Publications Scientifiques

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Author: search.filters.author.Baouche, RafikStart date: 2020

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    Assessment of borehole breakouts from acoustic image log and its geomechanical implications - A case study from Triassic-Ordovician interval of Berkaoui field, southeastern Algeria
    (Society of Exploration Geophysicists, 2024) Baouche, Rafik; Sen, Souvik
    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.
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    Geomechanical modeling to assess the injection-induced fracture slip-potential and subsurface stability of the Cambro-Ordovician reservoirs of Hassi Terfa field, Algeria
    (Elsevier Ltd, 2024) Benayad, Soumya; Sen, Souvik; Baouche, Rafik; Mitra, Sourav; Chaouchi, Rabah
    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°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 ∼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.
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    Constraining maximum horizontal stress using wellbore breakouts A case study from the Ordovician tight reservoir of the northeastern Oued Mya Basin, Algeria
    (Society of Exploration Geophysicists, 2024) Baouche, Rafik; Sen, Souvik; Ganguli, Shib Sankar; Benmamar, Salim; Kumar, Prakash
    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.
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    Triassic-Early Jurassic evaporites of the Saharan Platform, Algeria: Astronomical and geodynamic constraints on stratigraphy and sedimentation
    (Elsevier, 2023) Turner, Peter; Baouche, Rafik; Sabaou, Nordine
    The sequence stratigraphy of the Late Triassic - Early Jurassic evaporites of the Berkine Basin is described. Disconformities occur between all the major evaporitic units but lack of biostratigraphy (or other) chronostratigraphic control precludes their precise dating. The S4 and S3 Halites are predominantly non-marine halites deposited in low-lying salinas with a barrier to the north. The top of the S4 depositional sequence is marked by the D2, usually regarded as the Tr-J boundary in the Berkine Basin. Both the S3 and S4 salt deposits thin rapidly to the south-east and are thicker in the basin centre coincident with a subcrop of Carnian? aged volcanics. A combination of thermal cooling, rifting and reactivation of N–S lineaments parallel to the Hassi Messaoud-El Biod Arch controlled the (∼1500 m thick) depocenter. Time series analysis shows that astronomical forcing played a key role in the deposition of the S3 and S4 bedded halites. The prevailing climate was monsoonal with major replenishment of the basin indicated by long eccentricity cycles (405 kyr). Sedimentation rates were estimated using eCOCO analysis with average rates of 15 cm/kyr. Well to well comparisons shows that in marginal areas thinner sedimentary sequences relate to slower accumulation rates and periods of non-deposition or deflation. The pattern is similar in the S4 and S3 halite, but the reduced mud content and amalgamation of halite beds suggests a more arid climate in S3 times. The S1+S2 unit marks the first widespread deposition of sulphate in the basin. The lowermost anhydrite beds of the S1 + S2 rest unconformably on the underlying S3 and overstep the basin margins in the south-east; the sequence is capped by the B Horizon a basin-wide carbonate shelf deposit about 25 m thick indicating increased marine influence. Above there is a rapid return to thinly bedded mudstone-halite dominated sedimentation (Lias Salifère) which is overlain by the Lias Anhydritique an alternating sequence of halite and anhydrite deposits. Astronomical parameters of the whole sequence indicate an average sedimentation rate of ∼10 cm/kyr in this marine-influenced section, slower than the halite units. Although the time series analysis cannot provide precision dating of the evaporitic sequences the results indicate that there are important breaks in the depositional record. The combined S4 and S3 halites account for 4.75 Ma and the rest of the Liassic 9.4 Ma. It seems clear that much of the depositional record is missing. These Saharan Platform basins bear much in common with other western Mediterranean evaporite basins. Many show the same overall pattern of sedimentation with increased sulphate deposition above the Tr-J boundary. In late Triassic time they formed a contiguous low-lying zone flanked by cratonic highlands. This zone spanned the Gondwana-Laurussia boundary immediately prior to its break-up and Greater Adria formed a barrier between these basins and the developing Neotethys to the east. The major changes seen in the Saharan Platform are mirrored by the break-up of Adria and the separation of Gondwana and Laurasia and the ultimate connection of the western Mediterranean and the central Atlantic.
