- 1 - Sylta 2004

Hydrocarbon Migration, Entrapment and Preservation: Processes and Evaluation.







Øyvind Sylta, SINTEF Petroleum Research, 7465 Trondheim, Norway





Summary:



Hydrocarbon migration occurs at basin scale in tight mud-rocks and permeable carrier rocks. Hydrocarbons migrate from a source rock, through low permeable mud-rocks into carrier rocks. Hydrocarbons migrate laterally along the carrier rocks, just beneath a seal, until they are entrapped in traps that prevent further upward movement. Faults can act as both seals and migration conduits. Capillary leakage of gas and oil from the traps occurs when the capillary pressure within the hydrocarbon phase exceeds the cap rock entry pressures, while hydraulic leakage occurs when the pressures exceed the cap-rock leakoff pressures. Hydrocarbon components experience thermal alteration processes while being trapped, including cracking of heavy components into lighter components at high temperatures and biodegradation at low temperatures. The properties may also be changed by water washing and deasphalting.



The processes that control hydrocarbon migration include buoyancy, hydrodynamics and molecular diffusion. Sedimentary rocks exhibit a significant degree of heterogeneity, and the hydrocarbon migration process can be modelled using percolation theory concepts or Darcy flow using finite element and control volume techniques. The primary, secondary and tertiary migration processes may be modelled with different techniques.



Evaluation of migration often aims at describing the “source risk” by assessing the probabilities for different outcomes, e.g. trapped oil, gas or condensates in a trap. Expert opinions from experienced exploration geologists that rely on analogue systems have traditionally played an important role in describing the risks. Modern techniques have added the use of hydrocarbon migration simulations to provide estimates of oil and gas volume probabilities for traps. Future research should give improved estimates of risks by using, for example, Monte Carlo simulation techniques together with 3D basin scale fluid flow simulators.



Keywords:



Hydrocarbons, source rock, carrier rock, primary migration, trap, secondary migration, tertiary migration, buoyancy, hydrodynamics¸ compaction, permeability, overpressures, mud-rocks, adsorption, kerogen network, non-wetting phase, invasion percolation, faults, capillary seals, shale gouge ratio, diagenetic processes, hydraulic fractures, entry pressures, biomarkers, oil populations, diffusion, cracking, biodegradation, bacteria, thermal alteration, economic risk, basin simulators, risk factors, numerical modelling.



Glossary:



Capillary pressure: Pressure difference between the invading and the defending phases in a multi-phase porous system.



Capillary seal: Hydrocarbon seal caused by differences in entry pressures of different lithologies.



Carrier rock: A permeable rock horizon through which oil and gas migrate after leaving the source rock.



Compaction: Reduction of the bulk volume, or reduction of the pore spaces within, of a body of sediment in response to increasing weight of the overburden.



Diagenesis: All chemical, physical and biological changes undergone by a sediment after initial deposition and before final lithification.



Entry pressure: The minimum capillary pressure required to force a non-wetting fluid into capillary openings in a porous medium saturated with a wetting fluid.



Fault: A rock fracture or zone of fractures along which there has been displacement of the sides relative to one another.



Hydraulic seal: Low-permeability rocks seal for single and/or two-phase migration when total pore pressures are not sufficiently large to cause hydraulic fracturing. Fractures result in very high rates of migration, and therefore breach of the seal.



Invasion percolation: Migration is viewed as the invasion of a non-wetting hydrocarbon phase through a network of opposing capillary pressures. Hydrocarbons need to exceed (a) breakthrough pressure to migrate in stringers.



Mud-rocks: General term for fine grained sedimentary rocks; includes mudstone, claystone, shale and siltstone.



Primary migration: Migration of hydrocarbons out of the source rock and into the carrier rock.



Seal (rock): Impermeable rock preventing the upward migration of oil and gas from a trap.



Secondary migration: Migration of hydrocarbons in the carrier rock to the trap.



Shows: Hydrocarbons that are found in the pore space of porous rocks but cannot be produced by standard techniques during e.g. testing of wells.



Source rock: Sedimentary rock containing organic material that under appropriate conditions can be transformed into liquid or gaseous hydrocarbons.



Tertiary migration: Migration or leakage of hydrocarbons out of the trap.





Introduction



Hydrocarbons that have been generated in an organic rich source rock can be expelled from that source rock and then migrate within fine-grained (mud-) rocks until some of them reach a porous and permeable carrier rock. Migration within the fine-grained source rocks is referred to as primary migration. Migration then continues, usually up-dip, within the permeable carrier rock until a trap is reached and the hydrocarbons are trapped in the reservoir rock. This process is referred to as secondary migration. The hydrocarbons are retained in the trap by sealing rocks that act as barriers to further migration. Long and short-term processes that act upon the hydrocarbons trapped in reservoirs will frequently cause leakage of oil and/or gas. The leakage, referred to as tertiary migration, may be slow, i.e. occur over more than 50 million years, or very fast, i.e. during a time span of less than a million years.



