Hydrocarbon Habitat in Growth Fault Regime

The following text is focused on the role of growth faults in trapping hydrocarbons. Various kinds of traps involving growth faults have been discussed along with a brief case study of Niger Delta and a detailed study and interpretation of a block in Mumbai offshore‐Shelf Margin.

Hydrocarbon Habitat in Growth Fault Regime With case study on Mumbai Offshore and Niger Delta Vaibhav Singhal

Hydrocarbon Habitat in Growth Fault Regime Under Mr. S.N. Mohanty

Vaibhav Singhal Summer Trainee, EEPIL 3rd Year, Int. M.Sc. Applied Geology IIT Kharagpur

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Acknowkowledgement

I take this opportunity to express my gratitude towards my mentor Mr. S.N. Mohanty, Vice President, EOL‐E&P, Mumbai for his consistent guidance and support.

I am grateful to Ms. Urmi Surve and all the members of ESSAR Mumbai for their constant motivation to work positively and for extending a helping hand whenever in need.

Special thanks to Mr. Saurabh Goyal, Dy. Manager‐EOL, for his kind support, guidance and encouragement throughout the project work I would also like to thank all those who are knowingly or unknowingly involved in completion of my project.

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Table of Contents

1. Hydrocarbon Formation And Accumulation 1.1. Formation…………………………………………………………………………………………………………………..

1.2. Accumulation……………………………………………………………………………………………………………..

1.3. Migration………………………..………………………………………………………………………………………….

1.4. Entrapment……………………………..………………………………………………………………………………….

2. Petroleum System 2.1. Introduction……………………….…………………………………………………………………………………

2.2. Reservoir……………………………………………………………………………………………………………..

2.3. Seal……………………………………………………………………………………………………………………..

2.4. Traps……………………………………………………………………………………………………………………

2.4.1. Stratigraphic Traps……………………………………………………………………………………

2.4.2. Structural Traps………………………………………………………………………………………..

2.5. Trap Evaluation……………………………………………………………………………………………………

3. Growth Faults 3.1. Introduction…………………………………………………………………………………………………………

3.2. Formation And Structure……………………………………………………………………………………..

3.3. Geological Settings For Growth Faults….………………………………………………………………

3.4. Importance Of Growth Faults…………….…………………………………………………………………

3.5. Limitations…………………………………………………………………………………………………………..

4. Interpretation 4.1. Data Loading……………………………………………………………………………………………………….

4.2. The Process…………………………………………………………………………………………………………

4.2.1. Data Loading ……………………………..………………………………………………………….

4.2.2. Fault Picking…………………………….….…………………………………………………………

4.2.3. Horizon Picking………………………………………………………………………………………

4.2.4. Fault Polygon………………………….…….……………………………………………………….

4.2.5. Contouring……………………………………….……………………………………………………

4.3. Interpretation of Growth Faults…………………………………………………………………………..

4.4. Geometry of Growth Faults…………………………………………………………………………………

5. Mumbai Offshore 5.1. Introduction…………………………………………………………………………………………………………

5.2. Tectonic Setup………………………….…………………………………………………………………………

5.3. Stratigraphy………………………………………………………………………………………………………..

5.4. Petroleum System………………………………………………………………………………………………

5.5. Data Interpretation……………….……………………………………………………………………………

5.5.1. Seismic Data Interpretation…………………………………………………………………

5.5.2. Horizons and Faults ……………………………………………………………………………

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5.5.3. Time Structure Maps…………………….……………………………………………………

5.5.4. Isochronopach Map………………………………………………………

5.6. Prospect Analysis………………………………………………………………………………………..

6. Nigeria Delta 6.1. Introduction…………………………..……………………………………………………………………

6.2. Geology……………..………………………………….……………………………………………………

6.2.1. Tectonics…………..………………………………………

6.2.2. Stratigraphy………………………………………………

6.3. Petroleum System……………………………………………………………………………………

6.3.1. Location……..………………………………………………

6.3.2. Reservoir……………………………………………………

6.3.3. Entrapment….……………………………………………

6.3.4. Cap Rock……………………………………………………

6.4. Conclusion…………………………….………………………………………………………………

7. Conclusion

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INTRODUCTION

There has been a lot of study on growth faults w.r.t. subsurface exploration of hydrocarbons. The main reason for special recognition of growth faults in this field is their excellent hydrocarbon trapping capabilities. A schematic diagram of a growth fault has been shown in figure 1.

Fig. 1: Diagram of a common Growth Fault

Growth Faults are mostly Listric Normal faults generally found in extensional sedimentary regime.

Their dip decreases with depth and fault ends in the decollment zone. The thickness of the hanging wall (which is the down thrown block) is increased resulting in thickening of both reservoir and cap making conditions more favorable for industries.

Ample numbers of Growth faults have been found in both Niger Delta and Mumbai Offshore (discussed in a case study of this report later). The traps involving growth faults are structural traps of both Fault dominated (Fault block) and fold dominated (Rollover anticline).

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CHAPTER 1:

HYDROCARBON FORMATION AND ACCUMULATION

1.1 FORMATION

Oil is formed from diatoms, extremely small sized marine organisms. Diatoms float in the top few meters of the oceans and also happen to be a major source of food for many forms of ocean swimmers. Their skeletons are chemically very similar to sand and are also made of the silica. Diatoms produce a kind of oil by themselves to store chemical energy from photosynthesis and to increase their ability to float. But this small amount of oil still needs to become concentrated and mature before it can be taken from the ground and used as fuel.

