Oil & Natural Gas Projects
Exploration and Production Technologies
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
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
- 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
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 (email@example.com or 918-699-2047)
University of Texas at Austin - Jon Olson (firstname.lastname@example.org or 512-471-7375)