bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of the Galerkin's Finite Element Method to the Flow of Power-Law Non-Newtonian Fluids through Porous Media
Authors: Omosebi O. A. , Akabogu A. K. 
Published: April 2017

Abstract
Conventional approach of modeling fluid flow through porous media and analysis of pressure data often adopt a simplified approach by assuming a Newtonian fluid flow behavior. However, most of the fluids encountered in the oilfield exhibit non-Newtonian flow characteristics. Analysis of field data involving these fluids with conventional Newtonian flow models would result in erroneous interpretation. The generalized equation for the radial flow of non-Newtonian fluids through porous media has been solved analytically but a numerical solution by finite element is yet to be published. In this study, the Galerkin Finite Element technique is used to solve the generalized problem under the various inner and outer boundary conditions that are frequently encountered in the oilfield.
Weak formulation of the generalized PDE and boundary conditions is obtained and is discretized into finite elements. Element matrix in both the spatial and time domains are computed using Gauss quadrature technique. Subsequently, the nodal pressure values are computed and a derivative function is used to compute the corresponding pressure derivatives. A commercial simulator is used to verify the numerical solution for the conventional Newtonian fluid flow. The numerical solution is also compared to approximate analytic solutions involving non-Newtonian fluids.
Results show the commonly observed flow regimes in pressure transient testing, which include the early-time unit slope line (wellbore storage), the early-time trough signifying pseudo-steady state matrix fracture flow (naturally-fractured reservoirs), the infinite-acting radial flow regime line, and the late-time boundary-dominated footprints for no-flow boundary, constant-pressure boundary, and pseudo-steady state (closed reservoir system). The solution obtained in this study matches the numerical solution from a commercial simulator. Comparison of the numerical solution with approximate analytic solutions also shows strong agreement. Validation of the finite element solution with field data involving polymer injection shows a satisfactory match. Parametric study of the effect of fluid flow index indicates the strong dependence of pressure transient and characteristic flow regimes on fluid rheology.
Limited studies have established the application of finite element technique in modeling non-Newtonian fluid flow through porous media. This study demonstrates how the generalized fluid flow model can be solved by finite element method.
Workover Well Operations to Restore Full Reservoir Access in an Underground Natural-Gas-Storage Cavern: A Case Study for Developing New Technology in Dual-String Section Milling Methods
Authors: Smalley Michael T. , Teale David W. , Haq Mohammed A. 
Published: April 2017

Abstract
Both above and under the ground, hydocarbon storage is subject to many stringent compliance standards regarding health, environment, and ground water safety. Various issues—such as zoning regulations, future expansion needs, secondary and tertiary containments, design efficiency for storage and transfer, and financial viability of projects—determine the storage installation method. Underground storage maximizes real estate usage, reduces fire hazards, protects against weather events, and enables storing large amounts of hydrocarbons. The principal methods for underground storage include salt caverns, depleted reservoirs, and acquifers. Each method has its own application advantages and physical properties, such as retention capability and permeability. These factors, along with the economics of site establishment and maintenance as well as deliverability rates, regulate the suitability of that method for particular applications. For example, salt caverns provide very high withdrawal and injection rates relative to their working gas capacity. When the operator locates a suitable salt dome or salt bed, the site is excavated to form a cavern. This excavation process is usually accomplished by pumping or injecting highly pressurized water into the salt layer to dissolve the salt and create a cavern cavity; this method is referred to as cavern leaching or solution mining. After this process, the operator can remove the brine and commence operations.
However, if this leaching phenomenon occurs in existing natural gas storage caverns, the leached area behind the intermediate casing becomes an inaccessible part of the reservoir. To access this area, the lower section of this casing must be removed. Traditional section milling can achieve this; but if the inside diameter (ID) of the inner string is smaller than the outside diameter (OD) of the servicing tool, existing technology cannot be used. Situations such as this require new technology to pass through the restricted ID and open a section in the next-larger-size string.
A Distance Transform Method for History Matching of Discrete Geologic Facies Models
Authors: Elahi Siavash Hakim , Jafarpour Behnam 
Published: April 2017

