This research presents a comprehensive study of 1D geomechanics modeling and wellbore stability analysis for directional wells in the S field, South Sumatra Basin, Indonesia. The primary goals include pre-drilling analysis and determining safe mud weight requirements about well inclinations. The study integrates data from nearby drilling experiences, incorporating wireline logs, FIT/LOT data, pressure readings, rock samples, drilling records, gamma ray profiles, and mud logs. Petrophysical analyses, shear wave velocity modeling, and the Mogi-Coulomb failure criterion were employed to define a safe mud weight range for distinct formations. The geomechanics model was calibrated using caliper data and drilling records to validate the breakout model. Additionally, the study transferred the earth mechanical model from wells S-3 and S-4 to S-8 and S-9, performing sensitivity analyses to refine mud weight recommendations and prevent shear failure. The study concludes that a maximum inclination of 30 degrees should be maintained for future wells to ensure wellbore stability. These findings provide critical insights for optimizing drilling operations in the South Sumatra Basin.

Abstract: Comparing outcrop data to laboratory results is important to verify and validate experiments of analogue and reservoir materials especially regarding conditions for deformation experiments. This is important better understand highly complex carbonate reservoir strata and their response to changes in subsurface conditions, reducing subsurface uncertainty. This study develops methods to allow for a more straightforward comparison of outcrop data (m-scale) with experimentally created fracture arrays developed in cylindrical samples (cm-scale). The main objective is to assess usefulness of experimentally-produced fracture networks as analogues for subsurface structures, typically at the meter and above scale by developing new techniques to use the lab deformation. It analyses key characteristics of laboratory-induced fracture networks by adapting scanline methods to use with x-ray tomography (XRT) images to allow for comparison with outcrop and field data. To test and verify these new methods two low permeability carbonate samples were used for deformation testing and analysis. Applying the different scanline methods we show that they can be used to analyse lab induced fractures (mm to cm-scale) identified in XRT images for comparison with outcrop data (m-scale). In addition, these methods also allow for quantification of fracture network attributes e.g. fracture spacing, fracture apertures, orientation. This new data bridges the gap between micro-scanlines using thin sections and outcrop scanlines.

The results of applying drilling engineering tools in planned deviated and horizontal wells of oil and gas condensate fields have been examined. The basis for the implementation of a comprehensive approach was the information obtained from drilling horizontal wells in the West and East Siberia, Volga-Ural region, and Iraqi Kurdistan. A synthetic model is considered as an example of the data, incorporating geomechanical and geological properties. As a result of the conducted audit of the geomechanical model and drilling process, the methodologies used were further developed to obtain optimal drilling fluid densities, aiming to prevent cavity formation on well walls, hydraulic fractures, and other related issues. The implementation of the Python programming language was introduced in the stages of geomechanical model preparation, resulting in a time acceleration of up to 20%. During the pre-drilling stage, technological operations were synchronized with the geomechanical model, increasing the involvement of process participants through the synchronization of knowledge areas. The interrelation between drilling technology, drilling parameters, properties of flushing fluids, and rock stability analysis was established, ensuring a 5% increase in construction speed (through NPT reduction and modification of existing tools and technological operations) and accident-free drilling of complex deviated and horizontal wells, provided that the recommended drilling parameters are followed.

Natural rocks are highly heterogeneous due to various geological processes that constantly alter their properties. The accumulation, deposition, and cementation of mineral and organic particles continuously modify the spatial characteristics of rock properties. Property variability or anisotropy is commonly observed in most rock types and influences strength, transport, and thermal conductivity behavior. This unpredictability presents a significant challenge for laboratory testing. Binder-jet additive manufacturing (3D printing) has emerged as a valuable technology for characterizing rock properties in geoscience and engineering. This study proposes a methodology to evaluate the variability and repeatability of mechanical properties of 3D-printed sandstones during binder-jet additive manufacturing. The mechanical properties were analyzed statistically for samples located in various parts of the 3D printer build volume. The results showed that the 3D-printed sandstones exhibited significant variations in their strength and stiffness properties when measured from samples produced within the same build volume during binder-jet additive manufacturing. The Uniaxial Compressive Strength (UCS) varied from 23 to 38 MPa, with an average value of 29 MPa. The Young's modulus, on the other hand, ranged from 1.5 to 4.05 GPa, with an average value of 2.33 GPa. The variability of the mechanical properties, quantified by the standard deviation, decreased when the entire population of 3D-printed sandstones was divided into smaller samples situated at different elevations of the build platform.

This study investigates the petroleum potential of the Middle Jurassic Khatatba Formation (Fm) in the Matruh Basin, northwestern Egypt. This formation shows in situ dual source and reservoir characteristics, where alternations of fine and coarse clastics were deposited during semi-arid and semi-humid conditions due to climate changes and Tethyan sea level fluctuations. The organic-rich shales and argillaceous siltstones are fair to very good/excellent (TOCm wt%: 0.91–3.07) source rocks. They are rich in late mature to early postmature mostly gas-prone organic facies C, which sourced the juxtaposing intraformational coarse clastics of the Lower Safa Member with gas and condensates. The source rocks show poor to fair gas generation potential (S2: 0.38–1.96, mg HC/g rock). The middle part of the Lower Safa Member shows excellent organic richness (TOCm wt%: 5.39 and 22.90) of early postmature gas-prone carbonaceous material and coal deposits. These coaly shale layers exhibit fair to excellent wet gas and condensate generation potential (S2: 4.51–27.43, mg HC/g rock). Maturation of the source rocks was related to the Late Jurassic–Early Cretaceous Tethyan rifting. The onset of oil generation occurred in the Early Cretaceous (~ 116 Ma ago), while the onset of gas generation occurred in the Oligocene (~ 24 Ma ago). Shales of the Lower Cretaceous Alam El Bueib Fm are primary sealing rocks, while carbonates and shales of the Khatatba Fm are secondary sealing rocks. Trap types are structural, formed during the Late Jurassic and Early Cretaceous rifting of the Matruh Basin. Sandstones of the Upper Safa Member show upward increases in kaolinite and exhibit low-quality tight sandstone reservoirs. The Lower Safa Member sandstones show better gas reservoir quality with lower shale volumes. Operationally, the Lower Safa sandstone reservoirs in the Imhotep W-1X well are not suitable for gas production because they are ductile and show a high decline in production and pressure. Overall, the petroleum system of the Khatatba Fm shows mainly fair hydrocarbon potential in the study area.