The different processes that control hydrocarbon migration are in general fairly well understood. Several processes tend to act concurrently, and the various processes may be active in different types of sedimentary basins and hydrocarbon plays. The quantification of migration processes is still at an immature stage, but the large scale adoption of basin simulators with integrated fluid flow modelling into exploration settings and decision making teams holds the promise of quantifying the ranges of flow saturations and velocities and hydrocarbon migration directions under different geologic conditions.



Hydrocarbon migration evaluations have relied strongly on organic geochemical techniques. Laboratory measurements of source rock material and samples from oil and gas pools have allowed for the creation of one or more migration scenarios that can explain existing results and also make predictions about future drilling possibilities. In the future such techniques may be complemented by more quantitative approaches using fluid flow simulators in combination with high-resolution mapping of basins and traps from 3D reflection seismic data. However, the success of these techniques will rely on a proper and quantitative description of hydrocarbon migration processes.





A. Processes



1. Buoyancy and Hydrodynamics



The most important processes that influence hydrocarbon migration are buoyancy and hydrodynamics (Hubbert, 1953). Hydrodynamic conditions in sedimentary basins are associated with overpressures and barriers. Diffusion processes may also influence migration in some geologic settings. To some extent, hydrocarbon phase conditions and thermal processes also influence migration, not so much in migration direction as in the type of hydrocarbons that can be found in the reservoirs today. While temperature is the most important factor in the hydrocarbon generation process, pressure is definitely the most important for the migration process.



Buoyancy influences hydrocarbon migration because water is heavier than oil and gas at subsurface conditions. Only in extremely rare cases can “oil” become as dense as water, and therefore buoyancy will generally cause hydrocarbons to flow upwards. Buoyancy is very important for the secondary migration process, the entrapment of oil into traps, and for tertiary leakage out of traps (Fig. 1). There is always a significant upward component in the direction of migration for these processes. The rates of migration are high for the secondary migration process, while slower migration rates are more normal during primary and tertiary migration. Migration distances are generally less for primary and tertiary migration than for secondary migration in most basins.



Hydrodynamics is an important control on hydrocarbon migration in many sedimentary basins. During increased burial, sediments and faults become gradually less permeable due to mechanical and chemical compaction processes. Faults will often start to act as barriers as burial depth increases. Compaction is a result of increased loading on top of sediments during continuous sedimentation. When the permeability of fine-grained mud-rocks becomes very low, water is not able to escape from the low permeability formations sufficiently fast and, as a result, compaction is reduced and more of the sediment load is transferred from the grains to the interstitial liquid. This increased load on the water phase causes the pressure to increase in the pore-space, and overpressures result. Overpressures will be gradually reduced if the sedimentation rate decreases sufficiently, or a period of non-deposition or uplift follows. When the permeability of the mud-rocks is sufficiently low, pressure depletion may take millions of years. This will often be the case in passive margin basins at depths of e.g. 3500 to 5000 m.





Fig. 1 Formation of oil and gas accumulations. Hydrocarbons move (primary and secondary migration until they are trapped in accumulations (from Tissot and Welte, 1978).





As overpressures increase in mud-rocks, flow from the fine-grained rocks into the permeable carrier rocks will be maintained. In cases where carrier rocks communicate with very large aquifers or the surface/sea, no overpressure increase will occur in the carriers. This is because the supply of fluids from the mud-rocks is low, while the permeability of the carriers is many orders of magnitude greater than that of the mud-rocks (Schøn, 1996). In this case, an overpressures gradient will be maintained within the mud-rocks, and hydrocarbons that are expelled from source rocks within the mud-rocks will experience a push from this overpressure gradient towards the carrier system.



Expulsion



Before the hydrocarbons that are generated within the source rock units can start to migrate, they have to overcome a resistance to flow from the source rock organic matter. The surface of the organic matter has an affinity for the hydrocarbons, and adsorption causes some of the oil and gas to be retained at the organic matter surface (Pepper and Corvi, 1995). It can also be argued that primary migration cannot start until some of the pore space is saturated (e.g. Skjervøy and Sylta, 1993), leading to a saturation dependent expulsion. A third process description of the expulsion process assumes migration of hydrocarbons within a kerogen network (Stainforth and Reinders, 1990). This latter description combines the expulsion and primary migration into one single process.