Almost all oil comes from rocks that were formed underwater, floating ocean life (tiny creatures known as diatoms, foraminifera, and radiolarian) that settle to the bottom of the sea eventually turns into oil. It takes many millions of years to form thick deposits of organic‐rich sludge at the bottom of the ocean. This sludge afterwards undergoes Sediment Maturation. Given many thousands of years, a stack of mud and organic remains, many kilometers thick may pile up on the sea floor, especially in nutrient‐rich waters. Given enough time, the overlying sediments that are constantly being deposited will bury these organic remains and mud deeply so that they eventually are turned into solid rock. High heat and intense pressure help along various chemical reactions, transforming the soft parts of ancient organisms found in the deep‐sea sludge into oil and natural gas. This ooze at the bottom of the ocean turns into Source Rock.

1.2 ACCUMULATION

Reservoirs are the rock in which the oil is actually stored. An effective Reservoir must be of high porosity and permeability and must allow active exchange of fluids so that existing water in the trap is exchanged with hydrocarbons. It is a place that oil migrates to and is held underground.

Sandstone has plenty of room inside itself to trap oil and acts just like a sponge. It is for this reason

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that sandstones are the most common reservoir rocks. Limestone and dolostones, some of which are the skeletal remains of ancient coral reefs, are other examples of reservoir rocks.

Figure: 1 Reservoir grade rock

1.3 MIGRATION

It’s the process when oil migrates from source rock to reservoir rock, where it displaces water that was originally present in the formation. If hydrocarbons hit a trap they get stored there otherwise continue travelling upwards via different mechanisms e.g. Emulsification with water etc.

Migration is mainly of two types: Primary Migration involves release of petroleum compounds from solid organic particles (Kerogen) in source beds and their transport within and through the capillaries and narrow pores of fine grained source bed.

Secondary migration, on the other hand, involves expulsion of the oil from source rock into the reservoir, which has rocks with lager pore spaces and permeability through which it is passed to traps

1.4 ENTRAPMENT

Hydrocarbons once formed, being lighter than surroundings have a strong tendency to rise above until they reach the surface of the earth, after which they are lost in the environment. This is what happens at oil seeps (once common in Pennsylvania, California, Texas and Louisiana).

Therefore, it is mandatory for exploration purposes that the hydrocarbon reserve is contained in some way in the subsurface so that it can be explored and exploited. The geological structures that act as barriers are called Traps. Traps are geological settings that with the help of low porosity and permeable rocks trap the hydrocarbons. Shale, limestone (with low permeability), etc. act as good seal.

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In Figure 2 the yellow particles are clay particles and pink areas are pore spaces. As we can notice very clearly that clay particles are packed very tightly. Therefore, due to lack of pore spaces the movement of oil through these rocks becomes extremely difficult.

PORE SPACE

SAND GRAINS

Figure: 2 Seal

Peculiar case of limestone: Limestone can act as either a seal or a source rock depending upon the pressure temperature conditions it has faced. The limestone which has undergone higher pressures is likely to have a low permeability and is likely to end up as a Trap whereas the one that has seen fewer pressures might act as a reservoir.

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Chapter 2:

PETROLEUM SYSTEM

2.1 INTRODUCTION

Traps are the features that prevent oil from escaping from earth’s surface. To be a viable trap, a subsurface feature must be capable of receiving hydrocarbons and storing them for some significant length of time. This requires two fundamental components: a reservoir in which to store the hydrocarbons, and a seal (or set of seals) to keep the hydrocarbons from migrating out of the trap. The presence of hydrocarbons is not a critical component of a trap, although this IS a requirement for economic success. The absence of hydrocarbons may be the result of failure of other play or prospect parameters, such as the lack of an active source rock or migration conduits, and it may have nothing to do with the ability of an individual feature to act as a trap.

2.2 RESERVOIR

The reservoir within a trap provides the storage space for the hydrocarbons. This requires adequate porosity within the reservoir interval. The reservoir must also be capable of transmitting and exchanging fluids. This requires sufficient effective permeability within the reservoir interval and also along the migration conduit that connects the reservoir with a source rock. Because most traps are initially water filled, the reservoir rock must be capable of exchanging fluids as the original formation water has to be displaced by hydrocarbons. Trap with only one homogeneous reservoir rock are rare. Individual reservoirs commonly include lateral and/or vertical variations in porosity and permeability. Such variations may be caused either by primary depositional processes or by secondary diagenetic or deformational effects and can lead to hydrocarbon saturated but nonproductive waste zones within a trap. Variations in porosity and permeability can also create transitions that occur over some distance between the reservoirs and the major seals of a trap.

These intervals may contain a significant amount of hydrocarbons that are difficult to produce effectively. Such intervals are regarded as uneconomic parts of the reservoir and not part of the seal, or otherwise, trap spill points may be mis‐identified. Many traps contain several discrete reservoir rocks with interbedded impermeable units that form internal seals and segment hydrocarbon accumulations into separate compartments with separate gas‐oil‐water contacts and different pressure distributions.

