The success of shale gas and shale oil exploitation in North America in plays such as the Bakken, Eagle Ford and Marcellus (Figure 1), has ignited a global search for similar targets. There are several geologically distinctive aspects to North American resource plays, most notably their thickness, lateral continuity and relatively structurally undeformed nature; nonetheless, explorationists have begun looking for broadly analogous strata elsewhere. There are many areas of the world known to contain substantially thick and geographically extensive organic-rich mudrocks and carbonates in various onshore sedimentary basins. This poses a challenge: how can these potential plays be assessed quickly and ranked for more detailed examination? Additionally, how can individual parts of basins be high-graded as having the most likely potential?
Landmark Exploration Insights, a business line within Halliburton, has developed a variety of techniques for rapidly assessing the resource play potential of any basin. These include:
- Global mapping of gross depositional environments of precise stratigraphic intervals to identify basins likely to contain organic-rich sediments and the geographic distribution of these sediments within the basins;
- Evaluation of stratigraphically attributed geochemical data from organic-rich sediments worldwide. Screening workflows also consider thickness and depth of target horizon;
- Once an area has been high-graded, it can be further evaluated within the 3D geological interpretation platform of Landmark’s DecisionSpace® software, which facilitates, among other things, regional evaluation of maturity.
Where and When?
The starting point for a global or regional assessment of resource play potential is to determine where and during which geological periods organically rich shales and carbonates were deposited. Organic enrichment of sediment occurs for a variety of reasons, but there were several times during geological history which were particularly prone to organic-rich sediment deposition, particularly those associated with Oceanic Anoxic Events (OAEs). These are intervals when large areas of the seafloor became anoxic, synchronous with (and perhaps related to) times of high organic productivity. This allowed the extensive preservation of organic carbon, typically in the form of black shale. The cause of OAEs has typically been attributed to pronounced climate change resulting from volcanogenic and/or methanogenic processes. The ensuing greenhouse world would have presumably been characterized by enhanced rainfall, increased nutrient delivery to the oceans, increased upwelling, and increased organic productivity. Classically, OAEs have been recognized during the Mesozoic Era; but, increasingly, Paleozoic ‘black shale events’ are being related to OAE-like conditions. In particular, such events are widely reported throughout much of the Devonian, the early Silurian, and Late Ordovician (Figure 2).
OAEs and other geological periods of widespread black shale deposition can be examined with regard to the global distribution of sedimentary facies at these times. A geodynamic plate model can be used to place sedimentary facies in their palinspastic context to develop a global paleogeographic map of how the Earth appeared at the time of deposition (simplified version in Figure 2). Sedimentary facies are mapped with stratigraphic precision by using a eustatically mediated sequence stratigraphic model to recognize precise time slices. This means that the precise interval of organic-rich sediment deposition can be mapped without compromising accuracy by selecting too broad an interval for mapping. Well, outcrop, geochemical, and seismic data can be related to the sequence stratigraphic model, which allows depositional facies distribution to be mapped for each time-slice when integrated with tectonic controls on deposition and an understanding of the stratigraphic evolution of a basin.
Because data distribution is variable at a global scale, the technique requires the prediction of sedimentary facies into regions lacking data. Sequence stratigraphy facilitates this; but other techniques, such as paleoclimatic modeling, can be used to predict areas prone to deposition and preservation of organic-rich facies. As an example, it is possible to predict where coastal upwelling occurred in the geological past, which led to nutrient-enriched waters and high productivity of phytoplankton, in turn leading to organic-enrichment of the associated sediments being deposited.
The lithology of potential resource play intervals is also critical. Ideally, the organic-rich intervals should be associated with high (>35%) quartz or carbonate content that leads to a brittle, frackable nature. Once again, regional paleogeography can be used to determine likely lithology, for example, by predicting the input points of quartz-rich sediment from granitic or quartz-sandstone dominated paleo-highs. This involves mapping paleo-drainage patterns using tectonics, paleoclimate, and well and outcrop data.
