Browsing by Author "Baouche, Rafik"

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Analysis and interpretation of environment sequence models in Hassi R’Mel Field in Algeria
(2009) Baouche, Rafik; Nedjari, A.; Eladj, S.; Chaouchi, Rabah
Analysis of rock mechanical parameters from well log data and Dipole Shear sonic Imager. Application to Algerian sahara "Algeria"
(2009) Eladj, S.; Baouche, Rafik
The use of 'DSI' (Dipole Shear sonic Imager), in the Tin Fouye Tabankort area in Algeria allowed the exploitation of the rock mechanics properties in the field of drilling having for objective determination of the margin of ability of the well. The tool 'DSI' has a considerable advantage by its application which makes it possible to combine the technology of monopole and of dipole and to offer an effective method for the determination of the acoustic dynamic mechanical properties in - situ. The practical results of this study showed that: 1 - The phenomenon of BIOT is less when the medium is impermeable, 2- There is a significant effect of the petrophysic properties on the mechanical properties expressed by the effect of the coefficient of BIOT on the variation of the values of the density of mud. The beach of variation of the stability of the well obtained starting from the tool 'DSI' lies between the values 1.40 g/cc and 1.80 g/cc. On the other hand the results obtained by the application of Leake-off test and the successive increase in the density of mud vary from 1.50 g/cc with 1.90 g/cc. With the base of these results, it is necessary to note that the result obtained by tool DSI is almost closer than the practical methods and the percentage of error obtained by the application of this tool is due to the difference between the dynamic and static mechanical properties. The finality of this study is to determine a field of application of this new technique in the study of the stability of the well during drilling
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.
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.
Carbonate reservoir quality variations in basins with a variable sediment influx : a case study from the balkassar oil field, potwar, Pakistan
(American Chemical Society, 2022) Muhammad Raiees, Amjad; Muhsan, Ehsan; Muyyassar, Hussain; Al-Ansari, Nadhir; Abdul, Rehman; Zohaib, Naseer; Muhammad Nauman, Ejaz; Baouche, Rafik; Elbeltagi, Ahmed
The carbonate reservoir quality is strongly reliant on the compaction process during sediment burial and other processes such as cementation and dissolution. Porosity and pore pressure are the two main factors directly affected by mechanical and chemical compactions. Porosity reduction in these carbonates is critically dependent on the overburden stress and subsidence rate. A variable sediment influx in younger basins may lead to changes in the reservoir quality in response to increasing lithostatic pressure. Deposition of molasse sediments as a result of the Himalayan orogeny caused variations in the sedimentation influx in the Potwar Basin of Pakistan throughout the Neogene times. The basic idea of this study is to analyze the carbonate reservoir quality variations induced by the compaction and variable sediment influx. The Sakesar Limestone of the Eocene age, one of the proven carbonate reservoirs in the Potwar Basin, shows significant changes in the reservoir quality, specifically in terms of porosity and pressure. A 3D seismic cube (10 km2) and three wells of the Balkassar field are used for this analysis. To determine the vertical and lateral changes of porosity in the Balkassar area, porosity is computed from both the log and seismic data. The results of both the data sets indicate 2-4% porosities in the Sakesar Limestone. The porosity reduction rate with respect to the lithostatic pressure computed with the help of geohistory analysis represents a sharp decrease in porosity values during the Miocene times. Pore pressure predictions in the Balkassar OXY 01 well indicate underpressure conditions in the Sakesar Limestone. The Eocene limestones deposited before the collision of the Indian plate had enough time for fluid expulsion and show underpressure conditions with high porosities
Characterization and estimation of gas-bearing properties of Devonian coals using well log data from ﬁve Illizi Basin wells (Algeria)
(2020) Baouche, Rafik; Wood, David A.
