:
1. Source rock
2. Reservoir rock
3. Burial History
4. Maturation
5. Migration
6. Cap rock
7. Trap
Oia sama nanya komponen reservoar migas tuh apa aja ya? Makasih bantuannya semua, doakan saya sukses di bidang ini 
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asuteles: Jadi kalau perkenalan itu gini ya…
Nama saya reichstag, saya kuliah di universitas xxxx, jurusan xxxx
Jenis kelamin, pria atau wanita,
Tujuan hidup jadi raja minyak….
Nah ntar semua yang disini bantunya kan enak, ngk setengah-setengah.
Source Rocks (Petroleum Generation and Maturation)
The Source Rock
Source rocks are any rocks in which sufficient organic matter to form petroleum has been accumulated, preserved, and thermally matured. Organic particles are usually fine-grained, and will settle out most easily in quiet-water environments. Therefore, source rocks are most commonly fine-grained rocks, particularly shales. Other potential sources are fine-grained carbonates (lime mud), mud-carbonate mixtures (marl), or coal ( Figure 1 ).
Figure 1
One of the most important factors in determining whether an organic-rich rock will become a source rock is its thermal maturity. However, some potential source rocks have never reached this thermal level. An example is oil shales like the Green River Shale of the U.S. Rocky Mountain region, where instant maturation can be artificially induced by heating the rocks to temperatures of about 500 ºC, a process called pyrolysis.
Tar sands, like the Athabasca tar sands of western Canada, have sometimes been regarded as immature source rocks. However, the majority opinion is that they were once conventional oil reservoirs, in which the oil became degraded from flushing by fresh meteoric waters and by bacterial action, these processes having converted lighter oil into a viscous asphaltic tar.
Preservation of organic matter is usually harder to achieve than its production. On land, with the exception of some lakes and coal swamps, most organic accumulations are rapidly destroyed through oxidation and biological activity. More commonly organic matter is preserved in marine environments.
Rapid deposition is one way to avoid the destruction of organic matter and is characteristic of source rocks in thick, prograding sediment wedges, such as deltas. Rapid deposition, however, leads to dilution of the organic matter by sediment. Some shale source rocks found in rapidly prograding deltas have organic contents of only 1%. Shale usually requires a higher organic content than this to be an adequate source rock. However, deltas often have excellent source/reservoir rock geometries, and structures are developed early in response to the sediment load. In such cases, migration and accumulation of petroleum is probably more efficient than usual, and even organic-poor shales make adequate source rocks.
In most cases, however, marine shales with organic contents high enough to be petroleum source rocks are slowly deposited, under oxygen-free conditions that prevent organic destruction. This occurs most commonly in restricted marine environments, where a basin is silled or otherwise prevented from easy communication with the open ocean.
The Elements of the Exploration Task
Our first objective in exploration is to identify the five conditions that are necessary for hydrocarbon accumulations to occur:
the presence of a source rock
the presence of a reservoir rock
the presence of a migration path
the presence of a trap
the presence of a seal
All of these conditions must be met in order for oil or gas to be present ( Figure l ).
Figure 1.
Source Rock
The source rock is likely to be a thick shale or limestone, containing organic material. We hope that this rock and its organic content were deposited under airless conditions (favorable for the preservation of the organic material), that it became rapidly buried, and that it “cooked” at a favorable temperature for a sufficient time. The nature of the petroleum generated depends on the temperature history and on the origin of the organic material — woody-plant detritus and/or very high temperatures tend to yield gas, while marine detritus and/or moderate temperatures tend to yield oil.
Thus in the context of the source rock, our exploration task is to reveal the following parameters:
Rock type
Rock volume
Conditions of deposition
Temperature and burial history
Original organic content
Geophysical methods can make some contribution to all these factors except for original organic content.
Reservoir Rock
The reservoir rock is likely to be a porous sandstone or carbonate. In the best case, this rock will be very extensive, very porous and very permeable. The original porosity depends on grain character and depositional conditions; this porosity may be destroyed by cementation, or enhanced by solution or chemical change. The original permeability depends on the throat size between grains; this permeability may be destroyed by cementation, or enhanced by natural fracturing. Further, we know that (particularly in sandstones) permeability is seldom uniform; it tends to be largest in the direction of the water flow from which the rock grains were deposited.
In the context of the reservoir rock, our exploration task is to reveal:
Rock type
Thickness, extent and volume
Conditions of deposition and shape
Present permeability
Geophysical methods can make some contribution to all these factors except for present permeability. Occasionally, geophysical methods can also give some indication of the saturant, particularly if it is gas.
Migration Path
A migration path is necessary in order for the petroleum to move from the source rock to the reservoir rock. This may be a permeable rock (such as the silty rock of Figure 1), or a permeable zone of fracture. Although geophysical methods allow no measure of permeability, they can sometimes indicate the likelihood of such permeable paths. But complicating the problem is the fact that the path may have been permeable at some time in the past; it is not necessarily permeable now.
Trap
Figure 1 above shows a classical anticlinal trap, while Figure 2 shows this trap filled to the spill point.
Figure 2.
