A well-constrained geomechanical model of the Devonian clastic is presented to assess the fracture slip potential due to water injection in the Berkaoui field, Algeria. The study interval indicates a strike-slip tectonic regime with a mean maximum horizontal stress azimuth of 98 degrees N. A total of 131 natural fractures are interpreted from acoustic image logs. These fractures have dominantly east-west strikes, with the true dips ranging between 51 degrees and 80 degrees toward north and south. Critically stressed fracture analysis exhibits the onset of the shear displacement of optimally oriented steeply dipping fractures occurring at 2.7 MPa of the injection-induced pressure buildup. The practical injection threshold was inferred as 7 MPa based on the caprock integrity assessment. A total of 10 out of 131 fractures (with dips >= 70 degrees) can experience injection-caused slip within the maximum allowable injection limit. The east-west-oriented fractures, subparallel to the maximum horizontal stress azimuth, have a higher likelihood of being critically stressed during injection and, therefore, can contribute to permeability enhancement.

Abstract This study presents a case of successful delivery of a challenging build-up and lateral section through heterogenous lithologies from an exploration field in the Middle East using an integrated multidisciplinary approach of optimization, planning and execution. Based on the offset well drilling experiences, poor ROP, mechanical instability, and differential sticking against some of the highly porous and permeable carbonate reservoirs were identified as the main drilling challenges impacting delivery for the 8-1/2" and 6-1/8" sections parallel to the regional minimum horizontal stress azimuth. Comprehensive geomechanical modeling and wellbore stability analyses were carried out to recommend a safe mud weight window to tackle mechanical instabilities. Utilizing an optimum drill bit design ensured improved durability, trajectory control, a higher rate of penetration and resulted in a 33 % performance improvement on the field average. Drilling fluid chemistry was optimized with required bridging concentrations based on particle size distribution assessment. The 7" liner shoe placement and drilling practices were optimized based on the offset well events and subsurface characteristics to ensure successful execution of the landing section. Real-time monitoring of the LWD data (includes density imaging), aided by right-time geomechanical advisory support ensured successful well delivery without any significant drilling challenges. As a result of the implementation of this systematic and integrated multidisciplinary approach, both sections achieved geological objectives with zero NPT. The well was delivered 8.6 days ahead of the plan, and 14 days ahead of the best similar well.

This study presents a geomechanical assessment of the 4km thick Paleocene-Pleistocene succession of the Tui field area from Taranaki Basin, offshore New Zealand. Based on the core measurements, suitable rock-mechanical models have been presented for static and dynamic elastic properties and rock strength. The Cenozoic stratigraphy is inferred to be normally compacted and devoid of any notable overpressure. Based on the C-quality stress indicators, we infer a 16.48 MPa/km minimum horizontal stress gradient, while the static elastic property-based model suggests a maximum horizontal stress gradient of around 21.15 MPa/km. The estimated in-situ stress magnitudes of the Paleocene-Miocene interval indicate a normal to strike-slip transitional stress regime (SHMax similar to Sv> Shmin). The petrographic and routine core analysis reported medium to coarse-grained, macro-megaporous sub-arkose arenites within the Paleocene Farewell sandstone and Eocene Kaimiro sandstone, which were considered as suitable candidates for geological storage. We analysed the injection stress paths for these two storage units as a result of pore pressure build-up and consequent stress perturbations. The maximum sustainable injection threshold is determined to ensure storage integrity. The conventional approach exhibits a 5-6 MPa repressurization window, while a much higher build-up threshold has been inferred from the model by utilizing pore pressure-stress coupling effects.

