This paper illustrates a novel approach (based on seismic facies classification and 3D visualization) for tracking deltaic sand systems in the Urdaneta West producing field, Lake Maracaibo, Venezuela. As part of a major field review (volume evaluation and well planning), the following oil-bearing reservoirs were studied:• Oligocene sands (braided deltaic systems) • Eocene sands (lower deltaic systems) Among the geologic challenges associated with developing these reservoirs, the thinness of the sand layers and the lack of amplitude response of heavy oil-bearing sands were key. Consequently, a dedicated geophysical workflow was designed to address these issues. It comprises the following steps:• Improving seismic resolution by applying high-frequency imaging (HFI) processing ( Figure 1) • Implementing neural-network seismic facies classification techniques (loop-level trace-shape analysis for the Oligocene reservoirs and volume classification for the Eocene sands) to evaluate nonamplitude-supported plays • Calibration of seismic reservoir indicators This workflow integrated all available seismic attributes (including poststack attributes and impedance data), improved the seismic interpretation, and provided the means to predict sands (in a nonamplitude-supported play).The geophysical results have been compared with the geologic data (cores and logs) and have confirmed the depositional model established by the geologists. Geologic challenges and technical solutions. The UrdanetaWest field is operated by Shell Venezuela on behalf of Petróleos de Venezuela SA (Pdvsa). Even though this field has been producing for nearly 40 years (with more than 100 well penetrations over the study area), exploitation and development of Oligocene/Eocene oil-bearing sands remain complex due to the following geologic challenges:• Thin sand layers (~10 ft on average) with limited lateral extent (fluvial and braided-delta deposits) • Pore fluid characteristics (12-14°API oil with a low gasoil ratio of 50 scf/bbl) resulting in a nonamplitude-supported play. Amplitude/impedance variations are not indicative of hydrocarbon presence, but can be used as lithology indicators • Poor continuity of seismic events within the Eocene reservoirs resulting in complex seismic interpretation • Density of faults (particularly in the Eocene reservoirs) affecting event correlation and possibly reservoir connectivityTo minimize these risks, Shell Venezuela conducted a major field review performed by a multidisciplinary project team. The main objectives of this project were:• To increase seismic resolution using HFI processing (resolution was enhanced from 100 to 30 ft, but individual sand layers still could not be seismically characterized) • To implement multiattribute seismic facies classification SEPTEMBER 2004 THE LEADING EDGE 909 Figure 1. Comparison between original volume (top) and reprocessed HFI volume (bottom) on SW-NE seismic line (reverse SEG convention; trough = increased acoustic impedance). Inset is structure map of Oligocene unconformity with...
Carmon Creek is Shell's Heavy Oil In-Situ thermal field development project in Peace River, Alberta, Canada. The Peace River Lease contains some 10 billion barrels of bitumen in-place at a depth of 600 m with viscosity as high as 100,000 cP. The Carmon Creek Phase 1&2 facilities, targeting a subset of this resource, are planned to start-up in 2018 and include oil treatment at 80,000 bod, produced water recycling and steam generation at 50 kt/d and electricity from co-generation at 600 MW. Over the project life-cycle, approximately 7000 dedicated wells (injectors and producers) will be drilled. The Carmon Creek development concept is a combination of cyclic steam stimulation (CSS) and vertical steam drive (VSD) utilizing vertical and deviated wells in inverted 7-spot patterns at a well spacing of 115m (or 2.8 acres). Produced and imported gas is burnt to generate steam and electricity in co-generation facilities. Electricity is exported to market. After transfer of the thermal energy in the steam the bitumen viscosity is reduced sufficiently enabling production via conventional beam pumps. The produced emulsion is separated into gas, oil and water for treatment in the central processing facilities. Acid gas consisting CO2 and H2S is re-injected to deep disposal and the remaining treated produced gas burned in the co-generation facilities. Treated bitumen is mixed with diluents for pipeline export. Steam generation is fed by recycled water with excess water stored in a saline aquifer, which can be back-produced as needed. This paper provides an overview of the main aspects of the field development, the challenges related to project delivery for a mega-thermal development and the solutions that were selected to address these challenges.
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