Oil Fields for Students

8/10/2019 Oil Fields for Students

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Assam-Arakan BasinBasin Introduction :.

The Assam-Arakan Basin is situated in the northeastern part of India categorized as category-I basin. The basin

covers an area of 116000 Sq.Km.Major tectonic elements of the basin are:

Assam ShelfNaga Schuppen belt

Assam-Arakan Fold belt.


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and the Champang oil fields occur in that zone of the shelf which is overridden by the Naga thrust. In the Digboiand Kharsang oil fields, oil occurs in Tipam Sandstone and Girujan Clay formations, respectively, overlying the

Naga thrust.

Source Rock and Hydrocarbon GenerationThe important source rock sequences occur within the argillaceous Kopili Formation and in the Coal-Shale Unit of

the Barail Group. The average TOC of shales within the Sylhet Formation is about 0.60%, in the Kopili Formation,about 2.5% and in the Barail Coal-Shale Unit, about 3.8%. The average TOC ranges of different formations (shale

samples) are as follows:

Formation Average TOC Range Remarks

Barail (shales) 2.5% to 4.5% Excellent source potential

Kopili (shales) 1% to 3% Excellent source potential

Sylhet Limestone ~ 0.61% Poor source potential

Basal Sandstone ~ 0.62% Poor source potential

Organic matter richness of shales increases towards the Naga thrust. In both Kopilis and Barails, the organic

matter is terrestrial type-III with varying contributions of Type-II.

Barail Coal-Shale Unit in the Schuppen belt also form important source rock sequence. In the Naga fold belt, in

addition to above, Disang shales also possess excellent source rock characteristics with TOC around 4% and VRo

varying from 0.69% to 1.94%.

Geochemical analysis of exposed sediments from the Schuppen belt show a TOC range of 0.64-1.20% for Barail

shales. The dominant organic matter type is structured terrestrial. Presence of amorphous (upto 60%) and

extractable organic matter (upto 55%) indicates a fairly good liquid hydrocarbon generating potential. Organicmatter is mainly humic and sapropelic. TAI of 2.6 to 2.75 and VRo of 0.57 to 0.67% show that the sediments are

thermally mature and within oil window. In the subthrust, the source sequences occur at greater depths and,

therefore, should be in a higher state of thermal maturity. It is expected that the source sequences within the Kopili

and Barail formations in the subthrust would be at the peak oil generating state.

Reservoir Facies

Barring the Borholla and Champang oil fields of the Dhansiri valley and the adjacent schuppen zone respectively,

where oil occurs in fractured granitic basement rock (Precambrian) and Tura sandstones (Upper Paleocene/ LowerEocene), oil in the Upper Assam Shelf and schuppen belt occurs in sandstone reservoirs ranging in age from Upper

Paleocene-Lower Eocene to Mio-Pliocene. However, the major accumulations occur in Upper Paleocene + LowerEocene, Oligocene (Barail Formation) and Miocene (Tipam Sandstone) sandstones. The major oil fields, where oil

occurs in Upper Paleocene and Lower Eocene sandstone reservoirs are Tengakhat, Dikom, Kothaloni, Baghjan and

in Oligocene sandstone reservoirs (Barail Formation), are Nahorkatiya, Hapjan, Shalmari, Geleki, Lakwa, and

Rudrasagar etc. Oil reserves in Kopili sandstones (Upper Eocene) are found mainly in the Geleki field. Most of the

oil in the Tipam Sandstone is found in the Lakwa-Lakhmani and Geleki fields. In the Kumchai and Kharsang

fields of Arunachal Pradesh, oil occurs in the Girujan Formation of Mio-Pliocene age. Recently gas has been

discovered in the sandstone reservoir of Dirok structure within Girujan Formation. The Girujan Clay being

floodplain deposits, the reservoir sands are generally lenticular and some what erratic in distribution. In theKhoraghat oil field of Dhansiri valley, oil occurs in sandstone reservoirs within the Bokabil Formation (MiddleMiocene). In the North Cachar area of Assam, potential reservoir rocks are expected to be fractured granitic

basement rock (Precambrian)and sandstones in the Tura (Paleocene), Kopili (Upper Eocene), Renji (Oligocene),

Bhuban and Bokabil (Middle Miocene) formations.

Cap Rock and Entrapment

There are three well developed regional cap rocks within the Tertiary sedimentary succession, the lower one,


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occurring in the Upper Eocene is the argillaceous Kopili Formation, the middle one is the Barail Coal-Shale Unitand the upper one, overlying the Tipam Sandstone is the Girujan Clay. Most of the oil accumulations, discovered

till date in the Upper Paleocene-Lower Eocene, Oligocene (Barail) and Miocene (Tipam Sandstone) reservoirs,

occur in structural combination (fold + fault) traps developed by compressive forces during Mio- Pliocene and

later times. Most of these hydrocarbon traps, particularly those developed in post- Barail sediments, orient parallel

to the Naga thrust. Faults associated with these traps in the southeasterly sloping shelf zone in the Brahmaputra

and Dhansiri valleys have NE-SW to NNE-SSW orientation. Most of the prominent faults continue upward intopost-Tipam sediments, and the rest die out in the lower part of the Tipam Formation. Some of the prominent faults,

particularly those near the Naga thrust, are reverse faults, e.g., one at the northeastern flank of the Geleki structure,

another at the northern flank of the Rudrasagar structure. It may be mentioned that oil, generated in the Kopili and

Barail source beds, accumulated in post-Barail sediments by vertical migration through such prominent faults. Oil

within the Kopili Formation (composed predominantly of shales with subordinate sandstone) occurs in strati-structural combination traps, as in the Geleki field. Oil within the Girujan Clay Formation as in the Kumchai and

Kharsang fields also occurs in combination traps, but here the control of lithology on accumulation is more than

that of structure. In the Borholla field of the Dhansiri valley and Champang field of the neighbouring schuppen

belt, oil reserves occur in structurally controlled subtle trap in fractured basement rocks. Oil accumulations within

the Bokabil Formation (Middle Miocene) in the Khoraghat and Nambar fields of the Dhansiri valley, occur in

structural combination traps.

