Lateral Proppant Distribution: The Good, the Bad, and the Ugly of Putting Frac Jobs Away
- W.W. Aud (Integrated Petroleum Technologies Inc.) | T.D. Poulson (Integrated Petroleum Technologies Inc.) | R.A. Burns (Ocean Energy Inc.) | T.R. Rushing (Anadarko Petroleum Corp.) | W.D. Orr (Anadarko Petroleum Corp.)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- March 2001
- Document Type
- Journal Paper
- 4 - 11
- 2001. Society of Petroleum Engineers
- 2.2.2 Perforating, 5.4.2 Gas Injection Methods, 2.4.6 Frac and Pack, 2.5.1 Fracture design and containment, 3 Production and Well Operations, 2.4.3 Sand/Solids Control, 4.3.4 Scale, 4.1.3 Dehydration, 2.5.2 Fracturing Materials (Fluids, Proppant), 1.6 Drilling Operations, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 4.1.2 Separation and Treating
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This paper shows proppant-induced pressure increase (i.e., tip screenout, pack, body pack, etc.) can relate to restricted vertical and lateral proppant distribution in hydraulic fractures. The discussion focuses on interpretation of the character of the pressure response during the proppant stages. Essentially, this pressure response relates directly to the quality of the production response and the level of success. The technology presented has been found to apply to all rock types, frac packs, and low-permeability and water-frac applications.
This area of study is based on extensive engineering studies and common sense observation. Prior to publication of this work, this approach fit the reservoir engineering interpretation of the producing character and advanced fracture-treatment-pressure interpretation on a minimum of 1,000 wells. When premature proppant-induced friction occurs in the hydraulically induced fracture, lateral and vertical proppant distribution adjacent to the pay interval can be affected negatively. Restricted proppant distribution results in less effective stimulation because proppant is not distributed well both vertically and laterally adjacent to the pay interval. The fracture stimulation may have been "put away;" but the negative aspects of how the stimulation was designed and implemented may have a significant effect on the resultant production response.
To establish the basis for additional thought and investigation, there is discussion about deficiencies in overly simplified pretreatment minifracture-analysis procedures. Many of these analysis methods are not focused on the proppant-induced friction character, and therefore do not optimize proppant distribution. Discussion is provided regarding differences in the proppant-induced friction character of various fracturing fluids which is not an inherent variable typically included in fracture-treatment-design methodology.
The technology presented is derived from a significant volume of work based on an integrated engineering approach to determine the effectiveness of the completion and stimulation method. Over the last 6 years, the technical advancement by Integrated Petroleum Technologies Inc. (IPT) presented in this paper has been extensive in the application of this area of study. The resultant production responses in many areas have been significant, supporting the credibility of the technology presented.
During the mid-1990's, downward proppant movement (i.e., clustering, settling, convection1-4) in hydraulic fractures received significant attention in technical papers, forums, meetings, etc. It was depicted as a dominant variable in hydraulic fracturing and, if not addressed, the reason many wells did not produce properly. Proppant was theorized to move to the bottom of the fracture and not be adjacent to the pay interval. An approach for minimizing downward proppant movement was to "tip screenout" or "pack" the fracture.
The viewpoint existed for many years that a tip screenout is the ideal response. If conductivity is desired, then build the fracture conductivity by screening out or packing the fracture. This may apply in high-permeability, low-modulus rocks; however, packing the fracture in low- to moderate-permeability rocks has been found to be detrimental to desired results.
During the early to mid-1990's, many fractures were packed at various levels of pressure increase to minimize the hypothesized severity of downward proppant movement and achieve a tip screenout. Through detailed reservoir engineering evaluation, these packed fractures were determined to have either short effective fracture lengths or skin damage. Our initial evolution was to reduce the level of proppant-induced pressure increase/pack. Excessive levels of proppant-induced pressure increase were determined to be causing damage as a result of polymer dehydration ("polymer squeeze") in the formation and fracture. With proppant-induced pressure increases of less than 1,000 psi, reservoir engineering analysis continued to show effective fracture lengths shorter than expected. Design criteria evolved to a lower (<500 psi) proppant-induced pressure increase. The effective fracture length from reservoir analysis became longer, but still did not meet fracture model-treatment-design expectations. To improve the predictive capability derived from stimulation designs, customized fracture models were developed that matched the proppant-induced friction character observed for various fluids, formations, fracture geometries, etc. Using these customized models further reduced the level of proppant-induced pressure increase. With the application of these customized models, resultant fracture lengths determined from reservoir analyses became longer and matched fracture lengths predicted in the original fracture-treatment design.
When evolving in this direction, it was found that many minifracture techniques and standard industry fracture-model usage were flawed and did not rigorously account for proppant-induced friction effects. Standard minifrac evaluation was designed based on leakoff and fracture geometry assumptions during an era when a tip screenout was the ideal approach. These methods were not tailored toward optimizing proppant distribution because they do not focus on the influence of proppant-induced friction.
During this same period, we began studying and observing microseismic and tiltmeter imaging of hydraulically induced fractures.5-6 Conclusions from these projects relate primarily to hydraulically induced effects and do not discern proppant distribution in the fracture. However, a consistent observation was that injection of proppant affected the imaged fractures. Changes observed in fracture-growth profiles included reduced lateral-fracture growth and additional fracture-height growth, usually upward.
Fracture-imaging observations were coupled with the reservoir engineering and fracture-treatment net-pressure interpretation of many wells. The lateral proppant-distribution hypothesis was the consistent logic path that fit all scenarios. If proppant was entering the fracture and building proppant-induced friction, then how was the proppant efficiently distributing vertically and laterally adjacent to the pay interval? Furthermore, what effect does this frictional back-pressure have on the hydraulic-fracture geometry and injection profile of the slurry? As Baree7 presented in 1991, increased pressure at the fracture tip will cause fracture-height growth. The propped tip that is screening out could be significantly different than the hydraulic tip of the fracture.
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