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Murphy, Hugh D., and Tester, Jefferson W., Members SPE-AIME Univ. of California/Los Alamos Scientific Laboratory Abstract Results of preliminary heat extraction testing of a prototype hot dry rock geothermal energy reservoir are presented. This reservoir was produced by hydraulic fracturing of hot, otherwise non-porous, granite at a depth of 3 km in northern New Mexico. Heat was extracted from the reservoir during closed loop operation using two wells, one for injection and one for production. During 75 days of operation the steady flow impedence decreased by a factor of five as thermal contraction resulted in the opening of natural joints that provided additional communication with the producing well. Water losses to the rock surrounding the fracture steadily diminished and eventually this loss rate was less than 1% of the injected rate. The geochemistry of the produced fluid was benign and the seismic effects associated with heat extraction were immeasurable small. The relatively rapid thermal drawdown of the produced water, from 175 to 85 degrees C (345 to 185 degrees F), indicated that the effective hydraulic fracture radius was approximately 60 m (200 ft). The average thermal power extracted was 4 MW. Reservoir modeling was performed with a numerical simulator which handles two-dimensional fluid transport and heat conduction equation for the rock surrounding the fracture. The match obtained with field data indicates that the model is based upon a fundamental correct balance of the heat transport processes, convection and conduction, and provides bounds for the hydraulic fracture geometry. Introduction A program designed to demonstrates the feasibility of extracting energy from hot, dry rock has been initiated at the Los Alamos Scientific Laboratory (LASL). Basically, it is proposed that man-made geothermal energy reservoirs can be created by drilling into relatively impermeable rock to a depth where the temperature is high enough to be useful, creating a reservoir by hydraulic fracturing, and then completing the circulation loop by drilling a second hole to intersect the hydraulically fractured region. Thermal power would be extracted from this system by injecting cold water down the first hole, forcing the water to sweep by the freshly exposed hot rock surface in the reservoir-fracture system, and then returning the hot water to the surface where the thermal energy would be converted to electrical energy or used for other purposes. System pressures would be maintained such that only one phase, liquid water, would be present in the reservoir and the drilled holes. The concept is described in more detail by Smith et al. DRILLING AND COMPLETIONS The first reservoir is being investigated at Fenton Hill, located on the west flank of a dormant volcano, the Valles Caldera, in the Jemez mountains of northern New Mexico. The first deep borehole GT-2 (Geothermal Test-2) was drilled to a depth of 2.929 km (9609 ft) in granite, where the temperature was 197 degrees (386 degrees F), cased to 2.917 km (9571 ft), and then fractured in the open hole below the casing. The variation of equilibrium temperature and geology with depth is shown in Fig. 1. The Precambrian crystalline rocks were encountered at 730 m Precambrian crystalline rocks were encountered at 730 m (2400 ft). From this depth to the bottom the geothermal gradient is reasonably constant. The steeper gradient in the sediments above 730 m is caused by their lower thermal conductivity at 2.77 km (9100 ft), the geothermal heat flow at this site is 0.16 W/m2, 2-1/2 times the worldwide average. Following a series of hydraulic fracturing experiments at deeper depths, a new, larger fracture was created at 2.81 km (9220 ft), where a milling operation had accidentally broached the casing. This fracture became the main exit point when water was injected in GT-2. The granitic rock in point when water was injected in GT-2. The granitic rock in which these fractures were created is relatively homogeneous and unstratified, so it is assumed that all the fractures discussed here are approximately circular in shape, rather than rectangular as is usually assumed in oil and gas reservoirs.
