bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrated Modeling for Assisted History Matching and Production Forecasting of Low Salinity Waterflooding
Authors: Dang Cuong , Nghiem Long , Nguyen Ngoc , Chen Zhangxing , Yang Chaodong 
Published: April 2016

Summary
From a technical point of view, the success or failure of LSW (low salinity waterflooding) projects strongly depends on reservoir geology; however, this has not been systematically evaluated in the past and the effects of clay minerals are often neglected in conventional reservoir simulation. This paper presents one of the first studies on integrated modeling, assisted history matching (HM) and production forecasting of field-scale LSW.
To handle this complex recovery process, we used a comprehensive ion-exchange model, fully coupled with geochemistry specially designed for the modeling of LSW physical phenomena in an EOS reservoir simulator. The model is capable of accounting for the critical role of the properties, quantity, and distributions of clay minerals. We developed an integrated modeling approach that involves the combination of geological software, a reservoir simulator, and a robust optimizer in a big-loop workflow for sensitivity analysis, HM, optimization, and uncertainty assessment. The numerical simulation results indicate that LSW's performance depends critically on the reservoir geological characteristics. Multiple geological realizations can be automatically generated from the big-loop approach that are needed for fast and accurate HM and optimization of LSW. In sandstone reservoirs, clay content varies across regions, resulting in differences in ion-exchange capacity and weights of the relative permeability modification. We introduce the scaled-equivalent-fraction ion exchange which is associated with the calculated Cation-Exchange-Capacity function; the wettability alteration will be shifted based on both the ion exchange and the clay content in each grid block.
The key parameters for successful field-scale LSW HM include: clay distribution/quantity associated with different facies, relative permeability modification, wettability alteration thresholds, reservoir minerals, geochemical reactions, and operating conditions. Finally, LSW HM by tuning reservoir parameters only may lead to poor prediction results, while the integrated modeling approach provides much better forecasting results to the true history data.
The work presented in this paper contributes to an understanding of the critical roles of reservoir geology on the field-scale LSW performance, in particular, for substantially reducing HM errors, accurately predicting the future production, maximizing oil recovery and minimizing the risks of LSW implementation.
Maximizing Mature Field Production - A Novel Approach to Screening Mature Fields Revitalization Options
Authors: O'Brien Jeremy , Sayavedra Leopoldo , Mogollon Jose Luis , Lokhandwala Taher , Lakani Ramin 
Published: April 2016

Abstract
The industry is undergoing a transformational change, driven by increases in exploration and development costs in the last decade, combined with falling oil prices in recent months. As a result, there is an increased interest in squeezing more from mature assets. The general message is that a 1% increase in recovery factor could result in two additional years of global oil and gas supply; however, industry experts know how difficult it is to increase recovery from mature fields. This paper presents a novel screening method that enables a large number of scenarios to be considered and facilitates convergence on potential solutions.
By 2018, 70% of global oil production (more than 80 million B/D) is projected to come from mature fields (Fig. 1). Some major exploration and production (E&P) operators already have more than 70% of their portfolios in production decline. This global trend, combined with the pressure to reduce the cost per BOE resulting from declining oil prices, has pushed E&P operators to place a renewed emphasis on mature fields. This paper presents an integrated approach to revitalizing mature fields and addresses this new reality by focusing on three key areas: immediate impact solutions, reservoir optimization, and new pay.
The first step in this process is a screening and ranking method for mature field revitalization choices, which enables feasible options to be identified at an early stage, thus avoiding wasted time and money pursuing unfeasible and/or uneconomic options. A common challenge for the operators of mature assets is filtering the vast array of issues and potential solutions. This unique screening method leverages a global reservoir analog screening database combined with technical and economic modeling techniques to help ensure that the optimum revitalization strategy for the reservoir is achieved. In many cases, the proposed solutions may be technically interesting, but very expensive or operationally not feasible.
This paper explains how the proposed revitalization plans must be combined with a fully integrated end-to-end solution, from planning, design, and simulation to field implementation. Case studies are shared to demonstrate how this integrated approach, linking concept to implementation, can avoid expensive iterations and help to enable mature field production uplift.
Numerical Simulation of Natural Gas Flow in Shale Reservoirs with Thermodynamic Equation of State: A Comparative Study
Authors: Negara Ardiansyah , Elgassier Mokhtar , Saad Bilal 
Published: April 2016