Abstract
Construction of predictive reservoir models involves subjective interpretation and interpolation of spatially limited data, often using imperfect modeling assumptions. Hence, the process can introduce significant uncertainty and bias into production predictions. In particular, the uncertainty associated with the facies distribution in complex geologic environments, such as fluvial channels, can be consequential for production forecasting and reservoir development planning. Conventional history matching techniques are mainly designed to update continuous reservoir properties, such as permeability and porosity distributions. As such, calibrating discrete facies against production history may require a parametrization approach to convert discrete facies to continuous parameters. In this paper, we present a distance transformation method for calibrating the distribution of discrete facies againts production data. Distance-based transforms are widely used in discrete image processing, where the discrete values in each image pixel are replaced with their distance (i.e., a continuous variable) to the nearest cell with a different value (i.e., facies boundary). The history matching is then performed by updating the continuous distance maps based on observed production data. Once the distances are updated, an inverse distance transform is applied to convert them back to discrete facies models. The distance transformation enables discrete facies updating with history matching techniques that are designed for continuous variables, while ensuring that the final solution remains discrete. A low-rank representation of the continuous distance maps with the truncated singular value decomposition (SVD) is also presented for problems in which large-scale facies connectivity is expected. In that case, the production data is used to update the low-rank SVD projection coefficients of the distance maps. The developed discrete transformation ensures that the solution of the facies model calibration problem remains discrete. Furthermore, the use of prior models and SVD parameterization help to preserve the connectivity in the geologic facies after dynamic data integration. Examples with two and three facies models are used to illustrate the application of the method and to evaluate it performance.
Material Balance Applied to Dynamic Reservoir Surveillance Patterns
Authors: Batycky Rod P. , Thiele Marco R. , Razavi Mahdi 
Published: April 2017

Abstract
Determining the remaining spatial oil saturation distribution and current reservoir pressure distribution for a mature (water, solvent, CO2) flood is a cornerstone of reservoir management associated with improving sweep and selecting infill well locations. Decisions of this type are typically supported by reservoir flow simulation models that have been calibrated to the historical injection/production data.
In this paper, we present a material balance based approach to estimating remaining fluids in place as an alternative to using flow simulation. First we use the historical injection/production volumes to solve for streamlines and streamline derived pattern metrics such as well allocation factors and injector/producer well-pair reservoir volumes. Then we apply material balance on these volumes over time to estimate spatial fluid saturations and pressures existing at the end of history. Like reservoir simulation, the method accounts for changing well patterns through time, requires a 3D static geological model, and yields 3D saturation distributions of oil, water, and gas. However, unlike reservoir simulation the only calibration (history matching) required is the approximation of pore volumes and initial fluids in place of the patterns.
We present results for simple 2D models to illustrate the approach and compare to results from flow simulation. We then present a 3D pattern water/gas flood and the remaining oil and gas in place maps that are computed. The advantage of our method is that minimal history matching is required as historical injected/produced volumes are used explicitly; the disadvantage is that the resulting 3D saturation distributions are less detailed because the control volumes used for material balance are defined at the well-pair level which are many times larger than individual grid cells.
Efficient Modeling and History Matching of Shale Oil Reservoirs Using the Fast Marching Method: Field Application and Validation
Authors: Iino Atsushi , Vyas Aditya , Huang Jixiang , Datta-Gupta Akhil , Fujita Yusuke , Bansal Neha , Sankaran Sathish 
Published: April 2017

Abstract
This paper demonstrates the novelty and practical feasibility of the FMM-based multi-phase simulation for rapid field-scale modeling of shale reservoirs with multi-continua heterogeneity.
Modeling of unconventional reservoirs requires accurate characterization of complex flow mechanisms in multi-continua because of the interactions between reservoir rocks, microfractures and hydraulic fractures. It is also essential to account for the complicated geometry of well completion, the reservoir heterogeneity and multi-phase flow effects. Currently, such multi-phase numerical simulation for multi-continua reservoirs needs substantial computational time that hinders efficient history matching and uncertainty analysis. In this paper, we propose an efficient approach for field scale application and performance assessment of shale reservoirs using rapid multi-phase simulation with the Fast Marching Method (FMM).
The key idea of the reservoir simulation using the FMM is to recast the 3-D flow equation into 1-D equation along the ‘diffusive time of flight’ (DTOF) coordinate, which embeds the 3-D spatial heterogeneity. The DTOF is a representation of the travel time of pressure propagation in the reservoir. The pressure propagation is governed by the Eikonal equation which can be solved efficiently using the FMM. The 1-D formulation leads to orders of magnitude faster computation than the 3-D finite difference simulation. The use of FMM-based simulation also enables systematic history matching and uncertainty analysis using population-based techniques that require substantial simulation runs.
We first validate the accuracy and computational efficiency of the FMM-based multi-phase simulation using synthetic reservoir models and comparison with a commercial finite-difference simulator. Next, we apply our proposed approach to a field example in Texas for a multi-stage hydraulically fractured horizontal well. The 3-D heterogeneous reservoir model was built and history matched for oil, gas and water production using the Genetic Algorithm with the FMM-based flow simulation. Multiple history-matched models were obtained to examine uncertainties in the production forecast associated with respect to the properties related to hydraulic fractures, microfractures and the matrix.
A Case Study of Formation Testing in Antelope Shale
Authors: Lal Manish K. , Tran Viet H. , Singh Amit 
Published: April 2017

