Fracture-Related Diagenesis May Impact Conductivity
- Jim Dean Weaver (Halliburton Energy Services Group) | Mark Parker (Halliburton Energy Services Group) | Diederik W. van Batenburg (Halliburton) | Philip Duke Nguyen (Halliburton Energy Services Group)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- September 2007
- Document Type
- Journal Paper
- 272 - 281
- 2007. Society of Petroleum Engineers
- 1.6.9 Coring, Fishing, 2.4.3 Sand/Solids Control, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.1.1 Exploration, Development, Structural Geology, 4.1.2 Separation and Treating, 1.8 Formation Damage, 5.3.4 Integration of geomechanics in models, 2.5.2 Fracturing Materials (Fluids, Proppant), 4.2.3 Materials and Corrosion, 2.4.5 Gravel pack design & evaluation, 3 Production and Well Operations, 1.4.3 Fines Migration
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Rapid loss of fracture conductivity after hydraulic fracture stimulation has often been attributed to the migration of formation fines into the proppant pack or the generation of fines derived from proppant crushing. Generation of crystalline and amorphous porosity-filling minerals can occur within the proppant pack because of chemical compositional differences between the proppant and the formation, and the compaction of the proppant bed because of proppant pressure solution reactions. Findings presented in this paper suggest that diagenesis-type reactions that can occur between proppant and freshly fractured rock surfaces can lead to rapid loss of proppant-pack porosity and loss of conductivity.
Lehman et al. (2003) reported that the use of surface-modification agents (SMA) to coat proppants used in propping hydraulic fractures resulted in sustained and more uniform production from wells. Fig. 1, taken from that publication, shows the production decline curves from some of their data, and it does appear to show a significant change in decline rate compared to the use of untreated proppant. This SMA was described as a nonhardening resin that is insoluble in water and oil. It is supplied in a solvent that is quickly extracted once it is introduced to aqueous-based frac fluids, leaving a tacky, hydrophobic coating on the proppant.
Initial use of this type of SMA treatment (Dewprashad et al. 1999; Nguyen et al. 1998a, b) was promoted as a method to increase the conductivity of proppant owing to its capability to prevent close packing of the proppant, which can result in increased porosity and permeability of the pack, by rendering the proppant surface tacky. Subsequent studies indicated that its use provided proppant-pack protection from fines infiltration and migration. This mechanism has been employed to explain the observations that sustained production results from the use of SMA on proppants. This is further substantiated by long-term results obtained in a single field study known for fines production problems. That both mechanisms are active has been well established through laboratory studies, but they alone do not completely explain the reduction in production decline rate as reported.
A field study of SMA-treated proppant was reported to the Arkansas Oil and Gas Commission 2004 CBM Workshop that disclosed long-term results on gas production. These were CBM wells in the San Juan basin that typically required refracturing each year to produce at an economical rate. With the SMA-treated proppant, no refracs have been required, and as shown in Fig. 2, production has remained essentially constant for 5 to 6 years. This longevity was initially attributed to prevention of fines invasion into the proppant pack; however, it is possible that there are additional mechanisms operational.
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