Cambay Development Detail & Status

On 14 February 2024 Synergia Energy announced the agreement to farm out 50% of the 100% interest held by the Synergia Group in the Cambay PSC to Selan Exploration Technology Limited (“Selan”).

The Selan JV was approved by the Government of India on 19 July 2024.

Selan, is an Indian oil and gas operator listed on the Bombay Stock Exchange and the National Stock Exchange of India. Selan has currently entered into a scheme of amalgamation with Antelopus Energy Private Limited, another highly respected Indian oil and gas operator, which is currently awaiting regulatory approvals.

Synergia and Selan will be joint operators of the Cambay PSC with Selan to be appointed as Lead Joint Operator. The farm-out and associated joint operating agreement are conditional upon customary consents from the Government of India for the transfer of the 50% interest to Selan and Selan assuming a Lead Joint Operator role

In exchange for the 50% interest, Synergia will be carried by Selan through an agreed US$20 million work programme (“WP”) comprising 3 new wells focussed on the Eocene reservoir and 6 well work-overs.

The WP is to be completed within 18 months of the later of Government of India approval of the WP or the award of contracts for the WP, extendable by a further six months in certain circumstances.

Selan has the option to participate in the Cambay CCS scheme on terms to be agreed.

Synergia Energy’s Cambay Project, An Eocene-Aged Tight Gas Accumulation in the Cambay Basin, India

Synergia’s 100% owned tight gas project is located in Gujarat state in the Cambay Basin which has been one of India’s most significant hydrocarbon production regions. The reservoir is an Eocene Age siltstone with gas presence confirmed in multiple wells.

History

The Cambay licence has an interesting history and holds a very significant place in the development of India’s oil and gas industry. In 1958, the first well undertaken by India’s newly established national oil company (ONGC) was drilled within the area of the current licence. The well was also India’s first hydrocarbon discovery outside of Assam and marked the beginning of India’s modern hydrocarbon industry. It was the first indication of how prolific the Cambay Basin was to become and was followed by many more discoveries.

Some 70 wells have been drilled within the Cambay licence. Almost all of these have recorded hydrocarbon indications and a number were placed on commercial production from multiple reservoir zones. Around 60% of the wells were drilled between 1958 and 1969 using outdated drilling practices and rudimentary logging tools and are of limited reliability and use. The first 3 wells suffered blow outs of both water and hydrocarbons from over-pressured formations. However, the rich prospectivity of the area was established from the very first well.

Early work focussed on the shallower Miocene and Oligocene horizons with commercial production rates being achieved. The rich hydrocarbon occurrence in the Eocene EP-III and EP-IV sections was known from the first well but given the low reservoir quality, attempts to bring it on production came up short of target.

Eocene Horizon

The Eocene section has been intersected by hundreds of wells across the Cambay Basin. Within the Cambay licence area, over 40 wells have intersected the prospective section called either the ‘Y” zone or the “EPIII” and “EPIV” zones. Test rates and production rates are low because of the generally low permeability of the reservoir but the presence of gas and associated condensate and oil has been confirmed many times over. 

The shale gas revolution in the USA in the early 2000’s demonstrated the technology required to commercially produce both oil and gas from tight (or “unconventional”) reservoirs. These types of reservoirs require additional technology, usually horizontal drilling and fracture stimulation, to release the hydrocarbon resource from the rock.

Synergia’s (Oilex’s) initial attempts at horizontal drilling and fracture stimulation in wells C-76H and C- 77H have been partially successful. Both wells were drilled to TD with no problems. However, only a low rate of gas production was established from the C-77H, leading to a large volume of evaluation and analysis work to identify the reasons for failure and the optimal approaches to be undertaken.

In carrying out this work over the last 10 years, Synergia has used its own in-house resources coupled with international expertise from more than a dozen service companies and consulting groups to provide a detailed tight reservoir analysis. The gas production test rates from a number of wells (as shown in the map below) have contributed to the better understanding of the Eocene reservoir.

Cambay field production test results from wells drilled and tested in the Eocene reservoir

The work has included
i) Reprocessing and specialist analysis of the 3D seismic data
ii) Detailed geomechanical modelling addressing rock strength and behaviour, and regional stress regimes
iii) Detailed analysis of well logs and reservoir properties iv) Formation water studies
v) Fracture stimulation studies
vi) Gas and oil production modelling
vii) Field Development Studies.

The hallmarks of the Eocene Y zone accumulation and the reasons for the efforts directing at achieving commercial flow rates from the tight Eocene reservoir include:

1. i)  Oil and/or gas shows in almost every well which has intersected the section

2. ii)  Flow tests of oil and/or gas as shown in the map above

3. iii)  Anomalies on the resistivity logs, generally as a double peak as shown in the C-19Z example

    4. iv)  No discrete water leg defining the accumulation indicating the potential for a continuous resource

    5. v)  Low permeability

    6. vi)  Improved flow rates after fracture stimulation.

Potential Size of Resource

Multi-TCF potential defined by multiple third party expert reports

• 2P + 2C: 926 BCF gas and 61 mmbbl condensate (Ref: RISC 2015 and 2022)

• 2P gas reserves of 206 BCF

  Cambay Field Development Strategy

A. Horizontal wells

With modern drilling practices, the drilling of horizontal and extended reach horizontal wells has become commonplace. Despite the greater cost than vertical wells, horizontal wells have many advantages:

• Greater production rates due to greater wellbore exposure in the payzone

• Greater reserve recovery per well

• Reduced risk of “water coning” by placing wellbore in the upper part of the reservoir

• Ability to exploit large sections of the licence from one well pad with multiple wells

• Common processing and pipeline tie in point for multiple wells

The two horizontal wells drilled by Synergia (C-76H and C-77H) proved that these types of wells can be drilled to total depth efficiently. The challenge for the company is gas production rates per well.

Double Resistivity Peaks (High resistivity is generally associated with the presence of hydrocarbons

Synergia needed to establish a robust fracking methodology that results in economic productions rates for each well drilled.

B. C-77H Re-frac

The in-depth analysis undertaken by the company post C-76H and C-77H revealed several deficiencies in the fracking programs on both wells.

In preparation of a full-field development, Synergia Energy undertook a re-fracking operation in July 2022 on the C-77H well to establish a robust fracking methodology for future new wells. The original 4 fracked zones were isolated with a bridge plug and two new zones were individually fracked in the heel of the well. Testing during flowback resulted in gas flow rates of up to 0.5 mmscfd through a 16/64” choke while the well was being cleaned of frac fluid. 

The results of the re-frac were encouraging:

• Plateau production from the 2 newly fracked zones was established at 250-150 mscfd despite significant fluid loading – primarily gas condensate. Continuous stable gas production has been established with little discernible decline rates. 

• Future new wells with 15-20 zones can provide initial plateau production of c. 4 mmscfd