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Figure 1

2.3 SEAL

The seal is the most critical component of a trap. Without effective seals, hydrocarbons will migrate out of the reservoir rock with time and the trap will lack viability. Effective seals for hydrocarbon accumulations are formed by relatively thick, laterally continuous, ductile rocks with high capillary entry pressures, but other types of seals may be important parts of individual traps (e.g., fault zone material, volcanic rock, asphalt, and permafrost). All traps require some form of top seal. When the base of the top seal is convex upward in three dimensions, no other seal is necessary to form an adequate trap. Many traps are more complicated and require other effective seals. These are called the poly‐seal traps. Lateral seals impede hydrocarbon movement from the sides of a trap and are a common element of successful stratigraphic traps. Fades changes from porous and permeable rocks to rocks with higher capillary entry pressures can form lateral seals, as can lateral diagenetic changes from reservoir to tight rocks. Other lateral seals are created by the juxtaposition of dissimilar rock types across erosional or depositional boundaries. Stratigraphic variability in lateral seals poses a risk of leakage and trap limitation. In thinly interbedded intervals of porous and permeable rock in a potential lateral seal can destroy an otherwise viable trap. Base seals are present in many traps and are most commonly stratigraphic in nature. The presence or absence of an adequate base seal is not a general trap requirement, but it can play an important role in deciding how a field will be developed. Faults can be important in providing seals for a trap, and fault leak is a common trap limitation. Faults can create or modify seals by juxtaposing dissimilar rock types across the fault (Figure 1), by smearing or dragging less permeable material into the fault zone, by forming a less permeable gouge because of differential sorting and/or cataclasis, or by preferential diagenesis along the fault. Fault‐induced leakage may result from juxtaposition of porous and permeable rocks across the fault or by formation of a fracture network along the fault itself.

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2.4 TRAPS

Traps as discussed above are mainly of three types:   

Stratigraphic Traps Structural Traps Combination Traps

These traps and there types are briefly discussed below.

2.4.1 STRATIGRAPHIC TRAPS

Stratigraphic traps are those in which the requisite and reservoir seal(s) combination were formed by any variation in the stratigraphy that is independent of structural deformation, except for regional tilting They are mainly of 2 types:  Primary Stratigraphic Traps  Secondary Stratigraphic Traps

2.4.1.1 PRIMARY STRATIGRAPHIC TRAPS

They are formed by syn depositional processes by changes in contemporaneous deformation.

Theses traps are generally characterized by lateral depositional change e.g. depositional pinchouts and facies change.

2.4.1.2 SECONDARY STRATIGRAPHIC TRAPS

They are formed by post depositional pressure on the underlying strata due to deposition of sediments.

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Figure 2: A primary stratigraphic trap

Figure 3: Secondary Stratigraphic trap: Trap formed by post depositional differential pressures on the strata

2.4.2 STRUCTURAL TRAPS

Structural traps are created by the syn‐ to post depositional deformation of strata into a geometry (a structure) that permits the accumulation of hydrocarbons in the subsurface. The Hydrocarbon Habitat in Growth Fault Regime

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resulting structures involving the reservoir, and usually the seal intervals, are dominated by either folds, faults, piercements, or any combination. The most important types of structural traps are:  Fold Dominated  Fault Dominated  Piercement  Combination of Fault‐Fold  Subunconformity

Fold Dominated Structural traps are those in which are dominated by folds at reservoir seal level.

Fault dominated traps are those which are dominated by faults at reservoir seal level

Piercement traps are formed by introduction of salt body (or batholiths or dykes) in the sedimentary strata resulting in formation of traps

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Combination traps are formed when both fault and folding have important role in formation seal. Most successful structural traps are combination of both fold and fault

Subunconformity Traps are formed when the unconformity surface acts as top seal of the trap

2.5 TRAP EVALUATION

Trap evaluation is concentrated on placing potential traps in the context of the operating petroleum system. Plate tectonic setting, basin type, and structural evolution (sedimentary basin study) is used to predict the possible styles of structural and stratigraphic traps that should be expected in an area. Regional seals and their relation to potential traps are established early in the evaluation. Timing of trap formation and its relation to the timing of generation, migration, and accumulation of hydrocarbon is the key of trap evaluation. Traps that form after hydrocarbon migration has ceased are not attractive targets unless remigration out of earlier formed traps has occurred. Trap is then mapped. Ideally, this would be the sealing surface of the trap. Identification of the actual sealing surface requires that both seal and reservoir characterization. A common flaw in trap evaluation results from ignoring the transition (or waste) zone, if present, between an economic reservoir and its ultimate seal. Before drilling, reservoir and seal characteristics can be predicted by combining regional and local paleogeographic information, sequence stratigraphic concepts, and detailed analyses of seismic fades and interval velocities. A detailed log analysis and incorporation of pertinent drill‐stem test data is done for improved predictions. The absence of oil or gas in a subsurface feature can be the result of failure or absence of other essential elements or processes of a petroleum system and may have nothing to do with the viability of the trap.

Therefore, although we use the geometric arrangement of key elements to define a trap, trap Hydrocarbon Habitat in Growth Fault Regime

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evaluation must include much more than just mapping the configuration of those elements.

Reservoir and seal characteristics and their evaluation must be an integral part of any trap study.

Timing of trap formation is also critical. No trap should be viewed out of context but rather should be evaluated in concert with all of the other elements of a petroleum system. Traps can be classified as structural, stratigraphic, or combination traps. In addition, hydrodynamic flow can modify traps and perhaps lead to hydrocarbon accumulations where no conventional traps exist.

The trap classification discussed here is a useful way to consider traps during the early stages of prospect evaluation. An understanding of end‐member trap types can help guide data acquisition strategy and mapping efforts, but there is an almost bewildering array of documented and potential hydrocarbon traps, many of which may be subtle or unconventional. As more and more of the world's hydrocarbon provinces reach mature stages of exploration, such traps may provide some of the best opportunities for future discoveries.

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Chapter 3:

GROWTH FAULTS

3.1 INTRODUCTION

Growth Faults are the type of faults in which there were displacements at the same time as the sediments, on either side of the fault, were accumulating. Main distinguishing feature of a growth fault is the greater thickness of horizons, which is distinctly visible, in the downthrown block as compared to upthrown block. Other important feature of growth fault is the formation of rollover anticline (not always seen) on the hanging wall of the fault system. In absence of a rollover anticline, a tabular dip section is seen having contrasting horizon thickness in upthrown and downthrown blocks.