This study presents a comprehensive reservoir characterization of the channel sandstones of the Pliocene El Wastani Formation from the deepwater Scarab field, in Egypt. Routine core analysis, wireline logs, petrographic thin sections, X-ray diffraction, and drilling data were integrated to characterize the petrographical, petrophysical and geomechanical properties of the studied gas reservoirs to infer the implications for reservoir development. The petrographic analysis indicates fine to medium-grained glauconitic subfeldspathic wacke with dominantly primary intergranular porosity and minor secondary porosity contributed by feldspar dissolution. The reservoir facies exhibit pore-filling detrital clay (dominantly illite, smectite mixed-layer clay) along with minor carbonate and silica cementation. These reservoirs are megaporous and consist of an isotropic pore system, with 20-35 % porosity, 2400-3400 mD horizontal permeability, and 1300-2900 mD vertical permeability. Wireline log-based petrophysical assessments indicate excellent reservoir qualities with low shale volume (9-23%) and high hydrocarbon saturation of about 65-85%. Based on the geomechanical analysis, rock-mechanical properties, pore pressure, vertical stress, and minimum horizontal stress magnitudes were interpreted. The production and depletion-related risks were analyzed by utilizing geomechanical modeling which provided a quantitative assessment of drawdown and depletion limit to ensure sand-free hydrocarbon production without the risk of shear slippage on pre-existing weak planes. Considering the average unconfined compressive strength of 14 MPa, the Pliocene reservoir will require a 9.2 MPa depletion or 16.9 MPa drawdown to reach the onset of sanding, while the reservoir can be depleted to a pore pressure level of 4 MPa before it induces shear slippage on the optimally oriented fractures or fault planes. Inferences are drawn on reservoir quality, and reservoir development strategies are discussed accordingly.

Abstract In this study, we discuss the subsurface and operational challenges and effective remedial solutions for the wireline straddle packer microfrac operations to achieve successful breakdown and conclusive closure pressure, based on our recent experiences from the recently concluded microfrac campaign in the challenging Triassic and Cambrian unconventional reservoirs of Northern Africa. We share our experiences from the deeper clastic and carbonate targets which are tight, extremely strong, and exhibit a very high breakdown pressure gradient of up to 1.16 psi/ft. In case of breakdown pressure elevated by external factors (effect of mud filtrates etc.), the pump-out method facilitated the formation breakdown. The majority of the microfrac tests in these tight formations showed the proven benefit of multiple rapid loading and unloading cycles by injection (hole pressurization) and pump-out (hole depressurization) in inducing near-wellbore fatigue to effectively weaken the formation before achieving successful breakdown. The effect of near-wellbore poroelasticity was also observed, resulting in increasing fracture reopening and closure pressures in the consecutive microfrac test cycles; the pump-out technique was also effective in eliminating such effects. The tight unconventional reservoirs exhibited a low leak-off coefficient resulting in poor natural fall-off pressure decline response resulting in an overestimation of closure gradient. Therefore, controlled flowback by a small volume pump was adopted to achieve induced closure and conclusive Shmin estimates.

In this study, we interpret the maximum horizontal stress (SHmax) azimuth from the breakout positions of the wellbore and attempt to constrain the SHmax gradient based on the interpreted breakout width. A cumulative of 110 m of breakouts are deciphered within the Ordovician Hamra Quartzite interval of the Oued Mya Basin from a 138 m acoustic image log. These breakouts are ranked as “A-Quality” following the World Stress Map ranking guidelines. We infer a mean SHmax orientation of N28°E ± 8°. Following the frictional faulting mechanism and stress polygon approach, measurement of the minimum horizontal stress (Shmin) from minifrac tests and observations of the compressive failures from the acoustic image log provide strong constraints on the SHmax magnitude in the reservoir interval in the absence of core-measured rock strength. Interpreted breakout widths exhibit a range between 32.6° and 90.81°, which indicates a SHmax range of 24.4–34.7 MPa/km. The average breakout width of 62.58° translates to a narrower SHmax gradient range, varying between 27.2 and 31.2 MPa/km. The relative magnitudes of the principal stresses indicate a strong strike-slip tectonic stress state. Considering all the uncertainties, we infer a SHmax/Shmin ratio of 1.41–1.81 within the Ordovician interval.

