Dev Dutt Sharma

Dev Dutt Sharma
IUGF, 18 Jan 2013, Mumbai
Hydrocarbon Occurrence in Shale Reservoirs of Cambay Basin
Mechanism of production from Cambay Shale tight reservoirs
Evaluation & Development technologies applied for unconventional
shale reservoirs in past
New technologies of formation evaluation, drilling and production
Application of similar new technologies in other basins of India
Cambay Petroliferous Basin is on mature stage of exploration in view
of 55 years of development and production history with primary
focus on known conventional Middle Eocene reservoirs
Basin offers further scopes for exploration and production from
deeper tighter unconventional reservoirs of Cambay Shale & Olpad
formations, including fractured Deccan Trap, which constitute 2/3 of
sedimentary thickness
Recent development of new technologies of formation evaluation,
horizontal drilling and multistage hydrofracturing especially in US
and Canada have made low productive unconventional Shale Gas,
Tight Gas Sands and CBM as attractive resources for production.
Cambay Shale known for its major hydrocarbon source also acts as
reservoir in Cambay Basin
Occurrence of hydrocarbons in unconventional reservoir of Cambay
Shale is known since the first discovery oil at Cambay during 1958
Deeper wells like Cambay-40 & 45 drilled during 1963 & 1964
encountered oil & gas while drilling under high heat flow and over
pressure conditions
Thereafter, oil & gas production was obtained from so called
“fractured shale reservoir” of Cambay Shale in fields like Indrora,
Sanand, Jhalora, Kalol, Wadu & Nandej etc
Interestingly, Indrora-1 which was drilled in 1971 is still producing
oil on self from high pressured Cambay Shale Reservoir “Indrora
Shale Pay”, though in small quantity
Similarly, some wells in Kalol Field like K-165 produced oil from
Younger Cambay Shale for long (over 30 years), though at low rate
Unconventional hydrocarbon reservoirs act as source as well as
reservoir itself
Relatively thicker (500-1500m) and laterally continuous
Low permeability Tight Gas Sands fall in this category.
Shales are most prominent among them, next CBM.
Low permeability shaly sandstone and siltstone have stratigraphic
deposition with migrated and/or insitu hydrocarbon accumulation
Have no free water or oil/gas-water contact being dominantly
argillaceous with more of bound water than free water in micropores
and fractures.
Geologically, prodelta shale facies equivalent to Chhatral, Mehsana and
Mandhali members of arenaceous Kadi Formation form the shale
reservoir in Younger Cambay Shale.
Shales associated with thin silts, silt streaks or silt laminations and
microfractures act as reservoir in Cambay Shale
Pure shales may offer additional potential for “Shale Gas” due to
adsorptions of natural gas on shale surface which can be assessed based
on organic maturity.
Dual porosity and dual permeability mechanism is responsible for oil &
gas production from low permeability “tight” reservoir in Cambay Shale
Triple porosity and dual permeability model is applicable for “Shale Gas”
production from Cambay Shale
Formation evaluation:
was difficult to identify HC bearing zones by conventional logs due to their low resistivity and high
water saturation, interesting sections were picked up based on resistivity build up or kinks.
of density-neutron porosity on resistivity log was used when available in new wells.
concept of “Shale
Resistivity Ratio” was applied based on analogy with US Gulf of Mexico as
applicable to high pressure shales.
having SRR of 1.6-3.0 considered as “commercial”, 3.0-3.5 as “Small occurrence” and more
than 3.5 “Non-commercial” hydrocarbon bearing zones
concept was applied in newly drilled wells of Sanand, Jhalora, Wadu, Kalol, Indrora, Nandej fields for
perforation testing and identification of bypassed pays in old wells in Cambay Shale section, which proved
very effective.
Conventional Sw calculation indicated very high water saturation (70-90%) to which 20-40% shale
correction was applied for testing in shale reservoir because of their clayey nature having more of bound
water than free water.
thumb rule 1/6th of perforation interval in shale was considered as pay for estimation of reserves
Drilling and production:
Oil production from Cambay Shale reservoir which was initially @3050m3/d declined fast to 3-5m3/d within 2-5 years.
Wells required repeated HF for sustained production.