Abstract
Production from unconventional reservoirs like shale gas has increased considerably in the past few years due to the advancement in twofold, i.e., horizontal drilling and hydraulic fracturing technologies. Although there has been some success in increasing gas production from shale reservoirs, unfortunately, the physicochemical processes that take place in the shale formations remain challenging and are not completely understood. Unlike conventional reservoirs, shale reservoirs are characterized by very small porosity and extremely low-permeability. Gas flow in this tight formation involves complex flow processes such as Knudsen diffusion, Klinkenberg effect, adsorption and desorption, strong rock-fluid interaction, rock deformation, etc. Furthermore, because of high pressure and high temperature reservoir conditions the gas behaves as real gas. In this work, our shale gas mathematical model is built based on the dual-porosity dual-permeability model that incorporates the complex flow processes mentioned above as well as the thermodynamic calculations. Peng-Robinson equation of state (PR-EOS) was used to calculate the gas density and compressibility factor by solving the cubic equation. In the numerical method implementation we combine the finite difference method with the experimenting pressure field approach to solve the pressure equations for the matrix and fracture systems in the dual-porosity dual-permeability model. This combination greatly reduces the computational cost when solving the large systems of pressure equations of the matrix and fracture. In this approach, a set of predefined pressure fields is generated in the solution domain such that the undetermined coefficients are calculated from these pressure fields. In the numerical example, we considered a shale reservoir with single production well. Comparison between real gas and ideal gas is studied and the result shows that considering the real gas behavior generates higher cumulative production, which implies that the gas transport capacity is higher than the ideal gas case. The result also indicates that considering real gas behavior in the model would increase the production and retard the decline curve. Therefore, it is very important to incorporate the real gas behavior into the model in order to be able to forecast the production accurately.
Simulation of Complex Composite EOR Processes at Lab and Field Scale
Authors: Pettersen Øystein , Skauge Arne 
Published: April 2016

Abstract
Experiments on injection of composite EOR fluids, simultaneously or sequentially, have been validated by small scale simulation, with cell sizes in the millimeter-range. The injected fluids have been a combination of low-salinity brine, surfactant, and polymer. This presentation addresses the challenges of extending the lab scale results to larger models, up to field size.
The complex injection scheme itself is not straightforward to model in any simulator, and novel techniques have been developed to handle this. The main mechanisms that must be addressed are concentration dependent properties for all fluids involved and any combination of these, e.g. relative permeability and viscosity. The methods used have been adapted to both a black oil simulator, and a composition based simulator. As the basic modeling principles for black oil and compositional simulators are per se very different, the way of handling fluid descriptions from the user view point are naturally quite different for the two approaches. Hence also adaption to the composite processes necessarily differs.
History matching (validating) experiments at lab scale was successfully done with both simulators, with qualitative equal though not identical results. When attempting to generalize results to larger models, two issues have been addressed; extension, where the size of the simulation model was increased without changing the grid resolution (cell size), and upscaling, where model size was unchanged while grid cell sizes were increased. Ideally, simulated results should be identical at different scales and grid resolutions, at least within standard grid resolution errors. Both simulators were well-behaved with respect to upscaling, while the compositional simulator handled extension better than the black oil simulator. Moreover, the black oil simulator was found to be very sensitive to smoothness of relative permeability curves. As example, using a relative permeability curve that was determined by history matching of a lab experiment was not successful.
One magnitude that had to be focused on was simulated pressure. Simulated injection pressure and resulting average pressure during polymer injection was not in agreement with field observations, probably because the simulators do not include all the complex mechanisms of polymer flood. Hence maintaining reservoir pressure within a reasonable range during simulation turned out to be a challenge, especially for the black oil simulations.
In conclusion it was found that with the appropriate approach, robust and reliable results could be obtained at scales less than some critical value, consistent with similar results obtained for pure water flood simulations. Compositional simulations were apparently more reliably scaled than black oil simulations. An important finding was that results were extremely sensitive to correct and consistent definition of fluid descriptions, and users must be aware of different approach angles for compositional and black oil simulators in this respect.
Comparing Different Scenarios for Thermal Enhanced Oil Recovery in Fractured Reservoirs Using Hybrid (Solar-Gas) Steam Generators, A Simulation Study
Authors: Yegane Mohsen Mirzaie , Bashtani Farzad , Tahmasebi Ali , Ayatollahi Shahab , Al-wahaibi Yahya Mansoor 
Published: April 2016