Examining the Goldilocks Window
Within an area of focus, the geochemical, thickness, and depth parameters can now be employed within the workflow to define the location of the highest potential for resource plays. A window of optimal conditions can be identified within geochemical data beginning with organic richness and kerogen type. A cutoff of 2 wt.% Total Organic Carbon (TOC) is commonly used to screen for resource plays. By examining a geochemical database of stratigraphically attributed past analyses, it is possible to define a sub-region where TOC is commonly above 2 wt.%. Precise stratigraphic attribution of the data is fundamental to aiding focus on the interval of interest and to disregarding other data.
The next step is to establish thermal maturity of the sub-region of high organic carbon enrichment to screen out immature areas and highlight those within the present-day oil or gas window of hydrocarbon generation. Vitrinite Reflectance (Ro) can be used to define regions within the oil window (Ro = 0.6 – 1.35%) and within the gas window (Ro = 1.35 – 3%).
If shale oil is a desired target, then further geochemical screening can be performed by examining the Production Index (PI) values and the temperature at which the maximum amount of hydrocarbons are generated during pyrolysis (Tmax). The PI is the ratio of already generated hydrocarbon to potential hydrocarbon [S1/(S1 + S2)] derived from pyrolysis measurements. A cross-plot of PI and Tmax values high-grades locations where samples have a PI between 0.2 and 0.6 and Tmax values of 435 to 455°C.
Pyrolysis data, such as S1, is useful for determining if free oil is present within pore space. In such circumstances, S1 values will be greater than 2mg HC/g TOC.
Cutoffs for the thickness and present-day depth of organic-rich intervals can also be used during the screening process - a thickness greater than 30m is desirable, whilst depth cutoff will depend on local circumstances and the changing economics of drilling costs. However, 3,000 to 4,000m is typically considered a viable maximum.
The workflow for assessing a region, as summarized in Figure 3, can be accomplished in ArcGIS software or within the 3D software environment of DecisionSpace software. The latter has the advantage of the user being able to run multiple ‘what if’ scenarios by varying the cutoffs used in the screening parameters. It also facilitates the dynamic updating of the model as new data becomes available. This means the screening workflow can be rerun in minutes or hours, not days or weeks.
Timing is Everything
Once an area has been high-graded, further assessment to locate a precise sub-region with the highest potential is best facilitated in DecisionSpace software (Figures 4 and 5) by building a gridded depth model of key stratigraphic surfaces, draping facies maps on these surfaces, and evaluating maturity by integration with geothermal gradient information to define subsurface temperatures, or by integration with petroleum systems modeling tools, such as Permedia™ software. This will result in a precisely defined region for focused further study and, potentially, future exploitation.
In the example illustrated in Figure 4, a regional depth model for North Africa can be interrogated to assess the maturity of early Silurian source rocks. The Oil Generation Threshold (OGT) and the Base Oil Window (BOW) were defined as 80 and 130°C, respectively. Using geothermal data from a representative set of wells, we are able to ground truth an average geothermal gradient within key basins whilst applying a consistent continental scale value, which can be used in the workflow.
Assigning the relevant depth cutoffs to the model related to present-day subsurface temperatures, we can begin to assess the likely distribution of immature, mature, and overmature intervals against our gross depositional environment (GDE) maps. Where additional maturity data are available, such as vitrinite reflectance and detailed heatflow analysis, it is possible to further enhance screening and perform a superior assessment of regional hydrocarbon potential using a detailed basin-by-basin approach.
Resource Plays Beyond North America
There is no doubt that the global search for unconventional resources is firing the imagination of the international exploration geoscience community. At the recent Geo2016 conference on Middle East geology, a significant proportion of the presentations discussed resource plays. BP has recently entered into a joint venture to exploit a Chinese shale gas play. There are many exciting opportunities to be identified and exploited outside of North America, but it will require a sound understanding of regional geology, paleogeography, geochemistry and modeling to really identify where the best potential lies. Whilst deposition of organic-rich facies can extend across a huge area within a basin, when source rock quality, maturity, lithology, thickness and other filters are applied, the area of best potential is often greatly reduced, as in the North Africa example mentioned previously (not even considering sociopolitical and engineering factors).
As with conventional exploration, basin screening based on sound regional geoscience integrated with the technology to accelerate assessment will be a prerequisite to success.