The in-situ stress state and the distribution of the critically stressed fractures have significant implications on optimum wellbore placement, production enhancement, fluid injection, and induced seismicity which largely influence the reservoir management strategies. This study presents a comprehensive geomechanical modeling to infer the likelihood of shear slippage of the optimally oriented weak planes in response to water injection in the deep Paleozoic oil reservoirs from the Hassi Terfa field, central Algerian Sahara. The 'B-quality' compressive failures, i.e., breakouts from the acoustic image log indicate the maximum horizontal stress azimuth as N114 degrees E. The inferred in-situ stress magnitudes indicate a strike-slip tectonic regime in the study area. The reservoir is generally tight (porosity <8 %, permeability <0.4 mD) due to extensive silica cementation, however pre-existing closed to partially open natural fractures of variable geometries are identified on cores, thin sections, and image logs. The stress-based slip assessment indicates that none of the fracture geometries is critically stressed and hydraulically conductive at the initial reservoir stress state. The onset of slip on the critically oriented vertical fractures can initiate at 1200 psi of fluid injection at the reservoir level of similar to 3500 m. The E-W to EES-WWN oriented fractures, parallel to the maximum horizontal stress azimuth, have a higher likelihood of being critically stressed during injection and therefore can contribute to the permeability enhancement. We restrict the practical injection threshold at 3000 psi, which can create tensile failures on the shale caprocks. We infer that the NE-SW and NNE-SSW striking, steeply dipping fractures and regional faults being perpendicular or at high angles to the regional maximum horizontal stress azimuth, are the most stable ones and therefore, less likely to slip within the practical injection limit.

ABSTRACT: This study presents a comprehensive geomechanical modeling of the naturally fractured Cambrian reservoirs of the Hassi D'Zabat field, Algeria to assess the in-situ stress state and critically stressed fractures. The Cambrian reservoir exhibits vertical to sub-vertical open to partially open fractures, as interpreted from the cores as well as the image log. A cumulative of 41 m of ‘B-quality’ breakouts was interpreted from the acoustic image log indicating a mean SHMax azimuth of N118˚E. Based on the breakout occurrence, SHMax was constrained following the frictional faulting mechanism. The inferred in-situ stress magnitudes (SHMax > Sv > Shmin) indicate a strike-slip tectonic regime in the study area. The practical injection threshold has been inferred as 1850 psi to ensure caprock integrity. The onset of slip on the optimally oriented vertical fractures is estimated to occur at 150 psi of fluid injection in the Cambrian reservoirs. Within the practical injection window, the stress-based model indicates 41 out of 136 steeply dipping fractures becoming critically stressed and therefore experiencing shear slippage. 1. INTRODUCTION Geomechanics plays a critical role in optimizing the drilling trajectory, fluid injection, and production enhancement (Almalikee and Sen, 2021, 2022; Leila et al., 2021; Farouk et al., 2022; Sen et al., 2024a-c). It has critical implications for naturally fractured reservoirs. When the shear stress to effective normal stress ratio acting on a weak plane (fractures or faults) exceeds the sliding friction of that plane, the probability of shear failure occurrence becomes high, and the fracture is considered to be critically stressed. This study focuses on the prolific Cambro-Ordovician reservoir interval of the Hassi D’Zabat (HDZ), located in the Central Algerian Sahara. The reservoirs are naturally fractured. Waterflood (i.e., water injection) is commonly practiced in these reservoirs at the very early stage of production, to maintain aquifer pressure support. The primary objective of this study was to understand the interplay between natural fractures and in-situ stresses by geomechanical modeling and assess critically stressed fractures during any fluid injection.

ABSTRACT: This study presents a comprehensive geomechanical modeling of the Cambro-Ordovician clastic reservoir interval from Hassi Terfa field, Algeria. Wireline logs, direct downhole measurements and drilling data have been integrated for the work. The acoustic image log analysis exhibits B-Quality breakouts with a cumulative breakout length of 55m. These breakouts indicate a mean maximum horizontal stress orientation of N114˚E±7.6˚. The breakout width ranges between 25˚-89˚. Based on the regional microfrac data, we infer a minimum horizontal stress gradient between 0.8-0.9 psi/ft. SHMax gradient has been constrained from the breakout width using stress polygon approach. A mean breakout width of 53.77˚ translates to a SHMax gradient range of 1.2-1.6 psi/ft. The relative magnitudes of the principal stresses indicate a strong strike-slip tectonic stress state with a SHmax/Shmin ratio of 1.6 within the Paleozoic interval. A good match between observed and modelled breakout widths validates the inferences about the in-situ stress gradients and thus provides an excellent calibration of the geomechanical model. 1. INTRODUCTION Geomechanics plays a critical role in optimizing the drilling trajectory, fluid injection, and production enhancement (Almalikee and Sen, 2021, 2022; Leila et al., 2021; Alabere et al., 2022; Baouche et al., 2022a; Farouk et al., 2022; Sen et al., 2024a). Comprehensive geomechanical modeling provides the rock-mechanical properties, in-situ stress gradients and horizontal stress orientations. This study focuses on the Cambro-Ordovician clastic reservoir interval of the Hassi Terfa field, located in the central Saharan platform of Algeria. The studied field is a fault-compartmentalized oil pool along the N-S to NE-SW trending Amguid-Hassi Messaoud structure of the Algerian Sahara. The objectives of this study were to: i) estimate the rock-mechanical properties, ii) interpret horizontal stress azimuth from wellbore compressive failures, and iii) infer pore pressure and in-situ stress gradients. We have integrated wireline logs, acoustic image logs, downhole measurements, and drilling data to establish a well constrained and calibrated 1D geomechanical model.

