Abstract A procedure determines the relative importance of uncertainties in input information and in multiple parameter estimation to all outputs from two-dimensional basin modeling codes. The procedure does not rely on Monte Carlo methods, but on some simple properties of the cumulative probability distribution of output variations related to uncertainties. As a consequence, only a couple of computer trials are needed to evaluate the relationship of the variability of outputs to input uncertainties. The procedure is applied to a two-dimensional cross section with evolution of the section with time. Attention is focused first on mainly geologic input uncertainties, and then on uncertainties of thermal factors and of hydrocarbon kinetic factors. Each group is initially taken separately, and then all three groups of uncertainties are combined and used simultaneously. The influence of each group of uncertainties on a suite of different outputs from the basin model is explored at different times across the evolving section. At each lime step, the relative sensitivity is examined of the uncertainty in a specified output to each group of input uncertainties, as is the relative importance of the uncertainty in a specified input to the suite of all outputs at each time step. In addition, the global relative importance of input uncertainties to output variabilities is considered, thereby providing a measure of output uncertainty effects, no matter where and when they occur, as a consequence of input uncertainties. This work enables one to assess which inputs need to be more tightly constrained, and also to determine by how large a factor they need to be better constrained if the uncertainties on a suite of specified outputs are to remain within given tolerance limits. The advantage to this rapid procedure is that one can focus more quickly on those factors of dominance in controlling, say overpressure development or hydrocarbon charge in a basin, without having to spend an inordinate amount of time, effort, or financial or staff resources on providing narrower limits of uncertainty to those input factors that provide but little change in output uncertainties.

Multiple thermal indicator tomography is a non-linear inversion procedure which permits simultaneous determination of geological, chemical kinetic, and thermal parameters in the burial and thermal histories of sediments. The procedure is based on inverting measurements of multiple thermal indicators with depth in a well, each of which must have experienced the same thermal history. For two wells from diverse geological settings, tomography is used to assess the paleoheat-flux variations with time most consistent with all the thermal indicator data. Resolution and sensitivity of the results are also addressed. For the case history of well X in the North Sea, with both vitrinite reflectance and sterane isomer thermal indicators, a generally decreasing heat flux from past to present is obtained, roughly halving every 50 Ma. The activation energy for the sterane isomer is also determined simultaneously to be 42 ± 20 kJ/mole. For the second case history of the Irma Mclean well in the onshore Gulf of Mexico, data from four thermal indicators are available: vitrinite reflectance, sterane and hopane isomers, and sterane aromaticity. A general decrease in paleoheatflux from 2.8 heat flux units (HFU) at 100 Ma to 1.25 HFU at the present day is obtained, the activation energy for the sterane isomer is simultaneously determined to be around 50 ± 20 kJ/mole, while the corresponding values are around 80 ± 20 kJ/mole for the hopane isomer, and around 65 ± 20 kJ/mole for sterane aromatization.

A discussion is given of the impact of normal slant faults on basinal structure, compaction, fluid overpressure development, and thermal effects in sedimentary basins. Faults that are hydraulically closed or open to fluid flow are examined in a dynamical two-dimensional quantitative fluid/flow compaction model. From this numerical investigation three dominant factors characterize the effects of single and multiple faults with open or closed hydraulic behaviors: (1) there is a difference in excess pressure for fault planes with open versus shut hydraulic conditions, but the area where the effect of the fault is dominant is fairly localized (to within about half a kilometer or so laterally from the fault plane); (2) the lateral and vertical motion of sediments induces a thermal difference prior to, during, and post-faulting, which can play a role in influencing hydrocarbon generation, migration, and accumulation; (3) porosity retention and permeability modification by fault development could influence hydrocarbon exploration decisions regarding sealing, migration pathways, and fluid retention. The general patterns of slant fault effects described here should prevail in most geological situations, because the numerical experiments are designed to illuminate sharply the dominant response characteristics within the framework of simplified situations.

The presence of a salt sheet in the subsurface provides a permeability barrier to the flow of fluids, which can lead to the development of an overpressure condition and slower rate of compaction for formations underlying the salt sheet. These effects are demonstrated through (a) numerical simulations and (b) observations from four wells in the Gulf of Mexico which penetrated salt sheets and tested the underlying formations. The numerical models simulate the time-dependent fluid flow in a sedimentary basin containing a salt sheet; these models predict a significant increase in excess pore pressure in subsalt formations relative to the regional trend and also relative to the formations overlying the salt. The well data confirm the model results. Based on analysis of sonic log, density log, and mud weight data, the subsalt formations in three of the four wells are determined to be extremely overpressured while the fourth well is also highly overpressured, but not to the same extent. This work shows that pore fluid pressure constitutes a significant risk component in assessing a subsalt prospect and needs to be analyzed carefully before drilling.

ABSTRACT A steady-state simulation model for investigating the response of the hydrocarbon-water interface to changing hydrodynamic conditions has been developed. For any given aquifer geometry and water flow velocity, the model allows for permeability variations in order to simulate facies changes, and it also allows for variable density difference between water and hydrocarbons. Results from a variety of aquifer geometries and flow conditions will be exhibited and will show how the density difference between water and hydrocarbons, the velocity of flowing water, and varying permeability all influence the amount of hydrocarbons that can be trapped under hydrodynamic conditions. This procedure therefore reveals cases in which hydrodynamic conditions enhance the capacity of a given trap.