They are important class of syn sedimentary fault which have been widely recognized in the subsurface studies of hydrocarbon‐bearing clastic basin successions. They are Listric Normal faults that affect only a discrete sedimentary interval in which they were active.

3.2 FORMATION AND STRUCTURE

Growth Faults are not directly related to basement tectonics rather are triggered by gravity sliding within the sedimentary pile. Whilst active, faults cause the thickness of the successions in downthrown block to increase. The faults mostly dip towards basin. This is attributed to the fact that the rate of deposition increases as we go towards basin. Therefore, the increased load towards the basin side will have a tendency of going down so, more sediment is deposited there and therefore we get thickened horizons in basinward direction. Following factors may increase the rate of the formation of growth faults 1. Ductility of underlying sediments 2. Overburden of new sediments

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Fig. 3.1 A Growth Fault, listric and normal in nature and having thicker horizons on the downthrown block(right hand side) and relatively thinner horizons in the footwall wall

A ductile sediment succession flows easily and thus faulting occurs more easily, on other hand, hard, consolidated sediments require much more pressure for faulting.

Figure 3.1 shows a typical growth fault. As we can see the fault is listric normal fault. Two horizons are marked in the figure showing the increase in throw as we go deep.

The throw of growth fault increases as we go deep since the pre deposited successions undergo faulting for a greater period of time as compared to the newly accumulated ones.

Sometimes formation on an anticline is observed on the hanging wall of the fault as shown in figure 3.2. This roll over anticline also is caused due to gravity sliding of loose sediments in lower parts of the fault

The formation of growth fault leads to compaction of shale present in the footwall due to the overburden of the sediments in hanging wall side. Also, if there is salt dome intrusion below the fault there is arching in the layers (concave downwards) due the uprising body. This arching breaks when the salt body exceeds (or rises above) the layer

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3.3 GEOLOGICAL SETTINGS FOR GROWTH FAULTS

Since growth faults are generally restricted to more recent sedimentary successions rather than basement they are more common in extensional sedimentary basins, preferably where the sediments were loosely packed enabling there decollment or sliding at later stages e.g. in deltaic environments where frequently, load of new sediments is laid over loose older sediments( Niger Delta)

3.4 IMPORTANCE OF GROWTH FAULTS

Growth Faults are given special recognition in study of subsurface exploration of hydrocarbons because of unique kinds of conditions they form in trapping hydrocarbons.

The successions in hanging wall get thicker across a growth fault. Therefore, it is more likely that we will get larger reserves on the hanging wall rather than on footwall. This thickening is important as it restricts more and more oil on one side of the fault making the extraction much more economical. Apart from this, numerous kinds of traps are possible in growth faulted regime

Fig 3.2 Formation of a rollover anticline in a growth fault

The hanging wall of the growth fault often forms a roll over anticline can efficiently trap the hydrocarbons in presence of effective seal present on top. Also, the fault itself can act as a lateral seal.

Second trap possible in growth fault is a fault block trap. Though this kind of trap might form in any kind of fault, the growth fault geometry might enhance the trap’s capacity by virtue of its Hydrocarbon Habitat in Growth Fault Regime

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thickness. Also, the fault leak is significantly hampered due to thinner successions on the other side of the fault. Thus if the hydrocarbon reserve is followed by a reservoir grade rock across the fault the migration of oil from reserve will be reduced significantly.

Fig 3.3 Growth faults can effectively form excellent combination traps as shown

3.5 LIMITATIONS

First of all a trap may or may not have hydrocarbon trapped in it. One must know thoroughly the geological and tectonic history of the block being explored, along with the migration history and patterns of the hydrocarbon from source to reservoir. A trap has a positive chance only if the trap formation pre‐dates the migration. Also a trap loses the viability if it is not in the migration path of oil.

Also fault plane, due to sliding of various kinds of layers, may or may not seal the reserve. This may lead to significant loss of oil to atmosphere if the fault trace extends to the surface.

Similarly, if the rollover anticline is not capped by an effective seal the oil will not be trapped.

Nature of the rocks also plays dominant role. The reservoir rock must be permeable enough to let active exchange of fluids and keep the hydrocarbons absorbed for long periods of time.

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CHAPTER 4:

INTERPRETATION 4.1 INTRODUCTION Interpretation refers to study of acquisition data and mapping of the subsurface geophysical data by studying different seismic sections, marking the faults horizons etc. in the most geologically appropriate way, integrating the well log data and then tying the features to get a reasonable subsurface map.

4.2 THE PROCESS

4.2.1 DATA LOADING:

First of all the seismic lines are loaded on any interpretation software (SMT, Petrel, OpenDtect etc.). Along with lines well log data can also be included at this step. Also a Polygon is defined which essentially marks the area in which we want to restrict our analysis

4.2.2 FAULT PICKING:

Faults are picked by noting the abrupt change in horizons which is more or less same throughout the depth of the line (or atleast for a noticeable length). Though, in section fault trace may look perturbed (may be due to multiples, noise or other technical limitations) but we must mark the fault trace in the most geologically appropriate way (generally it is preferred to have smooth fault). Faults are marked on every line available

4.2.3 HORIZON PICKING:

To start horizon picking dip section is well suited as on a dip section faults are visible and we can easily take care of the throw of each fault. At preferred time depth level, a suitable and easily recognizable horizon is chosen and then marked. After we mark one horizon on one section a point is obtained on all the lines intersecting the marked section. This helps the interpreter to Hydrocarbon Habitat in Growth Fault Regime

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avoid the misties that might occur. Generally 2 or more horizons are marked for analysis of an area

4.2.4 FAULT POLYGON:

The fault traces on seismic section appear as a point on the base map. The points corresponding to a single fault are enclosed in a polygon. The thickness of polygon at a particular place represents the throw of the fault at that place. It is important to specify type of fault (whether normal or reverse), so that it is shown correctly on the contoured ma

4.2.5 CONTOURING:

The Software interpolates the surface from the marked lines for a particular horizon, marked by the interpreter, and prepares a contoured surface for the area.

