A comparative study of flowback rate and pressure transient behavior in multifractured horizontal wells completed in tight gas and oil reservoirs

Abbasi, Majid; Ezulike, D. O.; Dehghanpour, Hassan; Hawkes, Robert

doi:10.1016/j.jngse.2013.12.007

Cited by 121 publications

(54 citation statements)

References 12 publications

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“…6 presents the corresponding production profiles after a shut-in duration of 23.5 h. The production trends are in good agreement qualitatively with those observed in the field, as reported in Fig. 3 of Abbasi et al (2014). Oil production is zero when flow-back commences, and it continues to rise after approximately 3 hours; the initial high water rate, on the other hand, continues to decline as flow-back progresses.…”

Section: Fluid-loss Mechanismssupporting

confidence: 81%

“…For example, Abbasi et al (2014) assumed singlephase flow, although two-phase flow might exist even during early flow-back. Ezulike et al (2013) proposed a two-phase dual-porosity model with single-phase oil flow in matrix and negligible saturation and capillary pressure gradient in fracture, assuming that the initial hydrocarbon volume in fracture prior to flow-back was known.…”

Section: Introductionmentioning

confidence: 99%

See 1 more Smart Citation

Numerical investigation of fluid-loss mechanisms during hydraulic fracturing flow-back operations in tight reservoirs

Wang

Leung

2015

Journal of Petroleum Science and Engineering

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Section: Fluid-loss Mechanismssupporting

confidence: 81%

Section: Introductionmentioning

confidence: 99%

Numerical investigation of fluid-loss mechanisms during hydraulic fracturing flow-back operations in tight reservoirs

Wang

Leung

2015

Journal of Petroleum Science and Engineering

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“…We have made the simplifying assumption that all fractures contribute equally to the well. Abbasi et al (2014) also discuss application of the flowing material-balance technique to single-phase flowback data.…”

Section: Figurementioning

confidence: 99%

Innovative use of rate-transient analysis methods to obtain hydraulic-fracture properties for low-permeability reservoirs exhibiting multiphase flow

2014

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Multifractured horizontal wells, while enabling commercial production from unconventional gas and light-oil reservoirs, are challenging to analyze quantitatively to obtain reservoir and hydraulic-fracture properties. Production rates and flowing pressures gathered immediately after hydraulic-fracture stimulation (flowback) and over a longer time period (on-line production) can be interpreted for hydraulic-fracture properties such as fracture surface area or half-length and fracture conductivity, but dynamic fracture properties and multiphase flow during both stages of production can complicate the analysis. Recent studies have suggested that flowback data can provide early insight into these fracture properties if high-resolution fluid rates/pressures are gathered, but the physics of the process are complex, and analytic methods for interpretation are at an early stage of development. Analytic methods for longer-term production data analysis, although better established, are still limited primarily to single-phase flow and simple fracture and reservoir behavior. Rate-transient methods can be applied to both flowback and long-term production data to quantify hydraulic-fracture properties and changes in effective hydraulic-fracture length during production. For the flowback period, simplified analytic methods have been developed for before-breakthrough production of hydraulic-fracturing fluids and after-breakthrough production of hydraulic-fracture and reservoir fluids. These methods are still under development, and early applications can be illustrated. For long-term production analysis, classic rate-transient analysis techniques, such as the square-root-of-time plot, have been modified to account for multiphase flow and stress-sensitive permeability exhibited by low-permeability gas condensate and black-oil reservoirs producing below saturation pressure. A field example consisting of a multifractured horizontal well completed in a tight-oil reservoir isused to to compare hydraulicfracture properties derived from flowback and long-term production data. Although flowback analysis yields hydraulic-fracture half-lengths consistent with hydraulic-fracture modeling results, long-term production analysis yields much smaller fracture half-lengths, possibly because of breakthrough of gas once bubble-point pressure is reached. Additional mechanisms for effective producing fracture half-length reduction can be proposed. Another important observation is that estimation of fracture properties from long-term production analysis of a reservoir producing below saturation pressure can be in significant error if the estimates are derived from techniques assuming singlephase flow. Corrections to the analytic methods for multiphase flow yield fracture half-lengths consistent with those obtained from history matching using rigorous numerical simulation. In a preliminary analysis, the techniques under development are intended to aid hydraulic-fracture evaluation and design in tight reservoirs that exhibit complex flow characteristics....

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“…Bearinger (2013) distinguished flowback fluid behavior related to a single fracture plane from that of a complex fracture architecture. Sharak et al (2014) have developed two statistical based models and present that characterizing the trend of the salinity measurements of flowback fluid can lead to a representation of the fracture complexity, and Abbasi (2013) studied the transient pressure, rate and fluid concentration to establish a link between the salt returns at surface and the reservoir volume contacted. Song and Ehlig-Economides (2011) showed evidence of lower than expected gas drainage volume in Haynesville shale gas wells based on long term production data; they attributed this to shorter than expected hydraulic fractures.…”

Section: Introductionmentioning

confidence: 99%

Model for a Shale Gas Formation with Salt-Sealed Natural Fractures

Merry

Ehlig-Economides

Pang

2015

Day 3 Wed, September 30, 2015

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Most multiple transverse fracture horizontal wells in shale gas formations remain in transient bilinear or linear flow for very long periods, typically several years. Some plays show very different behavior that has been attributed to pressure dependent permeability. Often, there are reported cases of shale wells that exhibit boundary dominated flow in a very short period that implies a stimulated rock volume (SRV) much smaller than would be expected based on the hydraulic fracture treatment design. This paper offers an alternative explanation for the early boundary dominated flow related to dissolution of salt-sealed natural fractures in the shale. Three plays are the target of this study, namely, the Haynesville shale, the Marcellus shale, and the Horn River Basin.Flowback of water with significantly higher salinity than the injected fracture fluid may suggest that the injected low salinity fracturing fluid dissolved salts that seal an existing natural fracture system. Evidence would be seen in long-term transient rate and pressure production data as early boundary dominated flow providing the natural fracture pore volume dissolved by injected low salinity fracturing fluid that leaked off during the hydraulic fracture treatment. In this scenario, the effective permeability would represent that of the natural fracture system induced by salt dissolution, and the stimulated rock volume would be directly related to the leakoff volume.This study first discusses a plausible diagenetic history for generation of a salt-sealed natural fracture system in shale gas and how core, log, and conventional test data may behave. We then present a material balance model for behavior of the salt-sealed fracture porosity, the shale matrix porosity, and fracture pore volume dissolved by the leaked off fracture fluid, during the fracture treatment and subsequent early and long term production. We show the resulting permeability loss as residual water vaporizes. The significance of the model is a new rationale for a correlation between apparent stimulated rock volume and injected fluid during hydraulic fracturing.

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A comparative study of flowback rate and pressure transient behavior in multifractured horizontal wells completed in tight gas and oil reservoirs

Cited by 121 publications

References 12 publications

Numerical investigation of fluid-loss mechanisms during hydraulic fracturing flow-back operations in tight reservoirs

Numerical investigation of fluid-loss mechanisms during hydraulic fracturing flow-back operations in tight reservoirs

Innovative use of rate-transient analysis methods to obtain hydraulic-fracture properties for low-permeability reservoirs exhibiting multiphase flow

Model for a Shale Gas Formation with Salt-Sealed Natural Fractures

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