ABSTRACT Quantitative basin analysis techniques were used to study the structural history of Jurassic, Cretaceous, and Tertiary sediments in northern Louisiana, based on geological and geophysical data from 140 petroleum wells and 8 seismic lines. The uniformly distributed wells provide good control, on the regional scale, of the present day geometries of Cretaceous and Tertiary sediments. Seismic lines were used to identify deep Jurassic sediments, especially the Louann salt. The structural history in northern Louisiana can be separated into five major stages: (1) Jurassic rifting and extension; (2) Late Jurassic and Early Cretaceous subsidence; (3) mid-Cretaceous upwarping and westward tilting; (4) Late Cretaceous and Early Tertiary subsidence; and (5) Tertiary flexural downwarping. The regional tectonics and structures impact both the regional sediment deposition and lithology distribution. The hydrocarbon generation, migration and accumulation can be tied to the structural and depositional features. The dynamic salt movement associated with structural evolution could enhance the likelihood of hydrocarbon accumulations in sediments around salt diapirs.

ABSTRACT Cyclostratigraphy is the study of cyclic depositional patterns produced by climatic and tectonic processes ( Perlmutter and Matthews 1989 ). This paper describes a global scale quantitative cyclostratigraphic model which simulates carbonate growth patterns controlled by tectonic and climatic processes. The model uses seven factors simulating the effects of physical and chemical environments on the deposition rates of carbonate accumulations. These factors are sea level change, the rate of basement subsidence, food supply (influence of nutrient), available sunlight, temperature, salinity, and dissolved oxygen. The factors are considered as functions of climatic and tectonic processes. The model also integrates Milankovitch induced, short-term, climatic changes with the long-term, tectonic evolution of basins to examine the potential carbonate accumulation patterns. The two dimensional computer model results provided here show that: 1)Carbonate growth patterns in different climates and under different tectonic processes can be modeled quantitatively; 2) Carbonate production increases equatorward (latitude decreasing) due to both the temperature and nutrition supply increasing in tropical belts, and production changes because of the tropical belt expansion or contraction in different climatic periods; 3) When matched with the turbidity, the model describes different carbonate accumulation patterns in different climatic patterns; 4) At either abnormally high or low salinity, carbonate accumulation rates decline sharply, and the salinity becomes normal away from the strand line; 5) Cyclic sea level changes cause a cyclic change of carbonate accumulation. A case study is presented from the Texas Upper Pennsylvanian. The simulation results indicate that carbonate growth patterns observed from field, well or seismic data are accurately modeled by the quantitative procedure given here.

ABSTRACT The area of offshore Mobile Bay, Alabama is underlain by an extensive Jurassic salt deposit from the Louann Formation. Two procedures are given for estimating the original thickness of the Louann salt based on seismic information. The first procedure uses buoyancy pressure of the salt and empirical rock properties connected with fracture limits of rocks under pressure, to suggest a most likely salt thickness of 1600 ± 1400 ft. The second method uses the observed quasi-periodic amplitude variations of the Louann to estimate an original thickness of around 375 ft. An average of both estimates yields a mean thickness for the initial Louann salt of 1000 ± 500 ft.

ABSTRACT Due to the contrast in thermal conductivity between salt and typical sedimentary formations the presence of salt in various shapes in the sub-surface can have a significant impact on the sub-surface temperature distribution and thermal maturation of source rocks. Using a thermal indicator tomography 1-D modeling system, which deals with salt insertion, the thermal and excess maturity anomalies caused solely by the presence of a salt layer are investigated. Two cases, salt “plug” and “lens”, illuminate the different patterns of vitrinite reflectance variation with depth that would be recorded by borehole sampling. Salt can be inserted either as a primary depositional layer or by secondary intrusion at depth. The effects of salt are more dominant on the subsalt layers because: 1) salt insertion changes the burial paths of subsalt sediments. Thus the compaction-driven fluid flow of subsalt sediments, and also basement subsidence, are altered; 2) iso-temperature lines are modified by the presence of the salt and the variation depends on the thickness of the salt layer. The model was also designed to estimate the time of salt insertion and the variation of salt thickness in an inverse sense using present day data on temperature with depth and measured thermal indicators. An investigation is given of the degree to which inverse procedures resolve parameters associated with salt insertion, and the sensitivity of parameters is also discussed.

ABSTRACT Detailed fluid flow, thermal and petroleum generation histories were determined for C.O.S.T. No. 1 S. Padre Island, using data supplied by Phillips Petroleum Co. The study highlights (a) the significance of the petroleum potential of this area, and (b) the extremely good geologic control due to the quantity and quality of the extensive data base for this C.O.S.T. A discussion is presented on the sensitivity of the modeled histories to variations in the degree to which the modeled present day downhole properties (permeability, porosity, fluid pressure with depth, formation thicknesses and total thickness to TD) are in accord with the observations. The oil generation models are consistent with the observed downhole geochemical data that the Lower Miocene sediments (between 10,750 feet and TD) have generated significant oil and associated gas. The study improves our understanding of the relationship of the present geology to the prediction of generative oil potential.