This paper helps to address the growing need to resolve the severe loss of deltaic lands by providing a new understanding for shallow‐water digitate delta growth. The integration of satellite image analysis of modern deltas, field studies of the Ganjiang Delta in the Poyang Lake and ‘Delft3D’ simulations further results in improved facies models for shallow‐water digitate deltas. These analyses show that shallow‐water digitate delta bar fingers are sinuous in contrast to the straight deep‐water digitate delta bar fingers. These differences are assigned to the effect of water depth on outflow hydraulics, where friction‐dominated shallow‐water delta effluents promote mouth bar deposition that then divert flow around the mouth bar, resulting in the formation of sinuous bar fingers. These effects are further strengthened by the meandering of the shallow‐water jet that increases lateral sediment transport, and by the higher flow resistance and lower gradient of the shallow‐water outflows. Our data and analyses further show differences in the morphology and deposits of the shallow‐water sinuous bar fingers, where some bar fingers develop sinuous and others meandering (with point bars) distributary channels. Lateral channel migration and point bar formation (meandering) occur as a secondary process that does not change the shape or width of the bar fingers themselves, and is suggested to be a function of slight initial differences in channel sinuosity. These differences in distributary channel morphology have a strong effect on bar finger facies distribution. Sediment cohesion is another important control on bar finger bending processes, because high cohesion promotes formation of enclosed bays, where their bank strength exceeds the centrifugal force of water flow. Lower sediment cohesion results in sinuous bar fingers without formation of enclosed bays. This work provides insights into natural and artificial shallow‐water digitate delta growth and provides new quantitative facies models for shallow‐water digitate deltas.
Hydraulic fracturing in tight gas sandstone reservoirs increases the connectivity of the well to more reservoir layers and farther areal regions, thus boosting the production as well as the net-present-value of the project. When comparing different well performances, wells that far outperform other wells are usually connected to high permeability streaks or natural fractures. This paper demonstrates the analysis and performance evaluation of hydraulic fractures that are connected to high permeability streaks or natural fractures.In order for oil and gas operators to consider the development of tight gas sandstone reservoirs economically feasible, stimulation operations such as a large hydraulic fracture treatment of the wells are required. However, the induced fracture is not the main reason for the success of many of the field development in tight gas sandstone reservoirs. In the Southern North Sea, the more productive multiple hydraulically fractured horizontal wells (MHFHW) are usually connected to high permeability streaks or natural fractures. In this work, a reservoir with high permeability streaks and natural fractures was then modelled. This is then calibrated against several years of production and pressure history.The analysis of core data, borehole image logs, well tests and geomechanics data demonstrated the existence of high permeability streaks or natural fractures in the reservoir. The data derived from the analytical methods were then captured in the simulation model. The simulation model shows a very good match with the history data and when compared with a 3-week long shut-in, the build-up pressure response and its derivative displayed an excellent match. This study shows that, in addition to the role played by the hydraulically induced fractures, natural fractures and high permeability streaks also serve as dominant factors in success of tight gas sandstone reservoir development.This study demonstrates a practical integrated approach towards the modelling of high permeability streaks and natural fractures that are connected to hydraulic fractures. This can be used to better understand hydraulic fracturing and tight gas sandstone reservoirs in the Southern North Sea.
Autogenic processes are widely found in various sedimentary systems and they play an important role in the depositional evolution and corresponding sedimentary architecture. However, autogenic processes are often affected by changing allogenic factors and are difficult to be identified and analyzed from modern and ancient records. Through the flume tank experiment under constant boundary conditions, the depositional process, evolution principles, and the sedimentary architecture of a river-dominated delta was presented, and a corresponding sedimentary architecture model was constructed. The evolution of river-dominated delta controlled only by autogenic process is obviously periodic, and each autogenic cycle can be divided into an initial progradational stage, a middle retrogratational stage, and a late aggradational–progradational stage. In the initial progradational stage, one feeder channel incised into the delta plain, mouth bar(s) was formed in front of the channel mouth, and small-scale crevasse splays were formed on the delta plain. In the middle retrogradational stage, the feeder channel was blocked by the mouth bar(s) which grew out of water at the end of the initial stage, and a set of large-scale distributary splay complexes were formed on the delta plain. These distributary splay complexes were retrogradationally overlapped due to the continuous migration of the bifurcation point of the feeder channel. In the late aggradational–progradational stage, the feeder channel branched into several radial distributary channels, overlapped distributary channels were formed on the delta plain, and terminal lobe complexes were formed at the end of distributary channels. The three sedimentary layers formed in the three stages constituted an autogenic succession. The experimental delta consisted of six autogenic depositional successions. Dynamic allocation of accommodation space and the following adaptive sediments filling were the two main driving factors of the autogenic evolution of deltas.
The high prices of energy encourage investments in oil and gas research and development leading to new or improved technologies to recover more hydrocarbons from resources and re-evaluate the reserves. As a result of such technological developments and experience of job practices, hydraulic fracturing techniques have improved significantly in terms of designing and execution and this, at the same time, has made the process much more complicated. This paper suggests a practical multi-disciplinary workflow for hydraulic fracturing modelling mainly in tight gas sandstone reservoirs.Hydraulic fracturing stimulations in costly environments such as the Southern North Sea require deeper insight into the chemistry and mechanics of the process, characteristics of the formation, and most importantly, the interactions during and after the stimulation job. Different sources of information and analysis such as seismic, reservoir static modelling, initial geomechanical modelling, initial hydraulic fracturing study, fracture initiation point analysis, 1-dimensional (vertical) stress modelling per frac, mini-frac, mainfrac, flowback analysis, well test analysis, and reservoir dynamic modelling are discussed in this paper. The key data cross checks are recognised and lessons learnt from industry are also incorporated to highlight the possible outcomes of different decisions.Having more information, particularly from different disciplines, can be more productive only if a comprehensive guideline explains the essential elements of the required studies and illustrates their interrelations. This workflow has been the reference of a validated study for a multi-fracced tight gas sandstone reservoir in the Southern North Sea. The workflow has been deployed to organise and recognise the key elements that control the performance of hydraulically fractured wells in a heterogeneous environment. From the workflow, a thorough examination and analysis of available data were performed and fed into the static and dynamic models. As a result of the integrated workflow, a better understanding of the reservoir was formed and potential upside opportunities became visible.This paper highlights the importance of integrated multi-disciplinary workflow required to detect, characterise and evaluate information from the field into a product that can be used to better understand hydraulic fracturing and tight gas sandstone reservoirs.
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