- Proterozoic (0.44)
- Hadean (0.44)
- Archean (0.44)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Igneous Rock > Granite (0.44)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Renewable > Geothermal > Geothermal Resource > Hot Dry Rock (0.45)
Characterizing Gas Transfer from the Inorganic Matrix and Kerogen to Fracture Networks: A Comprehensive Analytical Modeling Approach
Zeng, Jie (The University of Western Australia) | Liu, Jishan (The University of Western Australia) | Li, Wai (The University of Western Australia) | Li, Lin (The University of Western Australia) | Leong, Yee-Kwong (The University of Western Australia) | Elsworth, Derek (The Pennsylvania State University) | Guo, Jianchun (Southwest Petroleum University)
Abstract An appropriate description of gas transfer from shale matrices to fracture networks is one of the most fundamental issues in shale gas extraction modeling. Existing gas transfer functions can be classified into the following categories: (1) direct single-continuum matrix to fracture transfer; (2) kerogen, inorganic matrix, and fracture series gas transfer; and (3) kerogen to fracture and inorganic matrix to fracture parallel gas transfer. The scanning electron microscope (SEM) images of shale samples reveal the heterogeneous distribution of pure inorganic regions, kerogen and inorganic-matrix interwoven regions, and pure kerogen regions. As fracture networks can penetrate different matrix regions at different locations, the mass transfer between matrices and fractures cannot be comprehensively simulated by any of the above methods. This paper presents a new matrix-fracture transfer function considering type 1: the direct inorganic matrix to fracture network inflow for pure inorganic regions; type 2: the kerogen, inorganic matrix, and fracture series flow for kerogen and inorganic-matrix interwoven regions; type 3: the direct kerogen to fracture network inflow for kerogen-rich regions. The contribution of each type in the transfer function is weighted through the volume percentage of each matrix-region type. Different multi-scale and multi-physics gas flow processes are included in kerogen and inorganic matter respectively. Finally, fluid transfer from fracture networks to hydraulic fractures is coupled through a linear flow system with stimulated reservoir volumes (SRVs). This model has been validated against field data with an excellent agreement. And the degraded model's calculation matches well with that of a published composite linear flow model. Sensitivity analyses indicate that matrix-fracture gas transfer patterns affect certain flow regimes from the matrix-fracture transient regime to the transient regime before the boundary dominant regime. Types 1 and 2 gas transfer mechanisms with direct inorganic matter and secondary fracture connection exhibit lower dimensionless pressure and higher dimensionless rate values. The effects of the organic matter volume fraction and organic-rich reservoir block allocations on well production are also documented. This approach is a general tool for characterizing the gas transfer from shale matrices to fracture networks.
- North America > United States (0.68)
- Asia > China (0.46)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (5 more...)
Abstract We present a streamline-based dual porosity simulator to model waterflooding in fractured reservoirs. Conceptually the reservoir is composed of a flowing fraction, representing the fracture network and high permeability matrix, in communication with relatively stagnant regions. Streamlines capture movement through the flowing fraction while the transfer of fluid from flowing to stagnant regions is modeled as a source/sink term in the one-dimensional transport equation along each streamline. We discuss different possible forms of the transfer function to represent counter-current imbibition. We implement three forms of the transfer function: the conventional steady-state model and two linear transfer functions that match experimental measurements on cores. An appropriate linear transfer function can be found that gives results similar to the conventional model, matches experiment and gives run times similar to standard single porosity simulation. We compare the results and run times of the streamline-based approach with conventional dual porosity grid-based simulation. Using an example North Sea dataset for a highly heterogeneous reservoir, we show that streamline simulation gives similar answers to grid-based methods when using the same transfer function, but is at least one to two orders of magnitude faster for models with 100,000 to 1,000,000 grid blocks. Introduction Streamline-based simulation is now established as an attractive alternative to conventional grid-based techniques for simulating displacements in highly heterogeneous reservoirs. For incompressible or nearly incompressible flow simulated through more than around 100,000 grid blocks, streamlines have been shown to be generally faster than grid-based methods and have been used to study several field cases in recent years. One important area of reservoir simulation that hitherto has not been addressed by streamline methods is modeling fractured reservoirs. In field-scale dual porosity models the reservoir is represented by a flowing, fracture network that transfers fluid with a less permeable matrix. As we demonstrate in this paper, conventional grid-based simulations of this problem take even more computer time than equivalent single porosity runs, which limits their use to relatively coarsely resolved reservoir models. Furthermore, there is no consensus in the literature on an appropriate form of the fracture/matrix transfer function, even for straightforward physical processes, such as capillary-controlled imbibition. We will develop a formulation that extends streamline-based simulation to model fractured media using a dual porosity approach. The fracture/matrix transfer is accommodated easily and elegantly as a source/sink term in the one-dimensional conservation equation along streamlines. Different forms of the transfer function to represent counter-current imbibition from fracture to matrix will be discussed and a new form will be proposed that matches experimental core flood measurements. Then the method will be tested on a North Sea dataset used for the 10th SPE Comparative Solution Project on Upscaling. We will show that streamline and grid-based approaches give almost identical results when using the same transfer function, but that the streamline method is 10 - 100 times faster. Streamline Formulation Conceptual model The dual porosity model represents a fractured reservoir at the large scale by two intercommunicating domains: a flowing fraction that consists of the connected fracture network and high permeability matrix; and a stagnant, low permeability matrix that holds the majority of the original oil and transfers fluid with the flowing fraction through viscous, capillary and gravity forces. While the separation of flowing and stagnant regions is geologically rather arbitrary, it is well defined mathematically. It must be emphasized that a dual porosity model does not assign a particular ‘sugar cube’ geometry to the fracture network, nor does it assume that the only flow is in fractures. We will not consider here a dual permeability model, where flow is also allowed between stagnant regions. We assume that flow in the matrix is accommodated in an average sense through a contribution to the effective permeability of the flowing fraction.
