Presentation on theme: "Dev Dutt Sharma IUGF, 18 Jan 2013, Mumbai. Introduction Hydrocarbon Occurrence in Shale Reservoirs of Cambay Basin Mechanism of production from."— Presentation transcript:
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
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: 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 zones The 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 1/6 th 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 @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.
140 - 400m gross interval 3 large pay zones (X, Y and Z) Further possible tight pay zones below Z zone CAMBAY 76H Well Path
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 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.
76H Heel 76H Toe Y Top X Top OSII Casing Point Cambay-76H NW SE 610m
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 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
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.
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
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