Primary migration



The primary migration of hydrocarbons in mud-rich sequences (Fig.1) is often a very efficient process, with relatively low losses of hydrocarbons. Any losses are due to retention of hydrocarbons in the pore-space. Observations of hydrocarbon saturations in shales that hydrocarbons must have migrated through to get from a source to a trap (e.g. the Heather Formation of the North Sea) show low values, except very close to the source rock units (MacKenzie et al., 1987). Many authors have studied the effects of primary migration using geochemical methods, e.g. Leythaeuser et al. (1984). Leythaeuser et al. (1982) and Krooss et al. (1993) investigated molecular diffusion as a primary migration process, but Darcy flow now seems to be the most commonly assumed process for primary migration. Darcy flow for hydrocarbons in tight shales will occur at very low migration rates, because these rocks have very low permeabilities. Laboratory measurements of permeability in shales show permeabilities in the nano-Darcy range (1D=10-12 m2), with a spread over at least two orders of magnitude (Ingram et al., 1997).



At very low permeabilities, the flow conditions are such that the hydrocarbon migration may occur at higher saturations, but through extremely focused flow-paths, while higher permeabilities in the mud-rocks may result in two or even three phase flow (oil, gas and water through the same pore-space). In tight shales, the generation of the hydrocarbons may lead to very localized pressure increases around the kerogen. This increase in the pressure is a result of density changes from converting organic matter to gases and liquids (and coke), and the relative increase in liquids to solid material within the rock. The removal of solid matter effectively increases the porosity and thereby load is transferred from the matrix to the liquids, thus increasing overpressures. When permeabilities are very low, the increased overpressures can result in localized fracturing of the source rock, and hydrocarbons would preferentially flow through these fractures because the highest overpressures would be where the oil is generated. The highest overpressure gradients would also be associated with where the hydrocarbons have been generated, and therefore hydrocarbon migration would increase more than the average water flow in the mud-rocks.



Secondary migration



Secondary migration, the flow of hydrocarbons within a permeable carrier system and into traps (Fig.1), occurs in a more open system than primary migration (Schowalter, 1979). The conditions of flow are more similar to the flow that occurs in oil fields during production because of the good permeabilities in many carrier systems. Frequently, the carrier system consists of the same type of rocks as the producing fields, or traps, and rock properties are therefore available through laboratory measurements. Because of the high permeabilities, attempts have been made to study the secondary migration flow in laboratories. Dembicki and Andersen (1989) published an experiment where oil was injected into a vertical cylinder of sand. The resulting flow was observed by slicing the sand after the experiment was completed. Flow was observed to occur within a single oil stringer only a few mm in thickness, and the saturation was very high within the stringer, although a quantitative estimate was not made.



Selle et al. (1992) measured the oil migration within a 60 cm long sub-horizontal core at 5o dip, and measured the oil saturations during the experiment using a gammy-ray methodology. They observed that migration occurred at relatively low hydrocarbon saturations (10-20%), and for a high permeability carrier the flow was focused to the upper 1-2 cm of the core. For a lower permeability carrier the flow occurred over the entire core and at hydrocarbon saturations that were consistent with a two-phase Darcy flow, as verified by using a commercial multiphase flow simulator. The experiment took weeks to complete, which suggests that secondary migration velocities can be expected to exceed 1000 km/My in sedimentary basins. The very focused migration and not so high saturations within the pathways result in quite low secondary migration losses. It is only when secondary hydrocarbon migration passes through very low permeability units, e.g. siltstones, and/or when the hydrocarbon generation occurs over very short time spans, e.g. less than 1 million years, that secondary migration losses in the migration pathways can become so large that the traps may be insufficiently filled. Effective secondary migration is possible over long distances, and some oil fields may have been sourced from kitchens that lie more than 1000 km from the traps (Sylta et al., 1998). This is possible if the carrier system is continuous, the dip is very low, and no disturbances cause migration pathways to be intercepted by vertical leakage to the surface.



Frette et al. (1992) performed experiments of slow upward migration due to buoyancy, of a non-wetting phase in a 3D medium and used a modified invasion percolation algorithm to help explain the process as quasi-static at the pore scale. Carruthers and Ringrose (1998) suggested that invasion percolation could be used to describe the (secondary) migration at the basin scale because feeding rates from the source rocks are very low and the migration will occur with hydrocarbon saturations at or very near a percolation threshold.



During secondary migration, hydrocarbons also have to saturate the pore space in dead-ends and micro-traps (Fig. 2). These are tiny accumulations that are too small to produce (at least until now). The size of a micro-trap could be in the range of a few tens of m3. However, when the carrier system is complex, with lots of lithology changes and/or small structurations, e.g. faults, the number of micro-traps and dead-ends can be very large, and therefore the volumes trapped in them may become significant in some geologic systems. The hydrocarbon phases trapped within dead-ends and micro-traps can be both oil and gas. Structural micro-traps may preferentially be filled with gas, because they are small and oil therefore tends to be spilled. Stratigraphic micro-traps may leak gas through the top, or laterally along a preferred flow-path because gases tend to migrate more easily through seals than oil due to their lower densities and viscosities.