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    In Situ Stress Determination Based on Acoustic Image Logs and Borehole Measurements in the In-Adaoui and Bourarhat Hydrocarbon Fields, Eastern Algeria
    (MDPI, 2023) Baouche, Rafik; Souvik, Sen; Radwan, Ahmed; Abd El Aal, Ahmed
    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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    Estimation of horizontal stresses from wellbore failures in strike-slip tectonic regime: A case study from the Ordovician reservoir of the Tinzaouatine field, Illizi Basin, Algeria
    (Society of Exploration Geophysicists, 2022) Baouche, Rafik; Sen, Souvik; Hadj Arab, Feriel; Ahmed, Radwan
    We present a geomechanical analysis of the Ordovician reservoir from the Tinzaouatine field situated in the prolific Illizi Basin, eastern Algeria. The sandstone reservoir has a hydrostatic pore pressure gra- dient (9.95 MPa/km). We analyzed a cumulative of 300 m of acoustic image log data and identified the coexistence of B-quality extensive drilling-induced tensile failures (DITFs) and compressive failures, i.e., breakouts (BOs), indicating a mean maximum horizontal stress (SHMax) orientation of N140°E. We used a combined BO and DITF-based solution to estimate horizontal stress magnitudes when the two failure types coexist. Based on the C-quality minifrac measurements, we interpreted the minimum horizontal stress (Shmin) gradient as 17.4–17.47 MPa/km, whereas the new approach indicates an Shmin range of 17.31–18.67 MPa/km. Using the BO width and DITF-based approaches, we inferred an SHMax gradient range of 28.37–38.59 MPa/km within the studied reservoir. Based on the relative stress magnitudes, we infer a strike-slip tectonic stress regime in the studied field.
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    Geomechanical and Petrophysical Assessment of the Lower Turonian Tight Carbonates, Southeastern Constantine Basin, Algeria: Implications for Unconventional Reservoir Development and Fracture Reactivation Potential
    (MDPI, 2022) Baouche, Rafik; Souvik, Sen; Radwan, Ahmed
    In this study, we assessed the unconventional reservoir characteristics of the Lower Turonian carbonates from the southeastern Constantine Basin. We integrated petrography, petrophysical, and rock-mechanical assessments to infer formation properties and unconventional reservoir development strategies. The studied fossiliferous argillaceous limestones are rich in planktonic foraminifera, deposited in a calm and low energy depositional condition, i.e., deep marine basinal environment. Routine core analysis exhibits very poor porosity (mostly < 5%) and permeability (<0.1 mD), implying the dominance of nano and microporosity. Micritization and calcite cementation are inferred as the major reservoir quality-destroying diagenetic factors. Based on the wireline log-based elastic properties, the upper part of the studied interval exhibits higher brittleness (BI > 0.48) and fracability (FI > 0.5) indices compared to the lower interval. Borehole breakouts indicate ~N-S SHmax orientation and a normal to strike-slip transitional stress state has been constrained based on a geomechanical assessment. We analyzed safe wellbore trajectory and minimum mud weight requirements to ensure stability in the deviated and horizontal wells required for field development. At the present stress state, none of the fracture orientations are critically stressed. We inferred the fracture reactivation potential during hydraulic stimulation required to bring the tight Turonian limestones into production. Additional pore pressure build-up required to reactivate
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    Assessment of reservoir stress state and its implications for Paleozoic tight oil reservoir development in the Oued Mya Basin, northeastern Algerian Sahara
    (Elsevier, 2023) Baouche, Rafik; Shib, Sankar Ganguli; Senc, Souvik; Radwan, Ahmed
