Hydrogeochemical Characteristics and Formation of Low-Temperature Geothermal Waters in Mangbang-Longling Area of Western Yunnan, China

Numerous low-temperature geothermal waters are distributed extensively in Mangbang-Longling of western Yunnan in China, whose formation mechanism has not been completely investigated yet. This study focused on the hydrogeochemical evolution, reservoir temperature, and recharge origin of geothermal waters using hydrogeochemical and deuterium-oxygen (D-O) isotopic studies. The low-temperature geothermal waters were characterized by HCO3-Na type, while shallow cold spring was of the hydrochemical type of HCO3-Ca. The hydrogeochemical characteristics of low-temperature geothermal waters were mainly determined by the dissolution of silicate minerals based on the geological condition and correlations of major and minor ions. The reservoir temperatures of low-temperature geothermal waters ranged from 111°C to 126°C estimated by silica geothermometry and the silicon-enthalpy graphic method. Low-temperature geothermal waters circulated at the largest depth of 1794–2077 m where deep high-temperature geothermal waters were involved. The data points of δD and δ18O of the hot spring water samples in the study area show a linear right-up trend, indicating the δ18O reaction between the water and rock and a possible mixture of magmatic water from below. The low-temperature thermal waters were recharged by meteoric water at the elevation of 2362–3653 m calculated by δD values. Upwelling by heating energy, low-temperature geothermal waters were exposed as geothermal springs in the fault and fracture intersection and mixed by up to 72% shallow cold waters at surface. Based on acquired data, a conceptual model of the low-temperature geothermal waters in the Mangbang-Longling area was proposed for future exploitation.

Modelling of Coupled Hydro-Thermo-Chemical Fluid Flow through Rock Fracture Networks and Its Applications

Most rock masses contain natural fractures. In many engineering applications, a detailed understanding of the characteristics of fluid flow through a fractured rock mass is critically important for design, performance analysis, and uncertainty/risk assessment. In this context, rock fractures and fracture networks play a decisive role in conducting fluid through the rock mass as the permeability of fractures is in general orders of magnitudes greater than that of intact rock matrices, particularly in hard rock settings. This paper reviews the modelling methods developed over the past four decades for the generation of representative fracture networks in rock masses. It then reviews some of the authors’ recent developments in numerical modelling and experimental studies of linear and non-linear fluid flow through fractures and fracture networks, including challenging issues such as fracture wall roughness, aperture variations, flow tortuosity, fracture intersection geometry, fracture connectivity, and inertia effects at high Reynolds numbers. Finally, it provides a brief review of two applications of methods developed by the authors: the Habanero coupled hydro-thermal heat extraction model for fractured reservoirs and the Kapunda in-situ recovery of copper minerals from fractures, which is based on a coupled hydro-chemical model.

Experimental investigation of proppant clustering in intersected fractures

This paper investigates the dynamics of proppant agglomerations during flow and transport within fractures intersected at the angles typical for the joint of pre-existing and newly formed fractures. The study considers variations and coupling of fluid flow rates, proppant volumetric concentrations, fluid dynamic viscosities and fracture intersection angles. Proppants are widely used during hydraulic fracturing to keep fractures open and enhance reservoir permeability. This study uses plexiglas experimental slots and visual analysis for identifying particle displacements. Geo-Particle Image Velocimetry–Reliability-Guided (GeoPIV-RG) method tracks particle movements among images by comparing the reference and subsequent snapshots at the point and time of interest. Results of this study show that the proppant volumetric concentration and the fluid flow rate are closely correlated with each other for affecting proppant flow, transport, and agglomeration formation. Increasing the proppant volumetric concentration generally promotes particle agglomeration, with different extent when coupled with the fluid flow rate. Proppant volumetric concentration affects the size, shape, and distribution of particle clusters. Increasing the fluid flow rate increases the occurrence of particle agglomerates at low proppant volumetric concentration; however, this trend is absent under high proppant volumetric concentrations. Sizes and shapes of proppant agglomerates change as the fluid flow rate changes. Changes of fracture intersection angle minimally affect shape, size and distance between proppant agglomerates and clusters. Furthermore, increasing the fluid dynamic viscosity strongly promotes proppant agglomeration. Although fluid dynamic viscosity changes do not affect the shape and size of particle clusters, the distance between adjacent clusters decreases at higher fluid dynamic viscosity.