Hydrocarbon Potential

Petroleum Plays :.S.No. Plays Formation Major Field

1 Mio-Pliocene Girujan Kharsang, Kumchai, Dirok

2 Miocene Tipam Hapjan, Digboi, Geleki, Charali

3 Oligocene Barail

Naharkatiya,Lakwa, Lakhmani, Rudrasagar, Demulgaon,

Sonari, Amguri, Hapjan, Shalmari,Kusijan, Laiplinggaon,Geleki

4Mid-Upper

EoceneKopili Geleki

5 Lower Eocene Lakadong+Therria Dikom, Kathaloni, Baghjan, Panidihing, Tamulikhat,Tengakhat

6 ArcheanFractured Granatic

BasementBorhola, Champang

Cambay

Basin Introduction:

Geographic Location of the basin

The Cambay rift Basin, a rich Petroleum Province of India, is a narrow, elongated rift graben,extending from Surat in the south to Sanchor in the north. In the north, the basin narrows, but


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tectonically continues beyond Sanchor to pass into the Barmer Basin of Rajasthan. On the southern side, the basin

merges with the Bombay Offshore Basin in the Arabian Sea. The basin is roughly limited by latitudes 21 00' and

25 00' N and longitudes 71 30' and 73 30' E.

Category of the basin : Proved

Area : The total area of the basin is about 53,500 sq. km.

Age of the Basin & Sediment-thickness

The evolution of the Cambay basin began following the extensive outpour of Deccan Basalts (Deccan Trap) during

late cretaceous covering large tracts of western and central India. Its a narrow half graben trending roughly NNW-

SSE filled with Tertiary sedimentswithrifting due to extensional tectonics. Seismic and drilled well data indicate a

thickness of about 8 km of Tertiary sediments resting over the Deccan volcanics.

Exploration Status

PEL AREAS P ML AREA M TOTAL AREAS T UNEXPLORED AREAS U = T ( P+M )

15,838.04 Sq. KM 5,083.62 Sq. KM 53,500 Sq. KM 32578.34 Sq. KM

Generalized Stratigraphy:


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Standard stratigraphic table.

Sedimentation survey and Depositional environment in different location zones

The formation of the Cambay Basin began following the extensive outpour of Deccan basalts (Deccan Trap) during

late Cretaceous covering large tracts of western and central India. The NW-SE Dharwarian tectonic trends got

rejuvenated creating a narrow rift graben extending from the Arabian sea south of Hazira to beyond Tharad in the

north. Gradually, the rift valley expanded with time.

During Paleocene, the basin continued to remain as a shallow depression, receiving deposition of fanglomerate, trap

conglomerate, trapwacke and claystone facies, especially, at the basin margin under a fluvioswampy regime. The

end of deposition of the Olpad Formation is marked by a prominent unconformity. At places a gradational contactwith the overlying Cambay Shale has also been noticed.

During Early Eocene, a conspicuous and widespread transgression resulted in the deposition of a thick, dark grey,

fissile pyritiferous shale sequence, known as the Cambay Shale. This shale sequence has been divided into Older

and Younger Cambay Shale with an unconformity in between. In the following period, relative subsidence of the

basin continued leading to the accumulation of the Younger Cambay Shale. The end of Cambay Shale deposition is

again marked by the development of a widespread unconformity that is present throughout the basin.


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Subsequently, there was a strong tectonic activity that resulted in the development of the Mehsana Horst and other

structural highs associated with basement faults.

Middle Eoceneis marked by a regressive phase in the basin and this led to the development of the Kalol/ Vaso delta

system in the north and the Hazad delta system in the south. Hazad and Kalol/ Vaso deltaic sands are holding largeaccumulations of oil.

Major transgression during Late Eocene-Early Oligocenewas responsible for the deposition of the Tarapur Shale

over large area in the North Cambay Basin. The end of this sequence is marked by a regressive phase leading to

deposition of claystone, sandstone, and shale alternations and a limestone unit of the Dadhar Formation.

The end of the Paleogenewitnessed a major tectonic activity in the basin resulting in the development of a

widespread unconformity.

During Miocenethe depocenters continued to subside resulting in the deposition of enormous thickness of Miocene

sediments as the Babaguru, Kand and Jhagadia formations.

Pliocenewas a period of both low and high strands of the sea level, allowing the deposition of sand and shale.

During Pleistoceneto Recent, the sedimentation was mainly of fluvial type represented by characteristic deposits of

coarse sands, gravel, clays and kankar followed by finer sands and clays, comprising Gujarat Alluvium.

Throughout the geological history, except during early syn rift stage, the North Cambay Basin received major

clastic inputs from north and northeast, fed by the ProtoSabarmati and ProtoMahi rivers. Similarly, the Proto

Narmada river system was active in the south, supplying sediments from provenance, lying to the east.

Petroleum System:

Source Rock

Thick Cambay Shale has been the main hydrocarbon source rock in the Cambay Basin. In the northern part of the

Ahmedabad-Mehsana Block, coal, which is well developed within the deltaic sequence in Kalol, Sobhasan and

Mehsana fields, is also inferred to be an important hydrocarbon source rock. The total organic carbon andmaturation studies suggest that shales of the Ankleshwar/Kalol formations also are organically rich, thermally

mature and have generated oil and gas in commercial quantities. The same is true for the Tarapur Shale. Shales

within the Miocene section in the Broach depression might have also acted as source rocks.

