Organic-rich marl is one of the best unconventional reservoirs because of its high calcite and low clay content leading to relatively high permeability and fracability. However, how its stiff pores and relatively high permeability affect the changes in its microstructure and elastic and transport properties during maturation remains a research interest. We have induced ex situ maturation of organic-rich marl core plugs by conducting confined pyrolysis in fine steps across the maturity windows from immature through the early-peak oil, late oil, wet gas, and finally, the dry gas window. This was performed under high and low confining pressures on different samples to investigate the role of confining pressure during maturation. After each pyrolysis, we monitored the changes in microstructure, porosity, velocity, permeability, and geochemical properties. The results indicate increasing porosity, decreasing velocity, and increasing permeability as the maturation progresses. The time-lapse scanning electron microcopy images reveal the progressive development of secondary organic porosity at the expense of kerogen volume. Most of the changes in the acoustic velocity and permeability occur in the late oil window and are concurrent with the generation of connected secondary organic porosity. The total organic carbon (TOC) and Rock-Eval results indicate that most of the generated hydrocarbons immediately exit the samples during pyrolysis so that the generation of microcracks from pore-pressure buildup is unlikely. Rather, secondary organic porosity is the main microstructural change, and the amount of depleted TOC can be used as a proxy to predict the increase in porosity and the changes in the velocity and permeability. Finally, confining pressure plays a minor role in the evolution of the elastic and transport properties of organic-rich marl.
Deriving global parameters for velocity-based pore pressure predictions in a complex overpressure origins regime is normally difficult and nonrobust. Applying large variations in Eaton’s exponent is an unsatisfactory work practice for velocity-based pore pressure prediction. This study investigates an alternative potential method to reduce the variation of Eaton’s exponent values in an environment of mixed disequilibrium compaction and fluid expansion overpressure mechanisms. Using 25 input wells, the fluid expansion components are estimated using velocity-vertical effective stress plot and then subtracted from the pressure measurements to obtain the disequilibrium compaction components. Eaton’s exponents are then derived only from the disequilibrium compaction components. The spatial variation of Eaton’s exponent is greatly reduced from the range of 1–5 to the range of 1–1.9 after removing the fluid expansion components from the raw overpressure data set. A constant Eaton’s exponent of 1.44 is used throughout the field to predict the disequilibrium compaction components and the fluid expansion components are predicted from gridding of the well data. The two components are combined to produce a final pore pressure prediction profile, which yields less uncertainty than the traditional Bowers method.
The elastic modeling of source-rock reservoirs during maturation must incorporate microstructural and geochemical alterations. The common challenge is calibrating the volumetric proportion between each form of organic porosity along with the changes in the bulk and shear moduli of kerogen as a function of maturity. Two forms of organic porosity have generally been observed: (1) spongy and bubble pores inside kerogen and (2) low-aspect-ratio pores or gaps at the interface between shrinking kerogen bodies and the matrix. We have constructed a rock-physics model of organic-rich marl during maturation and calibrated it using rock-physics data sets from controlled pyrolysis experiments of organic-rich marl under stress. We chose these pyrolysis data because the samples provide subsequent changes in porosity and P- and S-wave velocities as a function of maturity, while evidencing minimal grain sliding and mechanical compaction due to their stiff matrix. Our calibration results indicate that spongy and bubble pores should be used as the predominant form in the model regardless of maturity. Our results also indicate a competing effect between increasing kerogen porosity and the increasing moduli of solid kerogen. Kerogen porosity mainly develops throughout the oil windows. Whereas the moduli of solid kerogen increase by a factor of two in the early-peak oil window and remain relatively constant afterward. Consequently, the effective moduli of kerogen experience minimal changes in the early-peak oil window and rapidly decrease to half of the immature values in the late oil window. These calibration results are consistent with several petrophysical and nanoindentation studies on kerogen. Finally, we used the calibrated model to build a rock-physics template of organic-rich marl during maturation. The template was tested with pyrolyzed and naturally matured samples, which showed that our model can be used to characterize reservoir properties across different maturity windows.
Bright spot amplitude anomalies in seismic data are common indicators of natural gas; however, an interpretation based purely on these amplitude anomalies often yields a false indication of gas-saturated sands. A data set from the Marco Polo field, the Gulf of Mexico, demonstrates this problem. A discovery well was drilled into a sequence of bright spot anomalies that were indeed gas-saturated sands. This suggested that other bright spots in the seismic section also corresponded to gas sands and that non-bright spots were to brine-saturated sands. Nine development wells were later drilled into those bright spots, but not all of them were gas sands and not all of non-bright spots were brine-saturated sands. This study utilized Gassmann fluid substitution and three seismic amplitude versus offset (AVO) techniques (intercept and gradient, elastic impedance, and Lambda-Mu-Rho) as a comparison to purely using bright spots technique for fluid-type prediction at the location around the discovery well. This study used borehole information only from the discovery well in the purpose of AVO calibration. Forward models for the three AVO techniques were created from the well-log information in order to predict differences in the modeled attributes between gas- and brine-saturated scenarios. Pre-stack seismic data were inverted for intercept and gradient attributes, elastic impedance (EI) volumes, and Lambda-Mu-Rho (LMR) volumes. These volumes were compared to the forward models to predict gas- and brine-saturated locations. The prediction results were evaluated with information from the nine development wells. The intercept and gradient, elastic impedance, and LMR techniques yielded correct predictions of 52%, 61%, and 70%, respectively, of the observed sands. The traditional bright spot method yielded only 45% of correct fluid prediction. In conclusion, the pre-stack AVO techniques provided a better fluid prediction than relying solely on the post-stack bright spots alone. Furthermore, the prediction results improved as the computational intensity of the inversion increased from the intercept and gradient, to the elastic impedance, and to the LMR technique. Introduction Bright spot and its pitfall. The use of bright spot seismic amplitude anomalies to predict the location of petroleum resources has increased over the past four decades; however, this technique can be unreliable and inaccurate. Bright spot amplitude anomalies are purely an elastic effect. Only the right combination of petroleum fluid content and rock physics properties (such as porosity and lithology) can result in bright spot amplitude response. Thus, the bright spots do not always represent the presence of petroleum fluid, and non-bright spots do not always mean the absence of petroleum fluid (Young, 2006).
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