4.2.5 THICKNESS MAP: Thickness map is prepared by subtracting higher horizon contour map from lower horizon contour map. It essentially reflects the thickness of the strata between the selected two layers, throughout the area.

4.3 INTERPRETATION OF GROWTH FAULTS Distinguishing features of a growth fault include varying thickness of horizon across a fault, roll over anticline etc. They are listric normal fault and dip towards the basin though we often see opposite dipping antithetic faults which are consequence of growth faulting itself. While marking growth faults it must be kept in mind that the fault must dip in basin ward direction. Also, throw increases as we do deep inside the section. Also commonly observed feature in growth fault is rotation of the hanging wall if there is some kind of geological barrier e.g. a ridge etc.

4.4 GEOMETRY OF GROWTH FAULTS The dip of growth fault decreases with depth, therefore fault surface map of a growth fault must show denser contours as we go in the direction opposite to the dip of the fault. Amount of thickening in the horizon is a matter of the rate of sedimentation of the succession at the time of faulting, but a continuous increase in throw must be seen in growth faulting.

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CASE STUDY ON GROWTH FAULTS

 Mumbai Offshore  Niger Delta

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Chapter 5:

MUMBAI OFFSHORE

5.1 INTRODUCTION

Mumbai offshore is located on the western continental shelf of India between Saurashtra basin in NNW and Kerela Konkan in the south. The basin has been proven for commercial production of petroleum and hence falls under category I. It is approx. 116000 Km2 in area from coast to 200m isobath. The age of the basin ranges from late Cretaceous to Holocene with thick sedimentary fill ranging from 1100‐5000 meters though possibility of occurrence of Mesozoic synrift sequences in the deep‐water basin have been indicated by the recently acquired seismic data. The first oil discovery in this basin was made in the Miocene limestone reservoir of Mumbai High field in February 1974. Subsequent intensification in exploration and development activities in this basin have resulted in several significant discoveries including oil and gas fields like Heera,Panna, Bassein, Neelam,Mukta, Ratna,Soth tapti, Mid Tapti etc.

5.2 TECTONIC SETUP

Mumbai offshore is a pericratonic rift basin situated on western continental margin of India.

Towards NNE it continues into the onland Cambay basin. It is bounded in the northwest by Saurashtra peninsula, north by Diu Arch. Its southern limit is marked by east west trending Vengurla Arch, located at south of Ratnagiri, and to the easten boundary is marked by Indian craton. The Mumbai Offshore Basin is divided into 5 different tectonic zones (Figure 2)     

Surat Depression (Tapti‐Daman Block) in the north Panna‐Bassein‐Heera Block in the east central part Ratnagiri in the southern part Mumbai High‐/Platform‐Deep Continental Shelf (DCS) in the mid‐western side Shelf Margin adjoing DCS and the Ratnagiri

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Figure 2: Different tectonic zones in Mumbai Offshore

5.3 STRATIGRAPHY

Within the Bombay geologic province, the stratigraphic record is incomplete. In the subsurface, Mesozoic rocks are known from drilling only in the Kutch area. In the Depressions (Panna Formation) were filled with trap wash overlain by carbonates, shales, and interbedded siltstones from fluvial to transitional environments. In the Kutch area, marine sedimentation occurred only in the western part until the end of the Paleogene. Lower to middle Eocene rocks are absent from most of the offshore area, and an erosional unconformity that extends over most of the offshore area truncates the Panna Formation. Eocene marine carbonates and shales of the Belapur, Bassien, and Dui Formations extend over much of the present‐day offshore and Eocene‐Oligocene sandstones, siltstones and shales reflect shallow marine to alluvial environments in the south Cambay Graben. Middle to late Eocene time in the shelf margin or outer shelf, Bombay High, and Panna‐Bassein areas is represented by shallow‐marine shales and shelf carbonates of the Belapur and Bassein Formations. Shoreward, and to the northeast, shallow‐ marine to lagoonal Dui Formation shales dominate. Still farther to the north, in the south Cambay Graben, deltaic and alluvial sediments of the Ankleswar Formation dominate late Eocene‐Oligocene environments.

Today, the shelf area continues to receive terrestrial sediments, and the Cambay and Narmada Deltas continue to expand. The Stratigraphic chart of different zones of Mumbai offshore are shown in Figure 3 Hydrocarbon Habitat in Growth Fault Regime

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Figure 3: Stratigraphy of Mumbai offshore area

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5.4 PETROLEUM SYSTEM

5.4.1 SOURCE

The main source in the Mumbai offshore region is the thick Panna shale facies deposits and Belapur Shale facies deposited between Paleocene and Lower to Mid Eocene

5.4.2 RESERVOIR

Mumbai Offshore has both carbonate and clastic reservoir facies everywhere between Paleocene and middle Miocene. Reservoir grade rocks are frequently found interlayered between shales in lower Miocene and Mid Miocene level. Main reservoir successions include Mukta, Ratnagii etc.

