bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Parallel Streamline Simulator for Integrated Reservoir Modeling on a Desktop
Authors: Gaupaas Morten , Bratvedt Frode , Khataniar Sanjoy Kumar , Primera Alejandro , Ruan Feng P 
Published: June 2012

Summary
Desktop computing is undergoing a revolution with parallel processing on workstations. Parallel streamline simulators have been developed for shared memory architecture systems. In this paper, we discuss the implementation and performance analysis of a shared memory architecture commercial parallel streamline simulator based on native threading technology for both Windows® and Linux® operating systems.
In general the streamline simulation algorithm is relatively straightforward to parallelize, however, there are several challenges that require special attention in order to avoid computing bottlenecks and inconsistent results. Repeatability of parallel simulation results is a well-known challenge. A data-accumulation scheduling algorithm designed to ensure repeatable results independent of the number of processing units has been implemented. The algorithm is supplemented by an efficient loadbalancing algorithm, to minimize processor idle time.
Parallel scalability for various model characteristics and streamline solver options is analyzed. We have observed almost linear scalability up to 10 threads and a speed up factor of three to seven for simulation runs using a 1D explicit upwind finite difference solver to solve the transport problem along streamlines. The front tracking solver is inherently fast and does not gain significantly from parallelization. The run time of a serial simulation using the front-tracking solver is less than that of a parallel explicit solver run using up to 12 threads. The memory consumption of the front tracker is slightly higher than the explicit solver but overall streamline simulations are very memory efficient, enabling large geo-scale models to be simulated efficiently on 64-bit workstations. Complex three-phase blackoil simulation problems require a larger number of timesteps steps and speedup degrades as run time becomes dependent on the efficiency of the pressure solver. The results produced by our parallel streamline simulator are repeatable for any number of threads, and the algorithm used to achieve repeatability has little impact on performance.
A Versatile Representation of Upscaled Relative Permeability for Field Applications
Authors: Lomeland Frode , Hasanov Bashir , Ebeltoft Einar , Berge Marianne 
Published: June 2012

Abstract
A suitable approach to achieve a fit-for-purpose model for field application is upscaling of reservoir properties. However, upscaling of saturation functions like relative permeability is still a source of debate and is frequently omitted due to its inconvenient complexity. Upscaling of these functions, whether by steady-state methods or other techniques, typically generates a complex myriad of relative permeability curves that is challenging to handle pragmatically. This study investigates whether a three-parameter correlation of relative permeability is able to represent the saturation function for fine grid simulation models with the most common heterogeneities, coarse grid simulation models with upscaled properties in addition to verify two-phase core-flow experiments.
To demonstrate the applicability of two flexible three-parameter correlations at the field simulation scale, we have utilized three synthetic fine-scale models with the most common heterogeneities: a severe thief zone, upward coarsening and downward coarsening. All simulation cases use a down-dip water injector and an up-dip oil producer. Excellent matches are obtained by history matching on the parameters of the coarse grid correlations in all cases.
The flexibility of the correlations will, opposed to the restricted single-parameter Corey (1954) representation, enable a versatile, pragmatic and satisfactory upscaling for coarse grid blocks when used in combination with any well-known upscaling method. The benefit is a limited number of parameter arrays as opposed to numerous rather inconvenient tables. The proposed parametric representation of upscaled relative permeability is applicable to immiscible recovery methods in general.
Implementation of the proposed three-parameter correlations of the relative permeability in the algorithm of full field simulators will overcome the representation challenges of present published upscaling methods.
Upscaling of each coarse grid block individually can then be handled pragmatically, and hence provide fit-for-purpose models for field application.
On Population Diversity Measures of the Evolutionary Algorithms used in History Matching
Authors: Abdollahzadeh Asaad , Reynolds Alan , Christie Mike , Corne David , Williams Glyn , Davies Brian 
Published: June 2012

Abstract
In history matching, the aim is to generate multiple good-enough history-matched models with a limited number of simulations which will be used to efficiently predict reservoir performance. History matching is the process of the conditioning reservoir model to the observation data; 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 algorithm's control parameters result in different levels of diversity. These behaviours vary from explorative to exploitative.
The need to measure population diversity arises from two bases. On the 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 the objective function evaluations in history matching are computationally expensive, algorithms with fewer total number of reservoir simulations in result of a better convergence are much more favourable. Maintaining population'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 reservoir simulation model, PUNQ-S3, as well as on a real North Sea model with multiple wells. We demonstrate that introduced population diversity measures provide efficient criteria for tuning the control parameters of the population-based evolutionary algorithms as well as performance comparison of the different algorithms used in history matching.
Effect of Hot Water Injection on Sandstone Permeability: An Analysis of Experimental Literature
Authors: Rosenbrand Esther , Fabricius Ida Lykke 
Published: June 2012