Reservoir Rock

There are a number of the reservoirs within the trapwacke sequence of the Olpad Formation. These consist of sandsize basalt fragments. Besides this, localized sandstone reservoirs within the Cambay Shale as in the Unawa, Linch,Mandhali, Mehsana, Sobhasan, fields, etc are also present.

Trap Rock

The most significant factor that controlled the accumulation of hydrocarbons in the Olpad Formation is the favorablelithological change with structural support and short distance migration. The lithological heterogeneity gave rise to

permeability barriers, which facilitated entrapment of hydrocarbons. The associated unconformity also helped in the

development of secondary porosity.

Transgressive shales within deltaic sequences provided a good cap rock. (Fig 6: Generalized Tectono StratigraphyMap Showing Source rock, Reservoir Rock, and Oil and Gas Occurrences.)

Timing of migration & Trap formation:The peak of oil generation and migration is understood to have

taken place during Early to Middle Miocene.


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Cauvery Basin

Basin Introduction:

The Cauvery Basinextending Extends along the East Coast of India, bounded by -

08 - 12 5 North Latitude , 78 - 800 East Longitude has been under hydrocarbon exploration sincelate nineteen fifties. Application of CDP seismic in 1984 considerably increased the pace of

exploration resulting in the discovery of several small oil and gas fields. The first deep well for exploration was

drilled in 1964.

The Cauvery Basin covers an area of 1.5 lakh sq.km comprising onland (25,000 sq.km) and shallow offshore areas

(30,000 sq km). In addition, there is about 95,000 sq km of deep-water offshore areas in the Cauvery Basin. Most of

the offshore and onland basinal area is covered by gravity, magnetic and CDP Seismic surveys.

Category and Basin Type:

Cauvery basin is a pericratonic rift basin and comes under category first. (Basins with established to commercial

production.)

Basin Age & Sediment Thickness

Result of Gondwanaland fragmentation during drifting of India- Srilanka landmass system away from

Antarctica/ Australia plate in Late Jurassic/ Early Cretaceous.

The basin is endowed with five to six kilometers of sediments ranging in age from Late Jurassic to Recent

(mainly thick shale, sandstone & minor limestone).

Prognosticated resources : 700 MMT (430 MMT: onland areas and 270 MMT: offshore)


GROUP FORMATION AGE

NARIMANAM

Cuddalore Sandstone Younger Miocene to Recent

Madanam Limestone Younger Miocene

Vanjiur Upper Oligocene to Lower Miocene

Shiyali Oligocene to Younger Miocene

Niravi Late Eocene to Oligocene

NAGUR

Tirippundi Middle Eocene to Early Miocene

Pandanallur Lower Eocene

Karaikal Shale Paleocene to Eocene

Kamalapuram formations Maestritian to Lower Eocene

ARIYALUR

Portono Kampanian to Maestritian

Nanilam Santonian to Kampanian

Kudavasal Shale Konesian to Santonian

UTTATUR

Bhuvanagiri Senomanian to Turonian

Satapadi Albian to Senomanian

Andimadam Albian


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The stratigraphy is worked out from outcrop geology and sub-surface information gathered from seismic and drilling

data.

Precambrian:Precambrian cratonic rocks comprising granites and gneisses are exposed all along the western margin ofthe basin.

Late Jurassic-Early Cretaceous: Overlying the Cratonic basement along the margin of the basin are

exposures of sedimentary rocks of Gondwanic affinity identified as the Shivganga Beds and Therani

Formation. The Therani Formation contains index Gondwana plant fossils (Ptilophyllum acutifolium).

These rocks are feldspathic, gritty and kaolinitic.

Early Cretaceous:The rocks of the Uttatur Group is made up of Kalakundi, Karai Shale and Maruvathur

Clay formations in the outcrops and the Andimadam, Sattapadi and Bhuvanagiri formations in the sub-

surface. These formations overlie the older Gondwana rocks and basement granites and gneisses.

Andimadam Formation:In the subsurface, the formation is developed in grabens, namely, the Ramnad,

Tanjore, Tranquebar and Ariyalur Pondicherry grabens. The lower boundary of the formation is marked by

Archaean Basement rocks, while the upper boundary is defined by an argillaceous section. It comprisespale grey, fine to coarse grained, micaceous sandstone and micaceous silty shale.

Sattapadi Shale:This formation is widely distributed in the basin.It is absent in the southeastern part of the

basin. The Andimadam Formation marks its lower boundary and an arenaceous facies of the Bhuvanagiri

Formation marks its upper contact. It comprises mainly silty shale and thin calcareous sandstone. The

environment of deposition is inferred to be marine. The age assigned is Albian-Cenomanian. This is one of

the important source sequences for HC generation.

Bhuvanagiri Formation: The formation is developed mostly in the northern and central parts of the basin.

The formation is predominantly sandstone with minor claystone and shale. A Cenomanian-Turonian age

can be assigned to this formation. It is inferred to have been deposited in middle shelf to upper bathyal

environment.

Palk Bay Formation: The occurrence of this formation is restricted to the Palk Bay. The lithology isdominantly calcareous sandstone with a few bands of sandy claystone. The depositional environment is

inferred to be shallow marine in a fan delta setting.

Late Cretaceous: The sediments in the outcrops are classified under two groups, namely, the Trichinopoly

and Ariyalur groups. The Trichinopoly and Ariyalur groups in outcrops consist of Sandstones and

Limestone formations.

