- Home
- A-Z Publications
- First Break
- Previous Issues
- Volume 32, Issue 10, 2014
First Break - Volume 32, Issue 10, 2014
Volume 32, Issue 10, 2014
-
-
Optimal placement of a casing shoe in a challenging HP environment in the Santos Basin, Brazil: demonstrating the value of lookahead VSP methodology
Authors A. Sharp, G. Badalini, I. Troth and M. GalaguzaThis paper describes a look-ahead VSP operation that took place in the BM-S-52 concession (Block S-M- 508), Santos Basin, offshore Brazil in June 2009. S-M-508 is a deepwater block located on the north-western edge of the Santos Basin pre-salt province, offshore Brazil, which was awarded to partner Petrobras and BG during the 7th licensing round of 2005 (Figure 1). This paper does not address the numerous recent pre-salt Santos Basin discoveries, nor the geological results from the BM-S-52 drilling campaign. For further detail regarding the pre-salt discoveries, the interested reader is directed to the list of references at the end of this article (Carminatti et al., 2008; Gomes et al., 2008; Moreira et al., 2007). The stratigraphy in S-M-508 comprises (oldest to youngest), a locally untested, at the time of drilling, Aptian-Barremian (and older) pre-salt section, followed by an Aptian evaporitic interval, overlain by a thick post-salt section, comprising Santonian to Recent clastics. The thickness of the post-salt overburden varies greatly across the block due to irregular salt distribution, and ranges between c. 300 m and 5000 m. Two wells, 6-BG-006P-SPS/Corcovado-1 and 4-BG-007-SPS/ Corcovado-2, were drilled in 2009 during the 1st exploration phase of BM-S-52 between January 2006 and 2010. These wells were drilled in water depths of 818 m and 647 m respectively using the Transocean Celtic Sea rig. The pre-salt section had not been drilled in S-M-508 prior to Corcovado-1 and -2 although the prospectivity in the post-salt interval had been tested by wells 1-BSS-74, -75 and -76 which were drilled in 1994. These wells were located using 2D seismic control and targeted Late Cretaceous, post-salt sandstones.
-
-
-
Controlling the sedimentological realism of deltaic reservoir models by the use of intelligent sedimentological prior information
Authors S. Rojas, V. Demyanov, M. Christie and Dan ArnoldT he generation of multiple reservoir models that match production data is one of the advantages of automatic history matching. Including facies geometry variations within the AHM process without the modeller control could result in the selection of reservoir models that match production data but lack of sedimentological realism (facies geometry that mimic the geometry observed in nature). These unrealistic models will cause problems in production forecasting and reserves estimation. In this article, a technique is proposed to guarantee sedimentological realism within the AHM process. Building realistic prior models that describe the non-linear dependencies between sedimentological parameters of deltaic systems can prevent the development of geologically unrealistic reservoir models. Multi-dimensional realistic priors were generated using One-Class Support Vector Machine. This technique captures hidden relations of deltaic parameters: Delta Plane Width, Length and Thickness; Distributary Channel Width and Thickness, Meander Amplitude, and Wavelength and Mouth bar dimensions. Variables are sampled from the realistic priors in order to assure facies realism. A Multiple Point Statistics (MPS) algorithm is used to model facies in a deltaic reservoir. Variability of facies geometry is produced by changing the MPS geometrical parameter, different training images and regions. History-matched models produced under geological realistic constraints reduce uncertainty of the production prediction, ensures the realism of the selected reservoir and also helps in the identification of the reservoir geometry.
-
-
-
Identifying sweet spots and moving CBM reservoirs into production
Authors M. KhairulAzmi and H. SidiqC oalbed methane (CBM) is well recognised as an important natural gas resource. However, producing it commercially has proven to be a challenging process, primarily due to the complex nature of its gas storage and flow mechanisms. Although CBM reservoirs are naturally fractured due to the presence of face and butt cleats, gas storage and saturation depend on the adsorption capacity of the coal matrix. The ability to predict permeability variations and its evolution in a CBM reservoir, which is affected by several dynamic CBM properties and operating conditions, also define the design, optimization, and analysis of the gas recovery process. As the permeability is naturally low, interventions are necessary in order to achieve commercially viable gas production rates. CBM are also dual-porosity media where the vast majority of the gas is stored in the low permeability coal matrix by sorption. The flow to production wells, however, occurs through the coal’s natural fracture system, that stores relatively small amounts of gas, because coal matrix practically has no permeability. The result is that properties of the coal matrix have the greatest effect on the estimates of gas in place and recovery. It is well understood that the key parameter controlling gas flow in CBM reservoirs are cleat networks, gas storage, desorption and permeability anisotropy (coal shrinkage and swelling). While the role of reservoir simulation is well understood for conventional oil and gas reservoirs and its related techniques for prediction and production optimisation, for unconventional reservoirs (CBM, Shale, etc.) current reservoir simulation software needs to be further developed and adapted to represent the performance of these types of fields and generate more acceptable results. For example, the basic governing fluid flow regime in conventional reservoir simulations is limited to Darcy flow. For unconventional reservoirs, however, another flow regime term comes into the equation that reflects the flow of gas in the coal matrix and stands for diffusion. This new flow regime is not very well defined in the current simulators and needs further studies to appropriately address the production performance of a reservoir. Furthermore, the concept of multi-phase flow in reservoirs is well defined by the introduction of relative permeability equations in the flow equations. However, measuring relative permeability in coal is relatively complex (Ham and Kantas, 2008) due to its friability, heterogeneity, stress dependence and porous morphology. Young et al. (1992), for example, noticed that the derived relative permeability from a history match does not resemble the laboratory measurement. This phenomenon could be due to the change of matrix structure on phase flow in addition to wettability and capillarity. In other words, both phases may flow through different passages over time due to heterogeneity. Thus dynamic relative permeability (phase saturation) is required to accurately predict recovery from a CBM reservoir. As the focus on CBM has increased in the past decades, so has the quest for more effective technologies to help bring the reserves in such complicated conditions into production and to identify sweet spots. Reservoir modelling and reservoir simulation are technologies that are likely to play a key role in achieving this. Firstly, however, it is necessary to look at the challenges of CBM property variations.
