Data Processing Protocol for Regression of Geothermal Times Series with Uneven Intervals

Regression of data generated in simulations or experiments has important implications in sensitivity studies, uncertainty analysis, and prediction accuracy. Depending on the nature of the physical model, data points may not be evenly distributed. It is not often practical to choose all points for regression of a model because it doesn't always guarantee a better fit. Fitness of the model is highly dependent on the number of data points and the distribution of the data along the curve. In this study, the effect of the number of points selected for regression is investigated and various schemes aimed to process regression data points are explored. Time series data i.e., output varying with time, is our prime interest mainly the temperature profile from enhanced geothermal system. The objective of the research is to find a better scheme for choosing a fraction of data points from the entire set to find a better fitness of the model without losing any features or trends in the data. A workflow is provided to summarize the entire protocol of data preprocessing, regression of mathematical model using training data, model testing, and error analysis. Six different schemes are developed to process data by setting criteria such as equal spacing along axes (X and Y), equal distance between two consecutive points on the curve, constraint in the angle of curvature, etc. As an example for the application of the proposed schemes, 1 to 20% of the data generated from the temperature change of a typical geothermal system is chosen from a total of 9939 points. It is shown that the number of data points, to a degree, has negligible effect on the fitted model depending on the scheme. The proposed data processing schemes are ranked in terms of R2 and NRMSE values

Mitigation of Methane Emissions from Coal Mine Ventilation Air

U.S. EPA\u27s coalbed methane outreach program, (CMOP) has prepared a technical assessment of techniques that combust trace amounts of coal mine methane contained in ventilation air. Control of methane emissions from mine ventilation systems has been an elusive goal because of the magnitude of a typical airflow and the very low methane concentrations. One established and cost-effective use feeds the air into a prime mover in lieu of ambient combustion air. This method usually consumes just a fraction of the flow available from each ventilation shaft. The authors evaluated the technical and economic feasibility of two emerging systems that may accept up to 100% of the flow from a nearby shaft, oxidize the contained methane, and produce marketable energy. Both systems use regenerative, flow-reversal reactors. One system operates at 1000°C, and the other uses a catalyst to reduce the combustion temperature by several hundred degrees. Above certain minimum methane concentrations the reactors can exchange high quality heat with a working fluid such as compressed air or pressurized water. This paper discusses two illustrative energy projects where the reactors produce energy revenue and greenhouse gas credits and yield an attractive return on invested capital

Understanding and modeling of gas-condensate flow in porous media

 Well deliverability impairment due to liquid dropout inside gas-condensate reservoirs below dew-point pressure is a common production problem. The operating conditions and the thermodynamic properties of the condensate govern the production performance of this type of reservoir. Modeling condensate production using analytical, semi-analytical or empirical formula for quick assessment of reservoir performance is a complicated method due to the complex thermodynamic behavior. The objective of this study is to provide a fundamental understanding of the flow and thermodynamics of gas-condensate fluid to develop tools for the production prediction. The prior developments of flow modeling of gas-condensate are briefly reviewed. The multi-phase flow and the depletion stages during production are discussed. Each component of pseudo-pressure calculations to determine the condensate flow rate is explained. Thermodynamic properties and laboratory experiment relevant to the flow of condensate are also explored. Pressure-volume-temperature properties such as two-phase envelope, constant composition expansion and constant volume depletion are demonstrated for three different gas-condensate fluids namely lean, intermediate and rich. This article is also useful for future developments of the production model for a gas-condensate under various operational and completion scenarios such as horizontal wells and hydraulic fractures in tight formations.Cited as: Panja, P., Velasco, R., Deo, M. Understanding and modeling of gas-condensate flow in porous media. Advances in Geo-Energy Research, 2020, 4(2): 173-186, doi: 10.26804/ager.2020.02.06

