GENERALISED STRATIGRAPHY OF THE ASWARAOPETA AREANELP Block- KG-DWN-98/2, Offshore, KG Basin
Introduction
India's demand for petroleum products is growing at a very rapid rate, With a view to meet
this growing demand, the new Hydrocarbon policy aims at encouraging investment in oil
exploration and production.
India is dependent on Imports to meet the rapidly growing demand for petroleum products.
Current demand and supply projections indicate that the level of self-sufficiency is likely to
decline to about less than 30% over the next few years. Substantial efforts are therefore,
necessary to boost the level of exploration activity in the country, so that, new discoveries
can be made and the quantum of crude oil and gas production increases significantly in
the years to come. Today, India is venturing into frontier areas for Hydrocarbon
exploration. Thrust is being given in deep and ultra deep water offshore areas.
It is also evident that vast amount of capital investments are necessary, if exploration
efforts are to be substantially augmented. Therefore, there is need to attract both the
National as well as Private sector oil companies to invest in this critical area.
Background
Block KG-DWN-98/2, covering the total contract area of 9756.60 Sq.km. was awarded in
the year 2000, during NELP-I to M/s. CEIL. The effective date of the Block is 25-09-2000.
Presently, the Block covers an area of 7294.6 sq. km., after relinquishing of 2462 sq. km
by CEIL, which represents 25.23 % of the original holding, after end of Exploration Phase-
I. ONGC acquired 90% PI and Operatorship from CEIL w.e.f. 03-03-2005.
A total number of nine oil and gas discoveries were made in the block during exploration
phases I & II, viz., Annapurna (R1), Padmawati (M1), Kanakadurga (G2-P1), D1/KT-1, U1,
N1, A1 and W1 in the NDA and the Ultra deep gas discovery UD-1 in the SDA of the block.
Based on these discoveries the entire area was declared as Discovery Area, which was
divided into two areas viz. (i) Northern Discovery Area (NDA) comprising 3800 Sq.km and
(ii) Southern Discovery Area (SDA) comprising 3494.6 Sq.km.
During the Exploration Phase-III, the Contractor submitted the appraisal programmes for
the discovery areas and Proposals for Declaration of Commerciality (DOC) for both
Southern Discovery area and Northern Discovery area were submitted as per PSC
timelines prior to the completion of appraisal drilling programme notwithstanding the non-
announcement of Rig holiday policy (RHP).
Subsequently on 14-06-2012, the exploration period of the block was restructured up to
29-12-2013 by MOPNG for carrying out additional drilling programme. Contractor
undertook the drilling programme and established additional hydrocarbon (oil) volumes
through discovery well A-2 and the well M-3. The results of the wells drilled as part of the
additional drilling programme have substantially enhanced the commerciality perception of
NDA. In the meanwhile, CEIL submitted a proposal for assigning its 10% PI in favour of
ONGC during 2011, which has been approved by GOI on 27-09-2012. Consequently
ONGC now holds 100% PI in the block. This revised DOC is being submitted by ONGC,
the Contractor with enhanced commerciality perception incorporating the results of the
wells of the ongoing additional drilling programme. The DOC for NDA considers seven
discoveries viz., Annapurna (R1), Padmawati (M1), Kanakadurga (G2-P1), D1/KT-1, U1,
A1 and A2. In addition the hydrocarbon bearing fields E1 and M-3 have been considered
as part of the cluster. The discoveries N1 and W1 have not been considered at present as
they are smaller in volumes. The operator’s gas discoveries in adjoining Godavari PML
with GIIP of 36 BCM have also been considered in the integrated cluster development. In
the Southern Discovery Area, discovery of UD-1 has also been appraised by drilling of 4
wells and GIIP has been estimated as 80.33 BCM.
The Contractor’s estimates of in-place hydrocarbons considered for production profile
generation in Block KG-DWN-98/2 are tabulated below:
Summary of Free gas volume:
Discovery/ Find
Total GIIP
GIIP (BCM)
Summary of Oil volume:
11 42 10.5 58.7 19.6 141.8
The GCG volume is estimated to be of the order of 10.82 BCM
The Dynamic modelling results suggest the total gas production from the gas fields located
in the northern portion of KG-DWN-98/2 Block along with G-4 field starting from 2016-17
over a period of 15 years is 84.41 BCM with a peak gas rate of 33 MMm3/d (including AG
and GCG).