In Algeria, wells drilled in the Illizi Basin suggest the presence of a signiﬁcant areal trend of Devonian coal seams with the thickest coal seams penetrated in the Lower Devonian stratigraphic unit F6. This makes them some of the oldest thick coal seams encountered. These coals exist between approximately 1500 and 4000 meters below surface. In particular, numerous coals in these formations drilled in the Oudoume ﬁeld have recorded gas shows while drilling. A study of basic well log data from ﬁve wells penetrating Illizi Basin coals is conducted to characterize their distribution and provisionally evaluate their gas-bearing potential using petrophysical analysis coupled with machine learning. A simple multi-layer perceptron model (one hidden layer with four nodes) is used in a novel way to replicate estimates of gas saturation in the coal samples calculated approximately with the modiﬁed Kim equation. It does so by considering three commonly measured well-log variables: gamma ray, sonic travel time, deep resistivity (307 data records from the ﬁve wells studied). The log-calculated approximations (modiﬁed Kim equation) can be matched to better than plus or minus 1 scf/ton by the multi-layer perceptron model. The results and analysis presented provide preliminary encouragement that suggests the presence of a potentially extensive gas-bearing Devonian coal trend in the Illizi Basin that is worthy of further exploration. Future work is required to integrate data from additional wells and laboratory analysis of core samples to verify the extent of that coal trend and to quantify its gas concentrations.
Characterization of pore pressure, fracture pressure, shear failure and itsimplications for drilling, wellbore stability and completion design–A casestudy from the Takouazetfield, Illizi Basin, Algeria
(Elsevier, 2020) Baouche, Rafik; Souvik, Sen; Boutaleb, Khadidja
We analyzed drilling induced tensile fractures from resistivity image log data to ascertain the orientation of maximum horizontal stress (SH) from the eastern Illizi basin, Algeria. An average SH azimuth of 150�N (� 10�) has been interpreted from B-quality induced fractures, as per world stress map guidelines. The overall NW-SE orientation of SH translates to the relative plate motion of the African and Eurasian plates. Vertical stress (Sv) gradient of 1.07 PSI/ft has been derived from density log. Pore pressure estimated from sonic slowness reveals overpressure in Silurian shale, deposited in a transgressive depositional environment, whereas Devonian and Ordovician hydrocarbon reservoirs have been seen to be normally pressured. Poroelastic strain model has been employed to quantify maximum and minimum horizontal stress (Sh) magnitudes. An effective stress ratio of 0.6, interpreted from leak-off test has also been used to model Sh. Using frictional faulting theory, upper limit of SH has been quantified. SH/Sv ratio of 1.04 (1.01–1.26) has been seen in the study area. Based on the relative stress magnitudes (SH > Sv > Sh), a present day strike-slip faulting regime has been inferred in the eastern Illizi basin, Algeria. Fault reactivation potential at reservoir level has been inferred from stress polygon analysis.
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.
Determining shear failure gradient and optimum drilling mud window in the ourhoud oil field, berkine basin, Algeria
(2022) Baouche, Rafik; Souvik, Sen; Hadj Arab, Feriel
Optimum drilling mud window provides a workable downhole mud pressure range to prevent formation fluid influx, borehole instabilities, and fluid loss into the formation while drilling, and this can be achieved by a comprehensive geomechanical modeling using well data. We have integrated the wireline logs, drilling data, and measured downhole data to assess the vertical stress, pore pressure, minimum horizontal stress, and shear failure (SF) gradient of the 3400 m thick Mesozoic and Paleozoic succession in the Ourhoud field, Berkine Basin. We interpreted the hydrocarbon pressure gradient in the Triassic Argilo-Greseux Inferieur reservoir as 0.32 psi/ft and found the overburden shales to be hydrostatically pressured (0.46 psi/ft). Poisson’s ratio-based minimum horizontal stress has a 0.73–0.80 psi/ft gradient, whereas frictional faulting theory provided a lower limit of 0.66 psi/ft. We observed massive wash outs in the caliper logs against the Cretaceous shales, which is more prone to compressive failures. To address this wellbore failure, we modeled SF gradient by Mohr-Coulomb rock failure criteria and compared the results with the mud pressure used in drilling. We inferred that at least 10.5 ppg drilling mud weight is required to prevent such wellbore instabilities in the Mesozoic shales, whereas the minimum allowable mud weight for the Carboniferous shale is 10 ppg. Based on the interpreted pressure gradients, we have recommended an optimum downhole drilling window for the Ourhoud field, which will be helpful to deliver stable wellbores in future drilling campaign