Kudavasal Shale Formation:It is present all along the eastern part of the basin. The formation consists of

shale/calcareous silty shale with occasional calcareous sandstone bands.

Nannilam Formation: It is conformably overlain and underlain by the Porto-Novo and Kudavasal

formations respectively. The formation consists of alternations of shale, calcareous silty shales and

occasional calcareous sandstones. The formation age ranges from Santonian to Campanion.

Porto-Novo Shale: Predominantly developed in the northern part of the Ariyalur-Pondicherry Sub-basin,west of Karaikal Ridge and Palk Bay Sub-basin. It is predominantly argillaceous with minor siltstone. The

age of the formation is Campanion to Maastrichtian.

Komarakshi Shale: The formation has developed towards the eastern part of the basin. It unconformably

overlies the Bhuvanagiri/ Palk Bay Formation and underlies the Karaikal/Kamalapuram formations. The

formation consists mainly of calcareous silty shale. The age of the formation is Coniacian to Maastrichtian.

Tertiary: A complete sequence of Tertiary sediments is encountered in the sub-surface. The exposed rocks

are represented by the Niniyur Formation of Paleocene age and the Cuddalore Sandstone of Mio-Pliocene

age. The sub-surface section of Tertiary rocks is considerably thick and has been classified into two groups,

the lower part is named as the Nagaur Group and the upper part, as the Narimanam Group.

Nagore Group: The formations of this group overlie the Ariyalur Group. The base and top of the group is

marked by pronounced unconformities. The four formations recognized in this group are described below.

Kamalapuram Formation: The Porto-Novo---Komarakshi Shale unconformably underlies the formation,whereas the overlying Karaikal Shale has conformable contact. It consists of alternations of shaly

sandstones and shales.


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Karaikal Shale: The formation conformably overlies the Kamalapuram Formation. The formation

comprises shales, which are occasionally calcareous/pyritic. The age of the formation ranges from

Paleocene to Eocene.

Pandanallur Formation: It has a restricted areal extension. It consists of claystone sandstone, deposited in

middle shelf environment. Age of the formation is Lower Eocene.

Tiruppundi Formation: The formation is present in Pondicherry offshore, Nagapattinam Sub-basin, and

south of Palk Bay Sub-basin. The formation comprises limestone, siltstone and sandstone. It is of MiddleEocene to Early Miocene age.

Narimanam Group: The youngest sedimentary sequence comprising sandstone, clay/claystone andlimestone which are well recognized with distinct character is designated as a Group. This group comprises

eight formations.

Niravi Formation: The formation unconformably overlies the Tiruppundi Formation/Karaikal Shale. Theformation consists of grey coloured, fine to medium grained, calcareous sandstone with occasional pyrite

and garnet.

Kovilkalappal Formation: It occurs in Tanjore and Nagapattinam Sub-basins and overlies the NiraviFormation, and underlies the Shiyali Claystone. It is argillaceous in nature with a dominant presence of

limestone.

Shiyali Claystone Formation: : It is observed to occur in Madanam and Karaikal area. The age of the

formation ranges from Oligocene to Lower Miocene.

Vanjiyur Sandstone Formation: The formation has limited areal extent. It is predominantly arenaceous incharacter and comprises dark grey, calcareous sandstone and siltstone.

Tirutaraipundi Sandstone Formation: The formation is present in the southern part of the Nagapattinam

Sub-basin towards Palk Bay. It comprises mainly sandstones with minor limestone.

Madanam Limestone Formation: The formation is unconformably underlain by the Tirutaraipundi

Sandstone and Vanjiyur Sandstone. It comprises mainly limestone with minor silty clays.

Vedaranniyam Limestone Formation: The formation occurs only in the southeastern part of the basin. It

consists of predominantly coral limestone and minor grainstone.

Tittacheri Formation: The formation is present in a large part of the basin. It grades into the CuddaloreSandstone Formation near the outcrops. This consists of unconsolidated gravely sandstone and earthy

clays.The age of the formation is Lower Miocene to Pliocene.

Petroleum System:

Prognosticated Resources/Proved Reserve

The Cauvery Basin is an established hydrocarbon province with a resource base of 700 MMT.

430 MMT for onland areas and 270 MMT in the offshore.

Proven / Expected Play Types

TStructural and combination traps in Early Cretaceous to Paleocene sequences.

Stratigraphic traps such as pinch-outs / wedge-outs and lenticular sand bodies in Early to Late Cretaceoussequences.

SourceSattapadi shale within Cretaceous main source Kudavasal Shale within Cretaceous Basal part of

Kamalapuram Fm (Paleocene).

Reservoir Andimadam, Bhuvanagiri & Nannilam Formations within Cretaceous Kamlapuram and NiraviFormations within Paleocene Precambrian Fractured Basement.

Cap Rock Sattapadi shale within Cretaceous Post unconformity shales like Kudavasal and Kamlapuram.

Entrapment Structural/ Stratigraphic, Combination traps.

Krishna Godavari Basin


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Basin Introduction:

Extensive deltaic plain formed by two large east coast rivers, Krishna and Godavari in the state of Andhra Pradesh

and the adjoining areas of Bay of Bengal in which these rivers discharge their water is known as Krishna Godavari

Basin. The Krishna Godavari Basinis a proven petroliferous basin of continental margin located on the east coast ofIndia .Its onland part covers an area of 15000 sq. km and the offshore part covers an area of 25,000 sq. km up to1000 m isobath. The basin contains about 5 km thick sediments with several cycles of deposition, ranging in agefrom Late Carboniferous to Pleistocene.The major geomorphologic units of the Krishna Godavari basin are Upland plains, Coastal plains, Recent Flood and

Delta Plains.

