Modeling Pore Pressure, Fracture Pressure and Collapse Pressure Gradients in Offshore Panna, Western India: Implications for Drilling and Wellbore Stability

Sen, Souvik; Kundan, Ashani; Kumar, Mithilesh

doi:10.1007/s11053-019-09610-5

Cited by 27 publications

(4 citation statements)

References 44 publications

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“…Due to the intercalating sandstone-siltstone-shale lithostratigraphy, drilling mud weight was used as a pore pressure proxy in the studied wells. Usually, downhole mud weight is kept above the formation pore pressure to avoid any fluid influx from the formation into the wellbore [24][25][26][27][28]. On the basis of the S v and PP, S hmin and S HMax were modeled.…”

Section: Methodsmentioning

confidence: 99%

In Situ Stress Determination Based on Acoustic Image Logs and Borehole Measurements in the In-Adaoui and Bourarhat Hydrocarbon Fields, Eastern Algeria

Baouche

Sen²,

Radwan

et al. 2023

Energies

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The study of in situ stress from image logs is a key factor for understanding regional stresses and the exploitation of hydrocarbon resources. This work presents a comprehensive geomechanical analysis of two eastern Algerian hydrocarbon fields to infer the magnitudes of principal stress components and stress field orientation. Acoustic image logs and borehole measurements were used in this research to aid our understanding of regional stress and field development. The studied In-Adaoui and Bourarhat fields encompass a combined thickness of 3050 m of Paleozoic and Mesozoic stratigraphy, with the primary reservoir facies in the Ordovician interval. The Ordovician sandstone reservoir interval indicates an average Poisson’s ratio (v) of 0.3, 100–150 MPa UCS, and 27–52 GPa Young’s modulus (E). Direct formation pressure measurements indicate that the sandstone reservoir is in a hydrostatic pore pressure regime. Density-derived vertical stress had a 1.1 PSI/feet gradient. Minimum horizontal stress modeled from both Poisson’s ratio and an effective stress ratio-based approach yielded an average 0.82 PSI/feet gradient, as validated with the leak-off test data. Drilling-induced tensile fractures (DITF) and compressive failures, i.e., breakouts (BO), were identified from acoustic image logs. On the basis of the DITF criterion, the maximum horizontal stress gradient was found to be 1.57–1.71 PSI/feet, while the BO width-derived gradient was 1.27–1.37 PSI/feet. Relative stress magnitudes indicate a strike-slip stress regime. A mean SHMax orientation of N130°E (NW-SE) was interpreted from the wellbore failures, classified as B-quality stress indicators following the World Stress Map (WSM) ranking scheme. The inferred stress magnitude and orientation were in agreement with the regional trend of the western Mediterranean region and provide a basis for field development and hydraulic fracturing in the low-permeable reservoir. On the basis of the geomechanical assessments, drilling and reservoir development strategies are discussed, and optimization opportunities are identified.

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Section: Methodsmentioning

confidence: 99%

In Situ Stress Determination Based on Acoustic Image Logs and Borehole Measurements in the In-Adaoui and Bourarhat Hydrocarbon Fields, Eastern Algeria

Baouche

Sen²,

Radwan

et al. 2023

Energies

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“…Abnormal formation pressure yields increased complexity in drilling and nonproductive times. Direct downhole measurements provide the best PP estimates; however, these data are usually recorded only in the reservoir intervals (Sen et al, , 2020Agbasi et al 2021;Radwan 2021b).…”

Section: Vertical Stressmentioning

confidence: 99%

Determination of the mud weight window, optimum drilling trajectory, and wellbore stability using geomechanical parameters in one of the Iranian hydrocarbon reservoirs

Hoseinpour

Riahi

2021

J Petrol Explor Prod Technol

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The challenges behind this research were encountered while drilling into the Ilam, Mauddud, Gurpi, and Mishrif Formations, where severe drilling instability-related issues were observed across the weaker formations above the reservoir intervals. In this paper, geomechanical parameters were carried out to determine optimum mud weight windows and safe drilling deviation trajectories using the geomechanical parameters. We propose a workflow to determine the equivalent mud window (EMW) that resulted in 11.18–12.61 ppg which is suitable for Gurpi formation and 9.36–13.13 ppg for Ilam and Mishrif Formations, respectively. To estimate safe drilling trajectories, the Poisson’s ratio, Young’s modulus, and unconfined compressive strength (UCS) parameters were determined. These parameters illustrate an optimum drilling trajectory angle of 45° (Azimuth 277°) for the Ilam to Mauddud Formations and less than 35° for the Gurpi Formation. Our analysis reveals that maximum horizontal stress and Poisson’s ratio have the most impact on determining the optimum drilling mud weight windows and safe drilling deviation trajectories. On the contrary, vertical stress and Young’s modulus have minimum impact on drilling mud weight windows and safe drilling deviation trajectories. This study can be used as a reference for the optimal mud weight window to overcome drilling instability issues in future wellbore planning in the study.