- North America > United States (0.93)
- Europe > United Kingdom > North Sea (0.44)
- Europe > Norway > North Sea (0.44)
- (2 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
ABSTRACT Application of AC direct electrical heating (DEH) on subsea pipelines requires a special design of the corrosion protection system. The first electrically heated pipelines in the North Sea were supplied with anodes banks at the ends for AC current transfer in addition to single anodes distributed along the heated pipeline according to CP-design requirements from standards and class societies. Anodes were also installed at pipejoints where pipes sections with different magnetic properties are connected, as current transfer between pipe and seawater will occur at these locations. In case of buried pipelines high temperatures for the anodes implies reduced cathodic protection. For these installations modified solutions for cathodic protection are required. Measurements have been made on a scale test installation without distributed anodes in a project initiated by an oil company. In this case the anode banks at the ends must be designed both for cathodic protection and AC current transfer to seawater. For Cr13 (13% Chromium content) pipelines welding of the anode connections should be avoided related to hydrogen embrittlement. A design with clad steel carbon pipes for the current transfer zones at the ends where anodes are connected has been chosen to solve this problem. For economical and practical reasons, the length of the clad steel sections should be as short as possible. This is especially true for a reeled installation method. It has been verified by tests that the minimum length of the clad steel section depends on the material characteristics of both the clad steel carbon pipe and Cr13 pipes. When the magnetic and electrical properties of Cr13 pipes are known, carbon steel pipes can be selected to obtain a minimum current transfer length. These material data are not available from the manufacturer and must be determined by measurements.
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Offshore pipelines (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
Abstract In modeling of fractured ultratight gas-condensate reservoirs it is particularly important to represent liquid dropout, and its impact on fluid flow behavior, accurately. This, in turn, allows for design and optimization of reservoir production strategies, to mitigate potential production loss below the dewpoint pressure. Unfortunately, the traditional transfer functions used to describe the mass transfer between matrix/fracture segments in dual-porosity models (DPM’s) do not explicitly represent the complex physics of the inherent multiphase problem, which may complicate the application of existing simulators. Therefore, the objective of this work is to develop a two-phase transfer function that improves the modeling of gas-condensate systems via a DP representation. Commercial simulators typically offer a simple matrix/fracture mass transfer model to perform calculations in DP systems: The default shape factors are based on a pseudo-steady state (PSS) approximation, and for multiphase problems, the transfer function of Kazemi et al. (1976) is commonly used. Without sub-gridding, the traditional transfer functions cannot represent the extended transient behavior observed in ultratight fractured reservoirs. Furthermore, in compositional modeling of gas-condensate reservoirs, the averaging of matrix block properties masks the compositional changes near the matrix/fracture interface, that is critical to prediction of production behavior below the dewpoint. To overcome the limitations of the current models, we introduce a new transfer function that includes 1) a time-dependent shape factor and 2) a modified representation of the two-phase flow. We utilize the correction factor introduced by Zhang et al. (2022) allowing the shape factors to vary with time. For two-phase problems, instead of evaluating the mass transfer at an average pressure and composition, we propose a novel approach that evaluates the transfer function at conditions that reflect/approximate the pressure and composition/saturation gradients within the matrix block. By approximating the fluid state near the matrix/fracture interface, we represent the liquid buildup that dictates the fluid mobility more accurately. The open-source MATLAB Reservoir Simulation Toolbox (MRST) was used as a platform for the work presented in this paper: The existing single-porosity (SP) compositional model of MRST was first extended and validated (with the analytical solution for the single-phase pressure diffusion equation) to allow for DP modeling and simulation of condensate systems. We present calculation results for a single-block DPM, representative of a fractured ultratight gas-condensate reservoir, to demonstrate the limitations of the traditional mass transfer modeling approach. We then introduce the new transfer function and compare all calculation results with fine-grid SP reference models. In this work, we consider two condensate fluid descriptions: 1) a 4-component analog rich gas, and 2) a realistic 24-component fluid description from a gas-condensate reservoir. We demonstrate that the new transfer function represents the physical mechanisms at play more accurately and provides for a substantial improvement over the traditional formulation in terms of the amounts and compositions of the produced phases. The proposed method is motivated by the physics of the problem and requires no sub-gridding. The enhanced simulation of gas-condensate systems enables improved decision making in reservoir management and supports optimization of field development plans. In addition, the improved calculation of the surface streams, obtained from the new method, provides for a more accurate design of field surface facilities.
- Asia > Middle East (0.93)
- North America > United States > California (0.28)
- North America > United States > Texas (0.28)
- Information Technology > Software (0.68)
- Information Technology > Modeling & Simulation (0.66)