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Die Sättigungsdampfdrucke, die Verdampfungswärmen und das Destillationsverhalten des Stoffpaars Cyclohexanon-Cyclohexanol (1962)

Hennings, P. ; v. Weber, U.

New York, NY : Wiley-Blackwell

Journal für Praktische Chemie/Chemiker-Zeitung 18 (1962), S. 91-96

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ISSN: 0021-8383

Keywords: Chemistry ; Organic Chemistry

Source: Wiley InterScience Backfile Collection 1832-2000

Topics: Chemistry and Pharmacology

Notes: Die zwischen 800 und 5, bzw. 10 Torr gemessenen Sättigungsdampfdrucke des Cyclohexanons und des Cyclohexanols lassen sich durch eine dreigliedrige Formel lg p = A - B/T + C lg T mit weniger als ± 0,001 in lg p zwischen 800 und 35 Torr interpolieren. Die Verdampfungswärmen des Cyclohexanons sind normal, die des Cyclohexanols anomal groß. Das Dampfdruckverhältnis α° = p10/p20 nimmt von 1,143 bei 160° auf 2,124 bei 80° zu. Mit Hilfe einer allgemeinen Bewertungsformel für Gegenstromaustauscher wird gezeigt, daß die Rektifikation bei 80° auch unter Berücksichtigung der verminderten Intensität des Gegenstroms noch die achtfache Ertragsquote gegenüber der Rektifikation bei 160° liefert; die Durchrechnung des Beispiels der destillativen Trennung eines 50:50-Gemisches in die Komponenten mit 99% Reinheit, wobei auch die Abweichungen vom idealen Mischungsverhalten berücksichtigt werden, bestätigt das Ergebnis der allgemeinen Bewertungsformel.

Additional Material: 2 Ill.

Type of Medium: Electronic Resource

URL: http://dx.doi.org/10.1002/prac.19620180110

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Damage and plastic deformation of reservoir rocks: Part 2. Propagation of a hydraulic fracture (2012)

Busetti, S., Mish, K., Hennings, P., Reches, Z.

American Association of Petroleum Geologists (AAPG)

In: AAPG Bulletin

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Publication Date: 2012-09-01

Description: The aim of part 2 is to understand the development of complex hydraulic fractures (HFs) that are commonly observed in the field and in experiments but are not explained by most models. Our approach uses finite element simulations and a numerical rheology developed in part 1 to model damage fracturing, the fracturing process by damage propagation in a rock with elastic–plastic damage rheology. Using this rheology and a dynamic solution technique, we investigate the effect of far-field stresses and pressure distribution in the fracture on the geometric complexity of the fractures. The model is for the vertical propagation of an HF segment into an overlying bed located far from borehole effects. The layer is 2.3 m (7.5 ft) tall, has elastic–plastic damage rheology, and contains a 0.3-m (1-ft)–tall initial vertical fracture. Vertical and horizontal tectonic loads of 50 MPa (7252 psi) and 10 to 45 MPa (1450–6527 psi) are established, and then an internal fracture pressure of 10 MPa/s (1450 psi/s) is applied until the layer fails. The simulated fracturing is sensitive to the stress state and generated patterns range from single straight fractures to treelike networks. Reducing differential stress increases the injection pressure required to fracture and promotes off-plane damage, which increases fracture complexity. Consecutive periods of nonuniform weakening followed by unstable rupture generate multiple branches and segments. We find that the processes that form HF complexity occur under a range of in-situ reservoir conditions and are likely to contribute to complex far-field fracture geometry and enhanced network connectivity.

Print ISSN: 0149-1423

Electronic ISSN: 0149-1423

Topics: Geosciences

Published by American Association of Petroleum Geologists (AAPG)

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Faulting and fracturing in shale and self-sourced reservoirs: Introduction (2014)

Ferrill, D. A., Morris, A. P., Hennings, P. H., Haddad, D. E.

American Association of Petroleum Geologists (AAPG)

In: AAPG Bulletin

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Publication Date: 2014-10-28

Description: Production from self-sourced reservoirs relies on natural and induced fracturing for permeability and conductance of hydrocarbons to the producing wellbores, thus natural or induced fracturing is often a key to success in unconventional reservoir plays. On the other hand, fractures may compromise seals and large or well-connected fractures or faults may cause undesirable complications for unconventional reservoirs. Natural and induced fractures are influenced by (1) mechanical stratigraphy, (2) pre-existing natural deformation such as faults, fractures, and folds, and (3) in situ stress conditions, both natural and as modified by stimulation and pressure depletion. This special issue of the AAPG Bulletin elucidates some of these structural geologic and geomechanical controls. Understanding the occurrence and controls on natural and induced faulting and fracturing in self-sourced reservoirs is a key component for developing effective approaches for exploiting self-sourced reservoirs.