The Fate of Injected Water in Shale Formations

It is well known that only about a third of water injected for hydraulic fracturing of shales is recovered. It is important to understand the fate of this injected water. The amount of water infiltrating the matrix is determined by a number of parameters such as the pressure differential between the fracture and the matrix, the capillary pressure relationships in the fractures and in the matrix and other petrophysical properties of the formation. In this paper, we provide a breakdown for the various possible water losses depending on the reservoir, fracture and operating parameters. A set of capillary pressure relationships for the formation were first created based on the basic mineralogy and the total organic carbon (TOC) content. Fracture capillary pressure also changed depending on the concentrations and types of proppants in the fractures. Two basic end members can be defined – silicistic and dolomitic with different amounts of TOC. The capillary pressure relationships ranged from oil wet, neutral to water wet. Different porosity and permeability combinations were also examined. Amounts of water relative to the total amount injected that would infiltrate the formation were compiled as the operating conditions (pressures) and formation properties changed. This calculation shows that the infiltration due to the various phenomena are not sufficient to account for the water losses if the formations are strongly oil wet. In addition, situations where water blockages occur due to these multiphase flow effects were identified and the loss of productivity due to this phenomenon was quantified both for gas and for oil production. The study was conducted using a discrete-fracture network simulator developed at the University of Utah. A realistic (non-orthogonal) representation of a complex fracture network was employed in the study. Realistic representation of distribution and retention of these aqueous fracturing fluids is essential for optimizing hydraulic fracturing treatment volumes

On-line Optimization-Based Simulators for Fractured and Non-fractured Reservoirs

Oil field development is a multi-million dollar business. Reservoir simulation is often used to guide the field management and development process. Reservoir characterization and geologic modeling tools have become increasingly sophisticated. As a result the geologic models produced are complex. Most reservoirs are fractured to a certain extent. The new geologic characterization methods are making it possible to map features such as faults and fractures, field-wide. Significant progress has been made in being able to predict properties of the faults and of the fractured zones. Traditionally, finite difference methods have been employed in discretizing the domains created by geologic means. For complex geometries, finite-element methods of discretization may be more suitable. Since reservoir simulation is a mature science, some of the advances in numerical methods (linear, nonlinear solvers and parallel computing) have not been fully realized in the implementation of most of the simulators. The purpose of this project was to address some of these issues. {sm_bullet} One of the goals of this project was to develop a series of finite-element simulators to handle problems of complex geometry, including systems containing faults and fractures. {sm_bullet} The idea was to incorporate the most modern computing tools; use of modular object-oriented computer languages, the most sophisticated linear and nonlinear solvers, parallel computing methods and good visualization tools. {sm_bullet} One of the tasks of the project was also to demonstrate the construction of fractures and faults in a reservoir using the available data and to assign properties to these features. {sm_bullet} Once the reservoir model is in place, it is desirable to find the operating conditions, which would provide the best reservoir performance. This can be accomplished by utilization optimization tools and coupling them with reservoir simulation. Optimization-based reservoir simulation was one of the project goals. {sm_bullet} Providing remote access to the simulators developed was also one of the project objectives. The basic methods development is presented in Chapters 1-3. Development of a flux continuous finite element algorithm is presented with example calculations in Chapter 1. This is followed by discussion of three-dimensional, three-phase development in Chapter 2. A different numerical method, the mixed finite element method is presented in Chapter 3. Verification of the methods developed is described in Chapter 4. Introduction to fractured reservoir simulation is provided in Chapter 5 with an example of a fractured reservoir simulation study of a faulted reservoir in North Sea. Chapter six contains several examples of two dimensional simulations, while chapter 7 contains examples of three-dimensional simulation. In Chapter 8 optimization techniques are discussed. Chapter 9 contains a roadmap to use the remote programming interface for the fractured reservoir simulator

A GPU-accelerated package for simulation of flow in nanoporous source rocks with many-body dissipative particle dynamics

