In a giant, mature UAE offshore field, consisting of complex multi-stacked heterogeneous reservoirs, the western part has been less developed, due to contrasted reservoir properties and low-permeability layers. The development in that part of the field was re-visited, to account for reservoir challenges and surface limitations. The objective was to achieve production mandates, understand reservoir behavior, while minimizing well count and expenditures associated with interventions and surveillance activities. To evaluate this challenging area of the field, a unique multi-lateral well was designed, targeting three distinct reservoirs, and allowing to concurrently produce and understand them in a viable manner. The reservoirs have poor characteristics, with permeability lower than 10 mD, except for the deeper one, which has some high permeability streaks. Accounting for the tight formations, each horizontal leg had to be stimulated efficiently, despite being inaccessible with coiled-tubing. In addition, well production had to be reliably back-allocated to each drain, and meet pre-defined reservoir guidelines. Despite contrasting properties, all three drains had to be produced at reasonable rates, avoiding that one drain would dominate the other two. And finally, enhanced reservoir understanding was required within each drain, with qualitative indication of their flow profile and associated reservoir conformance. The 3-legged multi-lateral oil producer was drilled and completed successfully. In each of the three horizontal laterals, totaling more than 15,000 feet length, drop-off limited-entry ‘Smart Liners’ were installed, to allow bull-heading stimulation. This offered an effective high-volume matrix acidizing method, adapted to the contrasted properties and tight zones encountered along the laterals. The well was equipped with permanent downhole gauges and inflow control valves (ICV's) to dynamically monitor downhole contributions, modulate production from each drain, avoiding well delivery to be dominated by the highest potential reservoir and control unwanted water/gas production to the surface. To complete the picture, chemical in-flow tracers were installed, in the tubing and within each drain, to monitor the laterals’ flow profiles and performance, and measure the individual contribution from each reservoir. This aimed to determine the efficiency of the ‘Smart Liners’ design and proved a cost-effective option to quantify the contribution from the laterals, compared to running regular PLTs. The resulting pilot is the first well in the world to combine a smart completion with three limited entry ‘smart liners’ utilizing drop-off technique and chemical inflow tracers. The pilot well, which behavior is being evaluated over 2021, provides a groundbreaking approach to evaluate and unlock hydrocarbon resources in a poorly developed area of the field, allowing a significant optimization of well count and of associated capital and operating expenditures.
The value of the continuing integration of logging-while-drilling (LWD) and directional drilling processes has been more prominent in the current economic environment in terms of optimizing field development costs by means of precise well placement, as well as improved reservoir characterization and drilling performance in real time. A successful horizontal drain was drilled in an undeveloped Reservoir A for the first time in an offshore carbonate sequence, using advanced LWD acoustic and high-resolution microresistivity sensors. The well plan required maximizing the exposure of the most porous body in a thinner sublayer. This sublayer lies directly over a large, developed carbonate reservoir as part of the Upper Jurassic Carbonate sequence located offshore Abu Dhabi. The flow test results during the drillstem test (DST) operation for the first appraisal well in the target reservoir produced at a rate that was greater than expected. Production log data were acquired and integrated with the LWD microresistivity image interpretation. In addition, in this environment, the inferred Rt and Rxo measurements from the LWD azimuthal focused resistivity tool were shown to be more reliable than conventional electromagnetic wave resistivity measurements, which are prone to exhibiting significant polarization, anisotropy, and bed boundary effects. Lessons learned from the first appraisal well in Reservoir A for reservoir characterization and flow unit identification were used and implemented in the planning and successful delivery of the future horizontal wells. Unlike the other reservoir subunits that are deposited within the same sequence, the field development strategy for these undeveloped reservoirs has been under review based on the recent data. The field development strategy used enhancements in well placement, formation evaluation, and production technologies, including extended reach horizontal wells, with maximized reservoir exposure in the sweetest zones, to compensate for the poor petrophysical character and low oil mobility. This case study presents insights into the advanced geosteering and multidisciplinary reservoir characterization processes along these successful horizontal drains drilled in undeveloped Reservoir A and the future horizontal wells. It also demonstrates the integration between the geological and petrophysical interpretation and the use of acoustic measurements and high-resolution microresistivity imaging. This combination has enhanced the understanding of Reservoir A in terms of the unexpected production performance and helped optimize efforts for the future field development plan.