The cumulative oil production potential from the five oil fields of KG-DWN-98/2 Block is
25.63 MMm3 over a period of 10 years with a peak oil rate of 12,000 m3/d.
The SDA profile envisages a peak production of 15 MMm3/d with ten wells for plateau
period of five years with a cumulative production of 47 BCM at the end of 16 years.
Two integrated clusters have been conceptualized for NDA & G4 (in nomination Godavari
PML) discoveries. Cluster-I consists of D and E fields of KG-DWN-98/2 with G-4 combined
development. Cluster-II consists of Annapurna (R-1), Padmawati (M-1), Kanakadurga
(G2P1), G-2-2, M3, A1, U1, U3 and A2 fields for combined development. SDA Ultra
deepwater of UD-1 has been conceptualised for standalone development.
Cluster-I is a subsea cluster tied back to CRP at shallow water and subsequent evacuation
to Odalarevu for processing and subsequent transportation. Cluster-II is a subsea cluster
group tied to a FPSO for processing and stabilization. Oil evacuation is planned by tanker
and gas evacuation by pipeline to Odalarevu. UD-1 discovery evacuation is conceptualised
as subsea tied back to Semi submersible and Evacuation of gas to Odalarevu by pipeline.
The Contractor had made an investment of USD 1.2 Billion towards Exploration
expenditure till 30.9.2013. The following are the estimated Expenditure & Economic
indicators for conceptualized development scenarios.
Cluster-I:
Development
CAPEX
OPEX US$ 1949.5 MM US$ 4199.6 MM US$ 3005.5 MM
TOTAL US$ 3917.2 MM US$ 9012.2 MM US$ 6767.1 MM
Economic Indicators at Base Gas Price of US$ 7/MMBTU & Oil Price of US$ 90/bbl
IRR % 19.1% 26.26% 12%
NPV@14% ($MM) 332.7 2287.0 -211.3
The results of Techno economic analysis indicate that the Clusters-I and II in NDA are
viable at the base oil and gas prices. Sensitivity analysis for a range of price, CAPEX and
OPEX has also been carried out (+30% to – 30% from the base assumptions). The
analysis indicates that SDA yields a positive NPV @ 14% with a 10% rise in base price of
gas. However as UD discovery situated in water depth of more than 2800 m, the CAPEX
estimates at this juncture are indicative. It is observed that any increase in CAPEX would
require higher gas prices to make the project viable.
Based on the above, the Contractor proposes to declare the commerciality of gas (NANG)
and oil discoveries of KG-DWN-98/2 under a viable integrated cluster development
scenario.
G&G analysis carried out in the block has indicated that the block holds substantial upside
potential which is envisaged to be of the order of 265 MMt (O+OEG). It is proposed that
the Operator may be allowed to continue with further exploratory/appraisal drilling in the
block, which would enable addition of further volumes and facilitate in bringing the future
discoveries on production without loss of time. A proposal in this regard is being submitted
separately to DGH.
(Sq. Km.)
given in Figure below
Proposed Project
It is being proposed to carry out development drilling in NDA field by drilling 45 numbers of
wells, including Oil, Gas and Water Injection wells. The details of the fields and wells are
given below.
Details of the discoveries of Northern Discovery Area
Annapurna Discovery: R-1 and Annapurna-2 wells were drilled on the terminal
lobe located on structural flank and lateral seal provided by the shales. Seismic
section through well R1 and Annapurna - 2 shows two hydrocarbon bearing zones.
The shallower zone is interpreted to be sheet sand. Younger channels cutting down
sheet sands in a later episode can be observed in stratal slice, further suggested by
sand rich debris flow deposits observed in image log. This zone is more well-
defined in R-1 well, which is in structurally shallower position and gas bearing.
However, in Annapurna -2 well, this zone is becoming transitional zone with gas
shows only.
DWN-R-1 was drilled in 1,018 m of water depth, to a total depth (TD) of 2,330 m.
The well was spudded on the 4th May 2001 and reached TD on 20th May 2001.
The well drilled a section in Plio-Pleistocene. Petrophysical log and analysis and
MDT results confirmed that the well encountered gas bearing sandstones in two
zones within the Pleistocene; 1,870 to 1,940 m MDBRT and 2,062-2,098 m MDBRT
as given below.
There were also indications of gas bearing sands between 2,165 and 2,170 m
MDBRT. Two Drill Stem Tests (DST) were undertaken. DST No. 1 tested the
interval 2,060-2,099m MDBRT and produced dry gas at a maximum stabilized rate
of 41.92 MMSCFD. DST No. 2 tested the interval 1,870-1,874.5 m and 1,906-1,936
m MDBRT and produced dry gas at a maximum stabilized rate of 37.74 MMSCFD.
