Using publicly reported data, and established geochemical relationships, the familiar maturity map in unconventional fields presented as binned produced fluid types (black oil, volatile oil, wet gas, dry gas), can be upgraded into a quantitative tool for evaluating resources, economics, and field thermal maturity patterns. For single source hydrocarbons, thermal maturity is highly correlated to the thermally evolved fluid chemistry eventually produced at the surface. Production measurements such as gas density, oil density, and gas-oil ratio, directly reflect the evolved chemistry, and can inform a map of thermal maturity. These parameters are also the common dependent variables in fluid property models such as for bubble point, formation volume factor, and viscosity. These models can be viewed as a normalization function for synthesizing production properties into a common maturity metric. An added benefit of treating fluid properties as a maturity scale is that they are more closely tied to economics than more precisely accurate factors like transformation ratio, though transformation ratio can be used to confirm that fluid properties deliver an effective nonlinear maturity scale.
In unconventional resources, organic material thermal maturity is a key element for grouping like geologic areas to forecast production, support reserves, and prioritize development. As operators expand unconventional resource plays, especially into decreasing oil volatility, maturity risk becomes even more important to risk management. Unfortunately, sparse data coverage of geochemical samples, especially on the margins of a historical field, can conceal the risks and opportunities in the subtleties of thermal maturity. To make organic maturity more useful as a decision tool, geochemical features like hydrogen index or Tmax need to be calibrated to relevant productivity features so that changes in maturity can be considered in terms of expected changes in productivity.
The chemistry of produced hydrocarbons can be simplistically considered as a distribution of saturated hydrocarbons by carbon number. Changes in the shape of this chemical distribution impact physical features of the solution such as density, volatility, viscosity, etc. Higher maturity hydrocarbons become enriched in shorter saturates shorter molecules are cleaved from larger ones. The first aim of this paper is to link models of thermal maturity to hydrocarbon chemistry, and this chemistry to commonly measured fluid properties which can be used as maturity indicators.