Abstract
In new shale development, formation testing is critical to understanding reservoir properties and producibility. However, due to low permeability, a test usually takes much longer and can easily result in cost overruns. There are many ways to conduct formation testing such as drill pipe / tubing conveyed testing and coil-tubing or wireline testing. Formation wireline testing has advantage not only for its flexibility and combinable features but also for cost and time savings as compared to other methods. In a combination way, formation wireline tool can be run either through wireline alone or through the drill pipe for safety reasons.
The Antelope Shale in Monterey Formation in San Joaquin Valley is siliceous shale that is thinly laminated, has relatively high porosity, low permeability, small pore throats, and varying degree of fracturing. Siliceous shale hydrocarbon reservoirs are not very common and little is known about their production characteristics. These are much more geologically complex than the conventional shale and tight rock reservoirs and the traditional conventional formation testing methods may not be directly applied to them. Little or no literature review can be found on running formation evaluation wireline tools in the Antelope Shale.
In this paper, we discuss a case study of formation testing in Antelope Shale. The test was run with dual packers and downhole fluid analyzer in a vertical appraisal well to evaluate two intervals in the Antelope Shale. The run proved the value of formation testing method in terms of data collected versus cost & time. First, the drill pipe conveyed formation testing was selected among different methods to help characterize the reservoir and to measure fracture closure pressure to evaluate technologies that can lead to the development of tight reservoirs. Second, the microfracturing data collected from the formation testing job was used for designing the completion strategy to understand individual zone production such that we may target a single zone for future development. The additional values of the formation test were to measure formation pressure and collect fluid samples for Pressure, Volume, and Temperature (PVT) analysis to minimize uncertainties in key reservoir parameters.
The job proved its pivot values for formation testing. However, the experience from planning and running the tool in this new tight rock reservoir are much more important to achieving the appraisal objectives. The combinable features of the tool enabled continuous onsite monitoring, on-the-fly operational decision making in sample depths in response to formation behavior, and optimizing sample chamber opening time to collect critical oil and water samples, while successfully acquiring the fracture closure pressure. These results may be difficult to achieve with other methods in a single run.
Steady-State Relative Permeability Upscaling in Multiporosity/Multipermeability Core Assemblages
Authors: Ramsay Travis , Hinkley Richard 
Published: April 2017

Abstract
Steady-state two-phase relative permeability upscaling in synthetic and X-ray computerized tomography (CT) coal cores is performed with a three-dimensional (3D) reservoir simulator using an automated control procedure to drive a series of steady-state fractional flows. A clear understanding of relative permeability in coal is important for coalbed methane reservoir management from pore scale to sales point, as it is valuable for helping forecast production. Automation control enables greater continuity between physical corefloods and the numerical upscaling of the same coreflood procedure. Absolute permeability is computed for primitive synthetic core types using the reservoir simulator and is compared to an analytical formulation to validate the use of the simulator solution for core scale property determination.
Relative permeability was computed for synthetic cores considering several scenarios: fracture geometry/abundance (parallel vs. intersecting), rock-type matrix distribution (homogeneous vs. heterogeneous), ratios of matrix-to-fracture permeability (high vs. low), and injection rate conditions [capillary limit (CL) vs. viscous limit (VL)]. Additionally, injection rate conditions were evaluated in the upscaled relative permeability of an X-ray CT segmented composite coal core. Analysis of the upscaled relative permeability curves in the composite and synthetic cores illustrated the impact of each scenario on upscaling relative permeability and suggests that selected characteristics of unconventional cores can potentially be used to delineate parameter dependence in a manner similar to rock type volume fraction and ordering in conventional cores. The consistency of the developed upscaled results with previous studies confirms the applicability of automated process control in core scale multiphase upscaling using a commercial reservoir simulator at varied injection rates and upscaling conditions.
An Experimental Study of CO2 Saturated Brine Reaction with Berea Sandstone
Authors: Chen Peng , Saeedi Ali , Noble Ryan 
Published: April 2017

