Ku Geology 2

Maturation and expulsion

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Conversion of Kerogene to Oil and Gas

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Maturation and expulsion • With increasing burial by later sediments and increase in temperature, the kerogen within the rock begins to break down. • This thermal degradation or cracking releases shorter chain hydrocarbons from the original large and complex molecules found in the kerogen. • The hydrocarbons generated from the source rock are expelled, along with other pore fluids, due to the continuing effects of compaction and start moving upwards towards the surface, a process known as migration. Department of Petroleum Technology, University of Karachi

Oil and Gas Conversion

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Rock Pyrolysis •

S1 = the amount of free hydrocarbons (gas and oil) in the sample (in milligrams of hydrocarbon per gram of rock).

•S2 = the amount of hydrocarbons generated through thermal cracking of nonvolatile organic matter. S3 = the amount of CO2 (in milligrams CO2 per gram of rock) produced during pyrolysis of kerogen. Oxygen bearing volatile compounds are passed to a separate detector, which produces as S3 response.

Department of Petroleum Technology, University of Karachi

Rock Pyrolysis • Espitalie developed a standard procedure for the pyrolysis of rock samples known as ROCK-EVAL PYROLYSIS. • Method: About 100 mg finely ground rock sample is placed into a furnace at 250 degree C in an inert atmosphere than raised to a temperature of 550 degree C. • The amount of Hydrocarbon products evolved is recorded by a Flame Ionization Detector (FID) as a function of time. • Three Peaks are typically, Known as S1, S2 and S3 peaks are evolved and recorded. Department of Petroleum Technology, University of Karachi

Example of Rock Eval trace. HC = hydrocarbon • If S1 >1 mg/g, it may be indicative of an oil show. • S1 normally increases with depth. • Contamination of samples by drilling fluids and mud can give an abnormally high value for S1. S2 is an indication of the quantity of hydrocarbons that the rock has the potential of producing. The burial and maturation should continue at this stage. This parameter normally decreases with burial depths >1 km. Department of Petroleum Technology, University of Karachi

Example of Rock Eval trace. HC = hydrocarbon • S3 = the amount of CO2 (in milligrams CO2 per gram of rock) produced during pyrolysis of kerogen. • Oxygen bearing volatile compounds are passed to a separate detector, which produces as S3 response. • S3 is an indication of the amount of oxygen in the kerogen and is used to calculate the oxygen index. • Contamination of the samples should be suspected if abnormally high S3 values are obtained.

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Hydrogen index/oxygen index plot from Rock Eval pyrolysis data. TOC HI = hydrogen index (HI = [100 x S2]/TOC). HI is a parameter used to characterize the origin of organic matter. Marine organisms and algae, in general, are composed of lipidand protein-rich organic matter, where the ratio of H to C is higher than in the carbohydrate-rich constituents of land plants. . PC = pyrolyzable carbon (PC = 0.083 x [S1 + S2]). PC corresponds to carbon content of hydrocarbons volatilized and pyrolyzed during the analysis.

Department of Petroleum Technology, University of Karachi

Hydrogen index/oxygen index plot from Rock Eval pyrolysis data. TOC . OI = oxygen index (OI = [100 x S3]/TOC). OI is a parameter that correlates with the ratio of O to C, which is high for polysacharride-rich remains of land plants and inert organic material (residual organic matter) encountered as background in marine sediments. PI = production index (PI = S1/[S1 + S2]). PI is used to characterize the evolution level of the organic matter.

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EXPULSION EFFICIENCY

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PGI and PEE Mackenzie and Quigley (1988) has classified source rocks into three end member classes on the basis of initial kerogene concentration and kerogene type. These parameters determine the timing and composition of petroleum expelled. PGI : (Petroleum generation Index) is the fraction of petroleum prone organic matter that has been transformed into petroleum, and is thus a measure of source maturity. PEE: (Petroleum expulsion efficiency) is the fraction of petroleum fluids formed in the source rock that have been expelled Department of Petroleum Technology, University of Karachi

PGI and PEE •

Class I: Predominantly Labile Kerogen at concentration of 10Kg/ton and generation start at about 100 degree C. This rapidly saturates the source rock and between 120-150 degree C 60%-90% is expelled as oil with dissolved gas. The remaining fluid crack to gas at higher temperature and expelled as gas.

