Hydrocarbon Occurrence in Unconventional Shale Reservoirs of

Cambay Basin and their Exploitation technologies

Dev Dutt SharmaIUGF, 18 Jan 2013, Mumbai

Introduction 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

Presentation Outline

Hydrocarbon Resource Pyramid

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.

Introduction

Location of Cambay Basin

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

Hydrocarbon Occurrence in Shale Reservoirs of Cambay Basin

Generalised Stratigraphy of Cambay Basin

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.

Characteristics of Unconventional Shale Reservoirs

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

Mechanism of production from Cambay Shale

Prodelta Shale Facies- Chhatral Member

Prodelta Shale Facies- Mandhali Member

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 on resistivity log 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 occurrence” and more than 3.5 “Non-commercial” hydrocarbon bearing zonesThe 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.As thumb rule 1/6th of perforation interval in shale was considered as pay for estimation of reserves

Evaluation technologies applied for Shale reservoirs in the past

Typical Shale Resistivity Ratio Profile

Log correlation of producing Younger Cambay Shale section in Sanand wells

Shale Resistivity Ratio Profile Sanand wells

Sanand-A Sanand-B

Log correlation of producing Younger Cambay Shale section in Wadu wells

Shale Resistivity Ratio Profile Wadu wells

Wadu-A Wadu-B

Drilling and production:Oil production from Cambay Shale reservoir which was initially @30-50m3/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 25,000-30,000m3/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.

Technologies applied for shale reservoirs in past- contd..

New technologies for Tight Reservoir Development applied in Cambay field Formation evaluation Horizontal drilling Multistage fracturing Microseismic monitoring Extended production testing

Cambay PSC area showing Cambay-76H well

◦ 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

“Tight” Pay zones occurrence in Cambay Field

Cambay-23z Cambay-40

Deccan

Cambay-73Cambay-19z

OSII

Top Eocene

2 km

EW

X ZoneY Zone

Z Zone

Cambay-23z Cambay-40

Deccan

Cambay-73Cambay-19z

OSII

Top Eocene

2 km2 km

EW

X ZoneY Zone

Z Zone

CAMBAY 76HWell Path

Formation Evaluation of a Type Cambay Well• Sophisticated proprietary log

interpretation technology• 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 three 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-III (X-zone)

EP-IV A(Y-zone)

EP-IVB (Y-zone)

YCS (Z-zone)

“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 geometry and permeability trend in the reservoir for further 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.

Drilling & Completion of Cambay-76H

Cambay-76H Well Profile

76H Heel76H Toe

Y Top

X Top

OSIICasing Point

Cambay-76HNW SE

610m

C-76H well Drilling & Completion Schematic

Multistage Fracturing Cambay-76H 8 stage fracture stimulation (16 frac ports) in 7 daysGood fracture connectivity, frac height about 70m130-150 tonnes /stage, total about 1200tons 4,400bbl water per stage @60 bbl/minComparable 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 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 fracturing provided additional

calibration Extracted 617 microseismic events, 229 mechanical events Location errors less than +/-15m in horizontal and vertical directions

Microseismic Monitoring

Microseismic Acquisition 991 stations in array

represented by red lines. Station spacing is 20 m Array consists of 10 lines

radiating out from the well head

High fold, wide azimuth & large aperture coverage of 20.25 sq. km.

Cambay 76H well path shown by yellow dashed line

Data acquired using Aram Aries-II recording system at 2ms sampling rate provided by IOT.

Microseismic Interpretation

Extended Production Testing

Extended production testing includes:• Post frac well cleanup• Long term flow rate

testing through different beans

• Installation of EPS• Medium term reservoir

performance • PLT logging• PVT sampling , fluid

composition (gas, oil/ condensate, water) and pressure information

Field Development Strategy

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

Application of similar New Technologies for Tight Reservoirs in other basins of India

Multistage Fracturing Animation

Thank you