The well was subsequently plugged in such a way as to enable re-entry as a gas
discovery.
Annapurna-2 was the second well drilled on Annapurna Gas Field located in 1,144
m of water depth. The well was drilled vertically to a total depth of 2,575 m MDBRT
(2,546.7 m TVDSS). The well was spudded on the 24th August 2001 and reached
total depth (TD) on 17th September 2001. Two cores were cut between 2,036 –
2,045 m and 2,197 m – 2,213 m MDBRT. Petrophysical logs and MDT results
confirmed that the well only encountered an 8m gross hydrocarbon column at the
top of the Lower Reservoir Unit (LRU) sand; the two primary units, being essentially
water sands.
Padmawati Discovery: The DWN-M-1 ST-1 well is located in the northern
portion of the contract area in 465m of water depth was drilled to test the
hydrocarbon potential of the Plio-Pleistocene section. The DWN-M-1 well spudded
on the 27th September 2001, was drilled vertically to a total depth of 1,757 m after
observing oil shows at 1,692 m and controlling a 43 bbl gain at 1,710 m. Poor hole
conditions prevented evaluation of this section and led to the decision to plug back
and sidetrack the well. The DWN-M-1-ST-1 well kicked off from 1,318 m, was drilled
to a total depth of 2,722 m on the 15th October 2001. The primary and secondary
targets for the DWN-M-1 well were based on seismic amplitude mapping.
The primary target for the well was interpreted as a Plio-Pleistocene, deep-marine,
leveed-channel complex within the G-3 anticline. Secondary targets comprised two
shallower Pleistocene channel-levee complexes. The overall trap for all levels is
formed by a combination of structural rollover formed by the G-3 anticline and
stratigraphic pinch-out. Wireline logs and MDT results confirmed the presence of
hydrocarbons at three levels. The primary target (CLC-1) contained high quality gas
and oil bearing sands between 2,061 and 2,107.5 m. Two minor gas-bearing sands
were also identified at 1,870 and 2,002 m. One drill stem test (DST#1) was
performed over the CLC-1 sands with perforations from 2,081 to 2,092 m flowing oil
& gas @ 6,404 stb/d and 3.71MMSCFD from 48/64”inch choke, respectively.
Kanakadurga Discovery: DWN-P-1 is located in 493.7 m of water depth to
test the hydrocarbon potential of the Plio-Pleistocene stratigraphic section on G-2
structure. The main target for the well was a section of Lower Pleistocene deep-
marine (“P-Main”) sands in the G-2 structure, down-dip from the G-2-2 well which
was drilled by ONGC during pre-NELP regime.
These sandstones were proven to be hydrocarbon bearing in the nearby G-2-2
discovery well. Additional targets were the Plio-Pleistocene “P-South” and “P-Deep”
units in well DWN-P1. The trap is formed by a combination of structural dip, faulting,
and stratigraphic pinch-out. The well was spudded on 4th July 2001 and reached a
total depth of 2,585 m MDBRT (2,556.7 m TVDSS) on 23rd July 2001. Wireline logs
and MDT results confirmed that the well encountered thin-bedded oil and gas
bearing sands in the Plio-Pleistocene section in the intervals 1,966 m to 2,109 m
MDBRT and 2,243 m to 2,300.8 m MDBRT.
DWN-P-1 intersected two reservoir zones in the P-Main unit (1,997-2,011 m
MDBRT and 2,021-2,057 m MDBRT) and two in the P-Deep unit (2,242.5-2,285 m
MDBRT and 2294- 2300.5 m MDBRT). All four zones consist of silty and sandy
claystones and shaly sands thinly interbedded, medium to coarse-grained clean
sand. Laboratory measurements on the core taken in P-Main Unit show that the
clean sands have porosities over 33% and permeabilities (measured to air) between
1.6 and 9.4 Darcy. MDT results suggest that the P-main reservoir is gas bearing
with very little oil leg. The GOC is estimated at 2,037.8 m and an interpreted OSC
at 2041.8 m TVDSS.
N-1 Discovery: DWN-N-1 was drilled to test the hydrocarbon potential of the
early to late Middle Miocene and Pliocene section and is located in 606.3 m of water
depth. The well was drilled to a total depth of 3,037.5 m MDBRT. The well was
spudded on 23rd January 2001 and reached a total depth of 3,037.5 m MDBRT on
25thFebruary 2001.
