Basin modeling

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Basin modeling enables geoscientist to investigate the dynamics of sedimentary basins and their associated fluids to determine if the past conditions were appropriate to fill potential reservoirs with hydrocarbon and preserve the potential reservoirs. Basin modeling applies mathematical algorithms to seismic, stratigraphic, paleontological, petrophysical, well log and geologic data to reconstruct the evolution of sedimentary basins.  A petroleum system includes a pod of active source rock and the oil and gas derived from it as established by geochemical correlation. The essential elements for petroleum system are an effective source rock, reservoir, seal and overburden rock; the last facilitates the burial of the others. The processes contain trap formation and the generation, migration and accumulation of petroleum. These elements and processes must occur in the proper order for the organic matter in a source rock to be converted into petroleum and then to be stored and preserved. If a single element or process is missing or occurs out of the required sequence, a prospect loses viability. Basin and petroleum system modeling brings together several dynamic processes, including sediment deposition, faulting, burial, kerogen maturation kinetics and multiphase fluid flow. These processes may be examined at several levels, and complexity typically increases with spatial dimensionality; the simplest, 1D modeling, examines burial history at a point location (figure 1). Two-dimensional modeling, either in map or cross section, can be used to reconstruct oil and gas generation, migration and accumulation along a cross section (figure 2). Three-dimensional modeling reconstructs petroleum systems at reservoir and basin scales and has the ability to display the output in 1D, 2D or 3D, and through time. Most of the following discussion and examples obtain to 3D modeling; if the time dimension is included, the modeling can be considered 4D .[1][2]

Basin models can cover various areas about 10 x 10 km up to 1000 x 1000 km and to a depth of 10 km. They can be gridded into volume elements with up to 500 grid points in the lateral directions and up to 50 layers. Each volume element contains a constant facies in a bulk continuum approximation. The upscaling of physical properties from core to grid size may be applied [1].

Basin and petroleum system modeling can be defined in two main stages: Model building and Flow modeling (figure 4).

Model Building

Model building includes constructing a structural model and identifying the chronology of deposition and physical properties of each layer. The necessary inputs for model buildings are can be explained under these substages: geometry and stratigraphy, timing and deposition, geochemical data and boundary conditions.

Geometry and Stratigraphy

A depth-based structural model of the area of interest is created at the beginning of the basin modeling. Generally, the formation tops of the layers or thicknesses are entered into program. The source of the data may  contains  seismic surveys, well logs, outcrop studies, remote sensing data, electromagnetic soundings and gravity surveys. The present day geometric model is established in order to describe the chronology of deposition and physical properties of the basin fill materials and to define post-depositional processes. That will enable to reconstruction of the basin and its layers and fluids throughout geologic time. The stratigraphic events of specified age and duration will be established for a basin history.[1]

Timing and Deposition

Each event represents a span of time during which deposition, nondeposition or erosion formed. Syndepositional and post-depositional events such as folding, faulting, salt tectonics, igneous intrusion,diagenetic alteration and hydrothermal activity can be used to explain the model. To find the time of  trap formation and other processes which are generation, migration and accumulation of hydrocarbons is one of the most important aim of the basin modeling.  The selection of the time within this range is at the discretion of the modeler. [2]

Geochemical Data

Geochemical data is one of the most important input of the basin modeling. Source rock properties are needed as inputs to simulate the reactions. Total organic carbon (TOC) is the amount of carbon found in an organic compound which is measured by combustion of rock samples. Hydrogen index (HI) is a parameter used to characterize the origin of organic matter which is obtained by pyrolysis of rock samples for petroleum generation potential. Kinetic parameters for the thermal conversion of the source-rock kerogen to petroleum.

Boundary Conditions

Boundary conditions for the basin modeling inputs are paleobathymetry, which determines the location and type of deposition, sediment-water interface temperatures throughout geologic time which, along with paleo heat flow estimates, are required to calculate the temperature history of the basin.