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Class II: This is linear version of Class I with initial Keregen concentration < 5Kg/ton. Expulsion is inefficient up to 150 degree C because insufficient oil-rich petroleum generated. Petroleum is expelled mainly as gas condensate formed by cracking above 150degree C followed by some Dry Gas.

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Class III: Source rocks contain mostly Refractory Kerogen. Generation and expulsion take place only above 150 degree C and petroleum fluid is a relatively dry Gas

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The Origin of Petroleum

Organic-rich Source Rock

Thermally Matured Organic Matter

Oil

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Oil and gas are formed by the thermal cracking of organic compounds Kerogen Typesburied in fine-grained rocks. •

Algae = Hydrogen rich = Oil-prone

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Wood = Hydrogen poor = Gas-prone

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Petroleum System: Timing is Critical Trap Must Be Available Before/During Migration

Processes Generatio n :

Elements :

Source Rock

Migration

Accumulation and Preservation

Migration Avenue

Reservoir and Seal

For accumulations to occur, a trap must exist either before or coincident with the time of migration. The petroleum system events chart helps capture these critical aspects of timing.

Petroleum System 1) Early Generation

Spill Point

Migration from ‘Kitchen’

2) Late Generation

Spill Point

Reservoir Rock (Sandstone)

Seal Rock (Mudstone)

Gas beginning to displace oil

Displaced oil accumulates Gas displaces all oil

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Several specific forms of hydrocarbons• Dry gas- contains largely methane, specifically contains less than 0.1 gal/1000ft3 of condensable (at surface T and P) material. • Wet gas- contains ethane propane, butane. Up to the molecular weight where the fluids are always condensed to liquids • Condensates- Hydrocarbon with a molecular weight such that they are gas in the subsurface where temperatures are high, but condense to liquid when reach cooler, surface temperatures. Department of Petroleum Technology, University of Karachi

Several specific forms of hydrocarbons• Liquid hydrocarbons• commonly known as oil, or crude oil, to distinguish it from refined hydrocarbon products.

• Plastic hydrocarbons- asphalt • Solid hydrocarbons- coal and kerogen- (kerogen strictly defined is disseminated organic matter in sediments that is insoluble in normal petroleum solvents.

• Gas hydrates• Solids composed of water molecules surrounding gas molecules, usually methane, but also H2S, CO2, and other less common gases.

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Hydrocarbon Generation Stages

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Cross section through part of a sedimentary basin in which a hydrocarbon source rock layer has been buried to different depths. Due to increasing temperatures with increased burial depth, organic matter within this source rock `cooks', resulting in partial decomposition and petroleum generation (mature source rock). With further burial, organic matter decomposes to generate natural gas (over-mature source rock). Generated petroleum and natural gas are expelled from the source rock and migrate upward into porous overlying rock layers. If appropriate conditions exist, petroleum and natural gas are trapped and accumulate. If appropriate conditions do not exist, natural gas is eventually released to the atmosphere and petroleum seeps at the surface to form asphalt (tar) deposits.

Department of Petroleum Technology, University of Karachi

Expulsion of hydrocarbons from shale source Rocks • There is compelling evidence that movement of petroleum from organic-rich shales into sandstones and limestones, occurs in the subsurface. • This expulsion of material must occur if crude oil accumulations are to form, and it is termed primary migration. • Earlier studies suggested that this movement occurs with chemical fractionation: some components are more mobile than others. • One of the agents of expulsion at early maturity stages is compaction, which is not only capable of forcing water, but also organic components out of the pore network of a source rock. Department of Petroleum Technology, University of Karachi

OIL AND GAS MIGRATION • Traditionally (Illing, 1933), the process of petroleum migration is divided into two parts: • primary migration within the low-permeability source rocks • secondary migration in permeable carrier beds and reservoir rocks. • It is now recognized that fractured source rocks can also act as carrier beds and reservoir rocks so more modern definitions are: Department of Petroleum Technology, University of Karachi