-
-
-
Fracture characterization in basement reservoirs through seismic attributes
Authors R. Alai, A.A. Aqrawi, Abu Bakar Mohamed and M. Tahar A TahaR ecent efforts to understand fracture characterization, their density and numbers have increased significantly. With the introduction of novel technologies and methodologies of data preconditioning, decomposition, and attribute analyses, new workflows have been introduced to optimally determine and visualize effective fractured networks. In detailed seismic data analysis it is critical to determine the accurate location of effective fracture zones and their characterization as these may lead to high potential hydrocarbon exploration zones. Therefore we suggest a workflow to delineate and quantify effective fracture networks from seismic data. Our proposed methodology has been calibrated using all available surface and subsurface data that included testing results. The three core elements to this workflow are: fault network delineation, fracture density zones estimation, and effective fracture zones identification. These are then used to visualize the most potential regions in the area. Then through 3D volumetric representation of the blending results, one can quantify the amount of effective fractures per region and identify areas of interest. For a detailed description of the methodologies and workflows used to achieve the results, the reader is referred to (Aqrawi and Aqrawi, 2013) and (Alai et al., 2014). Here we showcase a sequential and systematic approach to delineate dense effective fracture zones from seismic data. Only the seismic data is used to perform this analysis, and the well data is solely used for correlation and validation. The paper discusses the integration of the sequential steps of the proposed methodology that incorporate ‘consistent’ unsteered fault networks, detailed estimation of the fracture density and effective fractures zones and the geologic and structural setting of the studied area. Three datasets were obtained from the Malay basin, which has been formed as a pull-apart related to the development of the three pagoda right lateral fault. Open fractures within the Malay basin that originated by strike– slip tectonics strike NE-SW and ESE-WNW and oblique to major bounding faults of the studied areas. Wells drilled with trajectories parallel to the bounding faults intersected higher numbers of effective synthetic fracture networks with higher testing rates. From the first dataset, numerous well data have been integrated to validate the workflows and our results are supported by well testing data. Regarding the second and third case studies, the trajectories of the planned exploration wells have been validated. In addition, our results identify potential nearby areas where appraisal wells are recommended to test additional well-developed fracture networks.
-
-
-
The Pelotas Basin oil province revealed – new interpretation from long offset 2D seismic data
Authors M. Saunders and S. BowmanT he Pelotas Basin is a relatively unexplored hydrocarbon province comprising a 500,000 km² passive margin located on the southeast coast of Brazil and northern Uruguay (Figure 1). Over much of the area thick Tertiary and Cretaceous clastic deltaic and pro-deltaic sequences are underlain by syn-rift and early-drift seaward dipping reflectors (Abreu, 1998) interpreted as Aptian and pre-Aptian age. The lack of post-Albian volcanics in this basin is markedly different to the more northerly Atlantic marginal basins such as Santos, Campos, Espirito Santo, and Sergipe basins. Sedimentation on the Pelotas Margin Since the inception of rifting between South America and Africa (at 125 Ma), the position of depocenters of paleo tributaries of the Rio de la Plata moved along the margin several times. Indeed the Pelotas Basin can broadly be divided into a dominantly aggradational southern delta and an aggradation and progradational northern delta, comprised of numerous discrete deltaic bodies inter-fingering and coalescing through time. The most recent depocenter in the southern delta forms a bathymetric feature named the Rio Grande Cone, which comprises a 4-km thick Tertiary siliciclastic sequence. This is the location of one of the world’s great gas-hydrate accumulations – discussed in the following section. Of the nine wells drilled in the Brazillian Pelotas Basin, five have encountered porous siliciclastic sands. The present-day coastline is lined with abundant quartz-rich sand grains that are derived from the locally eroding crystalline basement.