In this study, we interpret a cumulative 600 m acoustic image log across the Triassic to Cambro-Ordovician interval in the Berkaoui oil field, Algeria. We interpret 40 distinct breakout zones that have a combined length of 210 m. These breakouts are aligned in the north-northeast–south-southwest direction, indicating a mean maximum horizontal stress (SHmax) azimuth of 110°N. The observed breakouts are ranked as “A-Quality” following the World Stress Map ranking guidelines. The angular width of each breakout has been inferred from the image log analysis and the same has been used to infer the SHmax gradient by stress polygon approach following the frictional faulting mechanism. The stress polygon across all the breakout intervals provides a practical Shmax range between 24.7 MPa/km and 31.1 MPa/km, with an average gradient of approximately 27 MPa/km. Considering the Shmin range across the studied intervals, we infer a SHmax/Shmin ratio dominantly between 1.40 and 1.65, which is a much narrower and better-constrained range when compared with the previously published ranges from nearby fields with the same stratigraphy. The relative magnitudes of the in situ stresses indicate a strike-slip faulting regime in the Berkaoui Field. This study presents the utility of image log analysis and the integration of breakout interpretation to obtain a more robust geomechanical model with reduced SHmax uncertainty.

Lower Miocene rift sediments of the Nukhul Formation are one of the prominent hydrocarbon producers in the Gulf of Suez basin. In this study, we focused on the oil producing Nukhul sandstones of the Abu Rudeis-Sidri Field, located in the east central Gulf of Suez. Nukhul Formation is characterized by the prominent low amplitude seismic reflectors and represents the youngest identified reflector (Lower Miocene) in the study area. Petrophysical assessment was carried out using wireline logs to infer the reservoir characteristics. The Nukhul sandstone reservoir exhibits lower shale volume (< 0.1 dec dominantly), 0.07–0.16 dec total porosity and effective porosity up to 0.13 dec within the Nukhul sandstone interval. Bulk density-neutron porosity cross plot infers primarily sandstone matrix with the influence of carbonates, which characterizes the studied reservoir as calcareous sandstones. Spectral gamma ray data indicates montmorillonite as the principal clay phase along with minor kaolinite and illite. The calculated water saturation of the reservoir zone in the three productive wells ranges between 0.17 and 0.34 dec (i.e., the hydrocarbon saturation equals 0.66–0.87 dec). A small range of bulk volume of water (0.011–0.03 dec) indicates superior quality of the hydrocarbon-bearing sandstone intervals. Absence of productive sands in one of the studied wells, drilled in the hanging wall implied structural control on hydrocarbon accumulation in the study area. This study provides crucial insights regarding the quantitative petrophysical characteristics, reservoir quality distribution and hydrocarbon potential of the Lower Miocene Nukhul clastic reservoir.

This study presents the petrographical and petrophysical characteristics of the Cambro-Ordovician clastic reservoirs from the Risha field, northeastern Jordan. Routine core analysis, wireline logs, petrographic thin sections, scanning electron microscopy, and X-ray diffraction were integrated to characterize the gas reservoirs of the Risha, Dubeidib, and Umm Sahm formations (the equivalent of Sarah, Qasim, and Upper Saq formations of northern Saudi Arabia). These reservoirs are variably micro- and mesoporous, with permeability < 1 mD and dominantly < 6

