Once the land grab is over, operators should turn to seismic data to understand their valuable acreage.
In conventional exploration plays, 3-D seismic data and advanced processing with a detailed interpretation are usually used to locate wells on structural and stratigraphic traps. In shale plays, favorable geology studies are used to lease hundreds of thousands of acres, and wells are drilled almost immediately without 3-D seismic data studies to test the concept, advance to commercial development, and start holding acreage on often short-term leases.
Most oil companies begin by drilling vertical holes to acquire technical data such as multiple well logs, whole cores, and production test data. This is followed by a horizontal drilling program with various completion designs to improve production rates. Microseismic data in a nearby monitor well or from a surface geophone array can be used to gain some understanding of the fracture network. After a reasonable production history is established, companies determine an average estimated ultimate recovery (EUR) for wells on the leasehold. At this stage of development in most shale plays, 3-D seismic is a not a factor in the well locations, placement of wells in the shale, or hydraulic fracture designs.
Applying 3-D to shale plays
The cost of 3-D is a very small percentage of leasing and drilling costs. But permitting delays and the two-year cycle time from planning to interpretation of a large 3-D survey is not a good match for the accelerated drilling programs required for companies to hold acreage and generate cash flow. Shale plays are usually managed by petroleum engineers, and there is a gap in understanding terminology between engineers and geophysicists. Integration efforts are required for these disciplines to work together as a team.
Also, there are diverse opinions on the value of 3-D seismic, and the industry is on a steep learning curve.
A company must have a long-term view of the application of 3-D seismic in shale plays. Thousands (even tens of thousands) of wells will be drilled over the next dozen years and beyond, and there will be many issues concerning infill well location, well spacing, improving fracing methodology, characterizing and forecasting areas of better production, increasing average EUR per well, identifying refrac candidates, and making corporate strategic decisions such as acquisition and divestiture. Geophysicists must show oil company management that 3-D seismic is a good investment to help engineers address these issues and improve profit over the long term.
A simple approach
High-quality 3-D seismic can be used to make very detailed regional and local structure maps, show areas of complex faulting (drilling hazards), determine shale thickness, and outline depositional patterns such as scour zones or reefs where shale may be thin or absent. Seismic time-to-depth conversion can greatly assist in the planning and geosteering of horizontal wells.
The seismic industry today is focusing on important attributes to recognize shale sweet spots. It is routine to make coherence cubes to improve fault resolution and build basic full-stack acoustic impedance (velocity times density) volumes that transform the seismic into layers and remove the effects of the seismic wavelet. Seismic resolution may be impacted by high-velocity brittle zones in the shale, but in a general sense, low acoustic impedance is an indication of high porosity (above 10%) related to high TOC intervals. Similar to conventional plays, higher porosity usually is indicative of higher productive gas and oil wells.
All of the above mapping and technology is “old stuff” – geophysicists have been doing this for many years. Yet this standard interpretation work process still has much value.
Beyond traditional seismic
The next step can be advanced seismic inversion, which requires prestack seismic data measurements to discriminate among lithology, porosity, fluid, and possible fracture effects. Long-offset and full-azimuth data acquisition is required. The goal is to make volumes of compressional velocity, shear velocity, density, porosity, Poisson’s Ratio (compressibility), and Young’s Modulus (brittleness). Good seismic data quality and calibration to edited well log data and cores are essential for success.
Mapping fracture patterns using seismic data is very complex and is a major part of research today. One approach is to generate various types of curvature volumes –measurements of how curved or bent a surface is at a particular point – that can indicate areas of increased natural or healed fractures. A very advanced approach is to use anisotropic variations in rock formations, where velocity varies relative to the direction of propagation, to map the stress field, which can then be used to map the dominant fracture direction and patterns. Seismic processing requires understanding anisotropy in any geologic setting, and commonly used terms include horizontal transverse isotropy, typically related to vertical fracture patterns, and vertical transverse isotropy, related to horizontal bedding planes. Microseismic data, which now can be interpreted in real time, will play a big role relating 3-D seismic to drilling results.
Significant advances are being made to apply 3-D seismic data and processing to help oil companies increase shale play profitability. These advances can lead to cost savings, higher EUR wells, and even reduced drilling pad footprint. Service companies and oil companies are searching for the best group of seismic attributes to identify shale sweet spots. Observations on 3-D seismic tied to drilling results should be part of the continuous learning process, and a long-term view is essential.