bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Comprehensive Approach for History Matching A Giant and Complex Oil Reservoir
Authors: Aissaoui Karim , Moreno Manuel 
Published: September 2013

Abstract
History matching complex reservoirs with hundreds of active wells over decades of production history may reveal to be tedious and complex given the amount of data to be honoured, the level of uncertainty as well as software and hardware requirements. This paper aims at sharing ADCO's experience in achieving a satisfactory match quality on a giant carbonate oil reservoir in Middle East. The approach encompasses manual as well as assisted history matching techniques in a two way communication leading to consistent reservoir images that honour all observed data and mitigate any potential pitfalls which may lead to geologically unrealistic solutions.
Main outputs enabled a better understanding of key influencing reservoir uncertainties that can improve the match quality as well as identifying a few alternative reservoir images that can replicate the observed data both at well and full field level, in addition to an impact assessment on production forecasting uncertainty. Furthermore key remaining uncertainties were pin-pointed so that they can be acted upon.
The reservoir model history matching was undertaken on a single deterministic geological realisation via manual history matching to start with, and then assisted history matching was introduced as a way to rank uncertainty parameters based on their impact on match quality and to provide some directionality for history matching improvement. Moreover, the approach enabled identifying alternative equally history matched reservoir models.
Given the high number of mis-match parameters to satisfy both at reservoir and well levels and the number of reservoir uncertainties to be tested, a structured (staged) assisted history matching approach was implemented. A physically-sound and proper set of parameters with realistic ranges have been considered at each stage of the history-match process in a logical order.
Ranges of selected parameters were designed in a way that satisfactory solutions at each stage can be carried over to the next stage to continue the history-match. This process started with the Latin Hypercube technique as a browsing phase to assess uncertainty impact on response parameters and then discard those with no impact on match quality. The next step evolved proxy modelling - a mathematically / statistically defined functions based on existing realisations that replicated the simulation model outputs for selected input parameters. This helped reducing time required to get the solution to converge. Afterwards, sequential adjustments have been implemented from global then flow units, followed by local changes in model properties using Evolutionary Strategy algorithm. During each stage of this process the "heavy-hitters" with the highest impact on the history-match process were identified and thouroughly investigated.
A Multiple-Continuum Model for Simulation of Gas Production from Shale Gas Reservoirs
Authors: Li Ning , Ran Qiquan , Li Jianfang , Yuan Jiangru , Wang Cong , Wu Yu-Shu 
Published: September 2013

Abstract
Gas production from unconventional shale gas reservoirs is controlled by multi-scaled fractures, i.e., hydraulic fractures, natural fracture, micro fractures, etc., as flow pathways. On the other hand, shale matrix provides the majority of shale gas storage of both free and adsorbed gas. In addition, field data show that there exists significant amount of micro fractures within low-permeable shale matrix and these micro fractures may connect to large, global-connected fracture network. However, these micro fractures have been either ignored or lumped into the "matrix block" in the current simulation models. In this paper, we present a physically based multiple-continuum concept to include both natural and micro fractures as well as low-permeability shale matrix. The multiple-continuum conceptual model implemented considers shale gas rock consisting of (1) globally connected natural fractures, (2) micro fractures locally connected between matrix and/or kerogen to global fractures, and (3) low-permeability shale rock matrix. Similar to the classic double-porosity concept, the global fracture continuum is responsible for global gas flow to hydraulic fractures or wells, while low-permeability shale matrix, providing main storage space, is locally connected to micro-fractures and interacting with globally connecting fractures. In addition, our model formulation also includes the following processes: (1) nonlinear adsorption/desorption effect, (2) Klinkenberg effect, (3) non-Darcy flow (at high flow rate and low flow rate), and (4) pressure-sensitive rock deformation. We use a hybrid modeling approach to describe different types of fractures, including hydraulic fractures, natural fracture network, and micro fractures. We will demonstrate model application to quantify flow behavior in fractured shale gas reservoirs.
Investigation of Optimum Salinity of Injected Water in Carbonate Reservoirs using Wettability Measurement and Core Flooding
Authors: Sharifi Mohammad , Shaikh Murtdha 
Published: September 2013