Fig. 2 Conceptual view of secondary migration of oil in a carrier surrounded by mud-rocks. Oil stringers are thin black “ganglions” (from England et al., 1991).



Faults and barriers



Faults may act as barriers to hydrocarbon migration or as conduits for hydrocarbons. When sand/shale sequences are faulted, some of the sand and shale is often dragged into the fault plane. Large fault juxtapositions often lead to more drag into the fault zone. Clay or shale that is dragged (smeared) into the fault plane will act as capillary seals to the hydrocarbons that try to get through. For across-fault migration from the hanging to the footwall side of a fault, hydrocarbons can migrate through very small holes in the fault plane. Hence, across-fault migration will be controlled by the minimum entry pressures of the part of the fault plane that is in contact with hydrocarbons. When fault throws are large, hydrocarbons may have to look for migration pathways up along the fault plane, and then they have to overcome the maximum entry pressure of the fault plane to get through. It is therefore often much more difficult to get migration up fault planes than across fault planes. The smearing of clay/shale within the fault plane can be expressed quantitatively by a shale gouge ratio, SGR (Knipe, 1997; Yielding et al., 1997). This factor can be used in assessing which faults are sealing. When faults act as barriers, hydrocarbons may flow along the fault until a trap is reached, or until the hydrocarbons are able to migrate around the fault.



Diagenetic processes will also help in sealing faults to hydrocarbon migration (and water flow). Sands that are dragged into the fault plane may undergo compaction and diagenesis by, for example, pressure solution and kinetic reactions. The permeability of the conduits within the fault plane will then be reduced and the entry pressures will increase. There is often, therefore, a correlation between faults that seal for overpressures and hydrocarbon migration (and trapping). It should be noted, however, that overpressures result from the total fluid flow across faults, and the water phase flow is the more important phase. By comparison, hydrocarbons only migrate through a small fraction of the fault plane. The correlation between overpressures and hydrocarbon seal across faults is therefore highly variable.



Carrier systems that are highly over-pressured can cause hydraulic fracturing of faults. Faults often form the boundaries of pressure cells, and therefore the shallowest point of a pressure cell can in many cases be found at a bounding fault. Hydraulic fractures are most likely to start off from the shallowest point of each pressure cell. Hydraulic leakage up fault planes is extremely difficult to prove, because we have no direct access to the fault plane, and therefore cannot take measurements within it. The effects of hydraulic leakage can be that a trap has been emptied by leakage of all or some of the hydrocarbons in it. One can then observe the retained oil in the palaeo-trap and interpret the case as evidence of hydraulic leakage if the pressures are close to the leak-off pressures measured in the cap-rock. However, it is not possible to determine if the fault or the cap-rock contains the actual hydraulic leakage flow paths. It is therefore possible that hydraulic leakage up fault planes is a much more common process than it has so far been considered to be.





2. Entrapment



Trap types



Hydrocarbon accumulation in traps requires four-way closure by one or several seals to prevent hydrocarbons escaping to shallower levels. Traps are divided into structural, stratigraphic and combination types. Movements of the subsurface have formed structural traps after the deposition of the reservoir rock and the seal was completed, while stratigraphic traps are results of depositional changes that juxtapose reservoir and sealing rocks in a favorable position to trap hydrocarbons. The seals of the traps are usually not efficient until sufficient burial has reduced the permeability and increased the entry pressures to prevent hydrocarbons to leak out (see discussion later). Berg (1975) discussed the trapping potential of a trap and outlined equations for computing the oil column that could be trapped below a seal.



Numerous trap types have been defined. Salt is a nearly perfect seal, and a number of different trap types have therefore been defined around salt domes, along the flanks, over the top and within rim synclines. Combined stratigraphic and structural traps are fairly common. These traps rely on both a stratigraphic seal, for example a pinch out in one direction, and a structural seal, for example a structural ridge, may provide the closure in the other three directions. Early workers on hydrocarbon migration and trapping spent a significant time on defining trapping styles (see Watts, 1987 and Sales, 1993), and used these to correlate the sealing potential of different trap types between different basins. Later research has gone in different directions: (1) depositional and structural modelling to understand and predict how and where traps are formed; (2) fluid flow modelling to understand the filling and sealing of the traps, and (3) measurements of cap-rock sealing properties .



