Investigation of pore pressure, in-situ stress state and borehole stability in the West and South Al-Khilala hydrocarbon fields, Nile Delta, Egypt

Leila, Mahmoud; Sen, Souvik; Abioui, Mohamed; Moscariello, Andrea

doi:10.1007/s40948-021-00256-3

Cited by 28 publications

(14 citation statements)

References 69 publications

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“…Several kinds of research have been conducted to find an optimum relationship that better explains the variation of geochemical with petrophysical and geomechanical data (e.g., Schmoker and Hester, 1983;Passey et al, 1990;Shukla et al, 2013;Leila et al, 2021;Sen et al, 2021;Abdel-Fattah et al, 2022;Fea et al, 2022). Relationships of geochemical data with other datasets are very important to validate the field data and estimates of different properties from one to another and develop a continuous geochemical model (Abarghani et al, 2019).…”

Section: Resultsmentioning

confidence: 99%

Source rock geochemical assessment and estimation of TOC using well logs and geochemical data of Talhar Shale, Southern Indus Basin, Pakistan

et al. 2022

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Assessment of organic carbon content (TOC) by geophysical logs has been a challenging task in the formation evaluation of shale gas. This research is conducted to estimate the unconventional hydrocarbon (shale-gas) potential of Talhar Shale in the Southern Indus Basin (SIB), Pakistan. In this study, total organic carbon content (%) was estimated through well logs by different methods and then correlated with well cuttings/core data to determine the best method for estimation of TOC content especially when well cuttings/core data are not available. The Talhar Shale’s thermal maturity, as well as the organic content, were assessed from geochemical analyses. Talhar Shale of Dangi-01 well has good to very good source potential whereas Chak7A-01 well has fair-good. According to Ven Krevalen cross-plot, Talhar Shale of Dangi-01 well has type III kerogen; it can only produce gas while Chak7A-01 has type II/III kerogen which produces both oil and gas. The TOC was estimated using two methods i.e., Schmoker’s and Hester’s and Multivariate Fitting methods. The estimated TOC is then correlated with well cuttings data and concluded that the Multivariate Fitting method is selected as an optimized method for estimation of TOC because it shows strong correlation values of 0.93 and 0.91 in both wells respectively for Talhar Shale SIB, Pakistan.

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Section: Resultsmentioning

confidence: 99%

Source rock geochemical assessment and estimation of TOC using well logs and geochemical data of Talhar Shale, Southern Indus Basin, Pakistan

et al. 2022

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“…In general, Abu Gharadig Basin is an intra-cratonic rift basin and we have considered k = 0.5. However, recent studies have reported present-day normal faulting to strike-slip transitional stress state from the onshore Nile Delta (Leila et al, 2021). Based on the inferred geomechanical parameters, we employed Mohr-Coulomb failure criteria to decipher the shear failure gradient (SF) which denotes the minimum required mud weight for avoiding compressive failures (Zhang, 2013;Zhang et al, 2015):…”

Section: Methodsmentioning

confidence: 99%

Geomechanical assessment of the Lower Turonian AR-F limestone Member, Abu Gharadig Field, Egypt: Implications for unconventional resource development

Farouk

Sen²,

Abu-Alam

et al. 2022

Front. Earth Sci.

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This study evaluates the unconventional reservoir geomechanical characteristics of the Lower Turonian Abu Roash-F (AR-F) carbonates from the Abu Gharadig field, onshore Egypt, which has not been attempted before. The interval dominantly consists of planktic foraminifera and micrite matrix. The AR-F marine carbonate is organic-rich (0.59–3.57 wt% total organic carbon), thermally mature (435–441°C Tmax) and falls within the oil generation window. The studied interval is very tight with up to 2.6% porosity and 0.0016–0.0033 mD permeability with the wireline log-based brittleness index ranging between 0.39–0.72 which indicates a less brittle to brittle nature. AR-F exhibits a hydrostatic pore pressure gradient with minimum horizontal stress (Shmin) varying between 0.66–0.76 PSI/ft. Safe wellbore trajectory analysis was performed for deviated and horizontal wells to infer the mud pressure gradients required to avoid wellbore instabilities. Based on the inferred in-stress magnitudes and considering an NNE regional maximum horizontal stress orientation, none of the fractures are found to be critically stressed at present day. To produce from the AR-F, hydraulic fracturing is necessary, and we infer a minimum pore pressure increment threshold of 1390 PSI by fluid injection to reactivate the vertical fractures parallel to regional minimum horizontal stress azimuth.