Abstract
Geological sequestration of CO2 is one of the most promising technologies to mitigate the greenhouse effect by decreasing the anthropogenic CO2 emissions into the atmosphere. Deep saline reservoirs are a suitable target for CO2 storage because very often they can be found relatively close to today's large CO2 releasing sources. To investigate the chemical and physical impacts of a CO2-rich brine solution injection to a quartz rich sandstone, we flooded a Berea Sandstone core sample with CO2-saturated synthetic brine at the elevated temperature (60°C) and pressure (20MPa). After flooding, the porosity and permeability of the core were measured and compared to the pre-flooding values. We found that the porosity had increased by 1.8% while the permeability decreased by 5.1%. The decrease in permeability may be attributed to the movement of particles in the pore space of the sample (fines migration) and/or sample's physical compaction under net effective stress. Effluent brine samples were also collected during the core-flood experiment to be analysed for their chemical composition. We found that, on average, the concentration of Ca2+, Mg2+ and Fe2+ in the effluent samples to increase by approximately 100mg/l, 80mg/l and 95mg/l, respectively, with traces of other metals. It is believed that the Ca2+, Mg2+ and Fe2+ were liberated from the dissolution of the carbonate cement in the sample. As revealed by the differential pressure evolution of the experiment, for the quartz-rich sandstone reservoirs, where fines migration is not significant and reactive minerals are scarce, the injectivity may not be affected during the fluid injection process.
A Real-Time Interactive Drill-Off Test Utilizing Artificial Intelligence Algorithm for DSATS Drilling Automation University Competition
Authors: Bilgesu H. , Cox Z. D. , Elshehabi T. A. , Smith C. , Idowu G. O. , Florence F. R. 
Published: April 2017

Abstract
The current state of the drilling industry tends to focus on technology and techniques that reduce the cost of well construction. One approach is to use drilling automation to help improve ROP, and perhaps more importantly, to mitigate drilling dysfunctions and human errors than can lead to large, unplanned expenses. SPE's Drilling Systems Automation Technical Section (DSATS) created an international university competition to encourage the development of new drilling algorithms and to get more young people involved in drilling. The students must design, build and operate a small (6 ft / 2 m) drilling rig with fully automated sensors and controls. They drill a specially created, multi-layered rock sample as fast and as straight as possible, with only two buttons: start and stop. This paper summarizes the work done by the West Virginia University team that won the 2016 competition. It shows scalable drilling algorithms can be developed on a miniature rig that can later be transferred to ongoing drilling programs.
DSATS implemented a competition to encourage students to investigate the use of automation techniques and tools for drilling systems. The competition fosters a greater understanding of complicated drilling systems, challenging students across disciplines to consider the possibilities of a career in upstream drilling operations. This project requires each university team to first submit a proposal, including structural design, control architecture, and sensor selection with no knowledge of the material to be drilled. Teams were advised to consider mitigating the effect of nonplanar junctions as well as the possibility of lost circulation, and to be especially cognizant of vibration and torque issues. The winning team received a travel grant to attend the ATCE to present their test results at the DSATS symposium in Dubai.
This paper addresses the details of that presentation. It includes: Drilling limitations and critical parametersConstruction issues and initial operations that required a re-designFinal design criteria, constraints, tradeoffsSummary of recorded data and key eventsDrilling parameters and how they impacted the testEconomic considerationsSignificant lessons learnedConclusions and recommendations
As the competition finishes its second year, it remains the only competition of its kind that requires a multidisciplinary approach at a university level, and prepares those involved for the type of interwoven, team approach often at the heart of oilfield operations today. While the rig designs are practical, they are not limited by historical features or commonplace rig designs.
Hands-free drilling is possible and proven on a small scale as more and more companies begin to implement full scale operations to mitigate drilling dysfunctions and improve ROP to lower costs.