Abstract
The seasonal imbalance between supply and demand of renewable energy requires temporary storage, which can be achieved by hot water injection in warm aquifers. This requires that the permeability and porosity of the aquifer are not reduced significantly by heating.
We present an overview of published results regarding the effect of temperature on sandstone permeability. These tests are performed with mineral oil, nitrogen gas, distilled water and solutions of NaCl, KCl, CaCl2 as well as brines that contain a mixture of salts. Thirteen sandstone formations, ranging from quartz arenites to formations with a significant fraction of fine particles including clay minerals are investigated. The porosities range from 0.10 to 0.30 and permeabilities span the range from 1 to 1000 md. To compare different rock types, specific surface is determined from permeability and porosity using Kozeny's equation.
Heating causes thermal expansion, which results in porosity reduction if the sandstone is confined. The maximum effect of porosity reduction as a result of thermal expansion on permeability is modelled and compared the change in specific surface that is computed from the reported data. This does not account for all the permeability reductions observed.
Permeablity reduction occurs both when distilled water is the saturating fluid as well as in tests with NaCl, KCl or CaCl2 solutions, however, this is not the case in tests with mineral oil or nitrogen gas. The formation of a filter cake or influx of colloidal particles due to corrosion of the apparatus at elevated temperature causes permeability reduction in a number of investigations. Mobilisation of internal particles, particularly kaolinite particles, is considered a probable mechanism of permeability reduction for the other experiments reviewed here.
The parameters that strongly affect the success of heat storage therefore include the quality of the equipment and particularly the prevention of corrosion, as well as the sandstone lithology and its interaction with the reservoir fluid.
Rock Physics Modeling of CO2 Bearing Reservoir Rocks
Authors: Hossain Zakir 
Published: June 2012

Abstract
CO2 capture and storage (CCS) is a technique to reduce CO2 emission, and CO2 is also used in EOR (enhanced oil recovery). It may increase oil production by 15–25% from an oil field. In this paper we present how to deal with the seismic response due to CO2 injection. To understand the seismic response due to CO2 flooding requires knowledge of the distribution of CO2 in brine, viscous loss due to CO2 and dissolution of CO2 in brine. Furthermore, the basic principle for EOR methods by CO2 is that high solubility of CO2 increases the density and lowers the viscosity at reservoir conditions of the oil, thus improving the oil mobility and the efficiency of water flooding. However, the viscous losses during the fluid flow are responsible for seismic wave attenuation. Moreover, when injecting CO2 into the water-saturated sample, some CO2 may be dissolved in the water. The Gassmann and Reuss or Gassmann and Voigt method may be used to calculate CO2 saturated seismic properties. Considering the significant differences between velocity values in these two methods, a large uncertainty is associated with fluid-saturation estimation from seismic data. I provided the rock physics model to calculate the CO2 saturated seismic properties to understand the seismic response due to the CO2 flooding. This model was tested laboratory measured data of sandstone from Lei and Xueb (2009) and carbonate from Wang et al. 1998. Modeling results provided us the viscous loss and dissolution of CO2 effects to calculate the CO2 saturated seismic properties. This model may be also used to calculate the accurate hydrocarbon production during the EOR method by CO2 injection.
Comparison of Upscaling Methods in a Heterogeneous Carbonate Model
Authors: Kazemi Alireza , Shaikhina Dana , Pickup Gillian , Corbett Patrick 
Published: June 2012