The climate is hot and humid with temperature reaching up to 42 degree symbol is to be inserted C during summer.

The mean day temperature varies between 35 C and 40 C during summer and 25 C and 30 C during winter.



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In the northwestern and western margins of the basin, out crops of Achaean crystallines and sediments ranging in

age from Late Permian to Pliocene are present. However, major part of the basin is covered by alluvium/sea.The outcrop and sub-crop lithologic information has been gathered from a large numbers of wells drilled in theshelfal area and onland.

The stratigraphy has been worked out.

Litho - Stratigraphy Nomenclature.

Petroleum System:

Krishna-Godavari basin is a proven petroliferous basin with commercial hydrocarbon accumulations in the oldest

Permo-Triassic Mandapeta Sandstone onland to the youngest Pleistocene channel levee complexes in deep wateroffshore. The basin has been endowed with four petroleum systems, which can be classified broadly into two


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categories viz. Pre-Trappean and Post-Trappean in view of their distinct tectonic and sedimentary characteristics.

Seismic imaging of Pre-Trappean section poses problems in terms of data quality.Source rich areas at different stratigraphic levels

Hydrocarbon Generation Centres in Cretaceous.

Hydrocarbon Generation Centres in Paleocene.

Hydrocarbon Generation Centres in Eocene.

Pre -Trappean Petroleum System

Permo-Triassic Kommugudem-Mandapeta-Red Bed Petroleum System

This is the oldest known petroleum system in the basin.

Source Rock

Kommugudem Formation is the main source rock for this system. It belongs to Artinskian

(Upper Early Permian) age. This coal-shale unit is more than 900 m thick in the type wellKommugudem-1.It has a good source rock potential with rich organic matter with TOC ranging

between 0.5 to 3% and vitrinite reflectance in the deeper part of the basin is in the range of1.0 to

1.3. Generation threshold occurred during Cretaceous.

Reservoir

Rock

Mandapeta Sandstone of Permo-Triassic age is the principal reservoir rock for this system. It

may be noted that these sandstones are in general tight and need frac jobs for exploitation.

However, porous and permeable patches are also present and chasing them seismically is amajor exploration challenge.

Cap RockTight layers within Mandapeta Sandstone and the overlying argillaceous Red Bed act aseffective seals.

Entrapment

Entrapment is essentially structural in nature. As mentioned earlier, seismic mapping of pre-

trappean section has serious problems due to the presence of a good seismic energy reflector in

the form of Basalt above this system affecting the seismic data quality.

Late Jurassic-Cretaceous Raghavapuram-Gollapalli-Tirupati-Razole Petroleum System

Source Rock

Raghavapuram Shale of Lower Cretaceous age is considered as the principal source rock not

only for this system but also for the onland part of the basin. Maximum thickness up to 1100 m

is recorded in the subsurface. The sequence comprises essentially carbonaceous shale withintervening sands possibly representing brief regressive phases in an otherwise major

transgressive phase. The organic matter is dominantly of Type III and III B. The maturity levelvaries between catagenetic to inadequately matured in different parts of the basin. TOC is

recorded up to 2.4%. It has the proclivity for generation of both oil and gas.

Reservoir

Rock

Lenticular sands within Raghavapuram Shale possibly representing intervening regressive

phases are one of the potential exploration targets; though mapping them seismically poses some

challenges as mentioned above. A recent major find in its time equivalent (?) in shallow offshorepart of the basin opened up some very exciting exploration opportunities in this sequence.

Recent exploratory efforts in deep offshore also indicated prospectivity in Cretaceous sequence

Sands within Gollapalli Formation of Late Jurassic-Early Cretaceous in Mandapeta-Endamuru

area and its time equivalent Kanukollu Formation in Lingala-Kaikalur area are another potential

target in this petroleum system.

A northeast southwest trending corridor of Upper Cretaceous Tirupati Sandstone, product of aregressive phase, between southeastern side of Tanuku Horst and MTP fault is emerging as

another important target.

Cap Rock

Raghavapuram Shale acts as effective seal for both Gollapalli reservoirs and the sands within

Raghavapuram Shale. Shale intercalations within Tirupati Formation appear to act as seal for theaccumulations within the Formation.

Razole Formation (Deccan Basalt) acts as a regional cap for the pre-trappean hydrocarbon

accumulations. It is of interest to note that occasional occurrence of hydrocarbons is noticed

within Razole Formation itself, indicating its reservoir potential also.


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EntrapmentWhile the entrapment style is essentially structural, accumulations in Raghavapuram Shale have

strati-structural element in their entrapment.

Post-Trappean Petroleum System:

Palakollu-Pasarlapudi Petroleum System

It is the most prolific system in the onland part of the basin contributing major part of the onland hydrocarbonproduction. It has an abnormally pressured source sequence and a reservoir sequence with more than normalpressures.

Source Rock

The Paleocene Palakollu Shale is the source sequence. It is deposited in considerable thickness

in the area to the south of MTP fault with a ENE-WSW alignment paralleling the fault. It shows

fair to god source rock potential with proclivity to generate mainly gaseous hydrocarbons. TOCranges between 0.6 to >5% and is dominantly humic type, rich in inertinite and about 10-20%

contribution is from Type II organic matter. Subsidence history of Palakollu Shale suggests

generation threshold to be around Middle Eocene.

Reservoir

Rock

Sand layers within source rich Palakollu Shale are found to be potential reservoir rocks, though

most often with very limited accumulations. Associated high pressures also do not make themattractive targets. Pasarlapudi Formation of Lower to Middle Eocene is the principal producing

sequence onland with many potential reservoir levels.

