The role of hydraulic fracture geometry and conductivity profile, unpropped zone conductivity and fracturing fluid flowback on production performance of shale oil wells

Zanganeh, Behnam; Ahmadi, M.; Hanks, Catherine L.; Awoleke, Obadare O.

doi:10.1016/j.juogr.2014.11.006

Cited by 17 publications

(4 citation statements)

References 15 publications

(25 reference statements)

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“…Approximately 40% of the produced water from a well after fracturing comes back as rapid flow in the first 1 or 2 weeks of production (IHS, 2012). Based on simulation models, Zanganeh et al (2015) stated that most of the fracturing fluid recovery occurs during the first year and especially during the first 2 months of production.…”

Section: Mass Balance and Flowback Recovery Ratesmentioning

confidence: 99%

Recovery rates of fracturing fluids and provenance of produced water from hydraulic fracturing of Silurian Qusaiba hot shale, northern Saudi Arabia, with implications on fracture network

Birkle

2016

Bulletin

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Geochemical fingerprinting of produced water from hydraulic fracturing projects is an essential tool to trace their provenance during the postfracturing period, to quantify recovery rates and volumes of fracturing fluids, and to visualize the geodynamic structure of natural or induced fracture networks. A total of 41 produced water samples from an exploration well in the Northern Arabia Exploration Area in Saudi Arabia were collected daily from the fracture-stimulated Qusaiba hot shale and analyzed for major ions and trace elements and partially for environmental isotopes. The postfracturing period shows an initial return of supply water and potassium chloride brine, subsequently replaced by the inflow of sodium chloride-type formation water with a stable plateau salinity of 50,000 mg/L. Less than 10% of the total injected fracturing fluids were recovered during postfracturing, whereas 78.8 vol. % of the total recovered fluid is composed of formation water (20,843 out of 26,446 bbls) during the study period. Coinciding values between logged reservoir temperature and calculated geothermometers confirm the provenance of pore water from the Qusaiba hot shale or from nearby units. The recharge of the Silurian sequence with meteoric surface water occurred during the early Holocene (6-6.7 ka), as evidenced by geochronological dating with the 14 C method and d 18 O/d 2 H values close to the global meteoric water line. The inflow of formation A U T H O R SPeter Birkle~Geology Technology Team,

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Section: Mass Balance and Flowback Recovery Ratesmentioning

confidence: 99%

Recovery rates of fracturing fluids and provenance of produced water from hydraulic fracturing of Silurian Qusaiba hot shale, northern Saudi Arabia, with implications on fracture network

Birkle

2016

Bulletin

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“…Adil et al (2015) proposed a reservoir simulation strategy and the workflow for unconventional gas reservoirs. Zanganeh et al (2015) investigated the effect of fracturing fluid and fracturing geometry on shale oil performance. All of these methods require reservoir parameters and fracture distribution.…”

Section: Introductionmentioning

confidence: 99%

A workflow for flow simulation in shale oil reservoirs: A case study in woodford shale

Sharifi

Kelkar

Karkevandi-Talkhooncheh

2021

Adv. Geo-Energy Res.

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In recent years, with new technologies of long horizontal wells and staged hydraulic fracturing, the development of unconventional oil and gas reservoirs (i.e., shale gas and shale oil) has gained significant momentum. Due to extremely low permeability, these unconventional formations cannot be produced economically without significant stimulation. In the current research, the workflow for shale reservoir history matching that can be used for other shale resources producing from either condensate or oil reservoirs is developed. Production data and well geometry data for nineteen wells were available in Woodford shale. During this work, using the available data, single well simulation models for all the individual wells were constructed and then models were tuned to match the historical data. It has been shown that the fracture half length, shear fracture distribution and the interaction between matrix and fractures should be captured. Also, the results showed that fracture half-length can be longer than 2,000 ft, but the permeability of the fracture is dependent on how far the fracture is from the well. It was found that for multiple well history matching, fracture half-length and the interaction between the wells are the most important factors. Using multiple history matched models, it was shown that multiple models with different fracture distributions could capture the historical data, but they exhibit different future predictions.

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“…Shale oil has achieved great success in North America [1], forming the second peak growth of crude oil production in the United States, which has greatly alleviated the energy pressure of the US and made the energy independence of the US a reality [2]. The successful commercial development of the US shale oil has profoundly affected international energy and reshaped the global energy industry [3,4]. China is rich in shale oil resources, such as Cretaceous in Songliao Basin, Permian in Junggar Basin, Triassic in Ordos Basin, Paleogene, Neogene in Bohai Bay Basin and Jianghan Basin, etc.…”

Section: Introductionmentioning

confidence: 99%

Microscale Evaluation of Tight Oil Mobility: Insights from Pore Network Simulation

et al. 2021

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Pore network modeling based on digital rock is employed to evaluate the mobility of shale oil in Qingshankou Formation, Songliao Basin, China. Computerized tomography technology is adopted in this work to reconstruct the digital rock of shale core. The pore network model is generated based on the computerized tomography data. We simulate the dynamics of fluid flow in a pore network model to evaluate the mobility of fluid in shale formation. The results show that the relative permeability of oil phase increases slowly in the initial stage of the displacement process, which is mainly caused by the poor continuity of the oil phase. In the later stages, with the increase in the oil phase continuity, the range of relative permeability increases. With the increase of organic matter content, the permeability of the water phase remains unchanged at low water saturation, but gradually increases at high water saturation. At the same time, it can be seen that, with the increase in organic matter content, the isosmotic point of the oil–water phase permeability shifts to the left, indicating that the wettability to water phase gradually weakens.

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The role of hydraulic fracture geometry and conductivity profile, unpropped zone conductivity and fracturing fluid flowback on production performance of shale oil wells

Cited by 17 publications

References 15 publications

Recovery rates of fracturing fluids and provenance of produced water from hydraulic fracturing of Silurian Qusaiba hot shale, northern Saudi Arabia, with implications on fracture network

Recovery rates of fracturing fluids and provenance of produced water from hydraulic fracturing of Silurian Qusaiba hot shale, northern Saudi Arabia, with implications on fracture network

A workflow for flow simulation in shale oil reservoirs: A case study in woodford shale

Microscale Evaluation of Tight Oil Mobility: Insights from Pore Network Simulation

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