Abstract
Carbonate reservoirs are of great importance, due to their large hydrocarbon reserves. However, their complex structure makes them challenging targets to develop. In order to predict reservoir performance, we need to be able to model the effects of heterogeneity at a variety of scales. In this study, we have constructed a detailed geological model using published data for an outcrop in the San Andres Formation. The resolution of the model is 1.2 m × 0.6 m, much finer than a conventional reservoir simulation model. The aim of this work was to consider various upscaling methods and various modelling methods to understand the current limitations and challenges.
A number of single-phase upscaling methods were tested, including averaging (arithmetic/harmonic), and flow-based upscaling with local and extended boundary conditions. In addition the Well Drive Upscaling (WDU) method, a relatively new method, was applied. In this method a single-phase global simulation is performed with appropriate boundary conditions: high pressure at injection wells, low pressure at producers. The flows are then summed and the pressures averaged in order to calculate the effective transmissibilities between the coarse cells.
The upscaling methods were tested by simulating a waterflood. Cases with single and multiple relative permeabilities were examined. The upscaling factor in each case was 65 by 5. In general, the coarse-scale models gave late breakthrough, and overestimated the recovery. The WDU method was consistently better than the other methods, because it was able to preserve the correct flow between coarse cells. On the contrary, the conventional flow-based methods with local boundary conditions gave poor results, sometimes worse than averaging.
We then applied the WDU method to upscale various carbonate models that had been constructed using the Porosity Derived System approach (PODS). The results of this specific 2D study show that upscaling in a complex carbonate reservoir is feasible, providing a suitable method, such as the WDU method, is applied.
Assisted Seismic History Matching in Different Domains: What Seismic Data Should We Compare?
Authors: Sagitov Ildar , Stephen Karl D. 
Published: June 2012

Abstract
Time-lapse (4D) seismic data can be integrated into history matching by comparing predicted and observed data in various domains. These include the time domain (time traces), seismic attributes, or petro-elastic properties such as acoustic impedance. Each domain requires different modelling methods and assumptions as well as data handling workflows. The aim of this work is to investigate the degree to which the choice of domain influences theoutcome of history matching on the choice of best model and associated uncertainties. Another aspect of history matching is that long simulations often pose an obstacle for an automatic approach. In this study we use appropriately upscaled models manageable in the automatic history matching loop.
We apply manual and assisted seismic history matching to the Schiehallion field. In the assisted approach, the optimization loop is driven by a stochastic algorithm, while the manual workflow is based on a qualitative comparison of 4D seismic maps. By upscaling we obtained an order of magnitude gain in performance. Accurate upscaling was ensured by thorough volume and transmissibility calculation within regions. The parameterisation of the problem is based on a pattern of seismically derived geobodies with specified transmissibility multipliers between the regions. Seismic predictions are made through petro-elastic modelling, 1D convolution, coloured inversion and calculation of different attributes.
We were able to achieve a reasonable match of production and 4D seismic data using coarse scale models in manual and assisted approaches. We observed that the misfit surfaces are different when working in the various seismic domains considered. Use of equivalent domains for observed and predicted data was found to give a more unique misfit response and better result.
Accurate comparison of predicted and observed 4D seismic data in different domains is necessary for tackling non-uniqueness of the inverse problem and hence reducing the uncertainty of field development predictions.
Smart Waterflooding (High Sal/Low Sal) in Carbonate Reservoirs
Authors: Zahid Adeel , Stenby Erling H. , Shapiro Alexander A. 
Published: June 2012

Abstract
In the last decade, high salinity waterflooding has been emerged as a prospective EOR method for chalk reservoirs. Most recently, Saudi Aramco reported significant increase in oil recovery by low salinity waterflooding in Saudi Arabian carbonate reservoirs. Understanding of the mechanisms leading to an increase in oil recovery in both smart waterflooding processes (low and high salinity waterflooding) is still not clear. In this paper, we investigate experimentally the recovery mechanisms for both methods.
To understand high salinity waterflooding process, we studied crude oil/seawater ions interaction at different temperatures, pressures and sulfate ion concentrations. For low salinity waterflooding, flooding experiments were carried out initially with the seawater, and afterwards the contribution to oil recovery was evaluated by sequential injection of various diluted versions of the seawater.
Our results show that sulfate ions may help decrease the crude oil viscosity when high salinity brine is contacted with oil under high temperature and pressure. We have also observed formation of an emulsion phase between high salinity brine and oil with the increase in sulfate ion concentration at high temperature and pressure. We propose that the decrease in viscosity and formation of an emulsion phase could be the possible reasons for the observed increase in oil recovery with sulfate ions at high temperature in chalk reservoirs, besides the mechanism of the rock wettability alteration, which has been reported in most previous studies.
No low salinity effect was observed for the reservoir carbonate core plug at the room temperature. On the contrary, a significant increase in oil recovery was observed under low salinity flooding of the reservoir carbonate core plugs at 90 °C. NMR measurements indicated that low salinity brines did not significantly change the surface relaxation of the carbonate rocks.
Migration of fines, dissolution and destruction of rock particles are possible mechanisms of oil recovery increment with low salinity brines from carbonate core plugs at 90 °C. At the present stage, the mechanisms behind increment in oil recovery under various conditions appear to be different.
Optimization of Proactive Control Valves of Producer and Injector Intelligent Wells under Economic Uncertainty
Authors: Sampaio M. A. , Barreto C. E. , Schiozer D. J. 
Published: June 2012