Reservoir Age

Lithology/Location

Middle Miocene

Carbonate sections (Ratnagiri & The uppermost part has been found to be Bandra formations) hydrocarbon bearing at a few places A sheet like sand deposited over Mumbai High is also proved to be gas bearing in commercial quantity in Mumbai High

Lower Miocene

Represented by a thick pile of Deposited under cyclic sedimentation with carbonates hosting huge each cycle represented by lagoonal, algal quantity of oil and gas mound, foraminiferal mound and coastal marsh facies The porosity is mainly intergranular, intragranular, moldic, vuggy and micro‐ fissures and the solution cavities interconnected by micro‐fissures provided excellent permeability.

Oligo– Early Sands ( Panvel formation ) Miocene

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Comments

Deposited under conditions

prograding

delta

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Proved to be excellent reservoirs Eocene and E.Oligocene clastics (Mahuva Early Formation) Oligocene Deposition of thicker carbonate facies over the horst blocks (Bassein, Mukta & Heera formations).

Paleocene

Proven hydrocarbon bearing reservoirs in Tapti area.

Gradual increase of sea level, shielding from the clastic onslaught from the northern part of the basin.

The intervening regressive phases have aided in developing good porosity in these rocks making them excellent reservoir levels in the basin.

Coarser clastic facies developed The clastics of Panna formation are proved within the upper marine shale to be excellent reservoirs.

(Panna Formation)

5.4.3 CAP ROCKS

Main successions acting as cap are also shales deposited later in Pleistocene, also named Chinchini Shales. It is a thick shale succession that sits over other clastic and carbonate layers.

5.4.4 ENTRAPMENT

Mumbai Offshore has various tectonic settings that show a range of traps for example in Structural traps like tilted fault block type, fault closures. Fold dominated traps include anticlines and also roll over anticlines formed due to growth faulting. A large number of growth faults also have enhanced the probability of striking economic prospects, especially in the basinward direction of the zone. This study deals with the growth fault regime located within the shelf margin tectonic block of Mumbai Offshore basin

5.5 DATA INTERPRETATION

Interpretation of the study area located within the Shelf‐Margin tectonic block of Mumbai offshore was done on SMT KINGDOM on Mid Miocene and Lower Miocene level. The seismic time section of 21 lines was used to interpret these levels and prepare time structure maps and a mid‐ Miocene isochronopach.

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5.5.1 SEISMIC DATA INTERPRETATION

Figure 4: Base map showing the study area

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5.5.2 INTERPRETED HORIZONS AND FAULTS

Figure 5: Seismic section of line as marked in the figure

Figure 6: Seismic section of line as marked in the figure Hydrocarbon Habitat in Growth Fault Regime

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Figure 7: Seismic section of line as marked in the figure

Figure 8: Seismic section of line as marked in the figure

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Numerous listric normal faults are seen on the section. This is because large sediment deposition in the basin has led to formation of growth faults. Especially to be noted is the central main growth fault marked in red in the above sections. A roll over anticline is seen on the east of this fault which has been faulted by antithetic faults (Figure 8). The Green horizon represents Middle Miocene level and the yellow horizon denotes Lower Miocene level.

5.5.3 TIME STRUCTURE MAPS

Figure 9: Mid Miocene two way time structure map

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Figure 10: Lower Miocene two way time structure map

The faults trend NNW‐SSE on the map. A persistent rise is observed in the western part of the study area. This is because of Laxmi‐Laccadive Ridge which is present along the shelf margin in Mumbai offshore. Due to this ridge the horizons have been raised on the western part of study area. Eastern half of the area has homoclinal slope. Main basinal slope is towards west because of the presence of growth fault pockets. Sediment depocenters are observed in the eastern half of tha study area.

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5.5.4 ISOCHRONOPACH MAP

Figure 11: Isochronopach of Mid Miocene succession

The thickness is reduced sharply from center to west. As shown in (Fig 5‐8) the Middle Miocene level doesn’t vary much whereas there is a sudden rise in Lower Miocene Level after main fault (Marked in Red in respective figures).

5.6 PROSPECT ANALYSIS

Interpretation of the area shows that there is rollover anticline on the hanging wall of the main fault forming an excellent trap (Figure 12).

The anticline marked in figure 12 corresponds to ‘1’ in figure 13. Along with this, similar but smaller anticlines are also seen in the area e.g. those marked in figure 13. The prospect ‘3’ lies on the same fault as ‘1’. ‘2’ is another anticline, but the main problem with this region is that it lies on Hydrocarbon Habitat in Growth Fault Regime

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footwall of the fault in further east decreasing the thickness considerably which might not yield economic quantities of oil.

Figure 12: Prospect analysis of the area (line view)

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Figure 13: Prospect analysis of the study area (Plan view‐ Mid Miocene TWT map)

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CHAPTER 6

NIGER DELTA

6.1 INTRODUCTION

Figure 1: The changing coastline of the Niger delta (35 Ma History)

The Niger Delta is situated in the Gulf of Guinea (fig. 2) and extends throughout the Niger Delta Province. The coastal sedimentary basin of Nigeria has been the scene of three depositional cycles.