Abstract
The application of the renewable energy sources, especially solar energy, for thermal enhanced oil recovery methods as an economical and environmental valuable technique has received many attractions recently. Concentrated Solar Power systems are capable of producing substantial quantities of steam by means of focused sunlight as the heat source for steam generation. This paper aims to investigate viability of using this innovative technology in fractured reservoirs to generate steam instead of using conventional steam generators.
A synthetic fractured reservoir with properties similar to those of giant carbonate oil reserves in the Middle East was designed by using commercial thermal simulator. The dual porosity model was used to account for differences in matrix and fracture parameters. Different cyclic and continuous steam injection scenarios using combination of both solar energy and fossil-fuel to generate steam were designed. The cyclic scenarios were different in terms of contribution of solar energy in steam generation and in case of 100% solar scenario a small nightly steam injection using fossil-fuel was suggested to prevent flow back into the wellbore.
It was assumed that total amount of injected steam in 10 year time period is the same for all the scenarios regardless of how steam was generated. Simulation results showed that nightly injection of insignificant amount of fossil-fuel-generated-steam in a 100% solar-generated-steam injection process increases the cumulative oil production compared to 100% solar-generated-steam injection system with no nightly injection. Furthermore, there was no significant difference between the final oil recoveries for all the designed cyclic injection scenarios. Although continuous steam injection scenario had the highest final oil recovery among all scenarios, a detailed economical study showed that net present value for 100% solar-generated-steam scenario is the highest. An environmental analysis on all scenarios also indicated significant reduction of CO2 emission into the atmosphere for the latter scenario.
Therefore, hybrid steam generators which utilize solar energy instead of traditional fossil-fuel for steam generation is proposed for Middle East fractured reservoirs where there is abundance of sunshine during day time. The findings illustrate high economic efficiency of solar-generated steam injection and highlight it as a green EOR method.
Theoretical Analysis and Experimental Research of Channel Fracturing in Unconventional Reservoir
Authors: Hou Tengfei , Zhang Shicheng , Yu Baihui , Lv Xinrun , Zhang Jingchen , Han Jingyu , Li Dong 
Published: April 2016

Abstract
Channel fracturing, which greatly increase fracture conductivity by the creation of open channels inside fracture, has proved to be a novel stimulation technology that widely used in unconventional reservoir. The objective of this paper is to study the stimulation mechanism of channel fracturing by the combination of theoretical analysis and experimental research. However, for channel fracturing scenario, the currently available models are not accurate and appropriate in terms of prediction of proppant embedment and fracture conductivity in channel fracturing.
In this paper, new analytical models are derived to compute the proppant embedment, proppant deformation and fracture conductivity in channel fracturing. The mass deformation model and creeping deformation model are adopted to predict the change of proppant embedment and fracture conductivity over time. Many factors affecting the results of proppant embedment and conductivity, including closure pressure, elastic-plastic properties, properties of viscoelastic proppant and rock are investigated. Experimental researches are also conducted to evaluate conductivity at different closure pressures for the fractures of steel plate, shale and sandstone. Besides, the proppant embedment and proppant deformation are measured through the proppant embedment testing instrument, and the proppant distribution before and after experiments are comparatively analyzed.
The results show that the new analytical model proposed fits well with the experimental data, which verifies the accuracy and the feasibility of this model, though the decline rate of experimental data is a little bit faster than that of the model. The fracture conductivity is directly proportional to proppant viscosity, elastic modulus of proppant and inversely proportional to closure pressure, while elastic modulus of rock and large value of formation rock viscosity have slight impact on fracture conductivity. Moreover, the steady state of conductivity has been studied, and Comparisons between channel fracturing and conventional fracturing are analyzed in several aspects. The experimental results also reveal that the overall dimensions of created open channel may decrease or disappear due to the forced of formation stress.
Technical innovations in this paper are (a) new analytical models, including the mass deformation model and creeping deformation model, are adopted to predict the change of proppant embedment and fracture conductivity (b) Experimental tests are also performed to measure conductivity and proppant embedment at different closure pressures. This paper can demonstrate its own merits to show the advantage of channel fracturing technology.
Verification Of Geological Models With One Single Simulation Run
Authors: Mittermeir Georg M. , Steiner Christoph , Gharsalla Mohamed M. , Heinemann Zoltán E. 
Published: April 2016