Wireline logs and MDT results confirmed that the well encountered high quality gas
bearing sandstones in the Early Pliocene intervals 2,008 m to 2,011.5 m and
2,038.5 m to 2057.8 m MDBRT. Thick sands were penetrated in the deeper Middle
to Late Miocene section and are interpreted as water saturated at the well location.
Significant up dip potential however remains in these sandstones. The well is a gas
discovery within the Early Pliocene sands and was plugged and abandoned.
D-1/KT-1 Discovery: Deep water location “KG-DWN-98/2-D-1” at a bathymetry
of 603 m was drilled as a vertical well to its target depth of 2416 m TVD. One
conventional core (2112-2116.25 m, Recovery-64.5%) was cut in this well. Three
intervals viz. 2075.3 m, 2142.5 m and 2219.5 m were tested by MDT (Dual packer)
and AOFP was evaluated to be 1031, 4345 & 2839 Mm3/day respectively. A net
pay thickness of 78.7 m. was encountered in this well with GSC (as per MDT
pressure plot probable GWC at 2227 m, MD / -2213 m, TVDSS). Intervals 2223.5-
2214 m (Obj-I), 2209-2203 m (Obj-IA), 2185-2152 m (Obj-II), 2122-2105 m (Obj-
IIA), were identified for production testing. However due to complications (sheared 9
5/8” casing) testing could not be carried out and the well was permanently
abandoned.
Deep water location “KG-DWN-98/2-KT-1” was drilled to explore the hydrocarbon
potential of Cretaceous and Tertiary Channel sands, targeted to 4750m
(TVDSS)/Basement at a water depth of 594m. The location was spudded on
10.06.2007. After drilling to 3953m, the well was terminated in Paleocene section
due to safety reasons as high pressure regime was encountered below 3940m. Gas
pay sands were encountered in the intervals 2134-2254m (98/2-D-1 Sand
Equivalent), 1933-1934m and 2068-2069m with in Pliocene sequence in the drilled
section. However 68 m of net gas pay was established in Pliocene section.
U-1 Discovery: The well KG-DWN-98/2-U-1 was drilled up to a depth of 2435 m
(TVD-BRD) at a water depth of 1265m, to explore Terminal lobe/sheet sand located
on structural flank and entrapment by reverse fault, thrust and toe of slope. ELAN
results show three hydrocarbon bearing reservoir sands (2216-2226m, 2285-
2292m, 2355-2357m) in well DWN-U-1, which is tested to be gas-bearing. DWN-U-
1 has been drilled in terminal lobe/sheet sand occurring at the southeastern end of
the Vasishta channel system in close vicinity of the toe-thrust fault as seen in stratal
slice prepared at various levels.
This sheet sand is deposited from decelerating flows at the terminus of Vasishta
channels. This laterally extensive sheet sand reflects the sediments that have
bypassed through up-dip Vasishta channels and are deposited in primarily an
unconfined setting.
The toe-thrust fault provides entrapment for the target sands’ top and lateral seals
from shales.
A-1 Discovery: The well KG-DWN-98/2-A-1 was drilled up to a depth of 2609 m
at a water depth of 706 m, to explore the hydrocarbon potential of Pliocene
Distributary channel sands/Lobe sands. Well DWN-A-1 encountered two
hydrocarbon bearing zones. The shallower zone is interpreted to be channel sand
as seen in the seismic section and stratal slice.
The deeper zone is identified as channel sand from stratal slice and seismic
reflections. These channels are sinuous in character with well-developed levees on
its sides and towards down slope, they are transforming into widespread
depositional lobe (as seen in Annapurna area). Number of HC bearing zones are
present (in shallower level) together giving gross thickness of 51m. Based on Elan
processed logs, the sands developed in the intervals, 1704 – 1724m, 1726 – 1728
m, 1736-1739 m,1752.5 – 1756.0 m and 2095 – 2099 m appear to be interesting
from hydrocarbon point of view.
W-1 Discovery: The well KG-DWN-98/2-W-1 at a bathymetry of 1283 m was
drilled as an inclined “L” profile well to 2670 m MD (2449.5 m TVD-BRT) on 21st
Feb 2006. The well was drilled on a Terminal lobe/sheet sand located structural
flank and entrapment by reverse fault. The W-area is dominated by a number of
SW-NE reverse faults and NNW-SSE trending cross-cutting faults resulting in a
number of compartments in the area. The well DWN-W-1 itself passes through a
reverse fault. ELAN results show hydrocarbon bearing reservoir zone present in the
well in the interval 2170-2190m MD in the up-thrust block.