Print ISSN: 0149-1423

Electronic ISSN: 0149-1423

Topics: Geosciences

Published by American Association of Petroleum Geologists (AAPG)

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A scaling law to characterize fault-damage zones at reservoir depths (2014)

Johri, M., Zoback, M. D., Hennings, P.

American Association of Petroleum Geologists (AAPG)

In: AAPG Bulletin

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Publication Date: 2014-09-27

Description: We analyze fracture-density variations in subsurface fault-damage zones in two distinct geologic environments, adjacent to faults in the granitic SSC reservoir and adjacent to faults in arkosic sandstones near the San Andreas fault in central California. These damage zones are similar in terms of width, peak fracture or fault (FF) density, and the rate of FF density decay with distance from the main fault. Seismic images from the SSC reservoir exhibit a large basement master fault associated with 27 seismically resolvable second-order faults. A maximum of 5 to 6 FF/m (1.5 to 1.8 FF/ft) are observed in the 50 to 80 m (164 to 262 ft) wide damage zones associated with second-order faults that are identified in image logs from four wells. Damage zones associated with second-order faults immediately southwest of the San Andreas Fault are also interpreted using image logs from the San Andreas Fault Observatory at Depth (SAFOD) borehole. These damage zones are also 50–80 m wide (164 to 262 ft) with peak FF density of 2.5 to 6 FF/m (0.8 to 1.8 FF/ft). The FF density in damage zones observed in both the study areas is found to decay with distance according to a power law $$F={F}_{0}{r}^{-n}$$ . The fault constant $${F}_{0}$$ is the FF density at unit distance from the fault, which is about 10–30 FF/m (3.1–9.1 FF/ft) in the SSC reservoir and 6–17 FF/m (1.8–5.2 FF/ft) in the arkose. The decay rate $$n$$ ranges from 0.68 to 1.06 in the SSC reservoir, and from 0.4 to 0.75 in the arkosic section. This quantification of damage-zone attributes can facilitate the incorporation of the geometry and properties of damage zones in reservoir flow simulation models.

Print ISSN: 0149-1423

Electronic ISSN: 0149-1423

Topics: Geosciences

Published by American Association of Petroleum Geologists (AAPG)

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Using InSAR to detect active deformation associated with faults in Suban field, South Sumatra Basin, Indonesia (2014)

Schultz, R. A., Soofi, K. A., Hennings, P. H., Tong, X., Sandwell, D. T.

Society of Exploration Geophysicists (SEG)

In: Leading Edge

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Publication Date: 2014-08-06

Description: Suban field in southern Sumatra, Indonesia, is a fractured carbonate/crystalline wet-gas reservoir in a tectonically active island-arc setting. Reservoir-scale right-oblique reverse faults and folds that have trapped the hydrocarbons have been related previously to deformation in the back-arc setting of Sumatra associated with oblique subduction of the Indo-Australian Plate at the Sunda trench. Increased well productivity in some parts of the field was inferred to correlate with completing wells in the damage zones of critically stressed faults. Satellite interferometry acquired in 2008 through 2011 involving specially stacked and filtered interferograms, following prior applications to heavy-oil fields and Arctic sea ice, reveals active deformation in Suban field. Several areas of localized subsidence potentially exceeding ~5 mm/yr have been identified in the field. Horizontal movements of comparable magnitude were resolved above the major right-oblique, critically stressed fault zone in the southwestern part of the field, corroborating wellbore-based inferences from the reservoir. Block-tectonic models constrained by GPS measurements across the entire Sumatra contractional orogen predict comparable magnitudes and directions for horizontal motions observed locally at Suban. The combination of InSAR and GPS-based plate-tectonic models provides a robust tool for monitoring the deformation of oil and gas fields in tectonically active areas.

Print ISSN: 1070-485X

Electronic ISSN: 1938-3789

Topics: Geosciences

Published by Society of Exploration Geophysicists (SEG)

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