Abstract
Waterflooding is the most popular secondary oil recovery method. Attempts were made to increase the sweep efficiency of waterflooding by focusing on various physical and chemical aspects of this process. Low salinity waterflooding was an important research topic in recent years, with a focus on the possible effect of various compositions of injected fluid on oil recovery. In this study, the effect of the salinity level on oil recovery in a limestone reservoir was investigated. The methodology utilized multiple limestone core samples. After x-ray analysis, four samples with high calcite content (more than 98% calcite) were used in flooding experiments and the impact of the salinity level on oil recovery was measured.
This study is a continuation of a project at The University of Tulsa (Al Shaikh, 2012). The design of the coreflooding study was constructed base on the contact angle measurement results of the wettability study. The Tagochi method was used to design wettability measurement experiments that span varieties of salinity combinations. The current study showed that coreflooding recovery has a clear relationship with the contact angle measurement of calcite plate. We showed that contact angle values are better indicators for choosing optimum injected water composition in compare to the salinity level. Sequential injection of water with the lower measured contact angles led to the highest recovery. This relationship is not necessarily valid for the salinity level because our wettability experiments show that there is no direct relationship between the measured contact angle and the salinity level of water.
During this experiment, incremental oil recovery from 12 to 18 percentages was reported. This shows the high potential of success for this method. We showed that Tagochi method is an effective way to design an experiment for measuring the contact angle and finding the optimum level of salinity. Similar experiments are required before applying this method to the field. In practice, there is an optimum salinity beyond which purifying the brine water further will not lead to incremental oil recovery. Finding the optimum salinity scenario is essential for increasing recovery with minimum cost.
High-Resolution Numerical Simulations of Capillary Trapping for Carbon Dioxide in Fractured Formations
Authors: Annewandter R. , Main I. , Geiger S. 
Published: September 2013

Abstract
CO2 injection is one of the most common forms of enhanced oil recovery. It also allows us to sequester greenhouse gases in the subsurface. CO2 injection is currently considered for many clastic and carbonate reservoirs. The latter reservoirs often contain fractures, therefore quantification of sweep efficiency and CO2 trapping in fractured formations is of critical importance to design appropriate CO2 injection schemes for carbonate reservoirs.
Discrete fracture and matrix (DFM) simulations have emerged as a powerful technology to analyse the fundamental flow and transport properties in naturally fractured reservoirs and bridge gaps between geosciences and reservoir engineering: they help to validate upscaling workflows, improve the analysis of pressure transients from well-tests, and allow to explore how uncertainties in fracture network properties impact hydrocarbon recovery. The key difference between DFM simulations and traditional dual-porosity approaches is that the structurally complex fracture geometries are explicitly discretised as 2D surfaces in a 3D reservoir model, which hence comprises a geologically realistic representation of the fracture patterns and rock matrix.
Here we extend the DFM simulation workflow to account for capillary trapping of CO2 in fractured media. Fluid flow is described by a fully compositional model including an equation of state for CO2-H2O-NaCl fluids. The governing equations are discretised in space using unstructured and mixed-dimensional finite element - finite volume techniques. We demonstrate how our new DFM approach can be applied to simulate CO2 injection and trapping of CO2 in fractured geological formations with geologically realistic fracture networks. We show how matrix diffusion and capillary forces influence the rate at which CO2 is trapped in the rock matrix and discuss how this trapping could be modelled more accurately in conventional reservoir simulators.
Fast-Track Modeling Approach: An Alternative Workflow for Reservoir Simulation Modeling
Authors: Al-Jenaibi Faisal , Lacroix Sebastien , Meziani Said , Bugio Shamsudin , Ben Salem Ryadh 
Published: September 2013

Abstract
The oil and gas industry has a long history of model construction relying on the integration on multiple disciplines including seismic, sedimentology, geology and petrophysics. It is undeniable that all steps are required to lead to a good characterization of the studied reservoir and to provide reliable and realistic predictions. However the necessary time to finalize each step often leads to a modeling process of several years. This paper therefore discusses an alternative workflow, or Fast-Track modeling approach, which allows generating a representative and matched reservoir model in a considerably reduced time. This approach consists in: Using in-house technology for porosity/permeability prediction and property population.Introducing a new capillary pressure design and dynamic rock-typing concept.Using automated history matching tools to fine tune the match at the well level.
This workflow ensures achieving a better petrophysical properties consistency between logs, cores and models, a more representative asset volume estimates and also prevents utilization of non-measured parameters such as irreducible water saturation (Swc's) or unproven and extensive permeability multipliers. This altogether contributes in reducing convergences problems as well as providing more consistent dynamic model setup.
This workflow was applied on a complex offshore reservoir consisting of a large gas cap and significant oil rim. The results and achievements are presented within this paper and demonstrate the suitability of this workflow as a short term alternative and shortcut to complex simulation modeling, in waiting of all adequate studies to be completed and integrated in a detailed reservoir model.
Improved Reservoir Surveillance through Injected Tracers in a Saudi Arabian Oil Field: Case Study
Authors: Ali Almosa Muhanad , Zaberi Husain , Huseby O. 
Published: September 2013