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“…The pressure generated by combining vertical column pressure of various rock layers and fluids inside themselves at a certain depth refers to overburden stress or vertical stress (Sv) (Leila, Sen, et al, 2021; Plumb, Evans, & Engelder, 1991; Radwan, 2021). The Sv at a particular depth (H) is calculated using the following equation:

italicSv goodbreak= \int_{0}^{H} RHOB ((), H) * g italicdH,

where Sv is the vertical stress in (psi), g is the gravity constant (9.8 m/s 2 ), and RHOB is the total density (gm/cm 3 ).…”

Section: Methodsmentioning

confidence: 99%

“…to overburden stress or vertical stress (Sv) (Leila, Sen, et al, 2021;Plumb, Evans, & Engelder, 1991;Radwan, 2021). The Sv at a particular depth (H) is calculated using the following equation:…”

Section: Modelling Vertical Stressmentioning

confidence: 99%

“…Subsequently, the entire Mediterranean shelf and slope systems were subaerially exposed, deeply eroded and large‐scale fluvial canyons were incised along the entire Mediterranean margins (e.g., Barber, 1981; Bertoni & Cartwright, 2007; Clauzon, 1982; Leila & Moscariello, 2019; Lofi et al, 2005; Madof et al, 2019; Ryan & Cita, 1978). In the Nile Delta, this event is marked by the incision of the Eonile canyon which was infilled during the Late Messinian transgression (~5.45 Ma, Popescu et al, 2021) by the backstepping Abu Madi fluvial‐estuarine facies (Dalla et al, 1997; Dolson et al, 2005; El Adl, Leila, Ahmed, Anan, & El‐Shahat, 2021; Keheila, 1990; Leila & Moscariello, 2019; Leila, Sen, Abioui, & Moscariello, 2021; Rubino et al, 2015). On the basis of the quantitative modelling analysis of Gargani et al (2010), the Nile Delta has been significantly modified due to the isostatic rebound inherited from the Mediterranean sea‐level fall, sediment loading, and river incision.…”

Section: Geologic Settingmentioning

confidence: 99%

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Soft‐sediment deformation structures in the Late Messinian Abu Madi Formation, onshore Nile Delta, Egypt: Triggers and tectonostratigraphic implications

et al. 2022

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The Upper Messinian Abu Madi Formation of the Nile Delta constitutes sediments deposited during the final stage of the Messinian salinity crisis (MSC). Several levels of soft‐sediment deformation structures (SSDS) were observed in the transgressive heterolithic fluvial facies deposited adjacent to the deep‐seated faults. The most common deformation features include diapiric structures, intraformational lithoclastic breccia, small‐scale normal faults, slump folds, and liquefied beds. Such association of SSDS typically resembles those described elsewhere as generated by a complex interplay of gravity‐driven and seismically induced liquefaction processes. The pore pressure measurements revealed high pore fluid density ~ 9.1 ppg equivalent density values which reflect a mild pressure disequilibrium in Abu Madi sediments. Pressure disequilibration is observed all over the studied section of the Abu Madi Formation and is not only restricted to the fluvial channel sandstones deposited during rapid loading. Therefore, allogenic seismic activity has been proposed as the main trigger for pressure disequilibrium and the development of SSDS in the Abu Madi Formation. The heterolithic nature of the Abu Madi sediments as well as the scarcity of bioturbation provides the favourable conditions for the preservation of the seismically induced deformation. The lateral variation in thickness suggests deposition of the Abu Madi Formation during periods of active subsidence which promotes the generation of the SSDS. Late MSC tectonism likely controlled the evolution and sedimentary facies variability of the Abu Madi canyon‐infill system, and therefore the distribution of Abu Madi facies varies significantly over very short distances. Abu Madi SSDS follows the spatial distribution observed in other “lago‐mare” deposits (e.g., Foes Formation and SE Spain), characterized by spatial variability and vertical rhythmic alternation between deformed and non‐deformed layers. Accordingly, regional tectonic instability in the circum‐Mediterranean margins during the late stage of the MSC is proposed.

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Investigation of pore pressure, in-situ stress state and borehole stability in the West and South Al-Khilala hydrocarbon fields, Nile Delta, Egypt

Cited by 28 publications

References 69 publications

Source rock geochemical assessment and estimation of TOC using well logs and geochemical data of Talhar Shale, Southern Indus Basin, Pakistan

Source rock geochemical assessment and estimation of TOC using well logs and geochemical data of Talhar Shale, Southern Indus Basin, Pakistan

Geomechanical assessment of the Lower Turonian AR-F limestone Member, Abu Gharadig Field, Egypt: Implications for unconventional resource development

Soft‐sediment deformation structures in the Late Messinian Abu Madi Formation, onshore Nile Delta, Egypt: Triggers and tectonostratigraphic implications

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