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Seismic surveys are important because they can be considered a “snapshot image” of the subsurface acoustic properties for any hydrocarbon reservoir and their surrounding sediments; i.e., it is a static 3-Dimensional “picture” (of the reservoir at the exact time of surveying) that captures the physical properties of the geological bedding features of the reservoir being produced and the Area of Interest (AOI) captured by the seismic survey. Since seismic imaging is the one sure-fire way to image every 3-D point of a subsurface hydrocarbon reservoir, these snapshot images of the field are the most conclusive and comprehensive dataset available to any company attempting to gain a firm technical understanding of their reservoirs. Clearly, they can be considered the most valuable source of technical information for any reservoir.
Most seismic surveys are performed during the exploration phase of the reservoir’s life – rarely are additional seismic surveys acquired at later dates. They are not only expensive to perform, but they also shut down the production of the field to carry out the acquisition of the survey, therefore they are more cost-prohibitive than simply shooting the survey itself. This is the primary reason that management opts out of any additional seismic surveying during the production phase of their reservoirs.
Perhaps the most debilitating problem with a static image (i.e., a seismic survey) of any field is that these images are nearly always exclusively taken during the inception of the exploration phase of these reservoirs. Since most hydrocarbon reservoirs in the world produce for 20+ years, these surveys become less valuable over time as production of the hydrocarbons constantly alter the reservoir’s acoustic properties and the true delineation of the subsurface fluids and their migration pathways can only be extrapolated from this initial snapshot image. To compensate for this knowledge gap, the industry has learned to rely on other processes (such as reservoir engineering techniques [e.g., material balance]) to supplement the knowledge gained from the initial seismic survey – but these techniques are flawed, at best, and this is why PRM is considered to be the “Holy Grail.”
The best way any company can hope to keep an eye on the migration of the hydrocarbons in their reservoirs is to have constant, real-time updates of static snapshot images taken throughout their field. The collective term for this type of seismic monitoring is called 4-D imaging. 4-D imaging gives the technical professionals in charge of producing their reservoirs real-time static image updates of the field’s subsurface acoustic properties – allowing them to discern baffles to flow, low-permeability zones, faulting, and a myriad of other barriers that inhibit hydrocarbon production. This is why PRM is so important
In order to attempt to overcome these severe debilitations encountered by Oil and Gas producers that attempt to most efficiently produce their reservoirs based on snapshot images taken upwards of 10+ years from their current vantage point, Argus Reservoir Monitoring (ARM) has been formed in order to tackle this challenge head-on by developing the tools required to effectively and permanently image these subsurface reservoirs and their ever-changing acoustic properties. The cost required to emplace permanent monitoring tools in the subsurface in and around hydrocarbon reservoirs compared to the amount of technical knowledge gained from these tools makes this decision a no-brainer for any management team in charge of hydrocarbon production for their company’s reservoirs. A functioning and effective PRM system will be – simply put – a game changer.
ARM believes that any company capable of reaching this goal first will not only succeed in a technical sense, but the financial rewards from any initial investments will also be truly astronomical.
The prototype that ARM will build has been designed to mimic existing seismic sources used in the industry today. These tools create usable acoustic wavefronts capable of penetrating the subsurface 25,000 ft. Since these source tools and the receivers that record the reflected waves are located on the ground-level surface, these generated wavefronts must also travel an additional 25,000 ft upward from the lowest point in the subsurface. Put more simply, these existing source tools must generate enough acoustic energy to travel 50,000 ft in distance. This total distance of 50,000 ft is known in the industry as 25,000 ft “Two-Way Traveltime (TWT).”
Since a PRM tool is effectively located in the subsurface at the depth of interest (most hydrocarbon reservoirs occur around 10,000 ft or less), our PRM tool has been designed to take this geometrical positioning to our advantage. That is, our PRM tool need only generate an acoustic wavefront half as powerful as that of conventional source tools to reach some of the world’s deepest reservoirs. With this in mind, our PRM tool uses well established physics and engineering principles to form the basis of our design. There are no complex moving parts, nor is the tool reliant on cutting edge technology (e.g., piezoelectric technology) that has not proven effective in the restrictive environments (high pressures and high temperatures) encountered by subsurface reservoirs. Our tool has been designed to be robust enough to be emplaced permanently in the subsurface – and to function properly – for 10+ years.
Although a PRM tool must not only be robust enough to operate consistently in harsh environments for many years without any need of maintenance, they must also output an acoustic wavefront commensurate with existing seismic surveys (in regard to frequency content) so that any potential client companies can immediately compare our PRM generated seismic data with their existing seismic surveys. They will then be comparing apples to apples.
The reason this last paragraph is so important is that many companies have introduced technologies (e.g., Schlumberger’s Z-Seis Tool) that have three major drawbacks. They are:
1) The generated acoustic wavefront produces frequencies far higher (200+ Hz) than the lower frequencies encountered in conventional seismic surveys [which means they must use a mathematical correction algorithm to “match” these data – the prevailing scientific opinion is that this correction is in fact comparing apples to oranges]. Our PRM tool is designed to generate frequencies equal to those used in the seismic industry today, 10 – 120 Hz; theoretically we can produce frequencies as low as 4 Hz to as high as 200 Hz).
2) The depth of investigation of these acoustic wavefronts are no more than 1 km (~3000 ft). This is a far cry from the 10000+ ft our tool has been designed to generate. Theoretically, our PRM tool can potentially generate usable acoustic wavefronts as far as 20000+ ft.
3) Because of the insufficient frequency content, the limited depth of investigation, and the prohibitive costs of running these tools, they can only be used for very specific reservoirs and fields, thus limiting the scope of potential customers to a very small client base.
In addition to these 3 limiting technical factors, these tools must be run in cased holes, therefore, any production must cease operation to run these tools. Not only are these tools weak and produce the wrong frequencies desired, by definition, they are not permanent. For anyone contemplating whether to invest in ARM and its emerging technologies, consider that this Z-Seis Tool described above was purchased from Schlumberger for 50 MMUSD in 2008.
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