Trap filling



Basin modellers tend to view traps as being dynamic, where filling of a trap is a continuous process that continues frequently over more than 50 million years. This process starts immediately when a source rock in the catchments area of a trap has reached a thermal maturity sufficient to start expulsion and migration of hydrocarbons. The seal above the trap may not be efficient when hydrocarbons migrate into the trap, and hydrocarbons may then migrate through the trap and the seal above to the surface, only leaving a thin migration stringer saturated with hydrocarbons behind. Upon burial, the seal of the trap will become at least partially effective, and hydrocarbons start to fill it. In sedimentary basins with oil generating source rocks, an early phase of oil filling is quite normal. However, many source rocks will also contain some organic material, for example type III kerogen, with quite broad kinetics for the transformation of kerogen to oil and gas. The gas generating part of the kerogen can then start to expel hydrocarbons before the oil-generating fraction, and lead to a very early phase of gas filling of the trap. Often this filling will occur at a time when the seal is starting to become effective, and only a small gas cap may form within the trap. Increased burial of the source rocks causes effective oil expulsion to start and fills of the trap with liquid hydrocarbons. More and more of the gas cap will be dissolved in the liquid oil as the trap subsides to greater burial depths, and the trap may change from a very small under-filled gas cap to an under-saturated oil filled trap. Further burial of the source below the “oil window” starts to feed the trap with more gas than oil and a gas cap re-develops in the trap. As more and more gas migrates into the trap, oil will start to be pushed out of the trap by the lighter gas, and eventually all the oil is spilled out of the trap into shallower traps. Deep burial also frequently leads to excessive overpressure development, with resulting hydraulic leakage of some or all of the hydrocarbons in the trap. The end result may then be a trap with only oil and gas shows remaining. The above is a typical filling history of a generic, deeply buried trap. Traps that are not buried too deep can be stopped at any stage in the history, and consequently any type of hydrocarbons can be found.



The trap filling process has been studied extensively by geochemical methods. England et al. (1991) discuss the trap filling and mixing of hydrocarbons. Horstad and Larter (1997) applied geochemical investigations to explain the filling history of the Troll Field. Typical of this approach is the difficulty in arriving at unique explanations of the trap filling histories and processes. Biomarkers are typically used to group oil populations. Many geochemical parameters can be interpreted in different ways. It is by combining different parameters and measurement types that workers are able to differentiate oil populations, and suggest several migration phases for the filling of the traps. Using these techniques, suggestions on whether oil or gas first filled the traps can also be made (e.g. Horstad and Larter, 1997). Oil populations can be mapped in one or several traps and fields, and they can be used to split an oil province into several oil migration systems. There is no significant progress yet, however, in using the indicators in a more quantitative manner, for example as indicators of migration distances. A simple grouping into the prominent source rock types that source the trap (e.g. type I, II, III kerogen) is often attempted.





3. Preservation & destruction.



Sealing & leakage



Entry pressures obtained from laboratory measurements can characterize the sealing potential of cap-rocks. Cores are not easily obtained from exploration wells, and investigations of samples taken from the field will always be affected by their unloading history. Investigations of sealing potential by measuring entry pressures from cuttings have shown some potential, but are not yet performed on a large scale in the industry. Investigations into cap-rock processes rely on good geochemical data and a good understanding of fluid flow in mud-rocks. Leakage of hydrocarbons from traps is attributed to: (1) capillary leakage; (2) hydraulic leakage, and (3) molecular diffusion.



Krooss and Leythaeuser (1988) investigated molecular diffusion extensively by laboratory experiments. Molecular diffusion is today not considered the most important leakage mechanism because it takes too long time to leak out large quantities of hydrocarbons from a trap by this process, in particular for large (fluid phase) molecules. In some cases, with very diffusive and high entry pressure rocks, cap-rock diffusion can be more important. Molecular diffusion may also be an important process when leakage starts, to increase the content of hydrocarbons in the cap-rock just above the trap, and thereby modify the hydrocarbon saturation profile within the cap-rock.



Capillary pressure leakage (Watts, 1987) can in many cases be demonstrated above fields by estimating the hydrocarbon saturations and mapping out which parts of the cap-rock are saturated with hydrocarbons. One may find that the cap-rock is saturated with hydrocarbons to a certain level (e.g. Leith et al., 1993). The hydrocarbon saturation in the cap-rock can be correlated roughly to measured or inferred entry pressures of the cap-rock sequence, suggesting that capillary leakage may have occurred. The correlation is not straightforward, however, because of the dynamic change of both the filling of the trap and the change of cap-rock properties through time.



The question as to whether hydrocarbon migration through cap-rocks occurs at capillary pressures very close to the entry pressures, and through preferred pathways defined by the entry pressure distribution within the cap rocks, or through two-phase Darcy flow has not been resolved yet in the literature. With the former process description, the rates of leakage are not important. Time becomes unimportant as such and percolation theory can be used to simulate the process. In a Darcy flow process description, flow-rates control the capillary pressures in the pores through which hydrocarbons migrate. The saturation is therefore flow-rate dependent, and the volume of rocks saturated during leakage will therefore be larger for a high flow-rate leakage scenario than for a low leakage rate scenario. A Darcy flow approach to leakage will therefore be more dynamic in the calculations of migration losses, and the maximum leakage rates may have to be determined to estimate how much oil and gas can be lost within the cap-rock. The assumed direction of hydrocarbon migration through the cap-rock will often be very similar in both process descriptions. The Darcy flow may, however, become more spread out, and several small traps can be sourced from the same deeper structure. With percolation, ganglions form to create an oil stringer backbone through which all hydrocarbons later pass (Fig. 3). This leads to an extremely efficient leakage once the threshold pressure has been exceeded by the non-wetting phase (Carruthers and Ringrose, 1998).



