Real-time drilling analysis requires knowledge of lithology at the drill bit. However, logging-while-drilling (LWD) sensors in the bottom hole assembly (BHA) are usually positioned 2–50 m (7–164 ft) above the bit (called the sensor offset), leading to a delay in real-time drilling analysis. The current industry solution to overcome this delay involves stopping drilling to perform a bottoms-up circulation for cuttings evaluation—a process that is both time-consuming and costly. To address this issue, our study evaluates three methodologies for real-time lithology prediction at the bit using drilling and petrophysical parameters. The first method employs a petrophysical approach, which involves using bulk density and neutron porosity predicted at the bit. The second method combines unsupervised and supervised machine learning (ML) for prediction. The third method employs classification algorithms on manually labeled lithology data from mud log reports, a novel approach used in this work. Our results show varying degrees of success: the bulk density versus neutron porosity cross-plot method achieved an accuracy of 58% with blind-well test data; the ML approach improved accuracy to 66%; and the Random Forest (RF) classification with manual labeling significantly increased accuracy to 86%. This comparative analysis of three different methodologies for lithology prediction has not been previously explored in the literature. While clustering and classification methods have been regarded as the most effective, our study demonstrates that they do not always yield the best result. These findings demonstrate that ML models, particularly the manual labeling approach, substantially outperform the petrophysical method. This new algorithm, designed for real-time applications, uses selected input parameters to effectively minimize problems associated with the sensor offset of LWD tools. It rapidly adapts to changes, offering a quicker and more cost-effective interpretation of lithology. This eliminates the need for time-consuming bottoms-up circulation to evaluate cuttings. Ultimately, this approach enhances drilling efficiency and significantly improves the accuracy of lithology prediction, notably in identifying interbedded geological layers.

Permanent ocean-bottom seismic cables have been installed in the Valhall Field, offshore Norway.Five seismic surveys were acquired from the permanent system between October 2003 and April 2005, in addition to two towed-streamer surveys acqu

New completion techniques improving recovery, production rates and reducing cost and complexity are always looked for in the oil and gas industry. This paper is presenting a new concept where 100's of small level 5 laterals can be drilled simultaneously into the formation around a main wellbore. This paper presents the main concept as well as some preliminary results from qualifying the system for service in a high porosity very weak chalk reservoir. The qualification of the system is addressing three main aspects, the ability to jet a 12 meter long and 5–10mm diameter lateral, the ability to produce in high porosity weak chalk without loss of production, and simulation of production that is at least as good as or better than existing technologies like propped fractured horizontal wells, acid fractured horizontal wells and different types of openhole completions with and without liners. The experiments indicate that the system is able to achieve the results we are looking for.

Reservoir depletion/injection results in changes in effective stress, which may cause formation failure, propagation of existing fractures/faults and initialisation of new fractures/faults. A flow-deformation coupled reservoir geomechanical modelling approach has been applied to compute the change in reservoir effective stress and associated propagation of fractures and reactivation of faults. The computed inelastic strain change was used to predict the magnitudes of microseismic emissions associated with fault reactivations. The moment magnitude of microseismic events, consistent with the Richter scale, can be computed from the scalar value of their moment tensor. In a discontinuous model, the moment tensor can be calculated directly; in finite element models, the moment tensor is calculated by integrating the change in inelastic shear strain over the volume of the elements containing the failed fault. Coupled 3D geomechanical (deformation and fluid flow) simulations for Valhall field were conducted. Well rate and reservoir pressure histories were used as inputs to simulate reservoir depletion/injection. The 99 faults visible on seismic interpretations and 22 subregional fracture sets were included in the model. An elasto-inelastic cap model including water-weakening mechanism was used to model the chalk reservoir; the failure of faults and fractures were simulated by Mohr-Coulomb criterion. Prior to performing production simulation, preproduction stress modelling was carried out to reach an equilibrium stress state that was consistent with the in-situ condition, in terms of magnitude and orientation. Then, oil production at 112 wells and water injection at 15 wells for the period from 1982 to 2006 were simulated, during which the simulated microseismic events were in a good agreement with observations. The computed formation deformation in the reservoir and overburden was related to the in situ stress and faulting structure and was correlated over long distances. These characteristics are indicative of a near-critical process (and are also observed in flow rate correlations in the field). The coupled 3D geomechanical simulation provides a tool for validating modelled reservoir geomechanical effects against specific field data, and so enhances confidence in the implications predicted for drilling operations and reservoir management.