tight reservoir technology iugf 20 1 2012
TRANSCRIPT
Introduction
Hydrocarbon Occurrence in Tight Reservoirs of Cambay Basin
Mechanism of production from Cambay Shale Tight reservoirs
Evaluation & Development technologies applied in past
New technologies for Tight Hydrocarbon Reservoir
Development applied in Cambay Field, Cambay Basin
Possible application of such Tight Reservoir Development
technologies in other basins of India
Cambay Petroliferous Basin is on mature stage of exploration in view of
over 50 years of development and production history with focus on
known conventional reservoirs
Thrust is required for development of shallow Babaguru and Tarapur and
deeper Cambay Shale and Olpad formations including Deccan Trap
basement in view of recent encouraging discoveries
Basin offers further scopes for exploration and production from deeper
tighter unconventional reservoirs of Cambay Shale & Olpad formations,
including fractured trap which constitute 2/3 sedimentary thickness
Recent development of new technologies of formation evaluation,
drilling and stimulation/HF especially in US and Canada has made low
productive unconventional Tight Gas Sands, Shale Gas 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 in the basin at Cambay Field 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 Kalol, Indrora, Sanand, Jhalora, Wadu & Nandej etc.
Interestingly, Indrora-1 was drilled in 1971 is still producing oil on self from high pressured Cambay Shale Reservoir “Indrora Shale Pay”, though in small quantity.
Similarly wells like K-165 produced oil from Younger Cambay Shale for long (over 30 years), though at low rate.
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
organic maturity.
Dual porosity and dual permeability mechanism is responsible for oil &
gas production from low permeability tight reservoir of Cambay Shale
Tripple porosity and dual permeability model is applicable for “Shale
Gas” production from Cambay Shale
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 or insitu HC accumulation
Have no free water or hydrocarbon-water contact being dominantly
argillaceous with more of bound water than free water.
Formation evaluation:
It 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
Overlay of density-neutron porosity was used when available in new wells.
New concept of “Shale Resistivity Ratio” was applied based on analogy with US Gulf of Mexico as
applicable to high pressure shales
Intervals having SRR of 1.6-3.0 considered as “commercial”, 3.0-3.5 as “Small” and more than 3.5
“Non-commercial” hydrocarbon bearing zones
The concept was applied in newly drilled wells of Sanand, Jhalora, Wadu, Kalol, Indrora , Nandej etc
for testing or identification of bypassed pays in old wells in shale section, which proved very
effective.
Conventional Sw calculation indicated very high waster saturation (70-100%) to which 20-40% shale
correction was applied for testing in shale reservoir because of their clayey nature having more
bound water than free water.
As a thumb rule 1/6th of perf. interval in shale was considered as pay for estimation of reserves
Drilling and production: Oil production from Cambay Shale reservoir which was initially @30-
50m3/d declined fast to 3-5m3/d 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 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 tight silt or shale reservoirs Deviated drilling and MWD logging techniques were first time applied in
a Wadu well, which produced about 40m3/d oil and 27,000m3/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 Vindhyan Sandstone at 2450-2460m depth had to be abandoned.
Technology improved over the years, especially in last decade for formation evaluation, horizontal drilling and multistage fracturing, especially in US and Canada which resulted in making unconventional tight reservoirs attractive hydrocarbon resources.
At present, unconventional reservoirs of Shale Gas, Tight Gas Sand and CBM contribute about 40% of natural gas production in the US.
Shale Gas has become a hot resource and buzz word now world over.
In India, shale gas venture has just begun, whereas CBM is at threshold and Tight Gas Sand production is obtained knowingly or unknowingly.
New technologies of formation evaluation, horizontal drilling, multistage fracturing, microseismic monitoring applied for Tight Hydrocarbon Reservoir Development first time in a Cambay Field well in the Basin on analogy with US Shale Gas technology.
The well was drilled to 2740m (TVD 1760m) with horizontal section of
(>600m) in Tight Siltstone Reservoir of Eocene in Cambay Field
Completed with 5/12” 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 trend has been monitored by microseismic survey to define
fracture geometry and permeability trend in the reservoir for further
development and production enhancement.
The well is expected to produce 300,000-500,000 m3/d against the
normal production of 30,000-50,000m3/d with conventional
technology.
• Sophisticated proprietary log interpretation
• Curves generated include: – Shale Permeability * – Porosity – TOC * – Variable Density – Lithologies – Free Gas * – Sw – Bulk Volume Irreducible * – Free Water * – Effective Porosity – Free Fluid Volume – Volume of Hydrocarbons
• Results identified high potential zones in the Eocene section
Type Cambay Well
X Zone
Y Zone
EP-II
EP-III
EP-IV Marker
Base EP-IV
(20m)
(36m)
EP-II
EP-III
EP-IV
Base
EP-IV
140 - 400m gross interval
3 large pay zones (X, Y and Z)
Further possible tight pay zones below Z zone
Cambay-23z Cambay-40
Deccan
Cambay-73Cambay-19z
OSII
Top Eocene
2 km
EW
X Zone
Y Zone
Z Zone
Cambay-23z Cambay-40
Deccan
Cambay-73Cambay-19z
OSII
Top Eocene
2 km2 km
EW
X Zone
Y Zone
Z Zone
X Zone Y Zone
Z Zone
Used open hole completion 9-5/8"x 5-1/2" liner hanger packer, 5-1/2" tubing, 10 water-swellable packers, 16 stimulation sleeves (2 sleeves per stage).
Frac sleeves were actuated by dropping a ball matched to their respective seat sizes.
The fracturing treatment commenced by pumping an injection test, completed in 8 days
Long-term overnight shut-in performed after each fracturing stage resulted in one fracture treatment per day.
The last two stages (stage 7 and 8) were pumped on the same day.
Propped fracture geometry estimates to be carried out
Extensive artificial fractures increases the surface area exposed
Fluid + proppant pumped into well bore at pressure US example.
Microseismic Operations
8 Frac treatments at the Well C-XH monitored over period of 8 days.
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 activity
Velocity model initially calibrated by a perforation shot in an offset well.
Mechanical ball drop events during fraccing provided additional calibration.
Extracted 617 microseismic events, 229 mechanical events.
Location errors less than +/-15 metres in horizontal and vertical directions
991 stations in array represented by red lines.
Station spacing is 20 metres
Array consists of 10 lines radiating out from the well head
High fold, wide azimuth & large aperture coverage of 20.25 sq. km.
Cambay XH well path shown by yellow dashed line
Data acquired using Aram Aries II recording system at 2 ms sampling rate provided by IOT.
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 (300-
700m), 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.
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