Reservoir delineation beneath a heterogeneous shallow gas overburden using ‘True-3D’ seismic imaging approaches
A.R. GhazaliNabil ElKadyM. Faizal Abd. RahimR.J.J. HardyF.S. DzulkelfiSandeep Kumar ChandolaSanjay KumarS. ShukriS.M.T. Mohi EldinS. Saad ElkurdyNur Liyana RafiuddinS. MaitraF.F. BasirM.L. GhazaliM.H.F. Abdul LatibS. Zainal
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Abstract:
Imaging through a heterogeneous shallow gas-charged overburden, such as a gas cloud, presents several imaging challenges and is a demanding problem to solve. Our preferred technical solution for imaging beneath gas clouds is to utilize converted wave imaging (Radzi et al., 2015), but this is not always available or cost effective and velocity model building is still difficult. Many previous case studies have been produced from Malaysia which demonstrate subsurface imaging techniques and improvements for fields affected by gas clouds, e.g., Akalin et al. (2010); El Kady et al. (2012); Abd Rahim et al. (2013); Ghazali et al. (2016) and Gudipati et al. (2018). In this paper, we describe a new comprehensive high-density experimental project to readdress these ever-challenging seismic issues by imaging the reservoir from both above and within existing boreholes. The integration of multiple technologies has significantly improved the subsurface images of the field including better-quality velocity models below gas clouds. The new data reveal a larger scale of near-surface heterogeneities than previously expected and future studies will selectively reprocess subsets of the acquired data in order to optimize the images; and, by extension to other similar fields, address a cost-effective imaging strategy.Keywords:
Overburden
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The purpose of this study was to examine the effect of grain contacts and quartz cementation with regard to acoustic wave propagation in sandstones. Grain contacts have been considered essential when relating acoustic velocities to physical rock properties, and a parameter numerically representing the contact area between individual grains (contact length) has been measured. The method used involves digital petrographic microscopy pictures analysed by image analysis software. Other parameters, such as grain size, number of grain-to-grain contacts, cracks, clay content and porosity, have also been closely examined. The results showed that the contact area between sand grains may be useful for explaining velocity variations during the initial stages of quartz cementation and grain framework stiffening. Continued increase in grain-contact area by chemical compaction will have less influence on the sonic velocity compared to variations in porosity. The Garn Fm. from the Norne Field (2.6–2.7 km burial depth), which is in the early phase of initial grain framework stiffening by quartz cementation, and the Garn Fm. from the Kristin Field (4.6–4.7 km burial depth), which is thoroughly quartz cemented, were chosen as sample materials. Log-derived velocities, in addition to some laboratory ultrasonic velocity measurements, were used in this study.
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Conrad Judd, Risto Siliqi, Fabrice Mandroux, Jo Firth and Chu-Ong Ting present examples of wide-azimuth and full-azimuth acquisition technology in salt-dominated petroleum systems to ensure delivery of optimal data.
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The Draugen Field is an elongate, low relief, anticline containing mainly multi-Darcy sandstones. Oil initially in-place (STOOIP) is 182 x 10 6 Sm 3 . The 1987 Plan for Development and Operation (PDO) assumed a central cluster of 6 deviated production wells and 3 subsea water injectors at each end of the field. In addition two subsea wells would provide early production. Unsteady state relative permeability data indicate a residual oil saturation of 35%. In the full field simulation model this was increased to 40% to account for small-scale heterogeneity. The model yielded a recovery of some 67 x 10 6 Sm 3 . Modern steady state and centrifuge techniques have since demonstrated a long tail of very low oil relative permeability before reaching a residual oil saturation of some 15%. Fine grid simulations translated this into a gravity segregation process behind the displacement front. Other fine grid models reveal that horizontal wells will yield a slower build up of water cut than vertical wells. The increased productivity of the horizontal wells reduced the required number of platform producers from 6 to 5. Pseudo-relative permeabilities were developed to represent fine grid model performance in a new sophisticated full field model. This model predicted an ultimate recovery of 94 x 10 6 Sm 3 (40% increase). The additional predicted recovery is attributed to a reduction of the effective residual saturation and delayed water production associated with horizontal wells. In October 1993 Draugen started production from one horizontal subsea well, which has since demonstrated a better than expected coning performance. Production from platform wells was initiated in June 1994 with initial well rates up to 8000 Sm 3 per day, confirming the expected high productivity of horizontal wells. Optimization and tuning of facilities has since allowed the peak production rate for the field to be increased from the planned 17 500 Sm 3 per day to a present actual level of 24 600 Sm 3 per day. Further de-bottlenecking is ongoing with the aim of increasing process capacity.
