As a sedimentary basin matures, the processes
Kerogen maturation products
CO2, H2O Oil
Wet gas Dry gas
Type I 1.5 Type II
No hydrocarbon potential
Increasing maturation
that affect hydrocarbon generation, migration and accumulation result in complex fluid composi- tions. Understanding the complexity of hydro- carbon distributions in a reservoir begins at the source rock. Of the estimated 6 × 1015 tons of organic matter found in the Earth’s crust, 95% is in the form of kerogen.6
It is from this building block
that most hydrocarbons are generated. Kerogen consists of plant remains, such as
algae, spores, higher plant debris, pollen, resins and waxes.7
Thermal maturation of kerogen 1.0 Type III Type IV 0.5 0 0.1 0.2 Oxygen/carbon ratio
> Kerogen conversion to hydrocarbons. The Van Krevelen diagram classifies kerogen types by crossplotting ratios of oxygen and hydrogen to carbon. During the maturation process, kerogen is thermogenically converted to hydrocarbons. The evolutionary paths of increasing maturity (green arrows) indicate the type of hydrocarbons generated from each kerogen source type. Additional early-stage by-products of the conversion process are water and CO2.
is the biggest problem facing deepwater operators in terms of strategic reservoir development.4 This article reviews the creation and migra-
tion of reservoir fluids, including reservoir charg- ing, and the resulting effects on fluid properties. Compositional grading—the smooth and contin- uous variation of fluid properties with depth—is discussed, along with methods to detect reservoir compartmentalization. Also described are recent developments using asphaltene equilibrium dis- tribution as an indicator of reservoir connectiv- ity.5
Case studies from the deepwater Gulf of
Mexico, the North Sea and offshore Africa dem- onstrate the application of new sampling meth- ods and technologies.
Fluid Complexity Outside the oil and gas industry there are signifi- cant misconceptions about the habitat of hydro- carbons in nature. Perhaps such works as Jules Verne’s Journey to the Center of the Earth, or
40
Oilfield Review Autumn 09 FluidsLab Fig. 1
ORWIN09/10-FluidsLab Fig. 1
similar portrayals, have given the general public the impression that oil lies in vast lakes below the Earth’s surface, awaiting the adventurous oil company’s drill bit to pop in and drain the oil, like sucking soda through a straw. The petroleum technologist harbors no such illusion, under- standing that hydrocarbons trapped within the pore spaces of reservoir rocks must be coaxed from their hiding places through exacting effort and time-tested methodologies. Even among professionals, however, there is
often a simplistic view of the oil or gas in a reser- voir. Although it is recognized that oil is not found in a subsurface lake, many in the industry con- sider a reservoir as something akin to a large porous container filled with homogeneous fluids. Reservoir architectural heterogeneity and fluid compositional complexity not only exist in nature but are the rule rather than the exception. This is especially true in deep reservoir structures where time and natural forces create ideal conditions for such heterogeneity.
0.3
expels fluids, such as oil and gas, and leaves behind a solid, mature form of kerogen (left). Type I kerogens are rather uncommon. They are oil prone and are made up of mainly algal and bacterial remains. The kerogen in the lacustrine Green River Shale, found in the central USA, is an example of this group. Comprising a mixture of terrigenous and marine sources, Type II kerogens may be prone to oil or gas depending on the tem- perature and proportions of constituents. Gas- prone Type III kerogens are composed of woody terrigenous source material. Many North American and European coals contain Type III kerogen. The hydrocarbon gas from this kerogen type is dominated by methane but may also con- tain ethane, propane, butane and pentane. Type IV kerogen, dead carbon, has almost no potential for hydrocarbon generation and commonly consists of recycled organic matter that has undergone previ- ous burial and maturation.8 As kerogen-rich source rock is buried and
compacted, increased temperature and pressure convert the organic material into petroleum through catagenesis. Migration of the fluids into permeable rocks is controlled by three primary parameters: capillary pressure, buoyancy and hydrodynamics.9
As fluids charge into the reser-
voir, they may be significantly out of equilibrium (next page, top right).10
For example, if the fluids
enter a reservoir via a high-mobility path such as a fault, then poor fluid mixing takes place. Over geologic time, through molecular diffusion and gravity segregation, fluid equilibrium of the hydrocarbons can be established. Light gases will rise to the highest level in the reservoir, water generally fills the lowest level, and hydrocarbons of various densities are distributed in between. With rare exceptions, kerogen Types I and II
are required for generation of liquid hydrocar- bons. In the initial stages of conversion at low heat, heavy oils are created and can be preserved as asphalt or tar deposits. Increased temperature leads to generation of lighter oils, often cracked from early-stage heavy oils. There is, however, a
Oilfield Review
Hydrogen/carbon ratio
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