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“…Historically and despite decades of research into the subsurface sediment characteristics, it remains difficult to predict critical reservoir parameters of strata buried in sedimentary basins such as pore pressure (e.g., Gretener, 1979;Audet and McConnell, 1992;Martinsen, 1994;Gordon and Flemings, 1998;Dutta, 2002;Chopra and Huffman, 2006;Gutierrez et al, 2006;Zhang, 2011;Radwan et al, 2019b;Baouche et al, 2020a;Radwan et al, 2020a;Baouche et al, 2020b;Ganguli and Sen, 2020;Radwan and Sen, 2021a;Radwan, 2021b;Radwan and Sen, 2021b) and fracture pressure (e.g., Anderson et al, 1973;Traugott, 1997;Draou and Osisanya, 2000;Radwan et al, 2019b;Sen and Ganguli, 2019;Tariq et al, 2019;Radwan et al, 2020a;Radwan, 2021b). The importance of pore pressure and fracture pressure is related to their influence on drilling operations (e.g., Gray-Stephens et al, 1994;Swarbrick, 2012;Sen et al, 2020;Abdelghany et al, 2021;Radwan, 2021b), exploration (e.g., O'connor et al, 2011a;John et al, 2014), and reservoir stability and production (e.g., Hillis, 2000;Agbasi et al, 2021;Radwan and Sen, 2021a;Radwan and Sen, 2021b;Kassem et al, 2021).…”

Section: Introductionmentioning

confidence: 99%

A multi-proxy approach to detect the pore pressure and the origin of overpressure in sedimentary basins: An example from the Gulf of Suez rift basin

Radwan

2022

Front. Earth Sci.

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The pore pressure gradient and fracture gradient (PPFG) are critical parameters for drilling mud weight design in the energy industry. Successful drilling operations can be achieved successfully through the understanding of the pore pressure and fracture pressure in the subsurface succession. The scope of this research is to use an integrated approach that encompasses well-logging, basin modeling, drilling-based interpretations, and reservoir measurement methods to gain a reasonable PPFG model and decrease the drilling uncertainties in the El Morgan oil field in the Gulf of Suez. Moreover, it investigates the overpressure generation mechanisms in the basin, which have not been studied before in this area. In this work, PPFGs of more than 16 km of cumulative thick sedimentary succession were modeled and evaluated using an integrated approach. This study utilizes Eaton’s sonic and resistivity-based methods for pore pressure evaluation, while vertical stress was calculated based on the composite density profile. The study revealed that the top geo-pressure was detected at a depth of 1,030 m of Tortonian sediments. Late Miocene sediments reveal hard over-pressure with a maximum gradient of 0.55 PSI/feet, while Middle Miocene sediments exhibit mildly over-pressured, normal, and sub-normal pore pressure zones. The lowest pore pressure values were measured in the Langhian-Serravalian Kareem reservoir with a gradient of 0.29 PSI/feet. With the exception of a slight difference in the reservoir section, the pore pressure profiles in the northern and southern parts of the El Morgan oil field are relatively similar. Reservoir connectivity is believed to be the main reason behind pore pressure magnitude differentiation in the Middle Miocene reservoirs. The key mechanism for generating overpressure has been identified as disequilibrium compaction, and reservoir overcharging may contribute as an excess-pressure generation mechanism at the reservoir level. The presented approach can be applied in PPFG studies for both development and exploratory geomechanical studies in other areas of the Gulf of Suez basin or elsewhere in the world.

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Modeling Pore Pressure, Fracture Pressure and Collapse Pressure Gradients in Offshore Panna, Western India: Implications for Drilling and Wellbore Stability

Cited by 27 publications

References 44 publications

In Situ Stress Determination Based on Acoustic Image Logs and Borehole Measurements in the In-Adaoui and Bourarhat Hydrocarbon Fields, Eastern Algeria

In Situ Stress Determination Based on Acoustic Image Logs and Borehole Measurements in the In-Adaoui and Bourarhat Hydrocarbon Fields, Eastern Algeria

Determination of the mud weight window, optimum drilling trajectory, and wellbore stability using geomechanical parameters in one of the Iranian hydrocarbon reservoirs

A multi-proxy approach to detect the pore pressure and the origin of overpressure in sedimentary basins: An example from the Gulf of Suez rift basin

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