High-sand channel with associated features like splay is identified from seismic
attributes in this area. The channel feeds a terminal lobe, which is not probed by
any well yet. The extent of the lobe is quite large and so, bears high upside potential
with a range of uncertainty. The structural variability of the area may provide lots of
additional prospects in this area towards south and south-east of DWN-W-1 well.
Wireline logs and MDT results confirmed that the well encountered gas bearing
stacked sands within the Pliocene section in the interval between 2171 m and 2190
m (MD), i.e. 2116 m and 2130 m MSL. Water bearing sands were encountered
below 2244m,MD.
The potential of the sub thrust block in the interval 2419-2500m MD could not be
assessed properly due to inability to log the well by wireline or TLC. Gas bearing
sandstone with a net pay of 17 m is established.
E-1 well: In addition to above discoveries the well KG-DWN-98/2-E-1 (Shallow) to
explore the hydrocarbon potential of Pliocene Channel sands at a bathymetry of
664 m was drilled as a vertical well to 2564m. Wireline logs and MDT results
confirmed that the well encountered gas bearing stacked sands within the Pliocene
section in the interval between 2335 m and 2390 m (MD) i.e. 2321m and 2376 m
TVDSS and another discrete gas pack in the interval 1640-1649 m (MD) i.e. 1626-
1635 m, MSL. The quality of sandstones is dominantly clean and occasionally
grades into silty and shaly sand.
Effective porosity varies between 16 to 32 % with the clay fraction varying between
nil to 40%. Few thin low resistivity layers in the interval 1632-1890m could be
interesting.
The LWD data, which is not much affected by invasion, indicates some interesting
layers. These highly silty layers at 1703-1705m, 1764-1766m, 1771-1779m and
1786-1796m (all LWD depths), could be gas bearing. MDT sampling carried out in
the well suggests that the samples at 1642.5 and 2342.4m are gas bearing. Sands
at 1891.8m and 2337.0m are interpreted as gas (as collected in PVT), whereas
sands at 1988.7m and 2001.5m are water bearing. Straddle packer Mini-DST was
carried out at 2360.6m, 2381.3m and 2386.1m and proved to be gas bearing. AOFP
was estimated to be 14.68 MMm3/day (518.4 MMscf/D) for the interval 2358-
2361m. The geological objective of drilling the well was achieved as a net pay
(bottom package) of 31 m was established by both drilling and wire line data.
Details of the discovery of Southern Discovery Area
Initially based on sparse grid 2D seismic data large sized structural features were mapped
viz Main UD, UD-South and large nosal feature north of UD structure. Detailing of main UD
structure was done through additional 2D seismic data infilling existing lines.
Structural modeling was carried out to assess the origin of the structural prospect through
M/s Midland Valley. The evaluation led to the identification of two super large prospects
which are basement controlled 4-way closures extending over several hundreds of sq. km
The well DWN-UD-1 was successfully drilled and tested gaseous hydrocarbons from
sands within Middle Miocene formation.
UD-1 Discovery: The well KG-DWN-98/2-UD-1 was targeted to 6200m (TVDSS)
in 2841 bathymetry, was drilled to the depth of 6576m and encountered Lower
Barremian sequence at 6575m. Though multiple reservoir sands were encountered
in the well, gaseous hydrocarbons have been encountered in Miocene sequence in
the interval 5242.5-5305.5m (MD). The Discovery is of potential commercial interest
and as the area is quite large which include areas in the north and south of main UD
structure and merits appraisal.
Geological setting
The NELP block KG-DWN-98/2 falls in the offshore part of the Krishna-Godavari Basin
(KG Basin). Krishna-Godavari (KG) Basin, a peri-cratonic rift basin along the East Coast of
India, is located between 15 to 17.50 N and 80 to 89.50 E. It covers an area of 41,000
Km2 both onshore and offshore and includes the deltas of Krishna and Godavari rivers.
The basin comprises of the sediments ranging in age from Lower Permian to Recent. The
onland part of the basin is under alluvial cover. However, Permo-Triassic, Late Jurassic-
Cretaceous and Tertiary rocks outcrop along the western margin of the basin. The
basement is of Archaean and Proterozoic rocks of the Eastern Ghat.
The Krishna-Godavari Basin is characterised by a series of NE-SW trending en-echelon
horsts and grabens formed during the Jurassic - Cretaceous break-up between India and
Antarctica. These NE-SW structures overprinted the NW-SE trending Permo-Triassic
Pranhita-Godavari Graben. The morpho-tectonic elements of the basin are defined by
deep-seated basement controlled fault systems with a series of asymmetric half-grabens
and horsts.