Distribution of pore pressure and fracture pressure gradients in the paleozoic sediments of Takouazet field, Illizi basin, Algeria
(Elsevier, 2020) Baouche, Rafik; Souvik, Sen; Boutaleb, Khadidja
A comprehensive pore pressure and fracture gradient (PPFG) characterization is a basic requirement for subsurface geomechanical modeling. This study deploys indirect approaches to estimate subsurface pressure profiles in the Mesozoic and Paleozoic successions of eastern Illizi basin, Algeria. Amoco exponent has been modeled for pseudo density generation and overburden gradient has been deciphered from a composite density profile. PP calculated from sonic and resistivity logs have been calibrated and validated with direct downhole measurements. Results indicate normal pore pressure regime in the Mesozoic and Devonian sediments. Disequilibrium compaction induced abnormal pore pressure in Silurian marine shales with a maximum gradient of 12.7 PPG. Top of geopressure has been marked at Silurian top (2050m). Pore pressure drops sharply from Silurian to Ordovician sediments, across the glacial unconformity (2332 m). Fracture gradients have been interpreted by Eaton's Poisson's ratio based model and Mathews & Kelly's effective stress ratio based approach. Based on the vertical distribution of subsurface pressure, effective vertical stress, a safe mud window has been recommended for optimum drilling fluid design
Effect of petrophysical and sedimentological properties 1on heterogeneity of carbonate reservoirsin South Eastern 2Constantine’sReservoirs in Algeria: impact on produc-3tion parameters
(2019) Baouche, Rafik; Boutaleb, Khadidja; Debiane, Kahina
Carbonated reservoirs, concentrated mainly in the Middle East, contain about 50% of 10 the world's hydrocarbon resources and the challenge they represent for the sustainable devel-11 opment of oil resources is considerable and their production challenges are commensurate with 12 this potential. 13 The characterization of these reservoirs through the control of their heterogeneities makes it 14 possible to reduce the uncertainties on the quantification of their reserves in order to improve 15 their productivity as well as their recovery rate. 16 The recovery rates obtained from the carbonate reservoirs are mainly attributed to their deposi-17 tional environments, diagenetic history, and the very varied climatic conditions, resulting in a 18 very heterogeneous geology and represent difficult challenges to overcome where the permea-19 bility varies greatly, the only requirement for better results in production. The permeability 20 measured on cores or by production tests can vary from less than 10% to more than 40% on 21 average permeability deposits (10 to 100 md)). In addition to these parameters, the diversity of 22 recovery mechanisms and development patterns, on which the dynamic behavior of the intersti-23 tial fluids depends, are far from being conditioned by the single permeability factor. 24 Nowadays, in Algeria, the valorization of carbonated reservoirs, mainly located at the level of 25 South Eastern Constantinois reservoirs where most of these reserves remain unexploited, are 26 among the strategic and priority objectives, because of their complexity. 27 Indeed, the study of stratigraphic heterogeneities, obtained from logging data and core studies, 28 applied to SouthEastern Constantinois reservoirs (Algeria), shows that the results play an 29 important role in the development of carbonate reservoirs production in this area.
Effect of petrophysical and sedimentological properties on the heterogeneity of carbonate reservoirs : impact on production parameters
(Springer, 2020) Baouche, Rafik; Boutaleb, Khadidja; Chaouchi, R.