Cap Rock

Laterally persistent shales within Pasarlapudi Formation have been found to act as effective seals

for the accumulations within Pasarlapudi Formation. Palakollu Shale encompassing the

occasional sands within the Formation also acts as seal for them.

EntrapmentThough structural entrapment is the dominant element for Pasarlapudi Formation, strati-

structural element also appears to be occasionally present.

Vadaparru Shale Matsyapuri / Ravva Formation-Godavari Clay Petroleum System

Discovery of medium sized fields with liquid hydrocarbon in the Coastal Tract, significant discovery of Ravva Field

in the shallow offshore and some very exciting mega discoveries in deep offshore parts of the basin have made thisyoungest petroleum system, a very important one.

Source Rock

: Vadaparru Shale is the principal source sequence. Average TOC for this sequence is about 4%.

Organic matter is in the early phase of maturation in the coastal part and increases basin ward.

Organic matter is of Type III and has potential to generate both oil and gas. Generation threshold

for this sequence is around Lower Miocene.An interesting recent observation regarding the source sequence is that some major gas

accumulations in both shallow and deep offshore are found to be of biogenic origin also. Thisobservation throws some interesting challenges in terms of exploration strategies to be adopted

especially for the offshore part of the basin.

ReservoirRock

Sands within Matsyapuri and Ravva Formation and also the sands within Vadaparru Shale areimportant potential levels and are known to house significant hydrocarbon accumulations in the

basin. Recent discoveries in the channel- levee complexes in intra slope terrace/basin settingwithin Godavari Clay of Pliocene-Pleistocene has opened up hitherto unexplored frontiers of the

basin for exploration.

Cap RockShales within Matsyapuri and Ravva Formations, Vadaparru Shale and Godavari Clay act aseffective seals.

Entrapment

Though structural element plays dominant role for hydrocarbon accumulations in this system,

role of strati-structural element is noticed. Clear understanding of sediment induced tectonics

and precise mapping techniques for reservoir facies can yield very rich dividends especially in

the younger sequences.Krishna-Godavari Basin endowed with such effective petroleum systems ranging from Permo-


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Triassic to Pleistocene offer very exciting exploration challenges with matching rewards

especially in deep water areas.

Petroleum Plays:

Syn-rift Mesozoic playPennar-Krishna Graben, Nizapattinam depression, both onland and offshore, Synrift grabens in shallow and deep

waters (Block KG-OSN-2003/1, KG-DWN-98/1)

Source Rock Syn-rift Mesozoic sediments

Reservoir Sandstone

Trap Structural and strati-structural. Draping over reactivated structural high and wedgeouts.

Depositional

EnvironmentContinental (Fluvial to Laccustrine )

Discovery WellsKG-15, KG-16, & KG-8, KG-17 (Block KG-OSN-2003/1), KG-D4-MD1 (Block KG-DWN-98/1)

UD-1 (KG-DWN-98/2)

MA-1(Block KG-

DWN-98/3)

KG-D6-MA1 was the 19th exploration well drilled by RIL that was designed to test the

hydrocarbons potential of the Cretaceous in the D6 block in offshore Andhra Pradesh, Bay

of Bengal. The well is located in water depth of 1189 m in the Krishna Godavari basin.

Significant oil discovery was made in this well in the Cretaceous section.

Early Miocene Mid Miocene PlayShallow and Deep offshore area, Ravva Field, KG-OSN-2001/1(Dhirubhai-28,36,37), KG-DWN-98/3

Source Rock Eocene / Cretaceous

Reservoir Sandstone

Trap

Structural/Strati-structural growth related /roll over/faulted /unconformityrelated

Erosional subcrop beyond major sequence boundary (stratigraphic )

Combined fault seal and erosional remnant (strati-structural)

Tilted faults block(structural )

Updip stratigraphic pinch out on sequence boundary.

Depositional

EnvironmentShore face to deep- water channel and slope fan system

Discovery Wells Ravva wells R-2 to R-5, 1987-1990.

The Mio-Pliocene sequence in offshore part is promising. The commercial hydrocarbon accumulation in Ravva field

is well known. The prospects GS-38, G-1 and G-2 are also hydrocarbon bearing in Mio-Pliocene strata. As many as

fourteen commercial finds have come from this sequence.

Mumbai offshore


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Basin Introduction:

Geographic Location of the basinMumbai Offshore basinis located on the western continental shelf of India between Saurashtra basin

in NNW and Kerela Konkan in the south.

Category of the basinThe basin falls under the category I,which implies that the basin has proven commercial productivity.

AreaIt covers an area of about 116,000 km2 from coast to 200 m isobath.

Age of the Basin & Sediment-thickness

The age of the basin ranges from late Cretaceous to Holocene with thick sedimentary fill ranging from 1100-5000

m. Though possibility of occurrence of Mesozoic synrift sequences in the deep-water basin have been indicated by

the recently acquired seismic data by GXT, it needs to be further ascertained by future studies.

Generalized Stratigraphy: Standard stratigraphic table.

Sedimentation History and Depositional Environment

Late

Paleocene-

Early Eocene

This phase signifies the early syn-rift stage & is represented by trap-derived clastics contributed

by the then existing paleo-highs essentially in continental to fluvial environment in its lower

part (Panna Formation). It is overlain by grey to dark grey shales with subordinate sands


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possibly representing the first marine transgression into the basin. Presence of carbonaceous

shale and coal at a few places suggest localized restricted conditions.