The basin evolution shows remarkable correlation with various tectonic episodes of
opening of East Coast of India. Four stages of tectono-stratigraphic evolution represented
by four major tectono-stratigraphic units have been recognized. These are: early rift, rift,
early thermal subsidence, and late thermal subsidence stages.
The grabens were filled with thick Middle Jurassic to Early Cretaceous clastics. Rifting
ceased and widespread Late Cretaceous clastics buried the 'horst and graben'
topography. The onset of passive margin progradation towards the south-east commenced
during the Late Cretaceous, and paleo-shelf breaks have been recognized in the sub-
surface. During the latest Cretaceous to earliest Paleocene, the Indian sub-plate was tilted
down towards the south-east. This event was caused by the uplift of north-western India as
it drifted northwards over the Deccan "hot spot."
The Krishna-Godavari basin was down-warped so that the gradient from source to basin
(toward the east-southeast) was increased. Higher depositional energy of the proto-
Krishna-Godavari river system led to an influx of coarse clastics causing vigorous passive
margin progradation to the southeast. It has been postulated that this system had
coalesced during the Eocene to form a single delta front extending in a SE direction from
the current position of the Krishna River.
The two present-day delta promontories became established in their present positions in
the late Neogene. With the Tertiary base providing the glide plane, slippages and slides
controlled by the instabilities generated by rapid sedimentation at or near shelf edge led to
development of growth fault systems in the coastal and offshore areas. The abundance of
Tertiary mobile shale enhances the potential for remobilizing sediments later.
The basinal character of the distal offshore is strongly controlled by the lithological and
structural attribute of the Tertiary mobile shale formation. Sediment loading caused the
subjacent shale mass to squeeze forward and outward on the slope to build the distal
delta. Due to plasticity of the overpressured Vadaparu marine shales, the overlying
sedimentary sequence, therefore, built up over a relatively unstable substratum. The
attendant structural evolution is marked by sequences of major shale diapirism and
faulting, resulting in fault bounded mini-basins. Successive mini-basins contain
sedimentary fill that is younger down-dip. The shale diapirs started to grow in the offshore
area during Miocene and continued up to Pliocene.
Most of the extensional (growth fault system and related roll-over anticlines) and
compressional (shale diapir and thrust system) structures in KG basin's present day
continental slope is related to mobile Vadaparu shale deformation (Sahoo, 2005).
The thick Tertiary passive margin system is the primary focus for the exploration activities
in the KGDWN-98/2 Contract Area. The overall sequence thickens basin ward, away from
the present day coastline. The offshore portion of the Tertiary basin includes depositional
systems ranging from shore-face through to deep-water submarine fan sandstones. The
primary targets for exploration in the KG-DWN-98/2 permit area are Miocene to Pliocene
submarine sands. These sands were sourced from the Krishna and Godavari River
system, and deposited on the lower slope in the area of study.
Structuring in the basin is primarily related to the sediment loading and subsequent
collapse of the shelf edge, forming genetically linked growth fault and toe thrust pairs. Two
main phases of this occurred viz., Late Eocene to Early Miocene; and Late Miocene
through to Pliocene, and continue to the present day. The dominant structures in this part
of the basin are a major north-east-trending down-to-basin growth fault, the associated
large G1, G-2, G-3 and G-4 low-side rollover trend, and the genetically related younger toe
thrust complex. These Pliocene listric faults generally have a NNE-SSW trend and typically
sole out in the shales below. Stratigraphic trapping is also likely to be important, with traps
formed by up dip pinch-out of the linear slope fan channel complexes.
The subsurface information obtained so far through drilling has indicated that mixed sand-
mud system may be used to interpret the depositional process in the deepwater KG
offshore basin. Mixed sand-mud slope aprons are characterized by a wide variety of
massflow processes, resulting in complex, irregular and often disorganized lithofacies
distribution. The slope apron system is dominated largely by slump packages composed of
deformed hemipelagic shales and contorted thin bed turbidite, slide blocks and chutes
infilled with slope related mudstone, thick and thin bedded, discontinuous turbidites and
debris flows. Gullies and constructional channel systems may traverse the disrupted slope
apron surface and pass laterally and basin ward into more stable areas where laminated
mudstone and sandy mudstones predominate. Local developments of turbidites within
these gullied and channeled areas may lead to isolated channel fills of heterogeneous
turbidites containing sandstones with interbedded mudstones.
