Thin-bed sequences, especially those made up of alternating weak and strong sand layers with thickness of less than 1-ft, present a particular challenge in the generation of mechanical earth models (MEMs) for geomechanics design and analyses. Because these beds are thinner than the tool resolution, their heterogeneity and the variations between adjacent layers are often undetected by logging tools normally used to acquire geomechanics data. In other words, these tools cannot resolve the existence of alternating strong and weak sequences; they provide only averaged mechanical properties across these sequences. In one such case, an MEM and sanding study based on wireline sonic data indicated no tendency for sanding across a thick reservoir interval at the drawdowns required for economic oil production. The somewhat flat, log-derived curve of unconfined compressive strength (UCS) indicated that the entire reservoir was above the critical sand-free UCS state; however, laboratory data had revealed a large spread in UCS values, including rock strength values that are indicative of a significant sanding risk. In fact, the field had a history of solids production with depletion. Using the high-resolution images (with vertical resolution of 0.2 in.) provided by a microresistivity imaging tool across the same thin-bed intervals, and using alpha processing and other petrophysical log enhancement to further improve data interpretation, it was possible to generate a high-resolution (around 0.2 in.) porosity log. These downscaling techniques were combined with an empirical UCS-porosity relationship obtained from the available laboratory data. The resulting downscaled UCS log exhibited the wide range of strength values that were known to exist across the thin-bed sequence and were consistent with the history of sand production in the field. The remaining sanding evaluation for the well was completed using this integrated petrophysics and geomechanics approach. When the MEM and sanding analyses were extended to other wells in this field, the results matched well with the actual depletion curves and sanding history data. Introduction The Sarir field in Libya, operated by the Arabian Gulf Oil Company (AGOCO), has been experiencing progressively worse sand production problems in an increasing number of wells since 1984.[1,2] A geomechanics and sanding study initiated in 2004 investigated the probable cause of this problem and provided the information and interpretations needed to select an appropriate sand management solution, assist in future development decisions, allow appropriate completions planning, and optimize future reservoir management. To this end, the results of a data audit identified what geomechanics-related information existed that might be used to characterize previous sanding problems and diagnose their root causes. A laboratory testing programme using cores from the Sarir field obtained measurements of rock mechanics parameters relevant to stress modelling and sanding prediction. [3] Integrating laboratory results with other geomechanics information available from log, field, and drilling measurements provided an initial MEM. This MEM contained most of the information necessary for subsequent geomechanics analyses and sanding evaluations.[4,5] However, one significant finding was that routine UCS determinations from sonic logs in the Sarir field were unable to detect thin weak zones having thicknesses below the tool vertical resolution (i.e., 42 in.) of the sonic wireline tool. Therefore, petrophysical log-enhancement processing6,7 was conducted to obtain high-resolution, downscaled porosity logs using microresistivity image data. These data were then used to derive high-resolution (i.e., downscaled) UCS logs through UCS-porosity correlations. The UCS data from this process, which exhibited the same strength heterogeneities observed in the core data, provided the improved description of rock strength in the MEM that was needed in the subsequent sanding analyses of the thin-bed sequences.
The Karachaganak field is giant oil and gas condensate reservoir. Data collected from numerous wells confirms it is very heterogeneous. Because conventional logs are not sufficient to fully characterize reservoir properties, new technologies and interpretation techniques are always considered worthy of a trial run when they become available in this remote region. In particular, the operator, KPO, is experiencing serious problems related to wellbore stability in deviated wells. Those problems occur mostly in the overburden and are related to uncertainty in stress direction and stress magnitudes. Excessive fluid losses while drilling are also a serious issue, and there is a need to identify fracture zones and understand fracture attributes. Finally, estimates of the extent of the formation damage zone (or radial extent of alteration in reservoir intervals) would provide useful information for the design of optimal well completions.Recently, a new advanced-technology, wireline acoustic scanning tool was run in a new well in the Karachaganak field to provide 3D formation acoustic properties from all borehole modes (monopole, dipole, and Stoneley) and measurements for near-wellbore and far-field slownesses. Drilling and completion engineers at KPO used the interpretation of this data to help make decisions and identify key geomechanical parameters required for successful operations. Mild stress-induced anisotropy zones were detected in the formation. Some zones of formation damage were identified by monopole and dipole radial variation profiling. Prominent open fractures were detected using shear dispersion analysis and Stoneley propagation -and confirmed by the electrical borehole images.KPO plans to use the acoustic anisotropy information to compute stress magnitude for new-well placement and mudweight optimization, and for oriented perforation techniques to optimize hydraulic fracturing simulation. The estimation of radial formation alteration may help in designing optimal completions and identifying suitable depth intervals for fluid sampling.
Применение усовершенствованных акустических методов исследований скважин на месторождении Карачаганак, Казахстан В. Гаджиев, Ю. Соловьев, и Ф. Эйнауди, Шлюмберже; Д. Руссо, и С. Читтик, KПO Авторское право 2010 г., SPE (Общество инженеров нефтегазовой промышленности) Данный документ был составлен для презентации на конференции по технологиям карбонатов в Каспийском регионе (SPE), которая должна состояться в г. Атырау, Казахстан, 8-10 ноября 2010г.Данная статья была отобрана Программным комитетом SPE для представления на Конференции по краткому содержанию статьи (реферату), представленному ее автором (авторами). SPE не проверяло содержание статьи, допускается внесение поправок в статью ее авторами. Материал в том виде, в котором он представлен, может не отражать точку зрения SPE, его сотрудников или членов Общества.Копирование, рассылка, распостранение или хранение любой части данной статьи без предварительного письменного согласия SPE запрещается. Разрешение на воспроизведение в печатном виде распространяется только на реферат длиной не более 300 слов; при этом копировать иллюстрации не разрешается. Реферат должен содержать явное упоминание об авторских правах SPE.
The Vertical Seismic Profile (VSP) technique is routinely used to create seismic images near the wellbore and traditionally only the up-going wavefield is used to image the subsurface below the receivers. The standard VSP technique does not give any information of the seismic image above the well trajectory. The objective here is to produce a seismic image above the top receiver depth up to sea floor using the downgoing multiples recorded in the VSP for a more complete seismic to well-tie. A seismic source is positioned below Mean Sea Level and deployed near the wellhead. The source signal is recorded by a downhole receiver that is moved to cover a large number of depth levels in the well. The upgoing and downgoing arrivals are separated during processing; the up-going wavefield is used for subsurface illumination while the down- going wavefield and multiples are normally excluded from the processing. The standard VSP technique using VSP upgoing wavefield gives a seismic image along the range of receiver depths and below the well trajectory. However, a VSP image can also be obtained from the downgoing multiple sequences. The main application of processing the sea surface multiple is to obtain a VSP image of formations above the top receiver depth which is unattainable with standard VSP technique. Results show that by using multiples, illumination coverage increases significantly in comparison to using primaries. In addition, reflectors above the shallowest receiver can be imaged by multiples, including the sea bed itself. This can be useful for different purposes such as shallow hazard identification for sidetracks or to avoid the expense of in-fill nodal seismic below the rig. We also show that the image obtained from the VSP multiples can have good resolution comparing to the surface seismic data, with better signal to noise ratio especially for the shallower reflectors. The VSP data is true amplitude, zero-phase and perfectly tied in depth and in time. By using the sea surface related VSP multiples and the mirror imaging technique, the VSP image was extended successfully above the well trajectory up to the sea floor and shows a good correlation with the surface seismic. In this case study, we present some results of using the sea surface downgoing multiple for this unconventional VSP technique.
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