Wells when ceased production or became uneconomical, transferred to
higher conventional sandstone/siltstone reservoirs.
Vertical drilling and basic hydro-fracturing (30-40 tons) applied at that
time could not enhance productivity for long.
Options were either to drill a vertical well and frac or drill directional
for enhanced production from shaly sand, tight silt or shale reservoirs.
Directional drilling and MWD logging techniques were first time applied
in Wadu wells, which produced about 40-50m3/d oil and 25,00030,000m3/d gas on self flow.
There was no technology to fracture a deep well, greater than 2000m
earlier due to which wells like Jabera-1, which gave gas about
5000m3/d from Tight Vindhyan Sandstone at 2450-2460m depth had
to be abandoned.
Formation evaluation
Horizontal drilling
Multistage fracturing
Microseismic monitoring
Extended production testing
◦ Drilled in NW direction normal to Shmax
140 - 400m gross interval
3 large pay zones (X, Y and Z)
Further possible tight pay zones below Z zone
Well Path
Cambay-19z Cambay-73
Top Eocene
X Zone
Y Zone
Z Zone
2 km
Sophisticated proprietary log
interpretation technology
Curves generated include:
Type Cambay Well
Shale Permeability *
Variable Density
Free Gas *
Bulk Volume Irreducible *
Free Water *
Effective Porosity
Free Fluid Volume
Volume of Hydrocarbons
Results identified three high EP-IVB
potential zones in the
Base EP-IV
“Proof of Concept” well Camaby-76H was drilled to 2740m (TVD 1762m)
with horizontal section of 634m in low permeability Tight Siltstone
Reservoir of Eocene in Cambay Field
Completed with 9-5/8”x5-1/2” liner hanger packer with 5-1/2” tubing
in 8-1/2” open hole using sliding sleeves and swellable packers
Undergone multistage fracturing (8 stages) by pumping about 1200 tons
of proppant @130-150/ton per stage against normal 30-40 ton/job
Fracturing was monitored by microseismic survey to define fracture
development and production enhancement.
Expected to produce 300,000-500,000 m3/d of gas against the normal
production of 30,000-50,000m3/d with conventional technology.
X Top
76H Heel
76H Toe
Y Top
C-76H well Drilling & Completion Schematic
8 stage fracture stimulation
(16 frac ports) in 7 days
Good fracture connectivity,
frac height about 70m
130-150 tonnes /stage, total
about 1200tons
4,400bbl water per stage
@60 bbl/min
Comparable to US frac jobs
e.g. Haynesville
C76H well bore
Microseismic Operations
8 Frac treatments at the Well Cambay-76H monitored over a period of 8
Used Passive Seismic Emission Tomography (PSET®) technology to image
the microseismic activity resulting from the fracture treatment
Indian-based seismic company recorded 56.94 hours of data, processed
16.3 hours
Event signal strength generally weak, noise levels high due to cultural
Velocity model initially calibrated by a perforation shot in an offset well.
Mechanical ball drop events during fracturing provided additional
Extracted 617 microseismic events, 229 mechanical events
Location errors less than +/-15m in horizontal and vertical directions
991 stations in array
represented by red lines.
Station spacing is 20 m
Array consists of 10 lines
radiating out from the well
High fold, wide azimuth &
large aperture coverage of
20.25 sq. km.
Cambay 76H well path
shown by yellow dashed
Data acquired using Aram
Aries-II recording system
at 2ms sampling rate
provided by IOT.
Extended production
testing includes:
Post frac well cleanup
Long term flow rate
testing through
different beans
Installation of EPS
Medium term reservoir
PLT logging
PVT sampling , fluid
composition (gas, oil/
condensate, water) and
pressure information
The applied new technologies for production enhancement from
tight hydrocarbon reservoirs in Cambay Basin can be suitably
applied in other basins of India having similar reservoirs like KG,
Cauvery, Assam-Arakan, Rajasthan, Vindhyan and Gondwana
Advantage with Indian basins is large multiple pay thickness (300700m), moderate depths (1700-3700m),
better porosity and
permeability with evidence of hydrocarbons while drilling
Application of new technologies will help in making deeper, thicker
and tighter hydrocarbon reservoirs commercially producer, thus
contributing to the growing demand significantly in the country

similar documents