Forward Modeling

Basin modeling is dynamic forward modeling of geological processes in sedimentary basins over geological time spans. It incorporates deposition, pore pressure calculation and compaction, heat flow analysis, kinetics of calibration parameters such as vitrinite reflectance or biomarkers, modeling of petroleum generation, adsorption and expulsion processes, fluid analysis and phase compositions, and petroleum migration.

Deposition, Sedimentation and Erosion

Layers are generated on the upper surface during sedimentation or erosion. Current thickness of the layer does not represent the depositional thickness. Current thickness can be smaller than the depositional thickness of the layer, which is eroded after deposition, can be calculated by several methods such as porosity-controlled backstripping starting with present-day thickness, estimation from sedimentation rate and depositional environment and importation from structural-restoration programs.[2]

Pressure calculation and Compaction

The pressure calculation treats dewatering as a one phase flow problem driven by changes in overburden weight caused by sedimentation. In addition, internal pressure-building processes such as gas generation, quartz cementation and mineral conversions can be taken into account. Compaction causes changes in many rock properties, including porosity, and to a lesser extent, density, elastic moduli, conductivity and heat capacity. Therefore, pressure and compaction calculations must be performed before heat-flow analysis in each time step.

Heat-flow analysis

Heat can be transferred by conduction, convection and radiation in sediments (Beardsmore and Cull, 2001). The main boundary conditions of the heat flow analysis in sediments are the sediment - water - interface temperature (SWI) and the basal heat flow.Thermal and mechanical processes determine magnitude, orientation and distribution of  the heat flow at the base of the sediments.[3] The main direction of heat flow in sedimentary basins is vertically upwards. That enables to show basic effects with crude  one dimensional models. Steady state heat flow constitutes the most simple heat flow pattern which is time independent heat flow . Radioactive heat production can easily be incorporated. [4]

Petroleum generation

Petroleum generation from kerogen in source rocks is called as primary cracking. The subsequent breakdown of oil to gas in source or reservoir rocks is called as secondary cracking. These can be described by the decomposition kinetics of sets of parallel reactions. Petroleum generation models are generally used for source rock analysis. Generated petroleum from keregon can be classified according to the van Krevelen diagram into type I, II, III and IV as regards to its hydrogen and oxygen content. Oil generation is often modeled with two–component kinetics for oil and gas.[5]

Fluid analysis

The generated hydrocarbons are mixtures of chemical components. Fluid-flow models deal with fluid phases that are typically liquid, vapor and supercritical or undersaturated phases. The fluid-analysis step examines temperature- and pressure-dependent dissolution of hydrocarbon components in the fluid phases to determine fluid properties, such as density and viscosity, for input to fluid-flow calculations. These properties are also essential for subsequent migration modeling and calculation of reservoir volumetrics.[2]

Petroleum Migration

Migration is transportation of petroleum from the source rock to the reservoir rocks. The direction of migration and trapping of petroleum can be predicted if this process can be understood. The petroleum is mainly transported as a separated phase and that the process is mainly driven by the buoyancy of petroleum relative to water. The solubility of oil in water is very low for most compounds. The solubility of gas, particularly methane, is much higher both in oil and water and increases with depth (pressure). There is, however, also very limited flow in sedimentary basins to transport petroleum. Migration is the most sophisticated process in modeling.[6][2]

Reservoir Volumetrics

The height of a petroleum accumulation is limited by the capillary entry pressure of the overlying seal and the spill point at the base of the structure. Loss at the spill point and leakage through the seal reduce the trapped volume. Other processes, such as secondary cracking or biodegradation, can also impact the quality and quantity of accumulated petroleum [7].

Calibration Parameters

Calibration parameters are vitrinite reflectance (figure 5), biomarkers, Tmax values, isotope fractionations, fission track analysis, biodegradation, source rock analysis. These temperature-sensitive predictions can be compared with measured data to calibrate uncertain thermal input data, such as paleoheat flow values.

Critical Moment

The critical moment is the time of highest probability of trap and preservation of hydrocarbons in a petroleum system after traps form and hydrocarbons migrate into a reservoir and accumulate-and marks the beginning of preservation in a viable petroleum system (Figure 6). Critical point is an important concept in process timing. It also shows how the basin modeling is important for oil and gas exploration.