The main depositional elements in this geological setting are incised slope channels,
constructional leveed channels, distributary channel complexes and distributary lobes. The
intra-slope basin ponding is believed to depended, primarily on the prevalence of following
factors:-
• Toe-thrusting
• Sediment supply
• Prevailing eustatic condition
In the KG Basin, two main periods of listric fault toe-thrust detachment occurred during
Mid-Late Oligocene and Basal Pliocene to Pleistocene. Both the events led to an increase
in sedimentary input and subsequent loading. In both cases, the expected sequence of
events starts with an early stage lowstand (ponding "fill" episodes) and lowstand/highstand
("spill" episodes) at later stages (source – Peter M. Barber, July 2002).
Stratigraphy
Basement is been observed in the seismic sections below 5 seconds. The lower most
units as inferred to be Cretaceous from the correlation brought out from on land wells. This
is an unconformity surface and is overlain by Vadaparru shale of M.Eocene age.
Matsyapuri Sandstone formation of Oligo-Miocene age overlies the Vadaparru shale
.Godavari clay formation of Pliocene to Recent forms the youngest unit demarcated by
erosional cut surface. Seismically, the major events that can be picked up are Mio-
Pliocene erosional cut surface and the Cretaceous-Tertiary unconformity. The other
formation boundaries in this area are subtle breaks.
The area where the block KG-DWN-98/2 is located, the startigraphy consists of slope
depositionsl systems and deepwater depositional systems. The Pliocene section is
generally clay dominated with few deep water channel and fan deposits. Miocene to
Eocene consists of deep water clays and sand deposits in the form of basin floor fans and
channels. These form exploration targets over basement highs. On the slope Miocene
onlaps also form exploration targets. Cretaceous section is available in the rifts as well as
around the Basement highs and is expected to contain good quality source rocks and
reservoirs as in the nearby nomination acreages.
Project Justification
It is expected that the proposed drilling of 45 development locations will lead to the
accretion of the hydrocarbon reserves which will augment the production of hydrocarbons,
in the present scenario of growing demand of oil and gas in the country. A cluster
development scenario is envisaged for the monetization of the discoveries already made in
the block and the successful drilling will further enhance the commerciality of the block and
will help in cost effective implementation of the development project with upward revision
of hydrocarbon production figures.
Drilling Operations
Contractual drilling rigs are planned to be deployed for undertaking drilling in the block.
The technical details of the proposed drilling activity are given below:
Well location / Depth As detailed in the Map enclosed
No.of wells to be drilled 45
Duration of Drilling 90 to 100 days per well
Water depth Ranging from 620 to 2600 m
Qty. of drilling fluid. cu.m. 150-300 M3
Qty. of cuttings, cu.m. 100-170 M3
Qty. of drlg. Waste water, cu.m. 350-400 M3
Distance of Block boundary from the
coast line
The nearest point is 24.7 kms from coast
HC reserve (initial in place) OIIP: 141.8 MMm3 & GIIP: 146.99 BCM
Formation pressure Hydrostatic
Only water based drilling mud will be used. The quantity of drill cuttings generated will be
around 150 m3 . The quantity of wastewater produced will be about 20 m3/day. The rig will
be provided with solids handling system comprising Shale shakers (1200 GPM), Desander
(1200 GPM) and Desilter (1200 GPM) and Degasser with vacuum pump.
Drilling operations will be carried out using an electrical type deep-offshore drilling rig.
Drilling unit for drilling of oil and gas wells consists of a derrick at the top of which is
mounted a crown block and a hoisting block with a hook. From the swivel is suspended a
Kelly stem passes through a square or hexagonal Kelly bush which fits into the rotary
table. The rotary table receives the power to drive it from an electric motor. The electric
motor rotates the rotary table which passes through the Kelly bush and the rotations are
transmitted to the bit as the drilling progresses, the drill pipe in singles are added to
continue the drilling process. At the end of the bit life, the drill pipes are pulled out in
stands and stacked on the derrick platform. A stand normally has 3 single drill pipes. After
changing the bit, the drill string is run back into the hole and further drilling is continued.
This process continues till the target depth is reached.
During the course of drilling, cuttings are generated due to crushing action of the bit. These
cuttings are removed by flushing the well with duplex/triplex mud pumps. The mud from
the pump discharge through the rotary hose connected to stationary part of the swivel, the
drill string and bit nozzles. The mud coming out of the bit nozzles pushes the cuttings up
hole and transports them to the surface through the annular space between the drill string
and the hole. The mud not only carries away crushed rock from the bottom of the hole but
it also cools the bit as it gets heated due to friction with formation while rotating. The mud
also helps in balancing subsurface formation pressures and by forming a cake on the walls
of the well diminishes the possibility of crumbling or caving of the well bore.