Fig. 3 Generalized view of oil migration using invasion percolation concepts (from Carruthers and Ringrose, 1998).



Hydraulic leakage results when the pore pressures are so large that the effective stress reaches zero. Effective stress, the pressure that is acting on the solid rock framework (Terzaghi and Peck, 1968), is the difference between the weight of the overburden and the pore pressure. Hydraulic leakage is very efficient because the resulting flow occurs through open fractures that have high permeabilities. These fractures will close when the effective pressure starts to increase, effectively resealing the cap-rock for leakage. Once a fracture has been created in a cap-rock, it will be easier to reopen it at low effective stresses, because the tensile strength has been reduced to zero in the fracture, and resealing, even by diagenetic processes, may not restore the tensile strength. Hydraulic fracturing may be influenced also by tectonic stresses, but these stresses have been very difficult to predict at a prospect level. Traps that have leaked oil through hydraulic fractures tend to have significant volumes of oil remaining within the cap-rock, even though the trap itself may be dry or contain only residual hydrocarbons. Gas chimneys are sometimes associated with hydraulically leaking traps (Løseth et al., 2000).



While the process of hydraulic leakage is well understood, it is extremely difficult to predict prior to the drilling of an exploration well whether hydraulic leakage has occurred. Methods that can be used to predict the pore pressures are very important to assess the risk of hydraulic leakage. New generations of 3D basin fluid flow simulators (Grigo et al., 1991; Borge, 2000) may aid in increasing the predictability of hydraulic leakage occurrence.



Thermal alteration



Hydrocarbons that are exposed to high temperatures may undergo kinetic alteration (cracking) reactions. These reactions crack heavier components into lighter reactions and a residue (coke). Thermal alteration starts already in the source rock, but is also very effective in deep traps. Hydrocarbons in traps with temperatures that exceed 150oC are likely to be affected by thermal alteration. The cracking reactions are slower than those in source rocks because the source rock kerogen contains many catalysts that speed up the kinetic reactions. Artificial maturation experiments in the laboratory are used to quantify oil to gas cracking reactions (Schenk et al., 1997). In order to speed up the kinetic reactions that take millions of years to complete at natural conditions, laboratory temperatures used are much higher than those of the natural system. There are therefore some uncertainties whether the correct reactions occur in the laboratory. The kinetic models that result from artificial maturation experiments of oils do, however, give realistic conversion temperatures when applied to geologic heating rates.



At the resolution of existing experiments, different oil types only play a minor role on the results from laboratory experiments. Recent findings may suggest that the thermal stability of oils is greater than proposed by earlier workers (Tissot and Welte, 1978).



Biodegradation



Biodegradation occurs at relatively low temperatures by organic bacteria that use hydrocarbons as nutrients. The most important control is temperature, and biodegradation is observed at temperatures less than 80oC. A good supply of oxygen enhances the activity. The process is usually so fast that time does not seem to be a first-order constraint for the biodegradation process. Biodegradation can be classified into light, moderate and heavy biodegradation. Heavy biodegradation can result in major problems in producing oil fields, and some discoveries may not be possible to produce at all. Palaeo-biodegradation can be observed in some discoveries, and old biodegraded oil may partly have been flushed out by a new “fresh” oil phase that migrated into the trap at temperatures above the maximum temperatures for biodegradation. The biodegradation process causes oil to be converted to heavier and longer component groups together with light gas components.



Heavy biodegraded oil has a low API and is therefore easy to detect. Lower degrees of biodegradation can be observed from biomarkers in the oils. Although biodegradation has been demonstrated in the laboratory (both aerobic and anaerobic), the process has traditionally been described from an empirical viewpoint because access to biodegraded oil samples has been relatively easy (e.g. Horstad and Larter, 1992). Ranking schemes therefore dominate over mathematical/numerical models in the analysis of this process. Carpentier (2002) proposes a model for biodegradation based upon number of bacteria, hydrocarbon type preference, temperature, porosity, water saturation and water fluxes. The process is considered to contain a post-filling and in-filling part, where post-filling biodegradation acts on uplifted fields, while in-filling biodegradation occurs when hydrocarbons migrate into low-temperature traps. Okui and Tamura (2001) used basin-modelling techniques to elucidate on the biodegradation effects in some fields in the North Sea. This is an approach that is likely to be used extensively, particularly as 3D modelling of fluid flow at basin scales becomes more common.



