The ‘great integrator’ in petroleum exploration

The discovery and exploitation of oil and gas in unconventional reservoirs has been called a revolution for the energy industry. Indeed, the unconventional revolution is transforming the petroleum industry across all sectors as demand for trained personnel, proppant and water for well operations and scientific data skyrocket around the globe. Following the discovery of an unconventional resource play, operators focus on optimizing production efficiency. Detailed petrophysical analyses as well as sweet spot identification from seismic data are essential. Also critical are the collection and interpretation of organic geochemistry, geomechanical indicators of rock brittleness and stress regime, source potential and maturity, pore pressure, and depth of maximum burial. In short, the evaluation of source rock presence and producibility for oil and gas in unconventional reservoirs requires far more data than commonly employed during exploration for conventional stratigraphic or structural traps.

BPSM software

How does industry cope with the data deluge that accompanies the unconventional resource revolution? The answer lies in a familiar tool: basin and petroleum system modeling (BPSM). Developed initially to assist conventional exploration, BPSM software has become increasingly relevant for understanding the huge quantities of oil and gas that remain in organic-rich source rocks. As it does for conventional resource plays, BPSM for unconventionals predicts the thermal maturity of the source rock, physical properties of the generated oil and gas and subsurface properties such as temperature and pressure—important things to know when assessing the viability of a resource play.

What may have gotten lost in the rush to acquire data and optimize well performance, however, is that the BPSM goes far beyond providing traditional information to the investigator. BPSM, in fact, can serve as a holistic integration platform through all stages of the exploration and production process. For example, a key factor needed to assess the economic viability of an unconventional accumulation is “movability,” or how easily the petroleum can be mobilized to flow into the wellbore. The generation of petroleum proceeds along a well-established path from liquid that contains dissolved vapor to gas that becomes drier as the remaining hydrogen-poor kerogen is depleted. Two factors related to this process are relevant to the basin modeler studying unconventional resources. First, fluids that migrate into conventional reservoir rocks tend to be lighter, leaving both light and heavy components behind in the organic-rich source rock. These components—commonly nicknamed SARA for saturates, aromatics, resins and asphaltenes—represent a high-viscosity fluid that is challenging to produce. Second, if the petroleum system remains active, retained SARA compounds undergo secondary cracking to successively lighter ones. One strength of BPSM is the ability to use kinetics that are different for the oil that is expelled and fills conventional traps compared to those for the oil that is retained in the generating source rock. BPSM is thus a robust tool to predict the composition of the fluid that enters the wellbore during hydraulic fracturing. This is particularly important in liquid-rich plays to determine if the liquid contains enough dissolved gas to provide reservoir drive, especially in the absence of pressure-volume-temperature data in regions in the early stages of unconventional development.

FIGURE 1. The BPSM workflow is a forward, iterative process that requires numerous and varied input data. Figure is modified from Peters et al. (2008). (Source: Stanford University)

Data integration

Accordingly, just as exploration for petroleum in organic-rich rocks requires a multidisciplinary approach, this example shows that BPSM is a platform for integrating multiple and varied datasets within unconventional targets. Specifically, BPSM convolves the subsurface structure as defined by seismic data and well picks with source rock characteristics as defined by organic geochemistry (total organic carbon and hydrogen index) and subsurface lithologies that may be derived from core data or mud logs. Moreover, subsurface data such as temperature, pressure, porosity, permeability and principal stress are used to both define boundary conditions and calibrate the model. Because decisions are made every step of the way in the modeling process (Figure 1), BPSM projects act as archives or repositories both for data and for methods used in the project. Such archives become especially valuable when personnel changes occur or when priorities change within a company’s play portfolio and the BPSM project is stored to be used at a later date.

Another key aspect of BPSM, like unconventional production targets, is that modeling projects are continually increasing in geologic complexity. However, the rapid pace of modern E&P operations in unconventional targets coupled with an aging workforce means that fundamental research on these systems may lag behind. Research in academic settings can fill the widening gap. The Basin and Petroleum System Modeling Industrial Affiliates Program at Stanford University is advancing the scope of traditional modeling programs across many geologic disciplines.

Experiments defining the kinetics of the opal-CT to quartz transition in silica diagenesis, for example, were incorporated into an existing software package and used to predict reservoir quality in the San Joaquin Basin in California. A synthesis of rock physics, seismic attributes and basin modeling in the Gulf of Mexico was recently completed on a pilot basis before a full 3-D model is attempted. Geostatistical realizations of lithologic facies in source and reservoir rock layers also are being tested with an objective to run BPSM in “batch” mode, in which hundreds to thousands of scenarios are tested sequentially. Finally, strike-slip faulting was recently incorporated for the first time in a 3-D BPSM project. In petroliferous settings where strike-slip tectonics are active, the thermal history and the generation-migration-accumulation of petroleum can be greatly influenced by motion along the fault (Figure 2).

FIGURE 2. The inclusion of a strike-slip fault plane with motion through time (red arrows) is a recent advance in BPSM. Figure from Menotti (2014). (Source: Stanford University)

These recent advances, combined with the utility of BPSM in unconventional settings, show that BPSM is becoming more relevant than ever in worldwide oil and gas exploration. In fact, BPSM can be used at all stages of exploration, from frontier settings where few wells and seismic data are available to extensively explored conventional basins now being revisited to a maturely explored province where wells are continuously being drilled. In this range of scenarios, basin and petroleum system models leverage the exploration effort because in near-real time they can be tested and updated with information such as formation tops, geochemistry, observed mud gas compositions, mud-weight pressures or bottomhole temperatures when the next well is drilled. BPSM serves as the “great integrator” in petroleum exploration, integrating data and disciplines across research teams and settings.

References available.