Stimulation Flowback Management--Keeping a Good Completion Good

Crafton, Jim; Gunderson, Daniel

doi:10.2523/110851-ms

Cited by 9 publications

(3 citation statements)

References 15 publications

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“…For example, two different wells almost never follow the same pressure drawdown "path". So the integral over time of the pressure drawdown could strongly influence the cumulative production, not just of the individual phases but how they interact (17,21,22). Therefore, just comparing cumulative gas production would be misleading.…”

Section: (1mentioning

confidence: 99%

The Effect of Micro-Emulsions On High and Low GOR Gas Wells

Crafton

Penny

Burkett³

2009

SPE Tight Gas Completions Conference

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An extensive, ongoing investigation into the effectiveness of a micro-emulsion (ME) as a stimulation fluid additive is being conducted. Results from a population of 114 wells and 498 stimulation stages of hydraulic fracture stimulation provide the basis for this report. As part of the basis for the performance analysis, twenty four of the wells are producing from the Lance interval in the northeastern Pinedale Anticline area of the Green River Basin, Wyoming. The remaining 90 wells produce from the northern Denver-Julesburg Basin Codell and Niobrara formations. In both data sets about half of the wells had 1.5 gallons of ME per thousand used throughout the fracture stimulations, but at no other time during in-well operations. The stimulation fluid systems in the remaining wells contained no similar interfacial tension / surfactant system. Based on the performance matched reservoir properties and degree of effective stimulation, these comparisons and other performance metrics were used to assess the potential benefit arising from using ME. The determination of potential benefit was assessed using classical statistical methods to ensure that the interpretation was as unbiased as possible. From that analysis, there is distinct and clear benefit to be gained from using the micro-emulsion to facilitate placing the fracture stimulations, to increase effective fracture length and especially to increase hydrocarbon recovery from the wells in which the micro-emulsion system is used. Review of Prior Work The Codell-Niobrara reservoirs in the DJ Basin have been studied extensively (Refs. 1-4). Characterization of the reservoir system is well documented. Almost 80 percent of the wells in this study are in the "oily" portion of the Codell-Niobrara reservoir system. Likewise, the Lance formation in the Green River Basin has received considerable attention (5-8, 10). In particular, an analysis of the impact of micro-emulsions on well performance has previously been reported for the Green River Basin, Lance Formation (Ref. 5), in which ME is shown to facilitate placing the fracture stimulations, to increase effective fracture length, to minimize damage arising from operational shut-ins and to increase gas recovery of wells in which ME is used. The results of that investigation are relied upon in this study, as well. Similar studies have been conducted in the Canyon Sands of West Texas by Pursley, Benton, Nordlander, etal. (6). They concluded that the wells in which a micro-emulsion (ME) was used a) had better reservoir conductivity, b) longer effective fracture lengths, c) better resistance to damage resulting from shut-in events and d) better long-term performance than those without it. Reports have been made regarding the impact of ME on formation damage mitigation (7). Other studies have particularly investigated the impact of zone isolation (8, 9) and proppant type effectiveness (10). Neither of these employed rigorous normalization procedures to ensure proper assessment of the impact of reservoir quality, etc. The latter au...

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Section: (1mentioning

confidence: 99%

The Effect of Micro-Emulsions On High and Low GOR Gas Wells

Crafton

Penny

Burkett³

2009

SPE Tight Gas Completions Conference

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“…This idea is well followed when it comes to the MHF of a shale gas reservoir for a high shale gas production rate. 8,9 Numerous studies were focused on increasing the flowback rate of shale gas reservoirs. Adding surfactant into the fracturing fluid is an effective means of improving the flowback rate of HFF by reducing the gas−water interfacial tension and altering the rock wettability.…”

Section: Introductionmentioning

confidence: 99%

“…Therefore, pursuing a high flowback rate of hydraulic fracturing fluid (HFF) is the key to gaining a high tight sand gas production rate. This idea is well followed when it comes to the MHF of a shale gas reservoir for a high shale gas production rate. , …”

Section: Introductionmentioning

confidence: 99%

Zero Flowback Rate of Hydraulic Fracturing Fluid in Shale Gas Reservoirs: Concept, Feasibility, and Significance

et al. 2021

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A high flowback rate of hydraulic fracturing fluid (HFF) yields a high gas production rate in a tight sand gas reservoir. This idea is well followed when it comes to the hydraulic fracturing of a shale gas well. Therefore, numerous studies have focused on increasing the flowback rate of HFF in shale gas reservoirs to mitigate the water blocking damage. Yet, only a small portion of the injected fluid (less than 20%) could be recovered during flowback operation. Moreover, there is no good correlation between the gas production rate and flowback rate for shale gas wells. Surprisingly, a phenomenon that a low flowback rate of HFF usually yields a high gas production rate is found recently by field data studies. In this case, the authors investigated the reasons for this abnormal phenomenon and believed that reducing the flowback rate of HFF in a shale gas reservoir could be a new strategy for dealing with the injected HFF. Therefore, a new concept called zero flowback rate (ZFR) of HFF is put forward to serve as an unconventional way to manage the high volume of HFF. ZFR of HFF is a concept compared with the flowback rate of the fracturing fluid for a conventional reservoir. It is worth noting that zero in the ZFR concept does not stand for the absolute number 0. It means that reducing the flowback rate of HFF is the goal of the ZFR strategy. To analyze the feasibility of realizing ZFR, the geological conditions of gas shale and engineering conditions of hydraulic fracturing were evaluated by comparing the relative studies. It showed that gas shale has the potential to imbibe most of the HFF and retain the imbibed fluid without contaminating the groundwater. ZFR can be realized by extending the shut-in time or adjusting the properties of HFF. Compared with the conventional idea of increasing the flowback rate of HFF, ZFR is of great significance. It does not only recover the relative gas permeability of the shale reservoir by redistributing the liquid phase from the fractures into the shale matrix but also enhances it by creating new microfractures. ZFR is cost-saving and environmentally friendly by dealing with a reduced volume of flowback HFF. ZFR has a high potential of becoming a viable strategy for the development of shale gas reservoirs.

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Gas Shale Challenges Over the Asset Life Cycle

Kennedy

2015

Fundamentals of Gas Shale Reservoirs

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Stimulation Flowback Management--Keeping a Good Completion Good

Cited by 9 publications

References 15 publications

The Effect of Micro-Emulsions On High and Low GOR Gas Wells

The Effect of Micro-Emulsions On High and Low GOR Gas Wells

Zero Flowback Rate of Hydraulic Fracturing Fluid in Shale Gas Reservoirs: Concept, Feasibility, and Significance

Gas Shale Challenges Over the Asset Life Cycle

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