Water washing and deasphalting



Trapped hydrocarbons can be affected by a number of processes in addition to thermal alteration and biodegradation. Water washing occurs when water flushes the reservoir without removing all the hydrocarbons, but stripping only some of the components from the oil. The most water-soluble components are the ones being removed. Tissot and Welte (1978) defined deasphalting as the precipitation of asphaltenes from heavy to medium crude oil by the dissolution in the oil of large amounts of gas and/or other lighter hydrocarbons in the range from C1 to C6. While these processes are relatively easy to understand conceptually, successful attempts to make detailed models that can be used for prediction of properties away from existing wells have not yet been made. This may in part be because of the complexity of the problem, but also because of a general lack of tools available to make quantitative predictions of hydrocarbon component (groups) in traps. The earlier works of Tissot and Welte (1978) and Palmer (1991) are therefore still state of the art.



B. Evaluation



The main objectives of an evaluation of hydrocarbon migration and entrapment in oil companies are to constrain and reduce economic risk in the exploration for oil and gas. Migration is often considered a part of the “source risk” or “hydrocarbon charge” topic. One of the main tasks of the assessment will be to arrive at a probability that a prospect contains an economic quantity of oil and/or gas. Modern techniques of risk assessment often use Monte Carlo simulation techniques to compile overall probabilities for prospects and licenses before a possible drilling is decided upon. The risk for migration can vary from 0 to 100%, and therefore the chosen risk can be extremely important for the ranking of prospects.



Traditionally, the assessment of migration has been performed through the use of expert opinions. Over the last 10 years, more quantitative methods have been introduced into the exploration phase, but still today (2002), many prospects will be drilled completely without any quantitative assessment of migration.







1. Primary and secondary migration



With the introduction of 1D basin modelling, it has been possible to model the thermal maturity of kerogen quickly and with some degree of confidence in an exploration setting, where time for analysis will always be a constraint. During the 1990's many of the 1D basin simulators have added expulsion modelling and also some limited functionality for primary migration efficiency calculations have been achieved (Okui and Waples, 1993). The 1D type of simulators have mostly avoided fluid flow modelling, e.g. pressure modelling, and have therefore been extremely quick to use and have not required exceptional skills to learn. Therefore 1D simulators are used by many (more than 1000) geologists.



The 2D basin simulators have also been introduced into the oil industry during the 1990's. These simulators have been used to study flow patterns, both pressures and hydrocarbon migration. Typically, the 2D simulators model the process in depth and along a profile, and vertical burial with limited fault functionality has been the norm. Quantitative estimates of trapped hydrocarbon volumes could not be calculated, but predictions of phases in traps have been made with some success. The compositional simulators have also attempted to predict more accurately the history of phases and hydrocarbon components in traps, increasing the probability of predicting e.g. condensate traps.



Map migration techniques use a 2D approach where the two lateral spatial coordinates are used and hydrocarbon migration is simulated along a single carrier through time (Skjervøy and Sylta, 1993; Symington et al., 1998). Also these tools have used only vertical burial of the sediments, but the capability of handling lateral fault seal has been incorporated into many of the tools (e.g. Sylta, 1993).



Full 3D hydrocarbon secondary migration using, for example, Darcy flow, relative permeabilities and related numerical techniques, are starting to be used. These techniques have problems in retaining a sufficient resolution of the geologic model if simulation times are to be kept reasonable. Use of 3D percolation simulation techniques, based upon the methods of Carruthers and Ringrose (1998), has been proposed as a fast approach to modelling secondary migration. This approach can be combined with Monte Carlo simulation techniques even for very large numerical models.



2. Entrapment



The analysis of hydrocarbon entrapment typically makes extensive use of organic geochemical methods. Different types of investigations may be employed to group trapped hydrocarbons into “families”, which again allows for assessments on how the trap was filled with hydrocarbons. Future analyses will most likely combine these methods with input from (secondary) migration modelling. The tracing of different oils from their sources to their traps may be done in new computer simulators that can support already established organic geochemistry methods of source-oil fingerprinting.



The analysis of entrapment today uses elements from fault seal analysis, such as clay smear modelling of important faults. This analysis can indicate whether a particular fault has been sealing or open, where the sealing characteristics change, and therefore if or where hydrocarbons may have entered a particular trap. This information can be crucial as to whether the trap will be filled with oil or gas. This type of analysis results in information that is considered quite sensitive by the oil companies, and publication of results from applications can be expected to be few.



PVT modelling can be used to improve phase predictions in entrapment analysis. Component distribution of trapped hydrocarbons can be taken from oil samples from nearby wells and phase diagrams may be constructed. The difference in behavior of different hydrocarbon families can be elucidated, and used to assess the condensate concentration in traps (di Primio et al., 1998). Seismic AVO modelling techniques are starting to be used for assessing possible hydrocarbon fill in undrilled prospects directly from seismic (Davies et al., 2002).



