Formation Evaluation: Fractured Reservoir
1. During exploration phase, how precisely would we be able to define the prospective structure of a fractured reservoir field by using seismic records, gravity and magnetics?
How exactly to distinguish between low-permeable rock-matrix and a high-permeable fracture?
Feasible to delineate the fracture-matrix interface?
2. To what extent, the data associated with mud logging, logging while drilling (LWD); and measurements while drilling (MWD) – would get disturbed – upon drilling a wellbore through such a prospective structure (fractured reservoir)?
How easy would it remain to secure the cuttings of cores or sidewall samples from those wellbore – in the absence of losing the original reservoir property?
3. What exactly is the difference between well reaching the prescribed depth
(a) where, well meets low-permeable rock-matrix?
(b) where, well meets the high permeable fracture?
OR
(c) Geosteering would be able to steer the wellbore path to intersect the formation of interest at the desired position of the reservoir?
Will there be any difference between the above two cases upon running the conventional wireline logs (refining seismic interpretation/VSP)?
How about the initial analysis of mud-log and initial log analysis in such cases during drilling phase?
Would it precisely direct towards the required wireline formation testing or DST during testing phase?
Even, if the above analysis prove the formation to remain to be productive, how useful will be the following core analysis from such fractured reservoirs?
4. Is there any distinct identify associated with the mu-logging process of wildcat wells; and while, drilling and logging (with wireline logging tools) of development wells – in a fractured reservoir?
5. Albeit, DST would be able to provide the proof that hydrocarbons exist in a fractured reservoir, would it be able to supply the data on both the capacity of the reservoir and its ability to produce in the long run?
Feasible to have a correct interpretation of pressure records from DSTs?
DSTs along with wireline formation testers will be able to provide a detailed formation pressure data in a fractured reservoir?
Quite a list of fundamental questions:
I’ll try to address just a couple:
1)define prospective structure using seismic, gravity & magnetic.
Assuming ‘define prospective structure’ to you means the overall shape of the structure rather than the distribution of fractures in the structure than seismic is likely to do a good job at a scale range of horizontally 100’s to 1000’s of meters and vertically 10’s to 100’s of meters.
Gravity and magnetics will have a lower resolution.
To charactise the fracture system gravity and magnetics will have very little to no value. Seismic will need special processing ( eg of shear seismic - NB in principle only works onshore) and/ or interpretation software.
2) re ‘easy to secure cuttings , sidewall samples etc’ - bear in mind that if a well encounters a high permeability open fracture system the likely consequence is loss of circulation ( ie no mud returns at surface). If no mud returns, no cuttings return either. In addition, if I have no returns I would be reluctant to run wireline tools such as a SWS tool for fear of loosing the tool downhole.
- Prospective Structure: Seismic, gravity, and magnetics help outline structure. Distinguishing matrix from fractures needs well data.
- Drilling Impact: Drilling can disrupt data; securing samples without property loss is tough.
- Wellbore Interaction: Geosteering optimizes borehole placement. Wireline logs, mud logging, and initial analysis aid evaluation.
- Logging Differences: Similar techniques, focus varies for wildcat vs. development wells.
- DST and Reservoir: DST confirms hydrocarbons, limited for long-term potential. Pressure data from DSTs and wireline tools aid understanding.
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