A step forward of basin modeling

Basin and petroleum system modeling software can do more than indicate hydrocarbon accumulations. For example, the subsalt formations' effective stresses is modeled in the Central Gulf of Mexico. Effective stresses derived from the modeling were converted into seismic velocities that were used to remigrate the 3D seismic data. Applying the enhanced velocity model improved the illumination of the subsalt volume and delivered an updated model of the reservoir layers and the underlying source rock. The new imaging results also have major implications for insight into the petroleum system, revising the interpreted depth, and thus maturity, of the source rock, and increasing the areal extent of mature source rock. The prospect, when drilled, proved to be a large discovery that is now undergoing appraisal[2].

Differences than reservoir modeling

There is an important difference between reservoir modeling simulation and basin modeling and petroleum system analysis even though reservoir simulation is an analogous in concept. Reservoir simulators model fluid flow during petroleum drainage to predict production and provide information for its optimization. The time scale is months to years and, the distance scale is meters to kilometers. The model geometry is static the, remaining unchanged during the simulation whereas the flow model is dynamic. Contrarily, for basin modeling, the periods covered may reach hundreds of millions of years, and distance scale typically is tens to hundreds of kilometers. The model geometry is dynamic and often changes significantly during simulation. Basin and petroleum system modeling simulates the hydrocarbon-generation process to calculate the charge, or the volume of hydrocarbons available for entrapment, as well as the fluid flow, to predict the volumes and locations of accumulations and their properties[2].

Basin and petroleum system modeling software

Basin Modeling software programs: PetroMod (Schlumberger), Genesis-Trinity(Zetaware), Permedia (Halliburton),  PBM-Pars Basin Modeler(Research Institute of Petroleum Industry), BasinMod (Platte River Associates, Inc.), Genex, Temis 2D, 3D (Beicip/IFP), Migri, MigriX (Migris), Sigma2D (JNOC/TRC), Novva (Sirius Exploration Geochemistry Inc.), and WinBury software.

External Links

https://en.wikipedia.org/wiki/Source_rock

https://en.wikipedia.org/wiki/Sedimentation

https://www.linkedin.com/pulse/uncertainty-transformation-ratio-its-impact-oil-gas-roberto-aguilera/

https://www.glossary.oilfield.slb.com/en/Terms/c/critical_moment.aspx

https://en.wikipedia.org/wiki/Total_organic_carbon

References

  1. 1.0 1.1 1.2 Hantschel, T., and Kauerauf, A., 2009, Fundementals of Basin nad Petroleum Systems Modeling, p.148 ,DOI 10.1007/978-3-540-72318-9
  2. 2.0 2.1 2.2 2.3 2.4 2.5 2.6 Al-Hajari, M., Derks, J., Fuchs, T., Hantschel, T., Kauerauf, A., Neumaier, M., Schenk, O., Swientek, O., TesseN, N., Welte, D., Wygrala, B., Kornpihi, D., and Peters, K., 2009, Basin and Petroleum System Modeling, Oilfield Review Summer 2009: 21, no. 2. Copyright Schlumberger
  3. Allen, P. A., and J. R. Allen, 2013, Basin analysis: Principles and application to petroleum play assessment, 3rd ed.: Oxford, United Kingdom, p
  4. Hantschel, T., and Kauerauf, A., 2009, Fundementals of Basin nad Petroleum Systems Modeling, p.103-105 ,DOI 10.1007/978-3-540-72318-9
  5. Hantschel, T., and Kauerauf, A., 2009, Fundementals of Basin nad Petroleum Systems Modeling, p.151 ,DOI 10.1007/978-3-540-72318-9
  6. Bjørlykke K., 2010, Petroleum Geoscience., Springer, Berlin, Heidelberg, pp 349-360, doi.org/10.1007/978-3-642-02332-3_15
  7. Hantschel, T., and Kauerauf, A., 2009, Fundementals of Basin nad Petroleum Systems Modeling, p.20 ,DOI 10.1007/978-3-540-72318-9