-
-
-
Imaging and characterization of a shale reservoir onshore Poland, using full-azimuth seismic depth imaging
Authors H. Kowalski, P. Godlewski, W. Kobusinski, W. Makarewicz, M. Podolak, A. Nowicka, Z. Mikolajewski, D. Chase, R. Dafni, A. Canning and Z. KorenThe exploration and development of shale plays in Europe show that the ‘statistical drilling’ approach used in some basins in recent years cannot be extended to areas where local stress in rocks or fracture distribution varies both laterally and in depth. Moreover, drilling and fracturing practices confirm the presence of local geobodies resistant to hydraulic fracturing. This paper discusses the application of a new seismic data imaging method full-azimuth angle domain depth imaging, which is particularly useful when working with rich-azimuth seismic data. This innovative technology was applied to meet the challenges of imaging in a complex geological environment, and is a pioneering solution in Polish shale gas geology. Results obtained in the study from the analysis of seismic data were in line with results of the geologic and geophysical analysis of the borehole data, as well as with information from microseismic monitoring of fracturing treatment. The technology delivered high-quality images of the reservoir and geomechanical characterization of rocks with the precision needed to steer horizontal drilling, detect sweet spots, and locate geobodies resistant to fracturing. The seismic imaging workflow is based on software specifically developed to meet the challenges of shale gas seismic (Koren and Ravve, 2011, Koren et al., 2013, Canning and Malkin, 2013). One of the main advantages of this approach is that it works directly in the local angle domain (LAD) instead of the surface offset/azimuth domain. The use of in situ azimuth in LAD, visualized together with dedicated seismic attributes, provides information about the intensity and orientation of geological stress/fracture systems. Geothermal prospecting and seismic imaging of conventional hydrocarbon plays can also profit from this method. This technique is particularly suitable for Poland, where conventional seismic migration of reflections from geology covered by a complex overburden has frequently resulted in improper imaging.
-
-
-
Reservoir characterization of the Montney Shale – integrating seismic inversion with microseismic
Authors Claudia Dueñas and Tom DavisUnderstanding the optimization of heterogeneity of unconventional shale reservoirs prior to hydraulic fracturing is important for optimizing hydrocarbon production and recovery. Early prediction of geomechanical heterogeneity impacts the efficiency of horizontal well placement and completion design. Heterogeneity within shale reservoirs is influenced by composition and textural variation of the rock, ie, the rock quality. Rock quality can be evaluated or predicted with seismic-derived rock properties. This study shows how seismic data are used to determine rock quality through a multi-attribute analysis of wells logs integrated with post-stack and pre-stack inversion to characterize the Montney Shale at Pouce Coupe, Alberta (Duenas, 2014). The heterogeneity analysis combined with microseismic data and production profiles of the two horizontal wells in the area shows that lithology has a major influence on the rock quality of the Montney interval. The combined interpretation of this work with an understanding of the natural fracture system and the stress state of the reservoir can provide a rock quality index (RQI). This RQI can aid in future exploration and operational development of the Montney and other shale reservoirs worldwide.
-
-
-
An iterative AVO inversion workflow for pure P-wave computation and S-wave improvement
More LessAlthough routinely used for reservoir prediction, the conventional full-stack data is usually contaminated by AVO effects. So, AVO inversion, known for its real P-wave information with AVO effects removal and other abundant elastic attributes, is usually applied for a better reservoir prediction. However, it is not easy to conduct an AVO inversion precisely and efficiently, since the S-wave results of the conventional linear inversion method (relatively fast) have been concluded to be highly effected by the initial Vp/Vs model, while the non-linear inversion method easily falls into local optimization and is also computer-intensive. To overcome these shortcomings, this paper presents an iterative AVO inversion workflow to improve the inverted S-wave component for reservoir prediction at an acceptable speed at first, and then tests it by both modelling and field data. It is proven to be an effective workflow to improve inverted S-wave data.
-
Volumes & issues
-
Volume 42 (2024)
-
Volume 41 (2023)
-
Volume 40 (2022)
-
Volume 39 (2021)
-
Volume 38 (2020)
-
Volume 37 (2019)
-
Volume 36 (2018)
-
Volume 35 (2017)
-
Volume 34 (2016)
-
Volume 33 (2015)
-
Volume 32 (2014)
-
Volume 31 (2013)
-
Volume 30 (2012)
-
Volume 29 (2011)
-
Volume 28 (2010)
-
Volume 27 (2009)
-
Volume 26 (2008)
-
Volume 25 (2007)
-
Volume 24 (2006)
-
Volume 23 (2005)
-
Volume 22 (2004)
-
Volume 21 (2003)
-
Volume 20 (2002)
-
Volume 19 (2001)
-
Volume 18 (2000)
-
Volume 17 (1999)
-
Volume 16 (1998)
-
Volume 15 (1997)
-
Volume 14 (1996)
-
Volume 13 (1995)
-
Volume 12 (1994)
-
Volume 11 (1993)
-
Volume 10 (1992)
-
Volume 9 (1991)
-
Volume 8 (1990)
-
Volume 7 (1989)
-
Volume 6 (1988)
-
Volume 5 (1987)
-
Volume 4 (1986)
-
Volume 3 (1985)
-
Volume 2 (1984)
-
Volume 1 (1983)