Abstract
This work suggests a paradigm change. Instead of history matching an (upscaled) geological model by the reservoir engineer focusing on matching the dynamic data. The model builder should be equipped with the right tools to identify areas where the geological model cannot fulfill the dynamic requirements. The target is to make history matching obsolete. Every modification of the model must have its geological reasoning and justification. Introducing artifacts for the sole target of matching dynamic data is depreciated. Often such models lack forecasting credibility. Especially selecting infill drilling locations becomes highly uncertain. This paper presents applicable and ready to use methods which will be demonstrated on a full-field project.
There are two key elements, each to be fulfilled during every timestep. At first the average (region) pressures must fit and second each well must be allowed to search for the required phases to satisfy its production targets. The first requires at least one region for which the historic pressure decline is known. At the delineation towards an outer aquifer water will be automatically injected/withdrawn to match the pressure history. The second is realized by perforations (well-grid-connections) which are allowed to move away from the well's trajectory and to search for the required phases within a user or algorithm defined drainage area. There is just one restriction. Drainage areas must not overlap. In case the drainage area does not contain the necessary fluids the geological model has to be revised. At the same time important information about fluid movements are gathered.
The promoted concept was successfully applied to a North African naturally fractured carbonate reservoir having more than 500 MMstb original oil in place and a 35-years production history. The reservoir was divided into eight pressure regions. Five were selected as target for the automatic pressure match, the remaining three were control regions. Two update cycles were performed. During the first cycle the structure was corrected. Thus the phase distribution was affected so that all drainage areas could produce the required historic rates. During the second cycle local adjustments in porevolume and communication across faults were performed to increase the pressure match of the control regions. The demonstrated workflow has the potential to revolutionize the commonly practiced reservoir model creation.
Up to now no similar workflow allowing to assess the geological model quality within one single simulation run was published. It is unique that pressure and production targets can be met in each timestep without corrupting the underlying geological model. Contrary the modeler is provided with the required information where and how to improve the geological model.
Experimental and Numerical Studies of First Contact Miscible Injection in a Quarter Five Spot Pattern
Authors: Djabbarov Sultan , Jones Alistair D , Krevor Samuel , Muggeridge Ann H. 
Published: April 2016

Abstract
We quantify the impact of mobility, simple heterogeneities and grid orientation error on the performance of first contact miscible gas flooding in a quarter five spot configuration by comparing the outputs from experimental and numerical models. The aim is to quantify the errors that may arise during simulation and to identify a workflow for minimizing these when conducting field scale fingering studies.
A commercial reservoir simulator was validated by comparing its predictions with the results obtained from physical experiments. An uncorrelated, random permeability distribution was used to trigger fingering in the simulations. The physical experiments were carried out using a Hele-Shaw cell (40×40cm) designed and constructed for this study. The impact of a square low permeability inclusion (20×20cm) on flow was investigated by varying its permeability, location and orientation.
For lower mobility ratios (M=2 to M=10) the commercial numerical simulator was able to reproduce the experimental observations within the uncertainty range of the permeability distribution used to trigger the fingers, provided a nine-point scheme was used for the pressure solution. At higher mobility ratios (M=20 to M=100) the grid orientation effect meant that the simulator overestimated the areal sweep even when a nine-point scheme was used. The introduction of a square, low permeability inclusion near the injection well reduced the discrepancy between experimental and numerical results, bringing it back within uncertainty limits in some of the cases. This was mainly because the real flow was then forced to move parallel to the edges of the Hele-Shaw cell and thus parallel to the simulation grid. Breakthrough times were well predicted by the numerical simulator at all mobility ratios.
Gas Flow Transport in Shale Matrix: Simultaneous Effects of Stress and Slippage on Matrix Permeability
Authors: Moghaddam R. Nazari , Jamiolahmady M. 
Published: April 2016

Abstract
Gas flow modelling in shale and tight gas reservoirs is still challenging mainly due to different pore-scale flow regimes present in micro- and nano-pores of these reservoirs. The effect of geomechanical stress also significantly affect the measurement and prediction of apparent matrix permeability. In this study, series of experiments were designed and performed on three shale samples to study the simultaneous effects of slippage and stress at five different pore pressures and four net stresses. The experimental data were used to obtain a general slip plot, which quantifies the effect of slippage on matrix permeability. Then, the stress effect was taken into account by modifying the average pore size and non-slip permeability at each net stress based on the experimental observations. It is found that the matrix non-slip permeability and average pore size follow an exponential behaviour when changing the net stress. These two relationships are then proposed to be incorporated into the corresponding slip flow model in order to capture the effects of slippage and stress at the same time. The validity of the proposed model was also investigated (using published data in the literature), which shows that the proposed technique is able to capture the intensity of permeability reduction and enhancement due to stress and slippage, respectively. The outcomes of this study increase our knowledge of rarefied flow dynamic inside micro- and nano-pores under confining stress, which is necessary for accurate predictions of the apparent matrix permeability in unconventional reservoirs.