The first began with a marine incursion in the middle Cretaceous and was terminated by a mild folding phase in Santonian time. The second included the growth of a proto‐Niger delta during the late Cretaceous and ended in a major Paleocene marine transgression. The third cycle, from Eocene to Recent, marked the continuous growth of the main Niger delta. A new threefold lithostratigraphic subdivision is introduced for the Niger delta subsurface, comprising an upper sandy Benin formation, an intervening unit of alternating sandstone and shale named the Agbada Hydrocarbon Habitat in Growth Fault Regime

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formation, and a lower shaly Akata formation. These three units extend across the whole delta and each ranges in age from early Tertiary to Recent. From the Eocene to the present, the delta has shifted southwestward, forming deposition belts that represent the most active portion of the delta at each stage of its development). These depositional belts form a regressive delta an area of some 300,000 km2, a sediment volume of 500,000 km3, and a sediment thickness of over 10 km in the basin deposition center. The Niger Delta Province contains only one identified petroleum system, the Tertiary Niger Delta (Akata –Agbada) Petroleum System.

Figure 2: Index map of Nigeria and Cameroon

6.2 GEOLOGY

The onshore portion of the Niger Delta Province is lined by the geology of southern Nigeria and southwestern Cameroon (fig. 1). The northern boundary is the Benin flank‐‐an east‐northeast trending hinge line south of the West Africa basement massif. The northeastern boundary is defined by outcrops of the Cretaceous on the Abakaliki High and further east‐south‐east by the Calabar flank‐‐a hinge line bordering the adjacent Precambrian. The offshore boundary of the province is defined by the Cameroon volcanic line to the east, the eastern boundary of the Dahomey basin (the eastern‐most West African transform‐fault passive margin) to the west, and the two kilometer sediment thickness contour or the 4000‐meter bathymetric contour in areas where sediment thickness is greater than two kilometers to the south and southwest. The province covers 300,000 km2 and includes the geologic extent of the Tertiary Niger Delta (Akata‐ Agbada) Petroleum System.

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6.2.1 TECTONICS

The tectonic framework of the continental margin along the Niger coast is controlled by Cretaceous fracture zones expressed as trenches and ridges in the deep Atlantic.

Figure 2: Seismic section from the Niger Delta continental slope/rise showing the results of internal gravity tectonics on sediments at the distal portion of the depobelt.

The ridges in the fracture zone divide the margin into different basins and, in Nigeria, form the boundary faults of the Cretaceous Benue‐Abakaliki trough, which cuts far into the West African shield. The trough represents a failed arm of a rift triple junction associated with the opening of the South Atlantic. In this region, rifting started in the Late Jurassic and persisted into the Middle Cretaceous. In the region of the Niger Delta, rifting diminished altogether in the Late Cretaceous.

After rifting ceased, gravity tectonics became the primary deformational process.

Shale mobility induced internal deformation and occurred in response to two processes.

First, shale diapirs formed from loading of poorly compacted, over‐pressured, prodelta and delta‐ slope clays (Akata Fm.) by the higher density delta‐front sands (Agbada Fm.). Second, slope instability occurred due to a lack of lateral, basinward, and support for the under‐compacted delta‐slope clays (Akata Fm.) (Fig. 2). Shale mobility induced internal deformation and occurred in response to two processes. First, shale diapirs formed from loading of poorly compacted, over‐ pressured, prodelta and delta‐slope clays by the higher density delta‐front sands (Agbada Fm.).

Second, slope instability occurred due to a lack of lateral, basinward, and support for the under‐ Hydrocarbon Habitat in Growth Fault Regime

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compacted delta‐slope clays (Akata Fm.) (Fig. 2). For any given depobelt, gravity tectonics were completed before deposition of the Benin Formation and are expressed in complex structures, including shale diapirs, roll‐over anticlines, collapsed growth fault crests, back‐to‐back features, and steeply dipping, closely spaced flank faults. These faults mostly offset different parts of the Agbada Formation and flatten into detachment planes near the top of the Akata Formation.

6.2.2 STRATIGRAPHY

The Cretaceous section has not been explored beneath Niger Delta Basin, the youngest and southernmost sub‐basin in the Benue‐Abakaliki trough. Lithology of Cretaceous rocks deposited in the Niger Delta basin can only be extrapolated from the exposed Cretaceous section in the next basin to the northeast‐‐the Anambra basin. From the Campanian through the Paleocene, the shoreline was concave into the Anambra basin

Figure 3: Stratigraphic section of Anammbra basin resulting in convergent longshore drift cells that produced tide‐dominated deltaic sedimentation during transgressions and river‐dominated sedimentation during regressions. Shallow marine clastics were deposited farther offshore and, in the Anambra basin, are represented by the Albian‐ Cenomanian Asu River shale, Cenomanian‐Santonian Eze‐Uku and Awgu shales, and Campanian/Maastrichtian Nkporo shale, among others (figs. 3 and 6) . The distribution of Late Cretaceous shale beneath the Niger Delta is unknown in the Paleocene, a major transgression (referred to as the Sokoto transgression by Reijers and others, 1997) began with the Imo shale Hydrocarbon Habitat in Growth Fault Regime

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being deposited in the Anambra Basin to the northeast and the Akata shale in the Niger Delta Basin area to the southwest (fig. 5). In the Eocene, the coastline shape became convexly curvilinear, the longshore drift cells switched to divergent, and sedimentation changed to being wave‐dominated (Reijers and others, 1997). At this time, deposition of paralic sediments began in the Niger Delta Basin proper and, as the sediments prograded south, the coastline became progressively more convex seaward. Today, delta sedimentation is still wave‐dominated and longshore drift cells divergent Tertiary section of the Niger Delta is divided into three formations, representing prograding depositional facies that are distinguished mostly on the basis of sand‐shale ratios. The Akata Formation at the base of the delta is of marine origin and is composed of thick shale sequences (potential source rock), turbidite sand (potential reservoirs in deep water), and minor amounts of clay and silt (figs. 3, 4, 5 and 6). The Akata Formation formed during lowstands when terrestrial organic matter and clays were transported to deep water areas in low energy conditions and oxygen deficiency. The formation underlies the entire delta, and is typically over pressured.