OIL AND GAS MIGRATION • Primary migration of oil and gas is movement within the fine-grained portion of the mature source rock. • Secondary migration is any movement in carrier rocks or reservoir rocks outside the source rock or movement through fractures within the source rock. • Tertiary migration is movement of a previously formed oil and gas accumulation. Department of Petroleum Technology, University of Karachi

Mechanisms of Migration •

With regard to the mechanisms involved in migration there are seven main questions to answer.

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When did migration take place?

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What form were the hydrocarbons in when they migrated?

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What moved the hydrocarbons?

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If water was involved: where did the water come from?

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What caused the water to move?

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In which direction did the water move?

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Have much water moved?

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PRIMARY MIGRATION •

Primary oil migration within a finegrained mature source rock with > 2% total organic carbon (TOC) occurs initially as a bitumen that decomposes to oil and gas and migrates as a hydrocarbon (HC) phase or phases. •

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The process of HC generation causes expulsion of petroleum and is often a more potential mechanism for migration than mechanical compaction. Generation and expulsion of light oil, and gas can come from low (< 2%) TOC source rocks without a bitumen intermediate.

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Type III kerogens are the most likely source. Migration can also occur in aqueous solution for the smallest and most soluble molecules (methane, ethane, benzene, toluene). Migration by diffusion is not significant.

Department of Petroleum Technology, University of Karachi

PET 631 Migration • There are two types of migration when discussing the movement of petroleum, primary and secondary. • Primary migration refers to the movement of hydrocarbons from source rock into reservoir rock and it is this type that the following discussion refers to. • Secondary migration refers to the subsequent movement of hydrocarbons within reservoir rock; the oil and gas has left the source rock and has entered the reservoir rock. • Department of Petroleum Technology, University of Karachi

Primary Migration from shale source Rocks • A problem in close relation to the later stage of the project is the expulsion of hydrocarbons from source rock (primary migration). • The chemical aspects of this process has been extensively studied, but the physical aspects are poorly understood.

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Primary Migration

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

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Micro-pressuring. Mompers [1978] clearly outlines the characteristics of a source rock which are important in the development of micro-pathways with the rock. At some point the pressure increase causes micro-fracturing in the rock, and the hydrocarbons migrate into the micro-fractures which lead out of the source rock. This concept allows the hydrocarbons to migrate in a liquid phase. This is regarded as the main mechanism for primary migration out of the source rock. Department of Petroleum Technology, University of Karachi

GENERATION, MIGRATION, AND TRAPPING OF HYDROCARBONS

Seal

Fault (impermeable)

Oil/water contact (OWC) Seal Migration route Seal

Hydrocarbon accumulation in the reservoir rock

Reservoir rock

Top of maturity Source rock

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Migration through Fractures

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Mechanics of Secondary Hydrocarbon Migration • The mechanics of secondary hydrocarbon migration and entrapment are well-understood physical processes that can be dealt with quantitatively in hydrocarbon exploration. • The main driving force for secondary migration of hydrocarbons is buoyancy. • If the densities of the hydrocarbon phase and the water phase are known, then the magnitude of the buoyant force can be determined for any hydrocarbon column in the subsurface.

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Mechanics of Secondary Hydrocarbon Migration • Hydrocarbon and water densities vary significantly. • Subsurface oil densities range from 0.5 to 1.0 g/cc; subsurface water densities range from 1.0 to 1.2 g/cc. • When a hydrodynamic condition exists in the subsurface, the buoyant force of any hydrocarbon column will be different from that in the hydrostatic case. • This effect can be quantified if the potentiometric gradient and dip of the formation are known. • The main resistant force to secondary hydrocarbon migration is capillary pressure. Department of Petroleum Technology, University of Karachi

Mechanics of Secondary Hydrocarbon Migration • The factors determining the magnitude of the resistant force are the radius of the pore throats of the rock, hydrocarbon-water interfacial tension, and wettability. • For cylindrical pores, the resistant force can be quantified by the simple relation: , where Pd is the hydrocarbonwater displacement pressure or the resistant force, is interfacial tension, is the wettability term, and R is radius of the largest connected pore throats. • Radius of the largest connected pore throats can be measured indirectly by mercury capillary techniques using cores or drill cuttings.

