Milestone 2: Interview with oil/gas prospector

Completion Date: March 20, 2008

Interview

For this milestone, Warren Baumann, the owner of Baumann Resources, was interviewed to gather information about the process through which oil/gas prospectors go in order to find promising prospects.

Raw data

Process used to explore for oil and gas (quantitative factors and variables):

Look at regional setting for oil source, reservoirs and traps (need all three) and this is generally a sedimentary basin such as Michigan. Hundreds of sedimentary basins in world. Not area of igneous or metamorphic bedrock, like Wisconsin.

Now look more closely for traps in these areas. Nearly all the explored basins have 100 to 1000's of dry holes or wells for data points.

Existing wells give you statistical look at success. Dry holes versus producing wells. Look for areas already successful for better economics.
Development drilling in known oil or gas fields. These are bound by factors such as a structural dome or porosity pinching out at edges. Drill more wells within the field - best success but usally leased by operator who discovered the field.

Explore for wildcats: new fields. Statically less favorable but better economics when hit. Don�t have to share and get all offset leases befor anyone knows. Currently only 1 or 2 in 10 hit.

Do risk/reward ratio factor analysis in economis of drilling. Example: He has a wildcat project that could yield over 3 million Barrels of Oil (BO) (based on factors from similar nearby fiels) and drill cost is only $200,000.00 since only 1600' deep. Over 35:1 return on investment and a payout of 3 months. At 100/BO these are crazy good deals. But probably dry so you can expect to drill 8-10 before luck prevails. Sold this deal to two people and showed it to two.
Use a lot of simple economics when drilling. Look at factors: oil price, gas price, sev. Tax, production operation cost, drill cost, exploration cost (seismic, lease, geology), reserve estimates and production rates. The big two are product price and reserves.

Start a prospect: look at map of wells (all) (state govt all control this data and public domain). Only geophysical data such as seismic is kept secret. Also a geologist's interpretation (mostly interpretive and qualitative) is kept secret (that is why he has a high paid job).

Wellspot maps available online but lacks geological information unless you find it and import it. Some high price software has this public information from drilling forms turned into the states data base. Finds much data is inconsistent so you still must look up well file info and well log info (each well has a sample description by a wellsite geologist and most have electric log (ie: Schlumberger) for rock formation tops, oil and gas shows, etc.)
When I draw a geological structure map in area, he looks for a high area oil may have migrated to but must have closure so oil did not migrate out. Also a trap to seal it in.
Uses data points such as subsea formation tops (must take out elevation) to have correct datum subsea. Looks at all well info not just what's reported to be consistant.
Once the data points are on a map, he contours like [formations?] connecting the dots. Several computer programs do this but not always the best.
If area has a mapable structure based on contour of data points then I look at wells near the edge of structure that sets up the "high" (anticline, dome, fault block, etc) to see if hydrocarbon shows exist. A structure with no seal or porosity in the rock will not produce.
May look at many diffent depth in an area. Some area have production in 4-7 depths from 1000' to 10000'. Many dome structures are stacked and trap oil at several porous rock zones.
If an area has most of these factors, he may proceed to the next step.

Check and acquire leases on the mineral rights. If ownwed by state or federal government they must be submitted to open - big pain.
Try to get most leases ahead of time to cover the entire potential field or structure so no one gets in if you make a discovery. Depending on area and how much nearby competition, may give anywhere from 1/8 to � royalty to mineral owners. Also, cost of leases can be a factor. Usually $10 to $100 per acre. Some areas with new success may drive unleased acreage up to $2,000 to $5,000 per acre.
Geological map shows something, offset well indicate possible pay and have leases.
Next step do geophysical confirmation. In Michigan they use mostly seismic data. Magnetic, gravity, and landsat data is not as good here due to variable glacial cover.

Geophysisicst use quantitative thickness values and velocity values (from nearby electric log data sonic log) in the processing to take glacial effect out. Otherwise data worthless.
We look for existing data (Evan's Geophysical) and if quality is ok and goes over area, we buy it (fraction of cost to shoot new data at $10,000 per mile for 2D data and $100,000 square mile for 3D data).
Reprocess old data with new software improves and find new prospect. This is biggest tech advance in industry. Older computers could not do it, especially 3D. Terabytes of digtal data to work with.

If prospect develops with all positive facors from above (maybe 1 in 5 areas turn into a prospect and 1 of 3 get funded to drill and 1 in 8-10 wildcats will hit). Now see why oil is so expensive and why BIG oil likes to just ship it in and sell it.
Next step is to package and market it to investors who will use your and their economic analysis to determine if they want to spend money to drill.

Quantitative points of interest. Here are some factors:

Stats of drilling in an area "success."
Use of digital subsea depths of rock formation to contour map (by hand and automatic).
Digital data map bases (shaped files) for geographic coord.
Digital database for well locs like above.
Use of online data such as subsea formation tops.
Use on line production database to see how other wells in area are producing. Also tells total reserves expected.
Use this for economic study like mention above. Companies buying producing wells and reserves have very extensive programs with discounted value of money, depletion of reserves, etc. Lots of econ and stats.
Processing of seismic is mostly quantitative work for end result. Will Isotime (linear scale of time vs velocity between rock layers) Isotime thinning shows structures where oil may hide. Will map these values with values and contours.
Velocity changes horizontally at a certain depth with seismic may show low density area "hot spot" where low density gas in the rock shows up. These are digital values we map using feet/second changes in sound velocity.
Reads electric logs from old wells looking for missed oil sections. This all quantitative data. Values such as porosity, permeability of rock, water saturations, oil and gas saturations, lithology changes etc. This is very hightech using Neutron and Gamma transmission and reflection, electric resistance of the rock, etc. Places values to each factor to map porosity boundaries, oil and water boundary zones, values to determine flow rates of oil and gas, etc... These are all on file as rasterlogs which are stored on his 200GB hard drive.
The drill end (esp directional drilling) is all quantitative data. Based on triginometry using some high tech gyros.