Abstract Subsurface geomechanical assessment has critical implications for optimum drilling and completion design and successful well delivery to efficiently mitigate drilling challenges as well as avoid non-productive time. The present study focuses on the carbonate-dominated prolific hydrocarbon field of the Arabian Peninsula which exhibits significant wellbore instability challenges owing to high in-situ stress, and partial to total mud losses in naturally fractured and vuggy carbonates. Commonly faced challenges include differential sticking, drill string vibration, poor LWD (logging while drilling) log quality and subsequent wellbore instability. Being in a strike-slip tectonic regime, drilling long multi-laterals towards the minimum horizontal stress (Shmin) is associated with increased hole instability challenges, hard reaming, and mechanical sticking, which is leading to BHA (bottom-hole assembly)/ tools lost in hole and accidental side-tracks. Those contribute to significant NPT (non-productive time) and compromised drilling performance. This study discusses the benefit of integrating geomechanical modeling and real-time monitoring into the drilling operations: those helped to overcome the aforementioned challenges and reduce NPT by enhancing drilling performance. Comprehensive geomechanical modeling and wellbore stability analyses are carried out to study the impact of in-situ stresses, and pore pressure on the stability of the rock/ wellbore wall. Along with the safe mud weight window recommendation and supporting customized drilling fluid and bit design, the study also identified potential sub-surface and drilling risks, which were quantified to optimize the drilling practices and mitigation plans. The predrill models were updated in real-time to fine-tune the predictions on each well and to better constrain the regional geomechanical understanding. During real-time GeoMechanics monitoring we are using LWD logs and drilling parameters to aid in inferring early indicators about the wellbore condition, mud invasion into the formation and other drilling challenges; the real-time GeoMechanics group facilitated timely advisory and effective communication with the rig and relevant parties. Implemented recommendations based on the symptoms of wellbore failure (i.e., early, time dependent failure) exhibited measurable- and significant improvements in drilling performance, penetration rate, overall wellbore quality towards achieving well objectives with minimized NPT. Furthermore, by establishing new communication protocols and adhering to them, a proactive response culture has been developed in order to make informed and collective decisions timely and effective.

ABSTRACT: This study discusses the challenges faced during the wireline straddle packer microfrac tests and the effective solutions, based on our field experiences from the recently concluded successful microfrac campaign targeting the unconventional reservoirs (tight sandstones and dolomites from Triassic-Cambrian) of north Africa. The main challenges were posed by the near wellbore poroelastic effects by mud filtrate that yields pore pressure and stress perturbations locally and artificially elevates formation breakdown pressure. We adopted the ‘pump-out’ technique as an effective solution where the removal certain volume of mud from the near wellbore region reduces the artificial strengthening effect of the mud filter cake and helps reduce the breakdown pressure. The majority of the microfrac tests exhibited the proven benefit of multiple rapid loading-unloading cycles by injection (hole pressurization) and pump-out (hole depressurization) in inducing near-wellbore fatigue to effectively weaken the formation before achieving successful breakdown. In some of the stations, increasing trend observed in fracture reopening and closure in the consecutive test cycles, contributed by the poroelastic effect. The pump-out technique was also effective in eliminating such effects. This study demonstrates the benefits of pump-out technique in achieving successful breakdown and at times conclusive closure in challenging environments. 1. INTRODUCTION The application and importance of geomechanical modeling is well accepted and therefore extensively utilized for tackling mechanical wellbore instabilities, optimizing wellbore trajectories, hydraulic fracture designs and completion strategies, etc. (Almalikee and Sen, 2021, 2022; Farouk et al., 2022; Darjani et al., 2023). It is critically required in any fluid injection program including CO2 sequestration to ensure a long-term confinement of the injected fluid volume without compromising caprock integrity (Sen et al., 2023). Minimum horizontal stress (Shmin) is one of the most important parameters in geomechanical modeling. An over- or under-estimation of Shmin can significantly affect the inferences, therefore requires downhole calibration to reduce uncertainties. For example, lack of Shmin calibration can misinterpret the stress contrast between reservoir and caprock, thus affecting the fluid injection designs and hydraulic fracturing management etc.