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Mechanics of Secondary Hydrocarbon Migration • Subsurface hydrocarbon-water interfacial tensions range from 5 to 35 dynes/cm for oil-water systems and from 70 to 30 dynes/cm for gas-water systems. • Migrating hydrocarbon slugs are thought to encounter water-wet rocks. • The contact angle of hydrocarbon and water against the solid rock surface as measured through the water phase, , is thus assumed to be 0°, and the wettability term, , is assumed to be 1. • A thorough understanding of these principles can aid both qualitatively and quantitatively in the exploration and development of petroleum reserves. Department of Petroleum Technology, University of Karachi

Driving forces for migration: •

Secondary migration is the movement of hydrocarbons along a "carrier bed" from the source area to the trap.

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Migration mostly takes place as one or more separate hydrocarbons phases (gas or liquid depending on pressure and temperature conditions).

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There is also minor dissolution in waterof methane and short chain hydrocarbons.

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Buoyancy (This force acts vertically and is proportional to the density difference between water and the hydrocarbon so it is stronger for gas than heavier oil)

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Hydrodynamic flow (water potential deflect the direction of oil migration, the effect is usually minor except in over pressured zones (primary migration))

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Resisting forces: Capillary pressure (opposes movement of fluid from coarse-grain to fine- grain rock, also the capillary pressure of the water in the reservoir resists the movement of oil) One result of hydrodynamic flow is a tilted oil-water contact (OWC) in a trap. OWC is an equipotential surface, but if the water is flowing the equipotential surfaces are inclined in the direction of flow, so the OWC will be tilted too. During migration the pressure and temperature conditions of the hydrocarbons can change a lot affecting the phase behavior of the oil. •

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Rate of migration Rate of migration is controlled by

Darcy's law q= -k/v dp/dz • (for a single fluid phase) where q=volumetric flow rate, k=permeability, v=viscosity, dp/dz=pressure gradient. Given typical permeabilities of sandstone, and flow rate of oil can range from 1 to 1000 km per million years. This is faster than rate of generation and expulsion, so oil generation is the ratelimiting factor. Because the carrier bed has to reach a minimum oil saturation before oil can flow, there is a volumetric loss associated with migration. The oil will seek a tortuous path of least resistance which typically will be a small portion of the total carrier bed volume

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Retardatin of buoyant movement as an oil globule (X) is deformed to fit into a narrow pore throat (Y). The upward buoyant force is partly or completely opposed by the capillary-entry pressure, the force required to deform the oil globule enough to enter the pore throat. If the capillary-entry pressure exceeds the buoyant force, secondary migration will cease until either the capillary-entry pressure is reduced or the buoyant force is increased.

MECHANISM • Once hydrocarbons are expelled from the source rock in a separate hydrocarbon phase into a secondarymigration conduit, subsequent movement of the hydrocarbons will be driven by buoyancy. Hydrocarbons are almost all less dense than formation waters, and therefore are more buoyant. Hydrocarbons are thus capable of displacing water downward and moving upward themselves. The magnitude of the buoyant force is proportional both to the density difference between water and hydrocarbon phase and to the height of the oil stringer. Coalescence of globules of hydrocarbons after expulsion from the source rock therefore increases their ability to move upward through water-wet rocks

Two basic types of traps: Stratigraphic traps are depositional in nature. This means they are formed in place, usually by a sandstone ending up enclosed in shale. The shale keeps the oil and gas from escaping the trap.

Structural traps hold oil and gas because the earth has been bent and deformed in some way. The trap may be a simple dome (or big bump), just a "crease" in the rocks, or it may be a more complex fault trap like the one shown at the right.

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Migration of oil and gas into and out of an anticlinal trap.

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