3. Preservation & destruction



The analysis of preservation and destruction of hydrocarbons includes quantifying and risking the processes of: (1) hydrocarbon leakage; (2) thermal cracking of oil; (3) biodegradation, and (4) water washing and deasphalting . The most important process to quantify will often be the hydrocarbon leakage, while the cracking and biodegradation problems are often converted to simple depth ranges for the traps and prospects. The prospect risk is then considered much higher outside the favourable depth ranges. Water washing and deasphalting are problems that are studied when they are encountered, while generally little emphasis is put on these processes before exploration drilling.



Hydrocarbon leakage assessments can be based on a quantification of overpressures for determining hydraulic leakage. It has been common to create overpressure maps using a geological expert who interpolates overpressures from well data and using assumed fault seal to delineate pressures compartments with similar pressures. Borge and Sylta (1998) suggested using a modelling technique to facilitate the same, but using a quantitative model for fault transmissibilities. The use of 2D pressure modelling has been employed quite extensively during the 1990's as an aid in making predictive models of overpressure distributions along transects. The transects are typically located along the steepest gradient of the basin, where rapid changes in overpressures are likely to be modeled.



The 2D transect modelling technique has also been used to quantify leakage rates due to hydraulic fracturing and capillary leakage. Because both pressures and temperatures can be fairly well constrained in a 2D simulator, all the processes involved in the preservation and destruction of hydrocarbons in traps can be accounted for. This gives perhaps the best approach to the analysis of these processes today.



The preservation and destruction of pore space in traps is not strictly a migration problem. Nevertheless, it is important to note that the compaction and diagenetic processes affecting porosities are crucial to the analysis of hydrocarbon preservation and destruction. Methods for modelling these diagenetic processes were introduced in 1990’s (Walderhaug, 1996).



The major challenge for the evaluation methods is to become more predictive. Many of the processes that involve the preservation and destructions of hydrocarbons in traps are highly non-linear, and all aspects of the processes are not understood, e.g. biodegradation and water washing. Future research into these topics may benefit from advances in other research fields.



4. Risk & Economics



Oil companies aim to determine risk factors for hydrocarbon migration (sourcing) before they decide whether they want to pursue the licensing and/or drilling of traps and prospects. Traditionally, the geological and geophysical experts have been able to determine this risk factor by expert opinions based upon existing basin specific knowledge. One disadvantage of this approach has been that surprises (dry wells) are quite common because geological conditions change from trap to trap. Even small changes may cause a seal to leak in one trap while being effective in another.



Regional geological studies have traditionally been used as risk constraints. Recently, the use of regional migration modelling studies has also helped in the description of prospect risk. The use of full 3D hydrocarbon migration simulations is now being introduced to the oil industry. A few commercial packages are being marketed. The advantages of these packages are many. One of the most important facilities of 3D simulators is that they encourage geologists to create integrated models that explain not only a few but nearly all of the observations. Extensive calibration of the system to geologic observations allows for building complex models that consistently explain the observed temperatures, pressures, maturity indicators and hydrocarbon trapping. It is then simpler to arrive at consistent risking of prospects within that particular study area. One may still be too optimistic or pessimistic within one particular study area, but consistency between traps is maintained, and the ranking of prospects becomes simpler.



High resolution modelling techniques can in the future become more tightly integrated with economic risk assessment. Today’s practice seems to be to reduce the geologic risks down to a few economic figures for each trap, and then do the economics for only one or at most two geologic scenarios. The reason for this is that the economic assessment has to decide which type of platform to use, and the calculations take time to perform. Krokstad and Sylta (1997) showed that it is possible to derive more complete probability distributions for the volumes of trapped hydrocarbons in each trap. In the future, one may derive faster schemes for economic assessments and combine these with integrated high resolution basin modelling to derive better economic risk probability distributions for each trap. The advantages will be that one can more realistically assess the economic consequences of most of the possible geologic outcomes from drilling a well in a new trap.



5. Trends and Perspectives



Numerical modelling techniques are becoming more and more important for the study of migration, entrapment and preservation of hydrocarbons. Field work remains important to provide a basis for new geological insights into the processes. Laboratory work remains an under-utilized topic in this field, in particular to investigate and demonstrate hydrocarbon migration cases, for example migration across and along faults. New techniques that can account for a more dynamic geology during simulations will have to be developed to account properly for salt movements and structural inversion.



As computers become more powerful, there is a trend towards modelling with larger geological models. Just as important will, however, be the trends towards improved handling of uncertainties. Monte Carlo simulation is just one approach that can be used to quantify uncertainties and give improved probabilities for estimates of trapped hydrocarbons.



It is anticipated that in the near future oil companies will start to employ hydrocarbon migration simulation tools at a larger scale. The need for improved models and tools may result in a significantly increased effort in hydrocarbon migration research in the next decade.













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