This study presents an integrated formation evaluation of the Middle Miocene syn-rift sandstones of the Hammam Faraun Member from southern Gulf of Suez. Core data, XRD, wireline logs and gas chromatography data have been utilized to assess the reservoir characteristics. Three lithofacies are identified from the cored intervals: i) fine to medium-grained massive sandstone (F-1), ii) low-angle cross-bedded fine-grained sandstone (F-2) and iii) coarse to very coarse-grained massive sandstone (F-3). The dominantly massive nature of the sand units with sharp erosive base and bottom rip-up clasts strongly indicates a high energy channel or fan deposit. XRD analysis exhibits quartz and feldspar to be the dominant constituents of these calcareous arkose. Montmorillonite and kaolinite are the major clay phases along with minor illite. Routine core analysis of a total of 168 core plugs indicates meso- to megaporous sandstones with porosity up to 28% and Kh up to 1171 mD. Permeability anisotropy analysis exhibit the dominance of primary depositional fabric and isotropic pores. Wireline log analysis yielded shale volume < 0.2 v/v, porosity ~ 0.18–0.24 v/v, and water saturation ~ 0.33–0.49 v/v. Various gas ratios (wetness, balance, character, and oil indicator ratio) estimated from the chromatograph data indicates the presence of liquid hydrocarbon within the studied reservoirs. The study concludes excellent reservoir properties in the Hammam Faraun clastic intervals of the Esh Elmallha area.

This study presents the first-ever preliminary assessment of the potential reservoir intervals from the Cambro-Ordovician Shifah Formation of the Shushan Basin, Western Desert. Seismic data, thin sections, XRD, XRF, and wireline logs were integrated to characterize the potential intervals. The study area is characterized by E-W and ENE-WSW trending steeply dipping normal faults creating a series of horsts, grabens, and half-graben structures. Based on the wireline logs-based petrophysical assessment, three potential reservoir intervals are identified with the Shifah Formation below 15000 ft depth. All the promising intervals show little shale volume (10–20 %) and 70–80 % hydrocarbon saturation, but the porosity is dominantly below 10%. The two potential sandstone intervals are composed of quartz arenites affected by silica cementation and mechanical compaction. These glauconite-bearing sandstones exhibit low-angle cross-lamination and planar lamination, likely deposited in a fluvial to shallow marine depositional environment. Both the tight sandstone intervals exhibit E-W, and NW-SE striking, closed, and partially open fractures which can contribute to the reservoir flow capacity. The third potential reservoir interval is an igneous intrusive body, composed of alkali syenite and exhibits secondary intraparticle porosity due to partial feldspar dissolution and minor fractures. The preliminary assessment presented in this work shed critical insights into the reservoir potential of the Shifah Formation.

Abstract This study presents an example of geomechanics-aided successful delivery of a challenging 4100 ft long build-up section through mixed lithologies, towards minimum horizontal stress direction. The primary challenge in the build-up sections of the studied offshore exploration field in the Middle East was the mechanical instabilities of the weak shales which contributed to extensive tighthole, pack-off, backreaming, and therefore significant non-productive times. Other associated challenges were the differential sticking tendencies in the porous sandstone layers, and partial to total loss risks within the carbonates. The optimization roadmap comprised adequate mud weight design by geomechanical modeling in the planning phase, and real-time geomechanics advisory in the execution phase. The in-depth analyses of offset wells provided critical insights regarding the commonly occurring and potential drilling hazards across various formations. The post-drill geomechanical modeling and wellbore stability analysis of offset wells, calibrated with drilling events-based observations provided a clear understanding of the collapse pressure behavior of various formations. Based on the geomechanical modeling, a safe mud weight window as well as the minimum required mud weight were recommended to tackle mechanical instabilities. Real-time monitoring of the LWD data, aided by right-time geomechanical advisory support ensured successful well delivery. The drilling and the final BHA pull-out were completed without any mechanical instability issues which annulled the requirement of consecutive reaming trips, saving additional rig days. Successful completion of the challenging build-up section parallel to the Shmin azimuth registered zero NPT with notably improved drilling performance.

