorporated in the program Prosper were tested by comparing observed and calculated downhole pressures. Based on the production tests the ability of the different correlations to predict the VLP varies with the following top 3: Petroleum Experts, Petroleum Experts 2, and Petroleum Experts 3. These correlations are recommended if no measured data is available. In general too low pressure drops were predicted at low gas-liquid ratio (GLR), and too high pressure drops at high GLR. After tuning, accurate predictability was observed for the different correlations for limited ranges in GLR e.g. 50-300 Sm3/Sm3. However, for larger ranges in GLR it was not possible to achieve an accurate VLP correlation even after tuning. The error in the predicted production performance when a single VLP correlation is used can be substantial for highly productive wells with large variations in producing GLR. It is recommended to shift the tuning following the GLR development.
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The Volund Field - Developing a Unique Sand Injection Complex in Offshore Norway (SPE 154912)
Authors A. Townsley, E.W. Jameson and A. SchwabThe Volund Field, in offshore Norway, is unique in being composed entirely of a large-scale sandstone injection complex. It consists of stacked sandstone sills, surrounded by shallower, steeper dipping injected sandstone dykes (>20CB0). The sands are excellent reservoir with consistently high porosity and permeability. Based on seismic, good connectivity was expected within the injectites from the water leg through the oil and into the gas cap. However, pre-production the extent of aquifer support and efficiency of water sweep were unclear. The Early Eocene complex was identified from seismic, which exhibits a Class 3 negative amplitude AVO anomaly. Development drilling began in 2009. The team strove to build a simulation model that allowed rapid generation of multiple realisations to investigate the effects of geological uncertainty on recovery, whilst honouring the AVO data. Geobodies extracted from seismic captured the geometry of the injectite. By populating these core bodies and surrounding C"halosC" with sands of varying properties within a geomodel, a series of realisations were built. Simulation modelling was employed to complete a dynamic uncertainty study and understand the potential effects of connectivity on aquifer and injection support. Drilling of four horizontal production branches and one injector was successfully completed in 2010 giving ~5500m of well control. Production began in April 2010 and 18 months of plateau production have demonstrated good communication. The reservoir benefits from aquifer support, but requires injection to maintain pressures. To date, no water has been produced, suggesting sweeps efficiencies in the upper half of our uncertainty range. This case study presents a modelling method based on seismic attributes which allows very quick generation of realisations that focus variation where there is the most uncertainty. This was key to the successful development of the Volund Field, a unique example of an economically producing sandstone injection complex.
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