Pressure-Monitoring Technique Uses Sealed Wellbore Pressure as Source

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 199731, “Monitoring the Pulse of a Well Through Sealed Wellbore Pressure Monitoring: A Breakthrough Diagnostic With a Multibasin Case Study,” by Kyle Haustveit, SPE, Brendan Elliott, SPE, and Jackson Haffener, SPE, Devon Energy, et al., prepared for the 2020 SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, 4-6 February. The paper has not been peer reviewed. A pressure-monitoring technique using an offset sealed wellbore as a monitoring source has led to advancements in quantifying cluster efficiencies of hydraulic stimulations in real time. Sealed wellbore pressure monitoring (SWPM) is a low-cost, nonintrusive method used to evaluate and quantify fracture-growth rates and fracture-driven interactions during a hydraulic stimulation. The measurements can be made with only a surface pressure gauge on a monitor well. To date, more than 1,500 stages have been monitored using the technique. The complete paper reviews multiple SWPM case studies, collected from projects in the Anadarko and Permian Delaware basins; this synopsis will concentrate on the concepts behind, and the validation of, the technique. Introduction SWPM is performed on a well that acts as a closed system. The well cannot be connected to a formation through perforations or other types of access points; the casing must be sealed. Uncompleted wells can be used if the shallowest perforations are isolated from the formation. In an existing producing well, a plug must be set above the shallowest perforations to create a closed system from the top of the plug to surface where the pressure measurement is recorded. The wellbore should be filled with low-compressibility fluid (e.g., completion brine) to amplify the pressure response created during monitoring. Fractures intersecting the sealed wellbore cause local deformation, which results in a small volume reduction in the closed system (system being the fluid volume inside of the casing) and generates a discernible and distinct pressure response. Pressure can be recorded either using a surface gauge or a downhole gauge. Multiple sealed wellbores can be used as monitor wells for a single treatment well, allowing for a more-detailed understanding of fracture growth rates during a stimulation. The field execution of SWPM is simple and does not require any tools to enter the wellbore. A surface gauge provides the necessary data needed to evaluate the fracture interactions with the monitor wellbore. There is no need to alter zipper operations if sealed wellbores are available. The main restriction SWPM introduces to operations is the necessity to leave new wellbores, designated as monitors, unprepped by not opening toe sleeves or shooting perforations for Stage 1 until monitoring of the offset treatment wells is complete. Because the pressure response in the monitor well is a result of a fracture intersection at the wellbore, the method reduces the uncertainty related to the location of the monitor point commonly associated with other offset pressure-monitoring techniques.

Numerical simulation of the laws of fracture propagation of multi-hole linear co-directional hydraulic fracturing

Directional rupture is one of the most important and most common problems related to rock breaking. The goal of directional rock breaking can be effectively achieved via multi-hole linear co-directional hydraulic fracturing. In this paper, the XSite software was utilized to verify the experimental results of multi-hole linear co-directional hydraulic fracturing., and its basic law is studied. The results indicate that the process of multi-hole linear co-directional hydraulic fracturing can be divided into four stages: water injection boost, hydraulic fracture initiation, and the unstable and stable propagation of hydraulic fracture. The stable expansion stage lasts longer and produces more microcracks than the unstable expansion stage. Due to the existence of the borehole-sealing device, the three-dimensional hydraulic fracture first initiates and expands along the axial direction in the bare borehole section, then extends along the axial direction in the non-bare hole section and finally expands along the axial direction in the rock mass without the borehole. The network formed by hydraulic fracture in rock is not a pure plane, but rather a curved spatial surface. The curved spatial surface passes through both the centre of the borehole and the axial direction relative to the borehole. Due to the boundary effect, the curved spatial surface goes toward the plane in which the maximum principal stress occurs. The local ground stress field is changed due to the initiation and propagation of hydraulic fractures. The propagation direction of the fractures between the fracturing boreholes will be deflected. A fracture propagation pressure that is greater than the minimum principle stress and a tension field that is induced in the leading edge of the fracture end, will aid to fracture intersection; as a result, the possibility of connecting the boreholes will increase.

Partitioning of preferential flows in fracture networks: Smoothed Particle Dynamics simulations and analytical modeling of infiltration dynamics

<p>Recharge estimation in fractured-porous aquifers is an essential tool for proper water management and assessment of vulnerability. As opposed to diffuse infiltration, often encountered in consolidated and unconsolidated porous media, the infiltration dynamics in the unsaturated zone of fractured-porous media and karst aquifers often exhibit a rapid, gravity-driven flow component along preferential flow paths such as fractures, fracture networks, faults and fault zones. The partitioning into two hydraulically contrasting domains commonly leads to a breakdown of classical volume-effective flow equations employed in many FD or FEM modeling approaches which only consider the capillarity of the medium. Even in the presence of a porous matrix, preferential pathways along fractures have been shown to sustain flow percolation under equilibrium and non-equilibrium conditions. In order to properly capture the flow physics, various components have to be considered such as static and dynamic contact angles, surface tension, free-surface (multi-phase) interface dynamics, dynamic switching of flow modes (between droplets, rivulets, films) and associated formation of singularities in the case of merging or snapping flow. Here we study the process of vertical infiltration and partitioning at a single fracture intersection into a horizontal and vertical flow component. Via parallelized Smoothed Particle Hydrodynamics simulations we demonstrate how flow is first channeled into the horizontal fracture and then transitions into a Washburn-type inflow when pressure conditions are met and a connection to the next vertical flow path is established. We further proceed to capture this process with an analytical approach and finally demonstrate how to obtain a process-based transfer function to upscale this process to arbitrary fracture geometries and fracture cascades.</p>