In structural traps such as this, the reservoir rock itself may be widespread, and the search is for vertical closure; this may be supplied by four-way dip (a dome) or by a combination of dip and faulting ( Figure 3 ).
Figure 3.
In stratigraphic traps, on the other hand, the reservoir is limited by a change in rock type or sedimentary features, and the search is for indications of these limits. Examples are the uncomformity trap ( Figure 4 ),
Figure 4.
the reef ( Figure 5 ),
Figure 5.
the sand-filled channel ( Figure 6 ),
Figure 6.
and the sand bar ( Figure 7 ).
Figure 7.
An extensive suite of traps is shown in Figure 8 ,
Figure 8.
Figure 9.
Figure 10.
Figure 11 , and Figure 12.
Figure 11.
Figure 12.
In the context of traps, therefore, the task of our geophysical methods is to reveal:
the dip of the reservoir rock;
the presence of trapping faults; and/or
a three-dimensional picture of the reservoir body; by which its shape, and so its probable stratigraphic origin, can be determined.
The great successes of geophysical methods in the past have been in the search for structural traps. To a smaller extent, and with much less certainty, geophysics is now contributing to the search for stratigraphic traps.
Seal
As suggested in Figure 1 above , the seal may be an impermeable cap-rock (such as a thick layer of salt, or an unfractured shale, or a dense and unfractured limestone). Alternatively, the seal may be a fault, in which sealing minerals have been precipitated from compaction water escaping up the fault. In stratigraphic traps it may be a lateral transition — a facies change — from a permeable reservoir rock to an impermeable sealing rock ( Figure 7).
In the context of seals, therefore, the task of our geophysical methods is to reveal:
In structural traps
the nature of the rock above the trap:
the risk of fracturing in that rock
the risk that such a system of fractures vents, directly or indirectly, to the surface
In fault traps:
the likelihood that the fault is chemically sealed
the risk that the fault vents, directly or indirectly, to the surface
In stratigraphic traps, in addition to the above.
the likelihood that any critical unconformity is sealed
the likelihood that lateral facies changes represent a seal
We shall find that geophysical methods can make some contribution to all of these factors, but never with the certainty we would wish.
Let us suppose that we do find a situation having the necessary features: source; reservoir; migration path; trap and seal. There is another matter, the geological history, which we should explore before we drill. For example, let us look again at the rock layers of Figure 1 . First, we notice their parallelism; this is telling us that at one time (after the start of deposition of the cap rock) the layers were flat and horizontal ( Figure 13 ).
Figure 13.
Second, we notice that the present structure suggests both folding and tilting (or regional dip); now we ask which came first — the folding or the tilting? For if the tilting came first ( Figure 14 ) and was followed by migration of all the oil and gas before the folding, then the trap of Figure 1 is of no interest to us; it is barren.
Figure 14.
We shall find that geophysical methods sometimes do allow this reconstruction of the geological history. In favorable cases, we are able to establish the configuration of the earth’s surface, and of buried layers, in times past; we can also establish the time at which particular movements occurred.
We have identified, then, the elements of our task. We must find geological situations which combine a source, a reservoir, a migration path between them, a trap, and a seal. And we must reconstruct, as far as possible, the geological history which gave rise to each such situation.
Finally, we should note that it is only in an undeveloped area that the exploration problem is really as harsh as suggested above. Often we have some wells, so that the problem is mainly one of correlating a new prospect area to those wells; this may require no more than tracing the continuity of known rocks into the prospect area — which geophysics can usually do very well. Again, we may already have a producing field, whose geophysical response is known; then the problem is merely to find a geophysical analog of that field. This makes us feel more comfortable; at least we shall succeed some of the time.
Cap Rocks
Cap rocks (or seals) prevent hydrocarbon migration and escape from reservoir rocks in a petroleum trap. These rocks are primarily sedimentary and have little or no permeability, such as:
· pure clay, shale or unfractured slate;
· nonporous carbonates;
· evaporites, especially rock salt;
· nonporous, unfractured igneous or metamorphic rocks.
Clay is often the result of deposits made in the last stage of a clastic depositional fining-upward sequence that occurs during minimal movement of the transport medium. In marine environments, clays are often the primary deposit during transgressive or highstand phases. Nonporous carbonates can be found in deep-water marine sequences. Diagenetically altered carbonates are also potential cap rocks. Rock salt may be the only rock-forming evaporite, or it may be the last product during a complete evaporation cycle.
Traps
Hydrocarbon traps occur when rocks have physical properties that prevent hydrocarbon migration. The structure of the trapping area or layer is often distinctive. Its enclosure may become partly or completely filled with fluid or gas. The overlying cap rock shields this oil and gas from effects that may destroy or disperse it.
Structural traps are found in beds that have been deformed to create this critical reservoir and cap rock geometry. In stratigraphic traps, the reservoir and seal layers are not necessarily deformed. If the layers are deformed, they are called combined or stratigraphic structural traps.
· Structural traps also result from differential motion of the reservoir or cap rocks (such as differential compaction of sand-shale sections), from dissolution of carbonates or evaporites, or from the collapse of volcanic edifices.