Main clastic depocenters like Surat Depressionand the contiguous southward lows like Central

Graben (Panna Bassien block)and Vijayadurg Graben (Ratnagiri Block)received thesesediments in considerable thickness aided by syn-sedimentary activity of the bounding faults. A

few localized depressions in Mumbai Platformand over some other horst blocks also received

these sediments. Panna Formation is wide spread in the basin except over the crestal parts ofprominent paleo-highs like Mumbai High, Heera etc. Its thickness varies from almost nil tohundreds of meters in deep sinks.

Shelf Margin block,though under deep marine realm seem to have received lesser quantities of

sediments which were either derived from the Diu Arch (?) or from localized provenances. The

facies developed in this block are mainly claystone, argillaceous and carbonates with some

amount of pelagic fauna.

Carbonate facies (Devgarh Formation) development is observed towards the southern edge

of Mumbai Highin the form of muddy foraminiferal- algal banks; Deep Continental Shelf area

and isolated off-shelf carbonate build-ups at a few places in Shelf Marginand Ratnagiri.The syn-rift stage of Late Paleocene-Early Eocene period got terminated with a basin wide

regression and development of an unconformity

Middle LateEocene

After a period of peneplanation, the basin witnessed a major transgression. Extensive carbonate

sedimentation occurred in the shallow shelf area of Mumbai Platform, Panna-Bassein-Heerablock and Ratnagiri block(Bassein Formation). However the period witnessed essentiallyclastic sedimentation in Surat Depression(Belapur and Diu formations) with occasional

carbonate bands and a few sand stringers and argillaceous carbonates and shales in Central and

Vijayadurg Grabens (Panna-Bassein-Heera block and Ratnagiri block). Shelf margin wasgenerally starved of clastics with deposition of minor claystone and carbonates of mixed middle

shelf to bathyal origin ( Belapur Formation)

Bassein Formation also indicates a wide range of environments restricted platform, shelf

lagoon with isolated shoals in Bassein area to open carbonate shelf in DCSand Ratnagiri and

finally deep water carbonates in Shelf Marginarea. It also formed wedge outs against the rising

flanks of Mumbai High and Heera, which can be considered as potential exploration targets.

EarlyOligocene

During this period, Surat Depression experienced the maximum subsidence-accumulating

thick under compacted claystone relating to the prograding delta from northeast (Mahuva

Formation). TheMumbai platform experienced generally shallower water depths and shaleinterbeds within limestone becoming more frequent. In Shelf Marginarea thinner carbonates

are deposited under relatively deeper conditions.

End of Early Oligocene also witnessed initiation of the westerly tilt of the basin.

Late

Oligocene

Close of Early Oligocene is marked by a minor period of non-deposition except in Shelf

Margin area. A few brief spells of transgression followed by continuous eustatic rise in sea

level up to Early Miocene marked this period. Crestal part of Mumbai High that hitherto

remained a positive area also got submerged during this period.

Surat Depressionwitnessed reduced subsidence resulting in a regressive coastline. A package

consisting of sand bodies deposited in distributary channels, coastal bars, tidal deltas and othertransitional environments encased in marginal marine normally pressured silty and

carbonaceous shale overlying over pressured prodelta clay stone of Early Oligocene. (Daman

Formation) The reservoir facies within this Formation have assumed great importance as they

have been found to host significant amounts of hydrocarbons.There was faster subsidence inShelf Margin to accommodate the increased sediment load

supplied by the westward prograding delta system. The finer clastics reaching the Shelf

Marginblock were mainly deposited in the depression between Kori High and the carbonate

platform. (Alibag Formation)

Southward Close of Early Oligocene is marked by a minor period of non-deposition except

in Shelf Margin area. A few brief spells of transgression followed by continuous eustatic rise in

sea level up to Early Miocene marked this period. Crestal part ofMumbai High that hitherto

remained a positive area also got submerged during this period.Southward from Surat Depression, clays got dispersed over Panna-Bassein-Heera block,


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including the crestal areas and the northern part of Ratnagiri block as well as Bombay Platform.

While in Mumbai High-DCS area and southern part of Ratnagiri, the unit is termed as Panvel

Formation, in Panna-Bassein-Heera and northern part of Ratnagiri, the unit is named as AlibagFormation.)

Early

Miocene

It was a period of eustatic rise in sea level punctuated by a brief spell. The finer clastics entering

into Surat Depressiongot mostly dispersed westward into Saurashtra basin and Shelf Margin

area. Limited quantity of clastics got dispersed southward and entered Mumbai platform at itssoutheast and also up to Heera area. In response to the rising sea level, the delta being formedin Surat Depression in Late Oligocene shifted eastward.

Bassein and the area to its south that experienced shoaling conditions during Eocene was the

site for fine clastic deposition during Early Miocene.Mumbai Highand its western

part (DCS)underwent fairly thick carbonate sedimentation. In fact the major reservoir

of Mumbai Highthat hosts major part of the Countrys hydrocarbon reserves belongs to this

unit. While over the Mumbai Higharea the facies are low energy, very fine grained to clayeycarbonate reservoirs, the DCSarea represents high-energy bio-clastic grainstone facies along

with minor mudstone and wackestone.

Middle

Miocene

The sea level continued to rise during this period. Clastic supply also continued into the basin.

However much of the clastic material got dispersed westward into Saurashtra and Shelf

Marginareas. Considerable quantity of clastics got dispersed southward also covering the

entire Panna-Bassein area and also the Mumbai Highand its immediate surroundings to thewest and south. This clastic unit overMumbai Highincludes sheet like sand, which has also

been found to be hydrocarbon bearing. Carbonate sedimentation continued

in Ratnagiriand DCSareas. Toward the later part of Middle Miocene, clastic deposition almost

came to a halt in Mumbai Highand other areas and consequently carbonates got deposited overmany areas. Uppermost part of the Middle Miocene Limestone in Heera field has been found to

be hydrocarbon bearing. Close of Middle Miocene was marked by a very pronounced

unconformity.

