Diagnostic Techniques To Understand Hydraulic Fracturing: What? Why? and How?
- C.L. Cipolla (Pinnacle Technologies) | C.A. Wright (Pinnacle Technologies)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Facilities
- Publication Date
- February 2002
- Document Type
- Journal Paper
- 23 - 35
- 2002. Society of Petroleum Engineers
- 3.3.1 Production Logging, 5.5.8 History Matching, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 1.6.9 Coring, Fishing, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.7.2 Recovery Factors, 2.5.4 Multistage Fracturing, 2.2.2 Perforating, 3.3.2 Borehole Imaging and Wellbore Seismic, 2.4.3 Sand/Solids Control, 5.4.1 Waterflooding, 2.5.1 Fracture design and containment, 6.5.3 Waste Management, 4.1.2 Separation and Treating, 5.4.6 Thermal Methods, 3 Production and Well Operations, 5.6.5 Tracers, 5.4.2 Gas Injection Methods, 5.6.4 Drillstem/Well Testing, 1.6 Drilling Operations
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In recent years, there have been numerous advances in fracture mapping/diagnostic technologies. This paper details the state of the art technologies in applying both conventional and advanced methods to better understand hydraulic fracturing and improve treatment designs. The initial portion of the paper describes the application and limitations of various diagnostic tools and methods, including well testing, net pressure analysis (fracture modeling), techniques that employ open- and cased-hole logs, surface- and downhole-tilt fracture mapping, microseismic fracture mapping, and production-data analysis. The bulk of the paper is dedicated to case histories that illustrate the application of these fracture-diagnostic technologies. The case histories include examples of how several fracture diagnostics can be used in concert to provide more reliable estimates of fracture dimensions and allow better economic decisions.
The process of hydraulic fracturing has always had a "black box" image. This has been partly because knowledge about fracture geometry is difficult to obtain, with fractures growing thousands of feet below the surface, and partly because fracturing is proving to be vastly more complex than initially thought.1-3 While hydraulic fracture treatments continue to be designed with the best tools and techniques available, geometry estimates from fracture models have been difficult to verify. Numerous fracture-diagnostic techniques have been developed to fill this knowledge gap, improving our understanding of hydraulic-fracture behavior.4-10
The main purpose of fracture diagnostics is to help the producer optimize field development and well economics. This can include optimizing individual fracture treatments to obtain the most economic design and optimum interval/height coverage or optimizing the entire field development in terms of well spacing and location. Fracture diagnostics can be beneficial in numerous stimulation settings. Settings range from propped-fracture stimulation of a new pay zone in a newly developed field to infill-drilling development, and from field development with hydraulically fractured horizontal wells to the evaluation of fracturing during steamflooding or waterflooding.
When executing fracturing operations in one of these settings, several questions can be answered in the design/evaluation process using fracture diagnostics, including:
Do fractures effectively cover the pay zone?
Are fractures confined to the pay zone?
Does the fracture grow into an unwanted gas- or waterbearing zone?
What is the optimum number of fracture-treatment stages and the best treatment size to cover thick pay zones?
How much more length/height/production is obtained if treatment size is increased?
Is the final fracture conductivity sufficient to achieve the desired production? What is the optimum proppant?
Is the hydraulic fracture oriented in the same direction as the primary set of natural fractures?
What direction should a horizontal well be drilled to complete it with transverse (or longitudinal), multistage fracture treatments?
Is the well pattern appropriate to maximize sweep efficiency in steam/waterflood areas?
Do the injected waste and drill cuttings remain within the selected zone?
Numerous fracture diagnostics are available (see Fig. 1), including techniques that directly image "big picture" far-field fracture growth, dimensions, and orientation; tools that provide a local measurement of the fracture at the wellbore; and lower-cost, indirect (model-dependent) diagnostic methods. There are three main groups of commercially available fracture-diagnostic techniques, each with its own set of capabilities and limitations. A summary of the techniques, limitations, and the parameters each technique measures is provided in Table 1.11
Group 1-Direct Far-Field Fracture Diagnostic Techniques.
This group currently comprises two relatively new types of fracture diagnostics - tiltmeter and microseismic fracture mapping. These diagnostics are conducted from offset wellbores and/or from the Earth's surface during the fracture treatment and provide information about "big picture" far-field fracture growth. A limitation of these techniques is that they map the total extent of hydraulic- fracture growth but provide no information about the effective propped-fracture length or conductivity. The resolution of these techniques decreases with increasing distance from the fracture (see Table 1 for details).
Surface- and Downhole-Tilt Fracture Mapping.4-7
The principle of tiltmeter fracture mapping is quite simple (see Fig. 2 ). A created hydraulic fracture results in a characteristic deformation pattern of the rock surrounding the fracture. By measuring the hydraulic-fracture-induced tilt (deformation) of the Earth at several locations (surface and/or downhole) with extremely accurate "carpenter's levels," the fracture orientation (with surface tiltmeters) and geometry (with downhole tiltmeters) can be obtained.
Surface tiltmeters are deployed in shallow holes (20 to 40 ft deep) at radial distances from as close as a few hundred feet to as far as 1 mile around the injection well, depending on the depth of the treatment zone and the expected fracture dimensions. The array of surface tiltmeters measures the gradient of the displacement and provides a map of the deformation of the Earth's surface above the fracture. Analysis of this tilt field provides a measurement of the fracture azimuth, dip, depth-to-fracture center, and total fracture volume. Because surface tiltmeters are typically very far from the created fracture, they cannot precisely resolve fracture length and height.
Downhole tiltmeter mapping is based on the same concept as surface tiltmeter mapping, but instead of being at the surface, the tiltmeters are positioned by wireline in one or more offset wellbores at the depth of the hydraulic fracture. Downhole tiltmeters provide a map of the deformation of the Earth adjacent to the hydraulic fracture. In most applications, downhole tiltmeters can be placed much closer to the fracture than surface tiltmeters and are, therefore, significantly more sensitive to fracture dimensions. The measured tilt is used to determine fracture height, length, and width vs. time.
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