Trap formation and trap definition offer a clear example of what we might call applied plate tectonics. The deformation style and timing observed in a given basinal area is related to a larger deformation event. For example, foreland deformation in the Ecuadorian portion of the sub-Andean trend is caused by regional uplift and local shear faults. Both of these phenomena are connected with events in the Ecuadorian Andean Mountains and the eastern Pacific. Knowledge of one process may help in understanding the other.
General deformation styles are typical of certain plate tectonic features. Rift tectonics are mainly tensional, and involve deep-seated listric (flattening with depth) faults, rotated fault blocks, cross or transfer faults, and shears, or shear-related secondary transpressive or transtensional features. A compressional or thrust belt contains features such as thrust-related anticlines, fault traps and subthrust fault traps.
A large number of publications and reports have addressed plate tectonic-related trap formation. An excellent introduction to the subject is given by Lowell (1985). Other descriptions can be found in AAPG memoirs and bulletins. These descriptions primarily discuss specific, regional phenomena, and may be helpful in understanding a local problem by comparing it with other reported cases.
Principal Subdivisions of Petroleum
Hydrocarbon and nonhydrocarbon fractions can be subdivided into four chemically distinct groups based on molecule types present ( Figure 1 ,
Figure 1.
General classification system used for petroleum); the four major subdivisions are (1) saturated hydrocarbon molecules called alkanes, (2) unsaturated hydrocarbon molecules called arenes, (3) small nonhydrocarbon molecules called resins, and (4) large nonhydrocarbon molecules called asphaltenes.
Because arenes (ar for aromatics - fragrant - and enes for unsaturated) in petroleum consist entirely of aromatic-series compounds, the series term aromatics is generally substituted for the group term arenes in geochemical data dealing with petroleum. This discussion follows that convention and for the four petroleum groups uses the terms
· alkanes
· aromatics
· resins
· asphaltenes
Where necessary, as when identifying biomarkers or specific biological precursors to petroleum, we do define and incorporate nonpetroleum subdivisions. These include other unsaturated hydrocarbons (e.g., olefins; see Figure 2 ,
Figure 2.
Hydrocarbon compound groups too unstable to survive under subsurface geologic conditions but generally found in organic matter and refinery products), and specific categories of nonhydrocarbons (e.g., acids and alcohols) from broader organic chemistry classification systems.
Alkanes (al (k) for aliphatic-fatty-and ane for saturated), as defined in our Fundamentals of Petroleum Series, are those hydrocarbons that are fully saturated with hydrogen ( Figure 3 ,
Figure 3.
Figure 4 .
Figure 5 ,
Figure 5.
Figure 6 , Figure 7 ).
Figure 6.
No double bonds are present between carbon atoms.
Figure 7.
Any further addition of hydrogen, consequently, must occupy a preexisting carbon-carbon bond position. Such a bond exchange either breaks a hydrocarbon molecule into smaller saturated molecules or breaks a saturated ring (cyclic) structure into a saturated open (acyclic) structure.
Aromatics, as we have noted, are the unsaturated molecules generally present in petroleum. Aromatic hydrocarbon compounds consist of molecules that contain an unsaturated benzene ring ( Figure 8 and Figure 9 ).
Figure 8.
If hydrogen is added to an aromatic, or any unsaturated molecule, it can be taken into the structure at a double bond without breaking the molecule’s carbon chain or opening up a carbon ring structure.
Figure 9.
In so doing, however, the addition of hydrogen can create a saturated molecule out of an unsaturated one.
Resins are smaller heterocompounds present in the gross non-hydrocarbon fraction ( Figure 1 ) that remain in liquid form (can be extracted) in the presence of hydrocarbon solvents such as methane and pentane.
Asphaltenes are larger heterocompounds which, because of their relatively large molecular sizes, generally will precipitate in the presence of hydrocarbon solvents such as methane and pentane. (Note: Asphaltene precipitates can trap molecules of other groups within their large condensed structures. However, it is standard convention to apply the term asphaltenes to all precipitated materials because they responds like asphaltenes to chemical treatment and analysis.)
The hydrocarbon fraction forms the bulk of most petroleum accumulations. Within this fraction, alkane and aromatic components range widely in relative concentration. As an average, however, alkane hydrocarbons generally exceed aromatic hydrocarbons in most medium and light °API gravity oils and alkane-aromatic ratios can exceed 4:1. Ratios of resins to asphaltenes also range widely, but resins generally exceed asphaltenes in commercial petroleum accumulations. This variation in group distribution is primarily influenced by
· the nature of organic matter that has been the source of petroleum (e.g., a source rich in leaf waxes yields hydrocarbons rich in alkanes (paraffins);
· the extent to which the organic matter-to-petroleum system has matured (e.g., as bitumen and crude oil mature, the relative content of saturates, particularly paraffins, generally increases) ;
· the effects of migration on petroleum (e.g., as migration occurs, nonhydrocarbons are preferentially left behind);
· the effects of biodegradation and water washing on petroleum (e.g., bacteria attack different hydrocarbons preferentially, water washing removes soluble and light hydrocarbons preferentially; both combine to increase relative content of nonhydrocarbons).
Regards
DAT