The carbonated reservoirs, concentrated mainly in the Middle East, contain about 50% of the world’s hydrocarbon resources, where the considerable challenge they represent for the sustainable development of oil resources and the challenges posed by their production are commensurate with this potential. The characterization of these reservoirs through the control of their heterogeneities makes it possible to reduce the uncertainties on the quantification of their reserves inorder to improve their productivity as well as their recovery rate. The recovery rates obtained today on the main carbonated fields are mainly related to their sedimentary deposits and the very varied climatic conditions, resulting in a very heterogeneous geology and represent difficult challenges to overcome where the permeability is not the same, only condition for better production. This can vary from less than 10% to more than 40% on medium permeability deposits (10 to 100 md). To these parameters is added the diversity of recovery mechanisms and development patterns, on which the dynamic behavior of the deposit depends, which are far from being conditioned by the single permeability factor. Currently, in Algeria, the valorization of carbonated reservoirs, mainly located at the level of South Eastern Constantinois reservoirs where most of these reserves remain unexploited, are among the strategic and priority objectives, because of their complexity. Indeed, the study of stratigraphic heterogeneities, obtained from logging data and core studies, applied to South-Eastern Constantinois reservoirs (Algeria), shows that the results play an important role in the development of carbonate reservoirs production in this area
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.
Facies analysis and permeability/ porosity prediction from well log data using the non parametric regression with multivariate analysis and neural network in the reservoirs of the Hassi R’Mel southern field (Algeria)
(2016) Baouche, Rafik; Baddari, Kamel
Facies analysis of triassic formations of the Hassi R’Mel in southern algeria using well logs : recognition of paleosols using log analysis
(2009) Baouche, Rafik; Nedjari, A.; El Aadj, S.; Chaouchi, Rabah
Well logs are essential in the study of geological formations, in terms of taking into account the nature and the structure of the formations, as well as the sedimentary processes. Qualitative and quantitative interpretations of well logs respond to a sedimentologic need as well as the establishment of lithological columns, according to the response to logging tools. In this study, electrofacies have been defined by manual well-log analysis of ten surveys of Triassic formations in the Hassi R'Mel area of Algeria. The data thus obtained were then matched with sedimentary facies defined by core analysis. The results obtained during the facies analysis made it possible to define ten electrofacies (sands, shale, dolomite, and evaporite, as well as the presence of andesite and clay). The model obtained by the Petrolog software was also developed and tested on other wells. A semi-automatic data processing was then carried out on seven other wells.Our aim is to highlight the added value of this integrated regional-scale to reservoir-scale approach in identifying nearfield exploration potential and additional recovery opportunities in producing reservoirs. Based on this aim, we emphasise the following points using our facies modelling: (1) improved definition of deposition within and between reservoirs, (2) development of regionally sedimentological models for reservoir intervals (the Hassi R’Mel Formations), and (3) recognition of paleosols from well log analysis and controls on reservoir architecture and their links to the Triassic Province of Algeria
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
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.
Image log processing and interpretation : interpretation of well imaging by electrical logging
(Lap lambert, 2020) Baouche, Rafik
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.
Integrated reservoir characterization of the Paleozoic and Mesozoic sandstones of the El Ouar field, Algeria
(Elsevier, 2020) Baouche, Rafik; Souvik, Sen; Debiane, Kahina; Ganguli, Shib Sankar
This study presents the interpretation of depositional environment and petrophysical properties of Mesozoic and Paleozoic reservoirs from the south-eastern Berkine Basin, Algeria by integrating core analyses and geophysical logs. Sedimentary structures and ichnofossils identified from 100 m of recovered cores have been interpreted to characterize the depositional settings of the studied reservoirs. During the mid-late Triassic, fluvial to marginal marine processes deposited the TAGS and TAGI reservoirs, while the Palaeozoic megasequences are characterized by shallow marine reservoirs (tidal bars and foreshore deposits) interbedded with thin marine shales. Porosity and water saturation have been estimated from geophysical logs and calibrated with core-based laboratory measurements. An empirical relationship between core porosity and permeability has been established for the El Ouar area and the same has been employed to generate a continuous and confident permeability profile against the target reservoir formations. Petrophysical characterization indicates a higher porosity and permeability in Triassic and Carboniferous sandstones than the Devonian F6 members. Triassic TAGS and TAGI sandstones possess the highest reservoir qualities in the El Ouar field. The Thorium and Potassium content available from spectral gamma-ray data have been utilized to identify the clay types associated with various sandstone reservoirs (Illite in Triassic sandstone, Kaolinite in Carboniferous units, mixed clay and Th bearing heavy mineral dominance in Devonian units). The study will be helpful for understanding of hydrocarbon resource potential and subsequent production planning in the study area.