Sunday, October 14, 2018

Correlating Seismic and Well Data

Correlation is performed in several stages. The first is establishing geologic tops on each well using the detailed correlation module. With individual well data displayed for up to four wells simultaneously, the interpreter can correlate horizons from one well to the next, registering consistent geologic tops in every well across the field. All well data have the potential to aid in this process, with core information, petrophysical log interpretations, wireline testing results and production logs equally able to contribute to identifying significant geologic horizon. 

The next step signals the beginning of the merging of seismic and well data. In the well tie module, the 3D seismic trace at a given well is displayed versus two-way time alongside all pertinent well data, which are already converted to time using borehole seismic or check-shot data. The main purpose of this combined display is to tie events recognized on the seismic trace -seismic horizons - to the recently established geologic tops found from the well data. These ties, or links, between the two data types are crucial at several subsequent stages during the construction of the reservoir model. In addition, seismic markers found at this stage can be transferred to a seismic interpretation workstation for horizon tracking.

The first use of the tie, or link, between seismic and well data is in the velocity mapping module that enables the 3D seismic record versus time to be converted to a record versus depth. This crucial step subsequently allows the seismic data to guide the mapping of geologic horizons between wells. 

A velocity map for each layer is first assessed from the stacking velocities used in the 3D seismic processing. These are average velocities to the depth in question and must be converted to interval velocties using Dix's formula. The interpreter then maps these velocities for a given horizon, using one of four available algorithms including the sophisticated kriging technique, and reviews their appearance in plan view. Gradual changes in velocity are normal, but anomalies such as bull's eye effects -isolated highs or lows - that are geologically unacceptable can be edited out. 

Next, values of velocity at the intersections of horizons with wells are compared with velocity values obtained from acoustic log or borehole seismic data. The differences, determined in all wells, are also mapped and then used to correct the original velocity map. Finally, the corrected velocity map is used to convert the 3D seismic record to depth. To check the result, structural dip azimuth as estimated from dipmeter logs can be superimposed on the resulting map-structural dip azimuth should follow the line of greatest slope as indicated by map. 

With seismic data converted to depth, the interpreter can begin building a stratified model of the reservoir using the correlation module. First, seismic data acting as a guide allow geologic tops in one well to be firmly correlated with tops in adjacent wells. This display may be further enhanced by superimposing dipmeter stick plots and other forms of dipmeter interpretation along the well trajectories. Another display that shifts data to an arbitrary datum, generally an already correlated horizon, provides a stratigraphic perspective. Second, each geolgoic corrrelation is allocated descriptors that determine how it relates geometrically to its neighbors above and below. These descriptors are later used to build up the actual reservoir model. Third, all available information about reservoir compartemantilization -for example, saturation interpretations from well logs and wireline testing results- are used to identify flow barriers, such as a sealing fault, so the reservoir can be divided into a set of isolated volumes called tanks, essential for correctly estimating reserves.



Sometimes, the interpreter may want to manually dictate the geometry of a horizon or other feature - such as fault, bar, channel, etc.  - rather than let it be guided by established horizons on the 3D seismic data. This can be accomplished using the section modeling module, which offers an array of graphic tools to create and edit elements of the reservoir model in the vertical section. This labor-intensive manual creation of a reservoir model becomes mandatory when there are no seismic data or only sparse 2D data.

One source of data that may contribute to the definition of tanks and faults is the well test. Well tests give an approximation of tank size and , in particular, provide distance estimates from the well to sealing faults. Azimuth to the fault, however, is undetermined.



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