This study presents the evaluation of the potential reservoir intervals in the early Cretaceous Alam El Bueib Formation of the Shushan Basin, Western Desert. Seismic 2D lines, and wireline logs (including image logs) were assessed to characterize the potential intervals. The study area is characterized by E-W to ENE-WSW striking parallel sets of steeply dipping normal faults. Based on the breakouts on image log, the regional maximum horizontal stress orientation is inferred as NE-SW. The AEB Formation, as observed on the image log, consists of massive sandstones, planar laminated siltstones, sandstone-siltstone heteroliths and laminated shales, deposited in a fluvial depositional environment. The bedding planes are WNW-ESE striking with a mean true dip of NNE (around 10 degrees). Wireline log based quantitative petrophysical assessment identified multiple promising hydrocarbon-bearing reservoir intervals within the AEB Formation. The potential reservoir intervals are clean with shale content <10% with water saturation <50%. However, all these intervals are tight with effective porosity between 4 and 12%, dominantly similar to 5%. Such tight effective porosity can be contributed by extensive silica cementation in the AEB Formation, as seen from the nearby fields in Western Desert. High porosity zones are observed to be water-bearing. The wells drilled in the north and northeastern area exhibit a cumulative net pay thickness between 70 and 150 ft, while south-southeastern region exhibits a very low cumulative net pay of 10-30 ft. Based on the breakout son image log, the regional minimum horizontal stress orientation is inferred as NW-SE, which can be preferred azimuth for placing highly deviated or horizontal wells to exploit such tight clastic reservoirs by optimizing hydraulic fracture propagation. The formation evaluation presented in this work shed critical insights into the tight hydrocarbon reservoir potential of the early Cretaceous AEB.

One of the main drilling challenges in the offshore deep-water Nile Delta is the overpressured Tertiary shales, which causes formation fluid influxes, kicks, and very narrow drilling window, thus contributes to non-productive times and enhanced drilling risk. Accurate understanding of pore pressure distribution is crucial for casing design, mud optimization and safe and successful drilling. This study presents first ever in-depth analysis of the pore pressure distribution within the 4500 m thick Oligocene-Pleistocene stratigraphy from the West Delta Deep Marine block in deep-water Nile Delta. Direct formation pressure measurements indicated around 0.06–0.1 PSI/ft (1.36–2.26 MPa/km) gas gradient in the Pliocene El Wastani and Kafr El Sheikh sandstone reservoirs, while the Miocene Qantara sandstones are water-bearing with a 0.42 PSI/ft (9.5 MPa/km) pressure gradient. Shale porosity distribution exhibited additional porosity retention within the montmorillonite and mixed clay-dominated Late Pliocene and deeper sediments and marks the onset of overpressure at the top Kafr El Sheikh Formation. Based on the loading trends and acoustic slowness-density relationship, we inferred compaction disequilibrium as the primary overpressure generating mechanism resulted from high sedimentation rate. Shale pore pressure was interpreted by utilizing wireline logs by utilizing compaction trendline-based approach and calibrated with drilling events and mudlog data. Qantara and Tineh formations are characterized by 0.75–0.77 PSI/ft (16.96–17.41 MPa/km) pore pressure gradient leaving a narrow drilling mud window of 1.7–2 PPG. Based on vertical effective stresses, two significant overpressure compartments were identified in the Late Pliocene and Early Miocene-Late Oligocene, which were separated by the Middle Miocene Sidi Salem Formation acting as a pressure seal.

Global sea-level rise during the Early Turonian-Late Cenomanian Bonarelli event resulted in oceanic anoxia and deposition of organic-rich source rocks across Northern Africa, such as the Late Cretaceous Abu Roash-F carbonates. Here, using thin sections, SEM, XRF, standard core analysis, and Rock-Eval pyrolysis data, we examine the petrographic and geochemical properties of the Abu Roash-F (AR-F) carbonate source rocks. These deep marine carbonates consist of dominantly planktonic foraminifera and calcispheres and are classified as wackestone. Extensive micritization, calcite cementation, and ferroan dolomite cement replacement (filling the bioclastic tests and chambers) are identified as the principal diagenetic factors. Core measurements indicate that these carbonates have very low porosity below 3% and horizontal permeability of 0.003 mD (3x10-18 m2), which is also supported by the observed isolated nanopores in SEM. The elemental concentration from the XRF data confirms a highly reducing depositional environment that facilitated the organic richness during the Early Turonian Oceanic Anoxia Event 2 (OAE2). The studied carbonate interval consists of Type-II kerogen in the oil window with a Tmax of about 440 °C and up to 4.2 wt.% TOC indicating ‘fair’ to ‘excellent’ organic richness and a very high probability of active oil generation and expulsion. Following the wireline logs and core data, the self-sourcing unconventional reservoir potential of the AR-F carbonates has been emphasized.