MiddleMiocene-

Holocene

Post Middle Miocene witnessed a major transgression covering the entire basin coupled with

spectacular increase in clastic supply. The earlier initiated westerly tilt of the basin also becamemore pronounced. All these events brought the carbonate sedimentation to a total halt. The

increased clastic supply also resulted in a significant progradation of Miocene shelf at places up

to 80 km (Chinchni Formation)

Petroleum System:

Source Rock

There are three major depocenters in the basin viz. Surat Depressionin the north,Shelf Margin in the west andCentral and Vijayadurg Grabens in the south.

Source Rock

Blocks Character Comments

Surat

Depression

Shallow protected shelf facies consisting of

organic rich shales (Panna Formation-Paleocene to early eocene & Belapur

Formation- Middle Eocene)

3-11% organic carbon and the kerogene type

is mixed Type II and Type III.Expected oil window is around 3000 m

The bounding faults of this tectonic unit have

been continuously active accommodating huge

pile of sediments that are being brought by theNarmada/Tapti fluvial systems

The enclosure provided by the Diu Arch and

Mumbai High could have prevented free open

marine circulation and coupled with optimumsubsidence appears to have helped in

preservation of organic matter.

Shelf

Margin

Several layers of shale/claystone in a few

wells are reported to have requisite TOC and

Possible reasons for the exploration setbacks

could be the speculative nature of reservoir rocks


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have reached the oil window (Panna

Formation & Belapur Formation)

The oil window from the availablegeochemical data appears to be between

2900m and 3850m.

and hydrocarbon expulsion pressure did not

exceed the ambient hyper pressure within the

formation inhibiting primary migration .

Central and

Vijaydurg

grabens

The finer clastics entering into SuratDepression through Narmada /Tapti systemshave been getting partially dispersed

southward and entering these two prominent

lows that appear to be an arm of the

Depression extending to the south. Syn

depositional sinking of these two lows

accommodating the huge clastic influx from

north is evident from the seismic data.

It is widely perceived that the Central Graben

in Panna-Bassein Heera blockand VijayadurgGraben in Ratnagiri block had contributed tohuge hydrocarbon accumulations in many major

structural features like Panna, Bassein, Heera,

South Heera, etc. lying on the western horst

block suggesting a major westward hydrocarbon

migration. However discovery of Neelam field

within Central Graben indicated hydrocarbonopportunities within the graben itself provided

better reservoir facies coupled with proper

entrapment condition is available.

Reservoir RockMumbai offshore basin has been blessed with both clastic and carbonate reservoir facies in almost total TertiarySection ranging from Paleocene to Middle Miocene.

Reservoir

Age Lithology/Location Comments

MiddleMiocene

Carbonate sections at Ratnagiri, Mumbai high& Diu (Ratnagiri & Bandra formations)

The uppermost part has been found to be

hydrocarbon bearing at a few places

A sheet like sand deposited over Mumbai High(S1) is also proved to be gas bearing in

commercial quantity in Mumbai High

Lower

Miocene

Represented by a thick pile of carbonates

hosting huge quantity of oil and gas over

Mumbai High (Bombay, Ratnagiri)

Deposited under cyclic sedimentation with each

cycle represented by lagoonal, algal mound,foraminiferal mound and coastal marsh facies

The porosity is mainly intergranular,

intragranular, moldic, vuggy and micro-fissures

and the solution cavities interconnected bymicro-fissures provided excellent permeability.

Oligo Early

Miocene

Sands in the central and mid-eastern part of

Surat depression i.e. Tapti- Daman area,

Daman formation.

Carbonates adjoining Mumbai High( Panvelformation )

Deposited under prograding delta conditions

Proved to be excellent reservoirs

Eocene and

Early

Oligocene

E.Oligocene clastics of Surat

depression(Mahuva Formation)Deposition of thicker carbonate facies overthe horst blocks in Panna- Basein-Heera and

Ratnagiri blocks (Bassein, Mukta & Heera

formations).

Proven hydrocarbon bearing reservoirs in Tapti

area.

Gradual increase of sea level, shielding from theclastic 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.

PaleoceneCoarser clastic facies developed within theupper marine shale sequence in areas of

Mumbai High, Panna and Ratnagiri (Panna

The clastics of Panna formation are proved to beexcellent reservoirs in the Sw flank of Panna

Basin platform.


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Formation)

Cap RocksShale encompassing the coarser clastic facies in the Paleocene section, widespread transgressive shale overlying theMiddle Eocene Bassein Formation, alternation of shale and tight limestone over early Oligocene Mukta Formation,

widespread intervening shale layers within Early Miocene Mumbai formation over Mumbai High and in DCS area,post Middle Miocene clay/claystone of Chinchini Formation over parts of Heera etc. had provided effective seal forthe underlying hydrocarbon accumulations in the Mumbai offshore basin.

EntrapmentAs mentioned earlier, Mumbai offshore basin has been endowed with a wide variety of entrapment situations like-

structural closures with independent four way closures of very large, large, medium and small sizes, fault closures

and faulted closures with effective fault sealing, strati-structural features like Paleogene wedges against rising flanks

of paleohighs, mud mounds, carbonate build-ups, unconformity controlled traps, Paleogene and Neogene carbonate

wedges against the rising Eastern and Jaygad Homoclines. Mumbai Offshore Basin Introduction Tectonic HistoryGeneralized Stratigraphy Petroleum System Petroleum Plays

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