Abstract
High-quality reservoir characterization, improved reservoir dynamics, optimized water flooding and better understanding of fluid movements are some key factors for successful reservoir management. Interwell tracer test (IWTT) technology has been recognized as an efficient tool to determine fluid pathways between wells and evaluate areal water breakthrough between injectors and producers, along with estimating the velocities at which the injected water is breaking through, and these can be integrated in the geological and reservoir models of the field to reduce uncertainties attributed to fluid flow mechanism and interwell communication.
This paper presents a case study of IWTT technology application in a heterogeneous reservoir in a Saudi Arabian oil field and shows how this characterization tool was utilized to investigate the reservoir flow mechanism; and how the derived information facilitated a better reservoir management through improved reservoir monitoring and enhanced understanding of reservoir fluid dynamics. The project commenced in November 2007 through injecting unique chemical tracers into a set of injectors to effectively monitor injected fluid movement in the reservoir, after which tracers were continuously monitored through yearly sampling programs by collecting samples from adjacent oil producers.
The results of the project will be showcased on how it has provided valuable insights through identifying interwell pathways, estimating velocities at which tracers are traveling and optimizing water injection volumes. These findings were translated in optimized reservoir management, resulting in a tangible impact of the offset wells’ productivity and sustainability.
Optimisation of Smart Well Completion Design in the Presence of Uncertainty
Authors: Ghosh Baijayanta , King Peter 
Published: September 2013

Abstract
Intelligent/smart completions are widely used to maximize the value of production wells through higher ultimate hydrocarbon recoveries, to promote better clean-up of unconventional wells during ‘flow-back’ and to improve sweep efficiency in case of injector wells. To maximize the economic value of these applications, especially in the presence of uncertainties (geological, reservoir and long term tool reliability) and minimize the economic risk it's vital to optimise the placement and operational settings of the Interval Control Devices (ICDs)/AICDs (Autonomous Inflow Control Devices)/Interval Control Valves (ICVs). The requirement for optimisation could also arise from the limitation imposed by present technology on the maximum number of valves deployable in a single completion string.
In this paper an optimisation routine for determining the optimal placement of Interval Control Valves (ICVs), and their inflow settings is presented. The overall optimisation scheme uses the simulated annealing algorithm in conjunction with a commercial reservoir simulator to maximize an objective function that captures the mean and variance in the well's estimated value. Multiple geostatistical realizations are used to incorporate the element of geological/reservoir uncertainty in the optimisation process. The workflow also accounts for the risk of flow control valve failure. A brief description of the screening methodology (to choose the appropriate inflow control technology) and a decision analysis framework for deploying intelligent completion technology, based on utility theory, is also presented herein.
The optimisation technique was applied to cooptimise the positions and flow cross-section areas of the ICVs in a horizontal well, completed in an oil reservoir using a composite objective function. Geologic/reservoir and valve-life uncertainties were incorporated in the routine. The improvement in the well's Net Present Value (which is between 55–70% for the cases investigated) obtained through the employment of this technique, is also illustrated. An instance of the decision analysis is carried out to exhibit the suitability of intelligent completions deployment in the given well.
Multilevel Preconditioners for a New Generation Reservoir Simulator
Authors: Wu Shuhong , Xu Jinchao , Zhang Chen-Song , Li Qiaoyun , Wang Baohua , Li Xiaobo , Li Hua 
Published: September 2013

Abstract
As a result of the interplay between advances in computer hardware, software, and algorithms, we are now in a new era of large-scale simulation. Fine-scale reservoir simulations focus on fine reservoir characterization, accurate flow description, efficient nonlinear and linear solvers, and parallel implementation. In this paper, we discuss a multilevel preconditioner in the new-generation simulator HiSim developed by RIPED, PetroChina. This preconditioner relies on the method of subspace corrections (MSC) to solve large-scale linear systems arising from fully implicit methods in reservoir simulations. Unlike traditional purely algebraic methods, the proposed preconditioner takes into account some of the properties of pressure, saturation, and implicit well variables. We investigate the efficiency and robustness of the proposed method by applying it to a million-cell benchmark problems, and a real-world matured reservoir with high heterogeneity, high water-cut, geological faults, and complex well scheduling. The numerical results indicate that the proposed method is robust with respect to the heterogeneity, anisotropy, and number of wells.
Integrated Workflow Towards Characterizing Hydraulic Fractures in Tight Gas Reservoirs-Modeling, Uncertainty Analysis, History Matching & Production Forecasting
Authors: Thomas Tony , Belova Natela , Goloborodko Andrey 
Published: September 2013