Abstract
Intelligent wells can improve oil recovery, mitigate risks and avoid unnecessary well intervention in petroleum fields. However, there is no consolidated methodology to evaluate the applicability of intelligent wells and to represent them in commercial simulators, which complicates the comparison with conventional wells. Moreover, there are two main modes of operation of intelligent well valves, reactive and proactive; each one can provide different benefits. In general, proactive control seeks maximum oil recovery, but it requires larger computational effort and greater knowledge of the reservoir than the reactive control. This paper presents a comparison between different configurations of intelligent wells with proactive control and mode operation on/off: (1) five-spot configuration with conventional wells (producer and injectors), (2) one intelligent producer and four conventional injectors, (3) one conventional producer and four intelligent injectors and (4) one intelligent producer and four intelligent injectors, in order to compare the different behaviors. The objective of this study is to evaluate the potential of proactive operation for each type of configuration and the benefits of the intelligent injectors and producer acting separately or together, considering the effects on production and costs of intelligent completion. For this, a genetic algorithm was coupled to a commercial simulator to optimize the proactive control and to search the maximum net present value (NPV), determining the optimum operation control for each valve. The case study consists of one heterogeneous reservoir model, light oil and three economic scenarios (pessimistic, probable and optimistic). Results show that the use of intelligent injector and producer wells together, in this case study, can increase of oil production and decrease of water production, although it may not be the most advantageous alternative because of the higher investment. On the other hand, the configuration using only an intelligent producer well (lower investment) is capable of increasing oil recovery sufficiently, therefore making the best investment with intelligent completion, in this case study.
An Engineering Approach to Utilize Fiber Optics Telemetry Enabled Coiled Tubing (ACTive Technology) in Well Testing and Sand Stone Matrix Stimulation - First Time in the World
Authors: Shaheen Tarek , El Rahman Sayed Abd , Anwar Emad , Dilling Lambert , Noya Vidal 
Published: June 2012

Abstract
For the last several years, viscous pills, polymer based, were used to kill the wells during the workover operation in the tronian formation existing in the eastern desert of Egypt. These polymer pills have negatively affected the wells productivity by blocking the pore throats and reducing the permeability. As an example, the well A-1 was producing 300 bpd (Gross) which declined dramatically after a workover operation which included the viscous polymer pills to produce only 20 bopd.
An engineering study was carried out to identify the main reason for the decline in the production. Several experiments were performed in the lab in order to simulate the filter cake using formation samples and evaluate the effect of the polymer being injected on the sandface permeability. An engineered solution was designed to break the polymer subsequently pumped in the formation and stimulate the matrix in order to recover and enhance the oil production. The remedial work was executed using a Fiber Optics Telemetry Enabled Coiled Tubing (FOTECT) system to optimize the treatment leveraging on downhole real time measurements.
This paper describes the first application of FOTECT in sandstone formations, involving:
The sandstone matrix stimulation operation. Measuring both bottom hole pressure and temperatures at static and dynamic conditions during the entire operation. Accurate depth correlation to achieve optimum placement of the treatment fluids Monitor the chemical reactions in real time of the engineered treatment fluid. Monitor the diversion performance during Sand Stone stimulations and the timing required for efficient reactions. Qualitative production allocation of the interval as a response to the treatment fluids Evaluation of the skin value real-time while executing matrix stimulation. Pressure transient analysis in real-time enabling the standard output of a well test (permeability, skin, Pressure, and reservoir boundaries).
The experience demonstrates that use of real-time downhole measurements during the CT treatment allows: a) the evaluation of the well performance before and after the treatment, b) enables optimization of the treatment as it is executed, based on the formation response, enhancing the chance for a successful intervention, and c) provides an added alternative to perform a well testing operation right after the treatment, thus, obtaining valuable information to update the reservoir model.