Source Rocks as Reservoirs

Unconventional gas exploration is now focused on hydrocarbon source rocks as reservoir rocks. The term “unconventional” varies with time. In the 1950’s and 1960’s the Monterey Formation was ignored as a potential reservoir rock. In the 1970’s and 1980’s Chevron and Unocal both explored and produced oil from fractured shale. Various shales around the U.S. are shown in Figure 1.

Recent work in the Ft. Worth Basin shows that the low permeability, low porosity Barnett Shale is an outstanding source-reservoir rock system. Basically, all the components and processes of a petroleum system are contained in this single rock unit except overburden (Figure 2).

Unconventional thinking is that these source rocks are good storage containers for oil and gas, it’s just a matter of coming up with engineering solutions to produce the gas economically. Mitchell Energy, now Devon Energy, is leading the way in this play with years of effort in maximizing the producibility of this tight “shale”. The term shale is a misnomer as the Barnett Shale has quite variable mineralogy (Figure 3).

Many of these plays follow the Oauchita Thrust Front as shown in Figure 4. Wells are either active now and will be drilled in the coming months in all these basins for unconventional gas (except the Kerr Basin).

Geochemistry has been used to pinpoint the best areas for gas production, whether it is low BTU dry gas, or high BTU wet gas. The position of the gas window is a crucial aspect of shale gas assessments. The relationship between thermal maturity and composition of these source rocks is a crucial aspect. For example, classical interpretation of vitrinite reflectance data might suggest values as high as 1.4-1.5% for gas production, but this must be mapped against actual gas composition for a given thermal maturity. If a gas processing plant is designed for a certain BTU range gas, then the exploration program must be designed to map out the best prospective areas for wet gas. Vitrinite reflectance gives an indication of the maximum thermal exposure of a rock. However, its interpretation and assignment of oil and gas windows is not straightforward particularly with limited data sets. An example from the Ft. Worth Basin shows that analyzing shales only can often result in mis-interpretation of thermal maturity (Figure 5). For example, if only the Barnett Shales were analyzed in this well, the maturity data may not be interpreted correctly since the values are lower than projected when a full well profile is completed as shown. This could “kill” a play or prospect. The vitrinite reflectance values can be lower than expected due to a variety of reasons including suppression by the presence of oil/bitumen, dilution of cuttings with less mature cavings, and mis-identification of vitrinite. Generally these data can be corrected if other data is available including vitrinite reflectance from horizons above and below the shale of interest, TOC and Rock-Eval data for assessment of Tmax (a chemical indication of thermal maturity) and organic matter transformation ratio, which is also maturation dependent.

A recent paper by Jarvie et al. (2005) shows how various data sets can be used to assess and resolve any conflicts in thermal maturity assessments (Fig. 6). In this example thermal maturity was predicted to be early gas window; however, other data does not agree with this assessment (and neither did associated gas production!).

Figure 6. Risking shale gas prospects using all available geochemical data. Conflict resolution and prospect evaluation are completed using these risk factors for gas in the Barnett Shale.

The opposite case and themes and variation of this case can occur. The data sets must be thoroughly evaluated and understood in the more general context of the entirety of black shale data. This is where the Humble Barnett Shale Study is so useful and powerful. It doesn’t just apply to the Ft. Worth Basin; it is applicable to other shale gas plays as well.

The most important aspect of shale gas plays is reduction in the heavy components of the source system particularly resins, asphaltenes, and the high molecular weight paraffins. This is when the GOR begins to increase dramatically (Fig. 7).

Figure 7. A dramatic increase in GOR occurs when secondary cracking of oil and bitumen contributes to the gas content. The reduction in heavy components of petroleum is as important as the gas contribution.

Ultimately, regions of high interest for shale gas production are mapped and high-graded for leasing and drilling activities (Fig. 8).

Shale oil – no problem! This is readily predictable from simple logs of TOC and Rock-Eval data. Thermal maturity assessment is less important in these cases, but will almost always be oil window thermal maturity.

Turnaround time for vitrinite reflectance has been slow over the past 2 years, but Humble has aggressively pursued additional microscopists with experience in shale analysis. Many microscopists are good with coals, but we must have experienced source rock and shale analysts. Thus, we now have the following microscopists available to help on your projects:

Jack Burgess, 40 years experience

P. Mukhopadhyay “Muki”, 30 years experience

Dan Pearson, 25 years experience

Charlie Landis, 10 years experience

Wayne Knowles, 15 years experience

Mick Jones, 40 years experience

Mike Darnell, 20 years experience

Studies of Source Rocks as Reservoir Rocks

Permian Basin Study – New! Wells in Reeves, Culberson, Hudspeth, Jeff Davis, and Pecos counties are currently being analyzed – Phase I available March 31, 2005.