|Advanced Technology for Predicting the Fluid Flow Attributes of Naturally Fractured Reservoirs from Quantitative Data and Modeling
This project was selected in response to DOE's Oil Exploration and Production solicitation DE-PS26-01NT41048 (focus area: Critical Upstream Advanced Diagnostics and Imaging Technology). The goal of the solicitation is to continue critical upstream cross-cutting, interdisciplinary research for the development of advanced and innovative technologies for imaging and quantifying reservoir rock and fluid properties for improved oil recovery.
The goal is to study the size, clustering, and connectivity of rock fractures for improved ability to plot how these features control the movement of reservoir fluids during injection or extraction and to enable design of optimal production processes.
University of Texas at Austin
The project focused on predicting connectivity, clustering, and aperture-fracture pattern attributes that are exceedingly difficult to measure but can be the controlling factors for fluid movement (during injection or extraction) in an oil reservoir. The project involved a multi-disciplinary team whose purpose was to advance technology in the field of fractured reservoir characterization, integrating geological observational techniques and modeling to the fluid-flow quantification of fractured reservoir blocks.
The goal of this research is to develop new technology for the reliable prediction of fracture pattern attributes related to subsurface fluid flow. This would enable producers to optimize development and production schemes, thereby boosting oil production and ultimate oil recovery.
Fractured reservoirs are a challenging reservoir management and exploitation problem. There are two main aspects of fractured reservoir engineering that still need significant technology development: fracture pattern characterization and fractured reservoir flow simulation. This project has an interdisciplinary team of engineers and geologists working on both of these problems in concert in an attempt to advance the state of the art.
The project comprised four main tasks:
In tackling these tasks, the project focused on four main areas of challenge:
- Task 1: Quantify the systematics of fracture opening distributions, as only open fractures impact fluid flow. Previous work indicates that many permeable fractures in reservoirs are propped open by partial mineralization. The researchers sought to quantify that through microscopic analysis for subsurface core.
- Task 2: Investigate the theoretical aspects of fracture mineralization and why some fractures fill only partially while others completely close. This involves a geochemical analysis of mineral deposition in fractures. Observations and analysis of fracture infilling by minerals are being performed in the geomechanical context of natural fracture pattern development.
- Task 3: Conduct a systematic study of the fracture mechanics properties of rock that control fracture pattern geometry.
- Task 4: Integrate all of the fracture observations by using a reservoir simulation code that discretely accounts for each fracture in an effort to quantify the flow properties of different fracture realizations.
- Observational verification of a characteristic fracture size (aperture) below which natural fractures are completely mineralized and above which fractures preserve porosity and would be expected to be conduits for flow.
- Theoretical investigation of the geochemical controls on fracture mineralization and how fracture aperture size can affect the amount of preserved porosity in natural fractures.
- Quantification of the fracture mechanics properties, particularly subcritical crack growth parameters, in oil reservoir rock types and investigation of the role of diagenesis in controlling the change of these parameters through time (over the burial history of a reservoir).
- Fluid-flow analysis of fracture network realizations generated using a geomechanical model that incorporates diagenetic modification of fracture apertures.
In Task 1, extensive observations were made using SEM-based cathodoluminescence technology on a wide spectrum of samples from oil wells. The size at which porosity begins to be preserved in small natural fractures is being quantified. The data collected will help to identify the processes that preserve or destroy fracture porosity. This will lead to more-accurate estimates of fracture surface area and storage volume, and results will be usable in engineering simulations.
In Task 2, progress was made in the geochemical analysis of cement deposition in fractures, having developed a computer code that has two-dimensional fluid flow in the fracture as well as chemical reaction simulation.
In Task 3, researchers came up with a theoretical explanation for the nature of fracture length distributions in fracture patterns that will aid in predicting flow continuity in fracture systems. In addition to the theoretical expressions, numerical simulations have been made to better explain fracture clustering, a common attribute in fractured reservoirs. In order to support numerical modeling, laboratory fracture mechanics tests were performed to quantify the subcritical crack propagation properties of subsurface reservoir samples. This work has established a correlation between grain size, cementation, and fracture mechanics properties.
In Task 4, researchers were able to match analytical permeability calculations for a periodic array of non-interconnected fractures using the commercial simulator Eclipse and non-neighbor connections.
The project is complete.
Project Start: September 28, 2000
Project End: January 15, 2004
Anticipated DOE Contribution: $836,716
Performer Contribution: $316,064 (25% of total)
NETL - Daniel Ferguson (firstname.lastname@example.org or 918-699-2047)
University of Texas at Austin - Jon Olson (email@example.com or 512-471-7375)