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Shale barriers within the bituminous oil sand deposits of the McMurray Formation have a detrimental effect on the steam-assisted gravity-drainage chamber growth and oil recovery. Typically, the non-net shale barrier lateral extents are too small to be detected with a few widely spaced delineation wells. The information on net reservoir and shale interval thicknesses collected from wells, along with a vertical indicator variogram, provide limited information about the horizontal extent and connectivity of these intervals. In this paper, a novel quantitative approach for predicting the lateral extents of the barriers, using thickness information provided by well log data, is proposed. The proposed approach is based on moments of inertia (MOI) applied to the shale objects to determine their effective size. The MOI calculation is aimed to simplify the almost infinite complexity of shale bodies into summary size parameters that can be readily understood and calibrated to production parameters. A case study is presented for optimal well placement accounting for uncertainty in the shale barrier sizes.
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Time-lapse seismic often gives field wide information about fluid and pressure changes in a producing reservoir. The Reservoir Characterization Project at the Colorado School of Mines has collected two multi-component time-lapse seismic surveys over Delhi Field, Louisiana, USA to monitor CO2 injection into a producing oil reservoir. Multi-component time-lapse seismic data with good repeatability, coupled with rock physics modelling, has led to successful monitoring and interpretation of fluid and pressure changes in the reservoir interval. The combination of P and PS-wave amplitude changes, along with time-shift attributes, gives a clear picture of CO2 effectively sweeping the reservoir at Delhi Field, but also shows that large pressure changes in the western portion of the field have an effect on overburden layers.
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A new 1D bed-scale model has been built to help model shale smear in interbedded sand–shale sequences using the shale smear factor (SSF). A smear envelope is generated by mapping each potential shale smear onto the fault plane employing five different shale smear geometries. Graphical outputs then focus on the cumulative length of the resultant smears and the remaining sand–sand juxtaposition windows in the predicted shale smear envelope. The smears are evaluated stochastically with lengths that are a randomized function of the estimated Vclay content of the source shale layers, allowing the smear pattern to change with each realization. A new fragmented smear mode is developed that allows discontinuous smears to be distributed randomly on the fault plane and can be used to modify the smear pattern as fault displacement increases. The model has been tested using well data. Results show that windows in the smear envelope are commonly present, and that their frequency and location are dependent on the smear placement model and sand–shale stacking pattern. Smear fragmentation leads to more windows being preserved. The 1D model can also assess the impact of geocellular upscaling on fault seal analysis. Upscaling reduces cross-fault sand connectivity due to the elimination of thin beds. Shale smear envelopes are also reduced in length as fewer shale beds are involved, even though layers are thicker. A fault may or may not appear more sealing dependent on the layer configuration and net-to-gross ratio (NTG). The model offers results that can inform input to fault seal evaluations and allows the effect of geomodel upscaling to be more closely interrogated.
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Interest in reservoir characterization continues to grow as emphasis within the petroleum industry shifts from exploration to improved recovery of existing fields with complicated heterogeneity, to contact mobile oil unrecovered or bypassed by previous injection procedures. The optimization of production using advanced secondary recovery programmes is critically dependent upon the detection of reservoir bodies, together with the distribution, alignment and density of heterogeneities on a variety of scales. Seismic measurements are of value in inferring spatial variability, using various assorted attributes derived from the wavefield, such as impedance, instantaneous phase and instantaneous frequency.
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In western Kazakhstan there are several world class hydrocarbon fields, including the onshore Karachaganak Field. The geological setting is very challenging for the seismic imaging techniques where deep carbonate platform targets underlie a complex overburden including diapiric and detached salt structures. Furthermore, the extensive oil field infrastructure generates a noisy environment for seismic acquisition and reduced access for vibroseis trucks. KPO conducted an extensive integrated feasibility study for a new survey, complemented by a seismic acquisition test in 2008 which confirmed the need for dense source and receiver coverage, long offsets and wide azimuths to optimize imaging of the pre-salt targets. The survey was acquired in 2009 and survey execution exceeded local and international standards. It was the highest channel survey acquired in Kazakhstan and when fully depth image processed it will yield a high spatially sampled seismic volume, with improved resolution and structural definition. The application of the latest technology and techniques will enable better characterization of this complex carbonate reservoir, adding future value by better placement of wells and reducing overall costs for the ongoing development of the field.
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