Dev Dutt Sharma

IUGF, Mumbai 20 Jan 2012

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

76H Heel 76H Toe Y

Top

X Top

OSII Casing Point

Cambay-XH NW SE

610m

Cambay Well Drilling & Completion Schematic

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.

h