Abstract
This paper details real field case of an integrated approach followed in near wellbore modeling with the aim of characterizing hydraulic fractures in tight gas reservoirs. Uncertainties in the geology, inability to draw conclusions from data obtained and how to effectively integrate data from different sources (cores, logs, geological model, well test & production data) were the challenges.
The steps taken to overcome these challenges and addressing the uncertainty, using both analytical and numerical modeling, resulting in improved well and reservoir characterization, is presented in this paper.
The work done and outlined in this paper provides an integrated workflow for fracture modeling and performance prediction through a probabilistic approach.
The work involves: –Analyzing and incorporating the data and their uncertainty from varied sources.–Generating multiple realizations of the static model.–Selection of the appropriate static model based on an error function.–Near wellbore modeling to account for hydraulic fracture.–Probabilistic Model validation by replicating the well testing sequence.
This integrated workflow provided enhanced fracture characterization and performance prediction while incorporating the impacts of uncertainty. Reservoir structure and depositional environment understanding were improved.
In tight gas reservoirs in the early stage of development this approach is more comprehensive towards modeling hydraulic fractures parameters and hence production optimization from the reservoir. The value information gained from this workflow is then integrated into the full field dynamic model.
Seismic Attribute Utilization for FFDP Well Placement Optimization, Upper Cretaceous Fractured Complex Carbonate Reservoir, Onshore Oil Field, U.A.E.
Authors: Mahmoud Sabry L. , Hozayen Magdy , Radwan El Sayed 
Published: September 2013

Abstract
An Upper Cretaceous carbonate reservoir, onshore oil field in Abu Dhabi is characterized by its vigorous surface topography and subsurface complex structural setting. The studied reservoir is a highly fractured elongated anticline trending NE-SW. Fracture occurrence and distribution have influenced the reservoir performance in terms of oil production and water cut from the field. Seismic attributes integrated with well log data and well performance have provided a good understanding of the lineament/fracture distribution within the reservoir. In addition, this integration enhanced the Full Field Development Plan (FFDP) optimization in terms of well placement and reservoir performance to avoid early water break through (EWBT) due to fractures. 3D seismic data was acquired with high fold and wide azimuth over the field in 2007. The 3D seismic data was processed in 2008 with some processing issues. In 2012, new algorithms were applied over a pilot area in order to resolve the processing issues and to preserve relative true amplitude for further reservoir characterization purposes. The pilot products have better identified short falls in the 2008 processed data. Seismic attributes were analyzed and the interpreted lineaments/fractures distribution will help better understand fracture orientation and their impact on oil production and water cut for full field development. The Seismic attributes successfully captured additional information and guided the well planning to avoid the highly lineament/fractured area. In addition, the new identified fracture system provides essential information for the ongoing and future development plans for this field. This 3D seismic input for fracture detection and well trajectories optimization resulted in better well performance and delay of water production especially in mid flank wells. The preliminary results of the attribute extraction at the reservoir targets are encouraging and new 3D seismic reprocessing data is considered a potential solution for the quantitative seismic interpretation and the reservoir characterization which achieved optimum well locations and orientation in this complicated onshore field.
Multiscale Characterization On The Pore Network In Carbonate Rocks
Authors: Solling Theis , Marquez Xiomara , McKay Thomas , Fogden Andrew 
Published: September 2013

Abstract
The flow properties of carbonate reservoir rocks depend on the pore and throat shape (geometry), the way they are interconnected (topology) and on the forces associated with the fluid-rock interactions (wettability). Little quantitative information on these parameters and their dependencies are currently available. We present the preliminary results of an on-going multiscale study of carbonate rocks which integrates classical diagenetic characterization of their pore system with 3D visualization and analysis of its structure (from micro-CT imaging) and mineral and elemental surface composition (from QEMSCAN). Tomograms of carbonate cores and minicores were obtained with our in-house micro-CT scanners, which allow us a spatial resolution down to the order of 1 μm. Macroporosity, microporosity and pore networks were extracted by image processing and analysis using the MANGO software. These same cores and minicores were then sectioned for 2D maps of their mineral composition to be acquired by QEMSCAN and subsequently spatially registered into the corresponding 3D tomogram. In addition to this analysis of carbonate samples in their dry state, minicores were also prepared and micro-CT imaged in a series of wet states after saturation, drainage, aging and spontaneous imbibition. This facilitated visualization and quantification of the pore-scale changes in saturation during these processes. The observations will help to guide the further development of modelling and simulation of multiphase flow in carbonates to predict and enhance the recovery of oil.