Turbidity currents likely deposited deep sea fan sands within the upper Akata Formation during development of the delta. Deposition of the overlying Agbada Formation, the major petroleum‐ bearing unit, began in the Eocene and continues into the Recent (figs. 3, 4 and 5). The formation consists of paralic siliciclastics over 3700 meters thick and represents the actual deltaic portion of the sequence. The clastics accumulated in delta‐front, delta‐topset, and fluvio‐deltaic environments. In the lower Agbada Formation, shale and sandstone beds were deposited in equal proportions, however, the upper portion is mostly sand with only minor shale interbeds. The Agbada Formation is overlain by the third formation, the Benin Formation, a continental latest Eocene to Recent deposit of alluvial and upper coastal plain sands that are up to 2000 m thick (Avbovbo, 1978).

Figure 4: AA’ Section (refer Figure 1)

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Figure 5: BB’ Section (Refer Figure 1)

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Figure 6: Stratigraphic column showing the 3 formations of Niger delta

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6.3 PETROLEUM SYSTEM

6.3.1 LOCATION

Hydrocarbons are present throughout the Agbada Formation of the Niger Delta (Figure 1). Though, oil rich trends have been found having the lowest gas to oil ratio as shown in Fig. 7

Figure 7: The oil rich trend line in the Niger delta province As shown above, the oil rich trend runs close to the shore and roughly corresponds to transition between continental and oceanic crust, and within the axis of maximum thickness.

Source Rocks Marine Akata shales and interbedded shales cretaceous shale of Agbada along with Cretaceous shales have been identified. Also Agbada Formation has intervals that contain organic carbon contains in sufficiently high quantities but the thickness of those layers is not thick enough to produce a world class oil province. Also they are immature in various parts of the deltas. The thick Akata shales, below Agbada, are however are of large volume and produce oil in large quantities.

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6.3.2 RESERVOIR

The main reservoirs are sandstone and unconsolidated sands in Agbada formation. The reservoirs are often stacked and are show a large variation in thickness ranging from 15 mts to 10% having thickness of 45 mts.

6.3.3 ENTRAPMENT

Figure 8: Various traps found in the Niger delta province The traps in the Niger delta region are mostly structural mostly involving syn sedimentary deformations, mostly growth faults and rollover structures. The shales, acting as a seal trap typically either form clay smears along the faults or provide interbedded sealing units against which reservoir sands are juxtaposed due to faulting or set a vertical seal and act like lateral seals to prevent horizontal migration of oil. On the flanks of delta (offshore) the clay filled canyons provide top seal and form excellent traps.

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6.3.4 CAP ROCK The primary seal rock in Niger delta is the interbedded shale within the Agbada formation. As discussed earlier the shale provides three types of seals—clay smears along faults, interbedded sealing units against which reservoir sands are juxtaposed due to faulting, and vertical seals

6.4 CONCLUSION

It’s clear from above discussion that the main traps in the Niger Delta province are based on syn sedimentary structures. The abundance of such traps is increased mainly due to the uncompacted layers of sand stones being overpressured by the heavy sediment loads of the delta. This has result in gravity sliding and fracturing of subsurface on a large scale. Thickness of reservoir is selectively increased at places by growth faults making exploration and extraction very profitable.

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CONCLUSION From the study done till now following important points have been concluded:

 Oil occurrence in the trap depends on the time of formation of trap and the time of migration. The Trap should have formed before migration otherwise the oil will escape.  If the underlying sediments are not compact enough their ductility increases and hence their tendency of undergoing gravity sliding eventually leading to growth faulting (As seen in the case of Niger Delta)  Interpretation shows that, in the studied area of Shelf Margin of Mumbai Offshore, there is a possibility of good quantities of hydrocarbons due to existing rollover structures and highly faulted strata.

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Works Cited

Shelton, J.W., July 1984, Listric Normal Faults: An Illustrated Summary, AAPG Bulletin, v.68, p.801‐15, 32 Brown,L. Frank Jr,Loucks, Robert G., Trevino, Ramon H.,Hammes, Ursula, 2004, Understanding Growth faulted,intraslope subbasins by applying sequence stratigraphic principles: Examples from the south Texas Oligocene formation, AAPG Bulletin, v. 88, no. 11 ,pp. 1501 –1522 Brown,L. Frank Jr,Loucks, Robert G., Trevino, Ramon H.,Hammes, Ursula, 2004, Understanding growth‐faulted, intraslope subbasins by applying sequence‐stratigraphic principles: Examples from the south Texas Oligocene Frio Formation: Reply, AAPG Bulletin, v. 90, no. 5 (May 2006), pp. 799–805 Cazes, c.A., December 2004, Overlap zones, growth faults, and sedimentation: using high Resolution gravity data, Livingston Parish, LA, Phd. Theisis, Louisiana State University Wandrey, C.J , May 2004, Bombay Geologic Province Eocene to Miocene Composite Total Petroleum System, India, Petroleum Systems and Related Geologic Studies in Region 8, South Asia, U.S. Geological Survey Bulletin 2208‐F, v.1 Jackson, M.P.A, Vendeville, B.C., July 1991, The rise of diapirs during thin‐skinned extension, Catuneau, Octavian, 2005, Principles of Sequence and Stratigraphy Tearpock, D.J., BischkeR.E., 1991, Applied Subsurface Geological Mapping

www.wikipedia.com www.britannica.com www.banglapedia.com www. sciencedirect.com www.dghindia.org

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