    The Cambrian and Ordovician clastic reservoirs of the Oued Mya Basin exhibit significant vertical thickness and extensive lateral continuity, despite being tight. These reservoir intervals have not been properly understood yet in terms of in-situ stress distribution and pore pressure behaviour. The main objectives were to infer the reservoir stress state and draw implications for the tight oil reservoir development based on the geomechanical analyses. We interpreted breakouts from a cumulative 1485 m of acoustic image logs and interpreted a NW-SE SHMax orientation (N125°E-N147°E) in the Oued Mya Basin. The inferred breakouts were of B-D quality as per the World Stress Map ranking criteria. Both the reservoirs have a pore pressure gradient of 13.58-13.77 MPa/km, while the minifrac data infers a reservoir Shmin gradient of 17.3-19.2 MPa/km. Based on the breakout widths, we estimated the SHMax gradient as 23.8-26.5 MPa/km. Following the univariate regression analyses to identify various influencing parameters on horizontal stress magnitudes, we proposed multiple linear regression (MLR) models to predict the Shmin and SHMax based on pore pressure, Sv, Poisson's ratio, and Young's modulus. Results indicate that Sv influences the horizontal stress estimates significantly more as compared to the other influencing variables. The predicted Shmin and SHMax values are in good agreement (goodness of fit as R2 = 0.976 and 0.994) with the measured data. The newly proposed MLR equations can be utilized in absence of subsurface validation data. A strike-slip faulting reservoir stress state is concluded from stress polygon analysis. An optimum drilling strategy is discussed based on the observed wellbore failures. We recommended the drilling fluid pressure to be increased by 8 MPa and 14 MPa to avoid breakouts against the Ordovician and Cambrian reservoirs respectively, however, that may incur tensile fractures which do not have a considerable effect on wellbore stability while drilling. Based on this work, horizontal well trajectory along NE-SW (i.e., parallel to Shmin), together with oriented perforations aligned parallel to inferred SHMax direction is recommended. The potential fracture reactivation risks during reservoir pressurization are evaluated and discussed.
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    Petrophysical and geomechanical characterization of the Late Cretaceous limestone reservoirs from the Southeastern Constantine Basin, Algeria
    (Seg library, 2021) Baouche, Rafik; Sen, Souvik; Shib Sankar, Ganguli; Boutaleb, Khadidja
    We have characterized the petrophysical and geomechanical properties of the Late Cretaceous Turonian and Cenomanian carbonate reservoirs from the southeast Constantine Basin, northern Algeria. In general, Turonian carbonates exhibit a wide range of porosities (2%–15%) and permeabilities (0.001–10 mD), whereas the Cen- omanian reservoir appears to be very tight (<6% porosity and <0.1 mD permeability). Based on their storage and hydraulic flow characteristics, these carbonates were classified into two distinct reservoir rock types (RRT): RRT-I is hosted by nano- to microporosities that displays poor reservoir qualities compared to the RRT-II, con- sisting of mesoporous Turonian intervals (>10% porosity and 0.5–10 mD permeability). The reservoir pore-pres- sure gradient is interpreted to be a little above the hydrostatic (0.51 psi/ft), whereas the minimum horizontal stress (Sh) has a 0.72 psi/ft gradient. In situ stress analysis establishes a dominant strike-slip tectonic stress field in the basin. Shale intercalations associated with the carbonate facies are characterized by comparatively high failure pressure that can lead to wellbore failures, which may be avoided considering the recommended mini- mum drilling mud weight as obtained from the rock failure criterion. Extensive wellbore breakouts (C-quality) were observed in the acoustic image logs recorded in the studied reservoir intervals, inferring a mean maximum horizontal stress azimuth of 350°N. We recommend that deviated wells in the direction of the interpreted Sh orientation (approximately east–west) using hydraulic fracturing can be useful to attain optimum wellbore sta- bility and effective permeability enhancement. Our findings have significant implications for enhanced produc- tion within the tight carbonate reservoirs situated in a strike-slip domain.