The lower cretaceous carbonate sequence, offshore Abu Dhabi is represented by the third to forth order sequences. Limestone is the dominant lithology for this group of ramp to intrashelf basin sediments. Fracture intensity and density vary vertically along the sequences, controlled by rock texture contrast. Dense layers are heavily fractured compared to the porous bodies throughout these Formations. Two dominant sets of fractures are observed throughout the field, NW-SE and NNE-SSW. Historical well test data indicate strong preferential flow in that same direction compared to less flow in the NW-SE trend (anisotropic drainage behavior). The objective of this study is to demonstrate the capabilities of simultaneously acquired near and far field borehole sonic reflection logging measurements to characterize the present fractures along a dedicated horizontal drain for data gathering. Borehole image log interpretation and other well logs are integrated. Understanding fracture systems using resistivity imaging solely could be challenging due to the limited depth of investigation of the measurement (at the well location). Well trajectory, (open) fracture density and orientation can cause uncertainties in the number of fractures that intersect the borehole. Primary fractures could be abundant away from the borehole but still contributing to flow and reservoir pressure behavior. With a unique extended depth of investigation as well as azimuthal sensitivity, dipole sonic imaging is able to reach tens of meters into the formation and provide fracture intensity and extension information in the far field. A new scale of data integration using near field measurements from monopole sonic imaging, Stoneley wave reflectivity analysis and borehole image interpretation for a comprehensive fractures characterization is accomplished. A set of structural incidents could be detected tens of feet away from the borehole, some seemed to be extending towards the borehole wall itself as seen by the Stoneley reflectivity and the sonic-resistivity borehole imagers. Open fractures are clearly characterized in terms of orientation and aperture, extension inside the reservoir could be recognized, small-scale fractures near the borehole could be discriminated, as well as the closed ones, in addition to the dense stylolite markers. Comparisons with offset cores, seismic and offset well data shows a range of coherence. Most of the fracture clusters were observed at the stylolite boundaries. The main orientation of these fractures are consistent with the present day in-situ stress orientation. The integration of data with respect to resistivity, sonic borehole image and Stoneley wave data from sonic monopole processing are in coherence. Far-field dipole shear sonic imaging adds valuable information to investigate the major carbonate reservoir structural incidents away from the borehole. The value is maximized by integration with the high-resolution borehole image that drew some conclusions on the presence of different sets of fractures distribution and their nature.
The geophysical world has been recording seismic waves for over a century now, with the seismograph seeing first utilization towards exploration of oil and gas in the early 1900s. We started shooting 3D seismic data half a century later, and since then both our acquisition methods and how we reconstruct waves propagating through the earth with hyper-computing capabilities has evolved tremendously. Pushing the envelope of what we can image, in particular, is a major tranche of changes in seismic acquisition that started roughly a decade ago. Some of these recent developments include broader-bandwidth seismic acquisitions, particularly emphasizing low frequencies for both land and marine, and changes to sensors, sensor layouts and patterns used for shooting. These new acquisitions have refocused our emphasis on fundamentals in seismic processing, significantly advancing our ability to see the subsurface. Some of the ideas in seismic processing formulated for these acquisitions, not surprisingly, are not exclusively applicable only for modern acquisitions. Combining some of these newer approaches with pioneering ideas previous generations of geophysicists mastered, has allowed a fresh take on how large archives of legacy seismic, sitting-on-shelves, can be improved to provide fresh insights towards exploration. For the Middle East and North Africa region, where we often deal with ‘difficult’ seismic typically characterized by extremely high noise content, this re-look at older data has resulted in an evolution of workflows for vintage seismic data conditioning, leading to higher quality datasets that increase confidence and reduce uncertainty for the plays, leads and prospects we pursue. The data conditioning workflow involves a number of steps, and are mostly applied post-migration and often post-stack. These are applicable across a spectrum of data types from different sources and geological settings. Typically, these workflows are fine-tuned for each seismic dataset in a matter of days or often ‘on-the-fly’, with implementation on the next generation interpretation platform in Shell, providing extremely rapid turnaround, resulting in dramatic uplift in image quality in many cases. These have demonstrably impacted decision-making in exploration and production, providing the ability to, quite simply, see with significant more clarity what we could not see before. We share examples of utilization of these workflows, contributing towards a number of projects, including an extensive joint Abu Dhabi National Oil Company (ADNOC) and Shell effort to rejuvenate the Exploration Portfolio of Abu Dhabi, working with a country-wide database of multi-vintage onshore and offshore datasets constituting approximately 2500 2D seismic lines and more than 50 3D seismic volumes. Our workflows are grounded in past experience, yet leverage latest signal-processing innovations. They provide a step-change in our ability to rapidly investigate and interpret large volumes of challenging seismic data efficiently, in addition to enabling visualization of geological features indistinguishable on original seismic.
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