At the surface, the mud coming out from well along with the cuttings falls in a trough,
passes through the solids control equipment i.e. shale shaker, de-sander and de-silter.
This equipment removes the solids of different sizes which get mixed with the mud during
the course of drilling. The cleaned mud flows back to the suction tanks to be again pumped
into the well. The drilling mud/fluid circulation is thus a continuous cyclic operation. The
most suitable clay for mud preparation is bentonite which is capable of forming highly
dispersed colloidal solutions. Various other chemicals are also used in mud preparation as
per requirements dictated by the temperature/pressure conditions of the wells. The mud is
continuously tested for its density, viscosity, yield point, water loss, pH value etc. to ensure
that the drilling operations can be sustained without any down hole complications.
Drilling Facilities
Drilling is a temporary activity which will continue for about 45 days for each well in the
block. The rigs are self-contained for all routine jobs. Once the drilling operations are
completed, and if sufficient indications of hydrocarbons are noticed while drilling, the well is
tested by perforation in the production casing. This normally takes 10-15 days. If the well is
found to be a successful hydrocarbon bearing structure, it is sealed off for future
development, if any.
a. Drilling muds
Drilling of wells requires specially formulated muds which basically comprise inert
earth materials like bentonite, barite in water with several additives to give mud weight,
fluidity and filter cake characteristics while drilling. The drilling muds have several
functions like lubrication and cooling of the drill bit, balancing subsurface formation,
bringing out the drill cuttings from the well bore, thixotropic property to hold cuttings
during non-operations, formation of thin cake to prevent liquid loss along well bore etc.
Several additives are mixed into the mud system to give the required properties. Water
based mud will be used to the possible extent in exploratory drilling but use of
synthetic based mud may require due to complexities associated with the geological
formations and associated hole stability problems. The constituents of water based
mud (WBM) are given in Table below. The special additives and their functions in
WBM are shown in Table below.
b. Power Generation
The drilling process requires movement of drill bit through the draw works which
require power. The power requirement of the drilling rig will be met by using the six
Diesel Generator sets with a diesel consumption of about 15-20 Kl / day. The exhaust
stacks of the DG sets are likely to vent the emissions.
c. Water requirements
The water requirement in a drilling rig is mainly meant for preparation of drilling mud
apart from washings and domestic use. While the former consumes the majority of
water requirement, the water requirement for domestic and wash use is very less. The
daily water consumption will be 25 m3/d of which 15 m3/d will be used for mud
preparation and 10 m3/d will be used for domestic purposes including drinking.
d. Solids removal
The rock cuttings and fragments of shale, sand and silt associated with the return
drilling fluid during well drilling will be separated using shale shakers and other solids
removal equipment like desander and desilter. The recovered mud will be reused
while the rejected solids will be collected and discharged into the waste pit.
e. Drill cuttings and waste residual muds
During drilling operations, approx. 300-500 m3 per well of wet drill cuttings are
expected to be generated from each well depending on the type of formation and
depth of drilling. In addition to the cuttings 20 m3/day of wastewater is likely to be
generated during well drilling. The waste residual muds and drill cuttings which contain
clay, sand etc. will be treated locally and disposed.
f. Testing
Testing facilities will be available at drilling rig for separation of liquid phase and
burning of all hydrocarbons during testing. The test flare boom will be located at a
distance from the drilling rig.
g. Chemical storage
The drilling rig will have normal storage facilities for fuel oil, required chemicals and
the necessary tubulars and equipment. The storage places will be clearly marked with
safe operating facilities and practices.
h. Manpower
The drilling rig will be operated by approx. 50-60 persons on the rig at any time. The
manpower will operate in two shifts with continuous operations on the rig. On board
accommodation is available.
i. Logistics
Crew transfers to and from the drilling rig by helicopter and materials, diesel and
chemicals will be transported through & supply vessel.
Location Map Of KG-DWN-98/2 Block, KG Offshore, KG Basin
Ingredients of Water Based Drilling Fluid
Special Additives and their functions in Water-based Drilling Fluids
S. No. Chemical Name Functions
1. Sodium bicarbonate Eliminate excess calcium ions due to
cement contamination
3. Groundnut shells,
mica of cellophane
formation
6. Vegetable oil
7. Pill of oil-based mud
spotting fluid
drilling string; Pill is placed down hole
opposite contact zone to free pipe
S. No Chemicals
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