Mesoscopic simulations of hydrocarbon flow in source shales are challenging, in part due to the heterogeneous shale pores with sizes ranging from a few nanometers to a few micrometers. Additionally, the sub-continuum fluid-fluid and fluid-solid interactions in nano- to micro-scale shale pores, which are physically and chemically sophisticated, must be captured. To address those challenges, we present a GPU-accelerated package for simulation of flow in nano- to micro-pore networks with a many-body dissipative particle dynamics (mDPD) mesoscale model. Based on a fully distributed parallel paradigm, the code offloads all intensive workloads on GPUs. Other advancements, such as smart particle packing and no-slip boundary condition in complex pore geometries, are also implemented for the construction and the simulation of the realistic shale pores from 3D nanometer-resolution stack images. Our code is validated for accuracy and compared against the CPU counterpart for speedup. In our benchmark tests, the code delivers nearly perfect strong scaling and weak scaling (with up to 512 million particles) on up to 512 K20X GPUs on Oak Ridge National Laboratory's (ORNL) Titan supercomputer. Moreover, a single-GPU benchmark on ORNL's SummitDev and IBM's AC922 suggests that the host-to-device NVLink can boost performance over PCIe by a remarkable 40\%. Lastly, we demonstrate, through a flow simulation in realistic shale pores, that the CPU counterpart requires 840 Power9 cores to rival the performance delivered by our package with four V100 GPUs on ORNL's Summit architecture. This simulation package enables quick-turnaround and high-throughput mesoscopic numerical simulations for investigating complex flow phenomena in nano- to micro-porous rocks with realistic pore geometries

Reactivation of an Idle Lease to Increase Heavy Oil Recovery Through Application of Conventional Steam Drive Technology in a Low Dip Slope and Basin Resrvoir in the Midway-Sunset Field, San Jaoquin Basin, California

This project reactivates ARCO�s idle Pru Fee lease in the Midway-Sunset field, California and conducts a continuous steamflood enhanced oil recovery demonstration aided by an integration of modern reservoir characterization and simulation methods. Cyclic steaming is being used to reestablish baseline production within the reservoir characterization phase of the project. During the demonstration phase scheduled to begin in January 1997, a continuous steamflood enhanced oil recovery will be initiated to test the incremental value of this method as an alternative to cyclic steaming. Other economically marginal Class III reservoirs having similar producibility problems will benefit from insight gained in this project. The objectives of the project are: (1) to return the shut-in portion of the reservoir to optimal commercial production; (2) to accurately describe the reservoir and recovery process; and (3) to convey the details of this activity to the domestic petroleum industry, especially to other producers in California, through an aggressive technology transfer program

APPENDIX G - Detailed study of shale pyrolysis for oil production - A subpart of project oil shale pyrolysis and in situ modeling - Final Project Report - Reporting period: June 21, 2006 to October 21, 2009

reportThe oil shale industry is going through a revolution of sorts. After the oil crisis in the 1970s, a great deal of effort was spent on research and development and on pilot scale technologies. Extensive research was conducted with on-surface and in-situ production methods. Even though some large pilot underground retorting operations were performed, the on-surface (mining and processing) methods were closest to full-scale (~10,000 barrels/day) commercial implementation. The oil price collapse in the early and mid-1980s led to the total discontinuation of oil shale research and development programs. In recent years, in-situ production methods have seen a significant revival due to technological advances. With these methods, the slow thermal pyrolysis of the organic matter in shale leads to a light oil product that does not require additional thermal upgrading

APPENDIX C - In-situ production of Utah oil sands - Final Project Report - Reporting period: June 21, 2006 to October 21, 2009

reportTwo oil sand reservoirs located in Utah's Uinta Basin were considered for analysis: Whiterocks, a small, steeply dipping, contained reservoir containing about 100 million barrels, and Sunnyside, a giant reservoir containing over four billion barrels of oil in place. Cyclic steam stimulation, steam assisted gravity drainage, and in-situ combustion processes were considered for the production of oil from these reservoirs. Different well configurations and patterns were examined. It was found that the application of steam-based in-situ processes would be feasible but challenging for Utah oil sands. For most configurations, the steam to oil ratios were higher than five, indicating marginal economic viability. Additionally, the water production rates were high. The in-situ combustion process was simulated with and without the presence of a hydraulic fracture for a homogeneous reservoir. The nature of the combustion front was radial without the fracture and linear with the fracture. Even though the process appears feasible, rigorous evaluation with an appropriate geologic model will be necessary to determine technical and economic viability